Item 1. Business.
GENERAL
Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is an energy company located in the Americas that provides its services through the business units described below.
In the second quarter of 2006, Duke Energy and Cinergy Corp. (Cinergy) consummated a merger which combined the Duke Energy and Cinergy regulated franchises, as well as deregulated generation in the Midwestern United States.
Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy, for purposes of this discussion regarding the merger). On April 3, 2006, in accordance with the merger agreement, Old Duke Energy and Cinergy merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). As a result of the merger transaction, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares of Duke Energy common stock. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the year ended December 31, 2005. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy hereinafter.
Cinergy, a Delaware corporation organized in 1993, owns all outstanding common stock of its public utility companies, Duke Energy Ohio, Inc. (Duke Energy Ohio) and Duke Energy Indiana, Inc. (Duke Energy Indiana), as well as other businesses including cogeneration and energy efficiency investments.
Duke Energy Ohio, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its wholly-owned subsidiary Duke Energy Kentucky, Inc. (Duke Energy Kentucky), in nearby areas of Kentucky. Its principal lines of business include generation, transmission, and distribution of electricity, the sale of and/or transportation of natural gas, and power marketing. The regulated operations of Duke Energy Ohio are included in the U.S. Franchised Electric and Gas business segment, whereas the unregulated portion of the business is included in the Commercial Power business segment.
Duke Energy Indiana, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in central, north central and southern Indiana. Its primary line of business is generation, transmission, and distribution of electricity.
On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, named Spectra Energy Corp. (Spectra Energy), including its wholly-owned subsidiary Spectra Energy Capital, LLC (Spectra Energy Capital, formerly Duke Capital LLC). The natural gas businesses spun off primarily consisted of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DCP Midstream, LLC (DCP Midstream, formerly Duke Energy Field Services, LLC), which was part of the Field Services business segment. The results of operations of these businesses are presented as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the spin-off. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.”
During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former Duke Energy North America’s (DENA) remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006 (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). As discussed below, certain assets of the former DENA business were transferred to the Commercial Power business segment and certain operations that Duke Energy continues to wind-down are in Other. The results of operations of the former DENA businesses which Duke Energy exited have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the completion of the exit activities.
PART I
At December 31, 2007, Duke Energy operated the following business segments, all of which are considered reportable segments under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information,”: U.S. Franchised Electric and Gas, Commercial Power, International Energy and Duke Energy’s 50% interest in the Crescent Resources joint venture (Crescent JV or Crescent). Prior to Duke Energy’s sale of an effective 50% ownership interest in Crescent in September 2006 (see below), this segment represented Duke Energy’s 100% ownership of Crescent Resources, LLC. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business segments in deciding how to allocate resources and evaluate performance. For additional information on each of these business segments, including financial and geographic information about each reportable business segment, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, southwestern Ohio, central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. These electric and gas operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC), the Public Utilities Commission of Ohio (PUCO), the Indiana Utility Regulatory Commission (IURC) and the Kentucky Public Service Commission (KPSC).
Commercial Power owns, operates and manages non-regulated power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio, acquired from Cinergy in April 2006, and the five Midwestern gas-fired non-regulated generation assets that were a portion of former DENA. Commercial Power’s assets comprise approximately 8,020 megawatts of power generation primarily located in the Midwestern U.S. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the Rate Stabilization Plan (RSP). For more information on the RSP, see the “Commercial Power” section below. Commercial Power also develops and implements customized energy solutions. Commercial Power, through Duke Energy Generation Services, Inc. and its affiliates (DEGS), develops, owns and operates electric generation for large energy consumers, municipalities, utilities and industrial facilities. DEGS currently manages more than 6,600 megawatts of power generation at 23 facilities throughout the U.S. DEGS has 240 megawatts of wind energy under construction and well over 2,500 megawatts of wind energy projects in the development pipeline.
International Energy owns, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America. Additionally, International Energy owns equity investments in Saudi Arabia and Greece.
Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern U.S. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.
On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create the Crescent JV with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.21 billion, net of transaction costs, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. A 2% interest in the Crescent JV was also issued by the joint venture to the President and Chief Executive Officer of Crescent, which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this 2% interest can be put back to the Crescent JV after three years, or possibly earlier upon the occurrence of certain events, at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes. Duke Energy’s investment in the Crescent JV has been accounted for as an equity method investment for periods after September 7, 2006.
PART I
The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, DukeNet Communications, LLC (DukeNet) and related telecom businesses and Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary. Additionally, Other includes the remaining portion of Duke Energy’s business formerly known as DENA that was not exited or transferred to Commercial Power, primarily Duke Energy Trading and Marketing, LLC (DETM), which management is currently in the process of winding down. Unallocated corporate costs include certain costs not allocable to Duke Energy’s reportable business segments, primarily governance costs, costs to achieve mergers and divestitures (such as the Cinergy merger and spin-off of Spectra Energy) and costs associated with certain corporate severance programs. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. On a limited basis, Bison also participates in reinsurance activities with certain third parties.
Duke Energy is a Delaware corporation. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. The telephone number is 704-594-6200. Duke Energy electronically files reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies and amendments to such reports. The public may read and copy any materials that Duke Energy files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about Duke Energy, including its reports filed with the SEC, is available through Duke Energy’s web site at http://www.duke-energy.com. Such reports are accessible at no charge through Duke Energy’s web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.
GLOSSARY OF TERMS
The following terms or acronyms used in this Form 10-K are defined below:
Term or Acronym
Definition
AAC
Annually Adjusted Component
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income
APB
Accounting Principles Board
Bison
Bison Insurance Company Limited
BPM
Bulk Power Marketing
Bridgeport
Bridgeport Energy LLC
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
Campeche
Compañía de Servicios de Compresión de Campeche, S.A. de C.V.
CAMR
Clean Air Mercury Rule
CC
Combined Cycle
CMT
Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc.
CT
Combustion Turbine
Cinergy
Cinergy Corp.
CO2
Carbon Dioxide
COL
Combined Construction and Operating License
CPCN
Certificate of Public Convenience and Necessity
Crescent
Crescent JV
DCP Midstream
DCP Midstream, LLC (formerly Duke Energy Field Services, LLC)
PART I
Term or Acronym
Definition
DEGS
Duke Energy Generation Services, Inc.
DEI
Duke Energy International, LLC
DEM
Duke Energy Merchants, LLC
DENA
Duke Energy North America
DENR
Department of Environment and Natural Resources
DETM
Duke Energy Trading and Marketing, LLC
DOE
Department of Energy
DOJ
Department of Justice
DSM
Demand Side Management
Duke Energy
Duke Energy Corporation (collectively with its subsidiaries)
Duke Energy Carolinas
Duke Energy Carolinas, LLC
Duke Energy Indiana
Duke Energy Indiana, Inc.
Duke Energy Kentucky
Duke Energy Kentucky, Inc.
Duke Energy Ohio
Duke Energy Ohio, Inc.
EITF
Emerging Issues Task Force
EPA
Environmental Protection Agency
EPS
Earnings Per Share
FASB
Financial Accounting Standards Board
FEED
Front End Engineering and Design Study
FERC
Federal Energy Regulatory Commission
FIN
Financial Accounting Standards Board Interpretation
FSP
Financial Accounting Standards Board Staff Position
FTC
Federal Trade Commission
GAAP
United States Generally Accepted Accounting Principles
GCSA
Gas Compression Services Agreement
IGCC
Integrated Gasification Combined Cycle
IRS
Internal Revenue Service
ISO
Independent Transmission System Operator
IURC
Indiana Utility Regulatory Commission
KPSC
Kentucky Public Service Commission
LS Power
LS Power Equity Partners
MBSSO
Market Based Standard Service Offer
Mcf
Thousand cubic feet
Moody’s
Moody’s Investor Services
MSREF
Morgan Stanley Real Estate Fund V U.S., L.P.
MW
Megawatt
NCUC
North Carolina Utilities Commission
NDTF
Nuclear Decommissioning Trust Funds
PART I
Term or Acronym
Definition
NERC
North American Electric Reliability Council
NMC
National Methanol Company
NOx
Nitrogen oxide
NRC
Nuclear Regulatory Commission
OCC
Office of the Ohio Consumers’ Counsel
OIL
Oil Insurance Limited
OUCC
Indiana Office of Utility Consumer Counselor
PEMEX
Mexican National Oil Company
PSCSC
Public Service Commission of South Carolina
PUCO
Public Utilities Commission of Ohio
PUHCA
Public Utility Holding Company Act of 1935, as amended
RSP
Rate Stabilization Plan
SAB
Securities and Exchange Commission Staff Accounting Bulletin
SB 221
Ohio Senate Bill 221
sEnergy
sEnergy Insurance Limited
SEC
Securities and Exchange Commission
SFAS
Statement of Financial Accounting Standards
SO2
Sulfur dioxide
SPE
Special Purpose Entity
Spectra Energy
Spectra Energy Corp.
Spectra Capital
Spectra Energy Capital, LLC (formerly Duke Capital LLC)
SRT
System Reliability Tracker
S&P
Standard & Poor’s
Synfuel
Synthetic Fuel
TEPPCO GP
Texas Eastern Products Pipeline Company, LLC
TEPPCO LP
TEPPCO Partners, L.P.
UBE
United Bridgeport Energy LLC
VIE
Variable Interest Entity
Westcoast
Westcoast Energy, Inc.
The following sections describe the business and operations of each of Duke Energy’s reportable business segments, as well as Other. (For more information on the operating outlook of Duke Energy and its reportable segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Introduction-Executive Overview and Economic Factors for Duke Energy’s Business”. For financial information on Duke Energy’s reportable business segments, see Note 3 to the Consolidated Financial Statements, “Business Segments.”)
U.S. FRANCHISED ELECTRIC AND GAS
Service Area and Customers
U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity and transports and sells natural gas. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky collectively referred to as Duke Energy Midwest). Its service area covers
PART I
about 47,000 square miles with an estimated population of 11 million in central and western North Carolina, western South Carolina, southwestern Ohio, central, north central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas supplies electric service to approximately 3.9 million residential, commercial and industrial customers over 148,700 miles of distribution lines and a 20,900 mile transmission system. U.S. Franchised Electric and Gas provides domestic regulated transmission and distribution services for natural gas to approximately 500,000 customers in southwestern Ohio and northern Kentucky via approximately 7,100 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and service lines. Electricity is also sold wholesale to incorporated municipalities and to public and private utilities. In addition, municipal and cooperative customers who purchased portions of the Catawba Nuclear Station may also buy power from a variety of suppliers, including Duke Energy Carolinas, through contractual agreements. For more information on the Catawba Nuclear Station joint ownership, see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating and Transmission Facilities.”
Duke Energy Carolinas’ service area has a diversified commercial and industrial presence. Manufacturing continues to be the largest contributor to the economy in the region. Other sectors such as finance, insurance and real estate services also constitute key components of the states’ gross domestic product.
The textile industry, rubber and plastic products, chemicals, and machinery and computer products were the most significant contributors to the area’s manufacturing output and Duke Energy Carolinas’ industrial sales revenue for 2007. Motor vehicle parts, paper, food and beverage, building materials and electrical and electronic equipment manufacturing also have a strong impact on the area’s economic growth and the region’s industrial sales. The textile industry, while in decline, is the largest industry served in both North Carolina and South Carolina (collectively referred to as the Carolinas).
Duke Energy Carolinas has business development strategies to leverage the competitive advantages of its service territory to attract and expand advanced manufacturing and data intensive business. These competitive advantages, including a quality workforce, strong educational institutions, superior transportation infrastructure and competitive electric rates 30% below the national average were key factors in attracting new businesses. The success in attracting new companies, as well as expanding the operations of existing customers, substantially offset the sales declines in the industries like textile and furniture in 2007.
Duke Energy Ohio’s and Duke Energy Kentucky’s service area both have a diversified commercial and industrial presence. Major components of the economy include manufacturing, real estate and rental leasing, wholesale trade, financial and insurance services, retail trade, education, healthcare and professional/business services. Cincinnati, Ohio is positioned to become a healthcare hub and the presence of non-durable manufacturing makes the area less vulnerable to economic fluctuations than other areas.
The primary metals industry, transportation equipment, chemicals, and paper and plastics were the most significant contributors to the area’s manufacturing output and Duke Energy Ohio’s and Duke Energy Kentucky’s industrial sales revenue for 2007. Food and beverage manufacturing, fabricated metals, and electronics also have a strong impact on the area’s economic growth and the region’s industrial sales.
Duke Energy Ohio and Duke Energy Kentucky have business development strategies to leverage the competitive advantages of the Greater Cincinnati Region to attract and expand advanced manufacturing businesses. The availability of a highly skilled workforce, superior highway access, low cost of living, and proximity to markets and raw materials are key factors in attracting new customers in the transportation, food manufacturing, chemical manufacturing, plastics and data processing industries.
Industries of major economic significance in Duke Energy Indiana’s service territory include chemicals, primary metals, and transportation. Other significant industries operating in the area include stone, clay and glass, food products, paper, and other manufacturing. Key sectors among commercial customers include education and retail trade.
Duke Energy Indiana has business development strategies to leverage the competitive advantages of the Indiana region to attract new advanced manufacturing, logistics, life sciences and data center business to Duke Energy Indiana’s service territory. These advantages, including competitive electric rates, a strong transportation network, excellent institutions of higher learning, and a quality workforce, were key in attracting new customers and encouraging existing customer expansions. This ability to attract business investment in the service territory helped balance the slight decline in sales in the chemical, food and transportation equipment sector in 2007.
The number of residential and commercial customers within the U.S. Franchised Electric and Gas’ service territory continues to increase. As a result, sales to these customers are increasing due to the growth in these sectors. As sales to residential and commercial customers increase, the level of sales to industrial customers becomes a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales.
PART I
U.S. Franchised Electric and Gas’ costs and revenues are influenced by seasonal patterns. Peak sales of electricity occur during the summer and winter months, resulting in higher revenue and cash flows during those periods. By contrast, fewer sales of electricity occur during the spring and fall, allowing for scheduled plant maintenance during those periods. Peak gas sales occur during the winter months.
The following maps show the U.S. Franchised Electric and Gas’ service territories and operating facilities.
Duke Energy - Carolinas
Power Generation Regulated Facilities
PART I
Energy Capacity and Resources
Electric energy for U.S. Franchised Electric and Gas’ customers is generated by three nuclear generating stations with a combined net capacity of 5,020 megawatts (MW) (including Duke Energy’s 12.5% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with a combined net capacity of 13,552 MW (including Duke Energy’s 69% ownership in the East Bend Steam Station and 50.05% ownership in Unit 5 of the Gibson Steam Station), thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined net capacity of 3,213 MW, fifteen combustion turbine (CT) stations burning natural gas, oil or other fuels with a combined net capacity of 5,241 MW and two combined cycle (CC) stations burning natural gas or synthetic gas with a combined net capacity of 560 MW. Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Factors that could cause U.S. Franchised Electric and Gas to purchase power for its customers include generating plant outages, extreme weather conditions, summer reliability, growth, and price. U.S. Franchised Electric and Gas has interconnections and arrangements with its neighboring utilities to facilitate planning, emergency assistance, sale and purchase of capacity and energy, and reliability of power supply.
U.S. Franchised Electric and Gas’ generation portfolio is a balanced mix of energy resources having different operating characteristics and fuel sources designed to provide energy at the lowest possible cost to meet its obligation to serve native-load customers. All options, including owned generation resources and purchased power opportunities, are continually evaluated on a real-time basis to select and dispatch the lowest-cost resources available to meet system load requirements. The vast majority of customer energy needs are met by large, low-energy-production-cost nuclear and coal-fired generating units that operate almost continuously (or at baseload levels). In 2007, approximately 97.7% of the total generated energy came from U.S Franchised Electric and Gas’ low-cost, efficient nuclear and coal units (66.5% coal and 31.2% nuclear). The remaining energy needs were supplied by hydroelectric, CT and CC generation or economic purchases from the wholesale market.
Hydroelectric (both conventional and pumped storage) in the Carolinas and gas/oil CT and CC stations in both the Carolinas and Midwest operate primarily during the peak-hour load periods (at peaking levels) when customer loads are rapidly changing. CT’s and CC’s produce energy at higher production costs than either nuclear or coal, but are less expensive to build and maintain, and can be rapidly started or stopped as needed to meet changing customer loads. Hydroelectric units produce low-cost energy, but their operations are limited by the availability of water flow.
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U.S. Franchised Electric and Gas’ major pumped-storage hydroelectric facilities offer the added flexibility of using low-cost off-peak energy to pump water that will be stored for later generation use during times of higher-cost on-peak generation periods. These facilities allow U.S. Franchised Electric and Gas to maximize the value spreads between different high- and low-cost generation periods.
U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territories. Long-term projections indicate a need for significant capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC), coal facilities or gas-fired generation units. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. In March 2006, Duke Energy Carolinas announced that it had entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. In May 2007, Duke Energy announced its intent to purchase Southern Company’s 500 MW interest in the proposed William States Lee III Nuclear Station, making the plant’s total output available to Duke Energy Carolinas’ electric customers. On December 13, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors at the Cherokee County, South Carolina site. Each reactor is capable of producing approximately 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On February 27, 2008, Duke Energy Carolinas received confirmation from the NRC that its COL application has been accepted and docketed for the next stage of review. Also, on December 7, 2007, Duke Energy Carolinas filed applications with the NCUC and the PSCSC for approval of Duke Energy Carolinas’ decision to incur development costs associated with the proposed William States Lee III Nuclear Station. The NCUC had previously approved Duke Energy’s decision to incur the North Carolina allocable share of up to $125 million in development costs through 2007. The new requests cover a total of up to $230 million in pre-construction development costs through 2009, which is comprised of approximately $70 million incurred through December 31, 2007 plus an additional $160 million of anticipated costs in 2008 and 2009. The PSCSC has scheduled an evidentiary hearing on Duke Energy Carolinas’ application for April 17, 2008 and the NCUC has scheduled an evidentiary hearing for April 29, 2008. Also, in December 2006, Duke Energy announced an agreement to purchase a portion of Saluda River Electric Cooperative, Inc.’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy will pay approximately $158 million for the additional ownership interest of the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy will own approximately 19 percent of Catawba Nuclear Station. This transaction, which is expected to close prior to September 30, 2008, is subject to approval by various state and federal agencies.
On June 2, 2006, Duke Energy Carolinas filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. On March 21, 2007, the NCUC issued its Order, which explained the basis for its decision to approve construction of one unit, with an approved cost estimate of $1.93 billion (including allowance for funds used during construction (AFUDC)), and certain conditions including providing for updates on construction cost estimates. A group of environmental interveners filed a motion and supplemental motion for reconsideration in April 2007 and May 2007, respectively. Duke Energy opposed the motions and the NCUC denied the motions for reconsideration in June 2007. On January 31, 2008, Duke Energy Carolinas filed its updated cost estimate of $1.8 billion (excluding AFUDC of $600 million) for the approved new Cliffside Unit 6. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $125 million in federal advanced clean coal tax credits. On July 11, 2007, Duke Energy Carolinas entered into an engineering, procurement, construction and commissioning services agreement, valued at approximately $1.3 billion, with an affiliate of The Shaw Group, Inc., of which approximately $950 million relates to participation in the construction of a new 800 MW coal unit, with the remainder related to a flue gas desulfurization system on an existing unit, at Cliffside. On January 29, 2008, the final air permit was issued by the North Carolina Department of Environment and Natural Resources (DENR).
On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 600-800 MW combined cycle natural gas-fired generating facility at its existing Dan River Steam Station, as well as updated preliminary CPCN information to construct a 600-800 MW combined cycle natural gas-fired generating facility at its existing Buck Steam Station. On December 14, 2007, Duke Energy Carolinas filed CPCN applications for the two combined cycle facilities. The NCUC has consolidated its consideration of the two CPCN applications and scheduled an evidentiary hearing on the applications for March 11, 2008.
In August 2005, Duke Energy Indiana filed an application with the IURC for approval of study and preconstruction costs related to the joint development of an IGCC project with Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (Vectren). Duke Energy Indiana and Vectren reached a Settlement Agreement with the Indiana Office of Utility Consumer Counselor (OUCC) providing for the recovery of such costs if the IGCC project is approved and constructed and for the partial recovery of such costs if the IGCC project does not go forward. The IURC issued an order on July 26, 2006 approving the Settlement Agreement in its entirety.
PART I
On September 7, 2006, Duke Energy Indiana and Vectren filed a joint petition with the IURC seeking CPCN’s for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. The petition describes the applicants’ need for additional baseload generating capacity and requests timely recovery of all construction and operating costs related to the proposed generating station, including financing costs, together with certain incentive ratemaking treatment. Duke Energy Indiana and Vectren filed their cases in chief with the IURC on October 24, 2006. As with Duke Energy Carolinas’ Cliffside project, Duke Energy Indiana’s estimated costs for the potential IGCC project have increased. Duke Energy Indiana’s publicly filed testimony with the IURC states that industry estimates (as provided by the Electric Power Research Institute (EPRI)) of total capital requirements for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owners’ specific site costs). In April 2007, Duke Energy Indiana and Vectren filed a Front End Engineering and Design (FEED) Study Report which included an updated estimated cost for the IGCC project of approximately $2 billion (including AFUDC). An evidentiary hearing was held June 18-22, 2007, and a public field hearing was held on August 29, 2007. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana CPCNs for the proposed IGCC project and approved the timely recovery of costs related to the project. The IURC also approved Duke Energy Indiana’s proposal to initiate a proceeding in May 2008 concerning proposals for the study of partial carbon capture, sequestration and/or enhanced oil recovery for the Edwardsport IGCC Project. The Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc., all intervenors in the CPCN proceeding, have appealed the IURC Order to the Indiana Court of Appeals. That appeal is pending. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management. In August 2007, Vectren withdrew its participation in the IGCC plant. Duke Energy Indiana is currently exploring its options, including assuming 100% of the plant capacity. Absent identification of an alternative joint owner, Duke Energy Indiana would own 100% of the IGCC plant capacity.
Fuel Supply
U.S. Franchised Electric and Gas relies principally on coal and nuclear fuel for its generation of electric energy. The following table lists U.S. Franchised Electric and Gas’ sources of power and fuel costs for the three years ended December 31, 2007.
(a) Statistics related to coal generation and all fuels reflect U.S. Franchised Electric and Gas’ 69% ownership interest in the East Bend Steam Station and 50.05% ownership interest in Unit 5 of the Gibson Steam Station.
(b) Statistics related to nuclear generation and all fuels reflect U.S. Franchised Electric and Gas’ 12.5% ownership interest in the Catawba Nuclear Station.
(c) Cost statistics include amounts for light-off fuel at U.S. Franchised Electric and Gas’ coal-fired stations.
(d) Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.
(e) Includes legacy Cinergy regulated operations from the date of acquisition (April 3, 2006) and thereafter.
Coal. U.S. Franchised Electric and Gas meets its coal demand in the Carolinas and Midwest through a portfolio of purchase supply contracts and spot agreements. Large amounts of coal are purchased under supply contracts with mining operators who mine both underground and at the surface. U.S. Franchised Electric and Gas uses spot-market purchases to meet coal requirements not met by supply contracts. Expiration dates for its supply contracts, which have various price adjustment provisions and market re-openers, range from 2008 to 2016. U.S. Franchised Electric and Gas expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required as existing contracts expire, though prices will fluctuate over time as coal markets change. The coal purchased for the Carolinas is primarily produced from mines in eastern Kentucky, West Virginia and southwestern Virginia. The coal purchased for the regulated Midwest entities is primarily produced in Indiana, Illinois, and Kentucky. U.S. Franchised Electric and Gas has an adequate supply of coal to fuel its projected 2008 operations and a significant portion of supply to fuel its projected 2009 operations.
The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Carolinas is approximately 1%; however, as Carolinas coal plants continue to bring on scrubbers over the next several years, the sulfur content of coal purchased could increase as higher sulfur coal options are considered. The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Midwest is approximately 2%. Coupled with the use of available sulfur dioxide (SO2) emission allowances on the open market, this satisfies the current emission limitations for SO2 for existing facilities in the Carolinas and Midwest.
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Gas. U.S. Franchised Electric and Gas is responsible for the purchase and the subsequent delivery of natural gas to native load customers in the Midwest. U.S. Franchised Electric and Gas’ natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows U.S. Franchised Electric and Gas to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides U.S. Franchised Electric and Gas the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under U.S. Franchised Electric and Gas’ customer choice/gas transportation programs. In 2007, firm supply purchase commitment agreements provided approximately 97% of the natural gas supply, with the remaining gas purchased on the spot market. These firm supply agreements feature two levels of gas supply, specifically (1) baseload, which is a continuous supply to meet normal demand requirements, and (2) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.
U.S. Franchised Electric and Gas also owns two underground caverns with a total storage capacity of approximately 16 million gallons of liquid propane. In addition, U.S. Franchised Electric and Gas has access to nine million gallons of liquid propane through a storage agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.
U.S. Franchised Electric and Gas manages natural gas procurement-price volatility mitigation programs for Duke Energy Ohio and Duke Energy Kentucky. These programs pre-arrange between 25-75% of winter heating season baseload gas requirements and up to 25-50% of summer season baseload requirements up to three years in advance of the delivery month. Duke Energy Ohio and Duke Energy Kentucky use primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2007, Duke Energy Ohio and Duke Energy Kentucky, combined, had hedged approximately 52% of their winter 2007/2008 base load requirements.
U.S. Franchised Electric and Gas is responsible for the purchase and the subsequent delivery of natural gas to the gas turbine generators to serve native electric load customers in the Duke Energy Carolinas, Duke Energy Indiana and Duke Energy Kentucky service territories. The natural gas procurement strategy is to contract with one or several suppliers who buy spot market natural gas supplies along with firm or interruptible interstate pipeline transportation capacity for deliveries to the site. This strategy allows for competitive pricing, flexibility of delivery, and reliable natural gas supplies to each of the natural gas plants. Many of the natural gas plants can be served by several supply zones and multiple pipelines.
Duke Energy Indiana hedges a percentage of its winter and summer expected native gas burn from Indiana gas turbine units using financial swaps tied to the NYMEX-Henry Hub natural gas futures.
Nuclear. Developing nuclear generating fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and then the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
U.S. Franchised Electric and Gas has contracted for uranium materials and services required to fuel the Oconee, McGuire and Catawba Nuclear Stations in the Carolinas. Uranium concentrates, conversion services and enrichment services are primarily met through a diversified portfolio of long-term supply contracts. The contracts are diversified by supplier, country of origin and pricing. U.S. Franchised Electric and Gas staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements at Oconee, McGuire and Catawba in the near term, but so that its level of coverage decreases over time into the future. Due to the technical complexities of changing suppliers of fuel fabrication services, U.S. Franchised Electric and Gas generally sole sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.
Based on current projections, U.S. Franchised Electric and Gas’ existing portfolio of contracts will meet the requirements of Oconee, McGuire and Catawba Nuclear Stations through the following years:
Nuclear Station
Uranium Material
Conversion Service
Enrichment Service
Fabrication Service
Oconee
McGuire
Catawba
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After the years indicated above, a portion of the fuel requirements at Oconee, McGuire and Catawba are covered by long-term contracts. For requirements not covered under long-term contracts, Duke Energy believes it will be able to renew contracts as they expire, or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with uranium spot market purchases.
Duke Energy Carolinas has entered into a contract with Shaw AREVA MOX Services (MOX Services) (formerly Duke COGEMA Stone & Webster, LLC) under which Duke Energy Carolinas has agreed to prepare the McGuire and Catawba nuclear reactors for use of mixed-oxide fuel and to purchase mixed-oxide fuel for use in such reactors. Mixed-oxide fuel will be fabricated by MOX Services from the U.S. government’s excess plutonium from its nuclear weapons programs and is similar to conventional uranium fuel. Before using the fuel, Duke Energy Carolinas must apply for and obtain amendments to the facilities’ operating licenses from the NRC. On March 3, 2005, the NRC issued amendments to Catawba Nuclear Station’s operating licenses to allow the receipt and use of four mixed oxide fuel lead assemblies. These four lead assemblies completed their first cycle of irradiation on November 11, 2006 and have been inserted for a second cycle of irradiation in Unit 1 of the Catawba Nuclear Station.
Energy Efficiency. In May 2007, Duke Energy Carolinas filed an energy efficiency plan with the NCUC that recognizes energy efficiency as a reliable, valuable resource that is a “fifth fuel,” that should be part of the portfolio available to meet customers’ growing need for electricity along with coal, nuclear, natural gas, or renewable energy. The plan would compensate Duke Energy Carolinas for verified reductions in energy use and be available to all customer groups. The plan contains proposals for several different energy efficiency programs. Customers would pay for energy efficiency programs with an energy efficiency rider that would be included in their power bill and adjusted annually. The energy efficiency rider would be based on the avoided cost of generation not needed as a result of the success of Duke Energy Carolinas’ energy efficiency efforts. The plan is consistent with Duke Energy Carolinas’ public commitment to invest 1% of its annual retail revenues from the sale of electricity in energy efficiency programs subject to the appropriate regulatory treatment of Duke Energy Carolinas’ energy efficiency investments. A hearing is expected in 2008.
On September 28, 2007, Duke Energy Carolinas filed an application with the PSCSC seeking approval to implement new energy efficiency programs in South Carolina. Duke Energy Carolinas’ South Carolina application is based on the application filed in North Carolina. In advance of the evidentiary hearing held February 5-6, 2008, Duke Energy Carolinas reached settlement agreements with the South Carolina Office of Regulatory Staff (ORS), Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. Certain environmental groups that were also interveners on the proceeding did not join any of the settlements. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allows for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.
Implementation of these plans is subject to approval from the NCUC and PSCSC. As a result, Duke Energy is not able to estimate the impact this plan might have on its consolidated results of operations, cash flows, or financial position.
On July 11, 2007, the PUCO approved Duke Energy Ohio’s Demand Side Management/ Energy Efficiency Program (DSM Program). The DSM Program consists of ten residential and two commercial programs. Implementation of the programs has begun. The programs were first proposed in 2006 and were endorsed by the Duke Energy Community Partnership, which is a collaborative group made up of representatives of organizations interested in energy conservation, efficiency and assistance to low-income customers. The program costs will be recouped through a cost recovery mechanism that will be adjusted annually to reflect the previous year’s activity. Duke Energy Ohio is permitted to recover lost revenues, program costs and shared savings (once the programs reach 65% of the targeted savings level) through the cost recovery mechanism based upon impact studies to be provided to the Staff of the PUCO.
On October 19, 2007, Duke Energy Indiana filed its petition with the IURC requesting approval of an alternative regulatory plan to increase its energy efficiency efforts in the state. Similar to the plans in North Carolina and South Carolina, Duke Energy Indiana seeks approval of a plan that will be available to all customer groups and will compensate Duke Energy Indiana for verified reductions in energy usage. Under the plan, customers would pay for energy efficiency programs through an energy efficiency rider that would be included in their power bill and adjusted annually through a proceeding before the IURC. The energy efficiency rider will be based on the avoided cost of generation not needed as a result of the success of Duke Energy Indiana’s energy efficiency programs. The IURC is expected to consider the petition in an evidentiary hearing in May 2008.
On November 15, 2007, Duke Energy Kentucky filed its annual application to continue existing energy efficiency programs, consisting of nine residential and two commercial and industrial programs, and to true-up its gas and electric tracking mechanism for recovery of lost revenues, program costs and shared savings. An order on the application is expected in the first quarter of 2008.
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Renewable Energy. Climate change concerns, as well as the high price of oil, have sparked rising government support in driving increasing renewable energy legislation at both the federal and state level. For example, the new energy legislation passed in North Carolina in 2007 establishes a renewable portfolio standard for electric utilities at 3% of output by 2012, rising gradually to 12.5% by 2021. Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana have issued Request for Proposals seeking bids for power generated from renewable energy sources, including sun, wind, water, organic matter and other sources that can be available as early as 2012.
Inventory
Generation of electricity is capital-intensive. U.S. Franchised Electric and Gas must maintain an adequate stock of fuel, materials and supplies in order to ensure continuous operation of generating facilities and reliable delivery to customers. As of December 31, 2007, the inventory balance for U.S. Franchised Electric and Gas was approximately $817 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.
Insurance and Decommissioning
Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and the Catawba Nuclear Stations each have two nuclear reactors and the Oconee Nuclear Station has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to provide for public liability claims resulting from nuclear incidents to the full limit of liability, which is approximately $10.8 billion. See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies-Nuclear Insurance,” for more information.
In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. During 2007, Duke Energy expensed approximately $48 million and contributed approximately $48 million of cash to the Nuclear Decommissioning Trust Funds (NDTF) for decommissioning costs. The entire $48 million was contributed to the funds reserved for contaminated costs as contributions to the funds reserved for non-contaminated costs have been discontinued since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,929 million as of December 31, 2007 and $1,775 million as of December 31, 2006. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds Within Investments and Other Assets.
Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s 12.5% ownership in Catawba Nuclear Station. The other joint owners of Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. The previous study, conducted in 1999, estimated a decommissioning cost of $1.9 billion ($2.2 billion in 2003 dollars at 3% inflation). The estimated increase is due primarily to inflation and cost increases for the size of the organization needed to manage the decommissioning project (based on current industry experience at facilities undergoing decommissioning). Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Duke Energy believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.
After used fuel is removed from a nuclear reactor, it is cooled in a spent-fuel pool at the nuclear station. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the Department of Energy (DOE) for the disposal of used nuclear fuel. The DOE failed to begin accepting used nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial used nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional used fuel storage capacity. On March 6, 2007, Duke Energy Carolinas and the U.S. Department of Justice reached a settlement resolving Duke Energy’s used nuclear fuel litigation against the DOE. The agreement provided for an initial payment to Duke Energy of approximately $56 million for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs. Duke Energy will continue to safely manage its used nuclear fuel until the DOE accepts it.
Duke Energy has experienced numerous claims for indemnification and medical reimbursements relating to damages for bodily injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas on its electric generation plants prior to 1985. Duke Energy has third-party insurance to cover certain
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losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Reserves recorded on Duke Energy’s Consolidated Balance Sheets are based upon the minimum amount in Duke Energy’s best estimate of the range of loss for current and future asbestos claims through 2027. Management believes it is possible that claims will continue to be filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related reserve estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change management’s estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside Duke Energy’s control, management believes it is reasonably possible that Duke Energy Carolinas may incur asbestos liabilities in excess of its recorded reserves.
Duke Energy Indiana and Duke Energy Ohio have also been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. The impact on Duke Energy’s financial position, cash flows, or results of operations of these cases to date has not been material. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana and Duke Energy Ohio generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the foreseeable future is not material. This estimated range of exposure may change as additional settlements occur and claims are made and more case law is established.
See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies-Asbestos Related Injuries and Damages Claims,” for more information.
Competition
U.S. Franchised Electric and Gas competes in some areas with government-owned power systems, municipally owned electric systems, rural electric cooperatives and other private utilities. By statute, the NCUC and the PSCSC assign service areas outside municipalities in North Carolina and South Carolina, respectively, to regulated electric utilities and rural electric cooperatives. Substantially all of the territory comprising Duke Energy Carolinas’ service area has been assigned in this manner. In unassigned areas, Duke Energy Carolinas’ business remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina, competition continues between municipalities and other electric suppliers outside the municipalities’ corporate limits, subject to the regulation of the PSCSC. In Kentucky, the right of municipalities to serve customers outside corporate limits is subject to court approval. In Ohio, certified suppliers may offer retail electric generation service to residential, commercial and industrial customers. In Indiana, the state is divided into certified electric service areas for municipal utilities, rural cooperatives and investor owned utilities. There are limited circumstances where the certified electric service areas can be modified, with approval of the IURC. U.S. Franchised Electric and Gas also competes with other utilities and marketers in the wholesale electric business. In addition, U.S. Franchised Electric and Gas continues to compete with natural gas providers.
Regulation
State
The NCUC, the PSCSC, the PUCO, the IURC and the KPSC (collectively, the State Utility Commissions) approve rates for retail electric service within their respective states. In addition, the PUCO and the KPSC approve rates for retail gas distribution service within their respective states. The FERC approves U.S. Franchised Electric and Gas’ cost based rates for electric sales to certain wholesale customers. For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters-U.S. Franchised Electric and Gas.” The State Utility Commissions, except for the PUCO, also have authority over the construction and operation of U.S. Franchised Electric and Gas’ facilities. CPCN’s issued by the State Utility Commissions, as applicable, authorize U.S. Franchised Electric and Gas to construct and operate its electric facilities, and to sell electricity to retail and wholesale customers. Prior approval from the relevant State Utility Commission is required for Duke Energy’s regulated operating companies to issue securities.
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In June 2007, Duke Energy Carolinas filed an application with the NCUC seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008. This application complied with a condition imposed by the NCUC in approving the Cinergy merger. On October 5, 2007, Duke Energy Carolinas filed an Agreement and Stipulation of Partial Settlement (Partial Settlement), a settlement agreement among Duke Energy Carolinas, the NCUC Public Staff, the North Carolina Attorney General’s Office, Carolina Utility Customers Association Inc., Carolina Industrial Group for Fair Utility Rates III and Wal-Mart Stores East LP, for consideration by the NCUC. The Partial Settlement, which includes Duke Energy Carolinas and all intervening parties to the rate case, reflected agreements on all but a few issues in these matters, including two significant issues. The two significant issues related to the treatment of ongoing merger cost savings resulting from the Cinergy merger and the proposed amortization of Duke Energy Carolinas’ development costs related to GridSouth Transco, LLC (GridSouth), a Regional Transmission Organization (RTO) planned by Duke Energy Carolinas and other utility companies as a result of previous FERC rulemakings, which was suspended in 2002 and discontinued in 2005 as a result of regulatory uncertainty. The Partial Settlement and the remaining disputed issues were presented to the NCUC for a ruling.
The Partial Settlement reflected an agreed to reduction in net revenues and pre-tax cash flows of approximately $210 million and corresponding rate reductions of 12.7% to the industrial class, 5.05% - 7.34% to the general class and 3.85% to the residential class of customers with an effective date of January 1, 2008. Under the Partial Settlement, effective January 1, 2008, Duke Energy Carolinas discontinued the amortization of the environmental compliance costs pursuant to North Carolina clean air legislation discussed above and began capitalizing all environmental compliance costs above the cumulative amortization charge of $1.05 billion as of December 31, 2007. Over the past five years, the average annual clean air amortization was $210 million. The Partial Settlement was designed to enable Duke Energy Carolinas to earn a rate of return of 8.57% on a North Carolina retail jurisdictional rate base and an 11% return on the common equity component of the approved capital structure, which consists of 47% debt and 53% common equity. As part of the settlement, Duke Energy Carolinas agreed to alter the then existing bulk power marketing (BPM) profit sharing arrangement that included a provision to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Energy Carolinas’ generating units at market based rates. Under the Partial Settlement, Duke Energy Carolinas will share 90% of the North Carolina retail allocation of the profits from BPM transactions beginning January 1, 2008.
The NCUC issued its Order Approving Stipulation and Deciding Non-Settled Issues on December 20, 2007. The NCUC approved the Partial Settlement in its entirety. The merger savings rider and GridSouth cost matters are discussed in detail below. For the remaining non-settled issues, the NCUC decided in Duke Energy Carolinas’ favor. With respect to the non-settled issues, the Order required that Duke Energy Carolinas’ test period operating costs reflect an annualized level of the merger cost savings actually experienced in the test period in keeping with traditional principles of ratemaking. The NCUC explained that because rates should be designed to recover a reasonable and prudent level of ongoing expenses, Duke Energy Carolinas’ annual cost of service and revenue requirement should reflect, as closely as possible, Duke Energy Carolinas’ actual costs. However, the NCUC recognized that its treatment of merger savings would not produce a fair result. Therefore, the NCUC preliminarily concluded that it would reconsider certain language in its 2006 merger order in order to allow it to authorize a 12-month increment rider of approximately $80 million designed to provide a more equitable sharing of the actual merger savings achieved on an ongoing basis. Additionally, the NCUC concluded that approximately $30 million of costs incurred through June 2002 in connection with GridSouth and deferred by Duke Energy Carolinas, were reasonable and prudent and approved a ten-year amortization, retroactive to June 2002. As a result of the retroactive impact of the Order, Duke Energy Carolinas recorded an approximate $17 million charge to write-off a portion of the GridSouth costs in 2007. The NCUC did not allow Duke Energy Carolinas a return on the GridSouth investments. As a result of its decision on the non-settled issues, the NCUC ordered an additional reduction in annual revenues of approximately $54 million, offset by its preliminary authorization of a 12-month, $80 million increment rider, as discussed above. The Order ultimately resulted in an overall average rate decrease of 5% in 2008, increasing to 7% upon expiration of this one-time rate rider. On February 18, 2008, the NCUC issued an order confirming their preliminary conclusion regarding the merger savings rider. This order reaffirmed the prior tentative conclusion that the provisions of the Merger Order will not produce a fair sharing of the benefits of estimated merger savings between ratepayers and shareholders and that, for that reason, Duke Energy should be authorized to implement a 12-month increment rider to collect $80 million.
South Carolina passed new energy legislation which became effective May 3, 2007. Key elements of the legislation include expansion of the annual fuel clause mechanism to include recovery of costs of reagents (ammonia, limestone, etc.) that are consumed in the operation of Duke Energy Carolinas’ SO2 and nitrogen oxide (NOx) control technologies and the cost of certain emission allowances used to meet environmental requirements. The cost of reagents for Duke Energy Carolinas in 2008 is expected to be approximately $30 million. With the enactment of this legislation, Duke Energy Carolinas will be allowed to recover the South Carolina portion of these costs, incurred on or after May 3, 2007, through the fuel clause. The legislation also includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear base-
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load generation in rates during construction. The North Carolina General Assembly also passed comprehensive energy legislation in July 2007 that was signed into law by the Governor on August 20, 2007. The North Carolina legislation allows utilities to recover the costs of reagents and certain purchased power costs. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to construction work in progress for baseload plants in a rate case. The North Carolina legislation also establishes a renewable portfolio standard for electric utilities at 3% of energy output in 2012, rising gradually to 12.5% by 2021, and grants the NCUC authority to approve a rate rider to compensate utilities for energy efficiency programs that they implement. On August 23, 2007, the NCUC initiated a rulemaking proceeding to adopt new rules and modify existing rules, as appropriate, to implement the legislation. That proceeding is pending and final rules are expected in the first quarter 2008. At this time, Duke Energy is not able to estimate the impact these legislative initiatives might have on its consolidated results of operations, cash flows, or financial position.
On December 12, 2007, the PSCSC directed the ORS to provide a written report concerning the NCUC’s resolution of Duke Energy Carolinas’ rate application and its relevance to Duke Energy Carolinas’ rates in South Carolina. The ORS in turn requested information from Duke Energy Carolinas. After review of information supplied by Duke Energy Carolinas and several other documents related to the North Carolina rate case, and after conversations with the North Carolina Public Staff, the ORS filed its report with the PSCSC on January 31, 2008. The ORS concluded that the outcome of the North Carolina rate case had no bearing on Duke Energy Carolinas’ rates in South Carolina. The PSCSC has not yet responded to the report filed by the ORS.
Electric generation supply service has been deregulated in Ohio. Accordingly, Duke Energy Ohio’s electric generation has been deregulated and Duke Energy Ohio is in a competitive retail electric service market in the state of Ohio. Under applicable legislation governing the deregulation of generation, Duke Energy Ohio has implemented a RSP, including a market based standard service offer (MBSSO) approved by the PUCO. The RSP, among other things, allows Duke Energy Ohio to recover increased costs associated with environmental expenditures on its deregulated generating fleet, capacity reserves, and provides for a fuel and emission allowance cost recovery mechanism through 2008. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters-U.S. Franchised Electric and Gas - Rate Related Information” for additional information.
On September 25, 2007, at the request of the Governor of Ohio, the Ohio Senate introduced a bill (SB 221) that proposes a comprehensive change to Ohio’s 1999 electric energy industry restructuring legislation. If enacted, SB 221 would expand the PUCO’s authority over generation to: implement the state’s revised energy policy; regulate electric distribution utility prices for standard service; and permit the PUCO to implement rules for advanced energy portfolio and energy efficiency standards, greenhouse gas emission reporting requirements, and pilot project carbon sequestration activities in conjunction with other state agencies. Under SB 221, electric distribution utilities have the ability to apply for PUCO approval of one of two generation pricing alternatives -a market option or an Electric Security Plan (ESP) option. The market option is based upon a competitive bidding process. The ESP option would allow for the recovery of specified costs. The PUCO, however, would have authority to disallow the market option and compel the ESP option. SB 221, if enacted, would limit the ability of a utility to transfer its dedicated generating assets to an exempt wholesale generator absent PUCO approval. SB 221 passed the Ohio Senate on October 31, 2007, and is currently pending before the Ohio House of Representatives.
Federal
Regulations of FERC and the State Utility Commissions govern access to regulated electric and gas customer and other data by non-regulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of non-regulated affiliates with U.S. Franchised Electric and Gas.
The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 repealed the Public Utility Holding Company Act (PUHCA) of 1935, directed FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extended the Price Anderson Act for 20 years (until 2025), provided loan guarantees, standby support and production tax credits for new nuclear reactors, gave FERC enhanced merger approval authority, provided FERC new backstop authority for the siting of certain electric transmission projects, streamlined the processes for approval and permitting of interstate pipelines, and reformed hydropower relicensing. In 2005 and 2006, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. These rule makings have now been completed, subject to certain appeals and further proceeding. Duke Energy does not believe that these rulemakings or the appeals will have a material adverse effect on its consolidated results of operations, cash flows or financial position.
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The Energy Policy Act of 1992 and subsequent rulemakings and events initiated the opening of wholesale energy markets to competition. Open access transmission for wholesale transmission provides energy suppliers and load serving entities, including U.S. Franchised Electric and Gas and wholesale customers located in the U.S. Franchised Electric and Gas service area, with opportunities to purchase, sell and deliver capacity and energy at market based prices, which can lower overall costs to retail customers.
Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana are transmission owners in a regional transmission organization operated by the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a non-profit organization which maintains functional control over the combined transmission systems of its members. In 2005, the Midwest ISO began administering an energy market within its footprint.
On December 17, 2001 the IURC approved the transfer of functional control of the operation of the Duke Energy Indiana transmission system to the Midwest ISO, an RTO established in 1998. On June 1, 2005, the IURC authorized Duke Energy Indiana to transfer control area operations tasks and responsibilities and transfer dispatch and Day 2 energy markets tasks and responsibilities to the Midwest ISO.
The Midwest ISO is the provider of transmission service requested on the transmission facilities under its tariff. It is responsible for the reliable operation of those transmission facilities and the regional planning of new transmission facilities. The Midwest ISO administers energy markets utilizing Locational Marginal Pricing (i.e., the energy price for the next MW may vary throughout the Midwest ISO market based on transmission congestion and energy losses) as the methodology for relieving congestion on the transmission facilities under its functional control.
On December 19, 2005, the FERC approved a plan filed by Duke Energy Carolinas to establish an “Independent Entity” (IE) to serve as a coordinator of certain transmission functions and an “Independent Monitor” (IM) to monitor the transparency and fairness of the operation of Duke Energy Carolinas’ transmission system. Duke Energy Carolinas remains the owner and operator of the transmission system, with responsibility for the provision of transmission service under Duke Energy Carolinas’ Open Access Transmission Tariff. Duke Energy Carolinas retained the Midwest ISO to act as the IE and Potomac Economics, Ltd. to act as the IM. The IE and IM began operations on November 1, 2006. Duke Energy Carolinas is not currently seeking adjustments to its transmission rates to reflect the incremental cost of the proposal, which is not projected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.
Other
U.S. Franchised Electric and Gas is subject to the NRC jurisdiction for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy’s three Oconee nuclear units through 2033 for Units 1 and 2 and through 2034 for Unit 3. In 2003, the NRC renewed the operating licenses for all units at Duke Energy’s McGuire and Catawba stations. The two McGuire units are licensed through 2041 and 2043, respectively, while the two Catawba units are licensed through 2043. All but one of U.S. Franchised Electric and Gas’ hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act, with license terms expiring from 2005 to 2036. The FERC has authority to issue new hydroelectric generating licenses. Hydroelectric facilities whose licenses expired in 2005 are operating under annual extensions of the current license until FERC issues a new license. Other hydroelectric facilities whose licenses expire between 2008 and 2016 are in various stages of relicensing. Duke Energy expects to receive new licenses for all hydroelectric facilities with the exception of the Dillsboro Project, for which Duke Energy has filed an application to surrender the license. Duke Energy expects to remove this project’s dam and powerhouse, as part of the multi-stakeholder licensing agreement.
U.S. Franchised Electric and Gas is subject to the jurisdiction of the U.S. Environmental Protection Agency (EPA) and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)
COMMERCIAL POWER
Commercial Power owns, operates and manages non-regulated power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio, acquired from Cinergy in April 2006 and the five Midwestern gas-fired non-regulated generation assets that were a portion of former DENA. Commercial Power’s assets are comprised of approximately 8,000 net megawatts of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the RSP described below. See Item 2. “Properties” for further discussion of the generating facilities. Commercial Power also develops and implements customized energy solutions.
PART I
Commercial Power, through DEGS, is an on-site energy solutions and utility services provider. Primarily through joint ventures, DEGS engages in utility systems construction, operation and maintenance of utility facilities, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of usable energy from a single source. In support of a strategy to increase its renewable energy portfolio, DEGS acquired the wind power development assets of Energy Investor Funds from Tierra Energy in May 2007. Three of the development projects for a total of 240 MW of wind energy acquired from Tierra Energy are anticipated to be in commercial operation in late 2008 or 2009 and are currently under construction. DEGS also has over 2,500 MW of wind energy projects in the development pipeline.
DEGS also owns coal-based synthetic fuel (synfuel) production facilities which convert coal feedstock into synfuel for sale to third parties. The synfuel produced in these facilities qualified for tax credits through 2007 in accordance with Internal Revenue code Section 29/45K if certain requirements are satisfied. The production of synfuel was ceased at the end of 2007 upon the expiration of the tax credits.
In October 2006, Duke Energy completed the sale of Commercial Power’s energy marketing and trading activities, which were acquired in the Cinergy merger. Additionally, in December 2006, Duke Energy completed the sale of Caledonia Power 1, LLC, which is the project company that operated and managed the Caledonia peaking generation facility in Mississippi.
In February 2008, Duke Energy entered into an agreement to sell its 480 MW natural gas-fired peaking generating station located near Brownsville, Tennessee to Tennessee Valley Authority. This transaction, which is subject to FERC and other regulatory approvals, is expected to close in the second quarter of 2008.
Competition
Commercial Power primarily competes for wholesale contracts for the purchase and sale of electricity, coal, natural gas and emission allowances. The market price of commodities and services, along with the quality and reliability of services provided, drive competition in the energy marketing business. Commercial Power’s main competitors include other non-regulated generators in the Midwestern U.S. wholesale power, coal and natural gas marketers, renewable energy companies and financial institutions and hedge funds engaged in energy commodity marketing and trading.
PART I
Duke Energy Ohio has been charging the MBSSO to non-residential customers since January 1, 2005 and to residential customers since January 1, 2006. The MBSSO charge consists of the following discrete charges:
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Annually Adjusted Component - intended to provide cost recovery primarily for environmental compliance expenditures. This component is avoidable (or by-passable) by all customers that switch to an alternative electric service provider.
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Infrastructure Maintenance Fund Charge - intended to compensate Duke Energy Ohio for committing its physical capacity. This charge is avoidable (or by-passable) only by non-residential customers that switch to an alternative electric service provider and agree to remain off the RSP.
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System Reliability Tracker - intended to provide actual cost recovery for capacity purchases. This charge is by-passable only by non-residential load under certain circumstances.
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Generation Prices and Fuel Recovery: A market price has been established for generation service. A component of the market price is a fuel cost recovery mechanism that is adjusted quarterly for fuel, emission allowances, and certain purchased power costs that exceed the amount originally included in the rates frozen in the Duke Energy Ohio transition plan. These new prices were applied to non-residential customers beginning January 1, 2005 and to residential customers beginning January 1, 2006.
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Transmission Cost Recovery: A transmission cost recovery mechanism was established beginning January 1, 2005 for non-residential customers and beginning January 1, 2006 for residential customers. The transmission cost recovery mechanism is designed to permit Duke Energy Ohio to recover certain Midwest ISO charges and all FERC approved transmission costs allocable to retail ratepayers that are provided service by Duke Energy Ohio.
Regulation
Commercial Power is subject to regulation at the state level, primarily from PUCO and at the federal level, primarily from FERC. The PUCO approves prices for all retail electric generation sales by Duke Energy Ohio for its native retail service territory. See “Regulation” section within U.S. Franchised Electric and Gas for additional information regarding deregulation in Ohio.
Regulations of FERC and the PUCO govern access to regulated electric customer and other data by non-regulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of Commercial Power.
Other ongoing regulatory initiatives at both state and federal levels addressing market design, such as the development of capacity markets and real-time electricity markets, impact financial results from Commercial Power’s marketing and generation activities.
Commercial Power is subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)
INTERNATIONAL ENERGY
International Energy operates and manages power generation facilities and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through DEI and its activities target power generation in Latin America. Additionally, International Energy owns equity investments in: National Methanol Company (NMC), located in Saudi Arabia, which is a regional producer of methanol and methyl tertiary butyl ether (MTBE) and Attiki Gas Supply S.A. (Attiki), located in Athens, Greece, which is a natural gas distributor and was acquired in connection with the Cinergy merger.
International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and industrial/commercial companies. International Energy’s current strategy is focused on optimizing the value of its current Latin American portfolio and expanding the portfolio through investment in generation opportunities in Latin America.
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International Energy owns, operates or has substantial interests in approximately 4,000 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including its interest in non-generation facilities in Saudi Arabia and Greece.
In February 2007, International Energy closed the sale of its 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International.
International Energy had an investment in Compañia de Servicios de Compresión de Campeche, S.A. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. In August 2007, as a result of the expiration of a gas compression services agreement with the Mexican National Oil Company (PEMEX), ownership of the facility transferred to PEMEX.
Competition and Regulation
International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government owned electric generating companies, local distribution companies with self-generation capability and other privately owned electric generating companies. The principal elements of competition are price and availability, terms of service, flexibility and reliability of service.
A high percentage of International Energy’s portfolio consists of baseload hydro electric generation facilities which compete with other forms of electric generation available to International Energy’s customers and end-users, including natural gas and fuel oils. Economic activity, conservation, legislation, governmental regulations, weather and other factors affect the supply and demand for electricity in the regions served by International Energy.
International Energy’s operations are subject to both country-specific and international laws and regulations. (See “Environmental Matters” in this section.)
PART I
CRESCENT
As previously discussed, effective September 7, 2006, Duke Energy completed the Crescent JV transaction, whereby Duke Energy sold an effective 50% interest in Crescent.
Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. As of December 31, 2007, Crescent owned 0.9 million square feet of commercial, industrial and retail space, with an additional 0.5 million square feet under construction. This portfolio included 0.7 million square feet of office space, 0.7 million square feet of warehouse space and 49 thousand square feet of retail space. Crescent’s residential developments include high-end country club and golf course communities, with individual lots sold to custom builders and tract developments sold to national builders. Crescent had two multi-family communities at December 31, 2007, including one operating property and one property under development. As of December 31, 2007, Crescent also managed approximately 122,608 acres of land.
Competition and Regulation
Crescent competes with multiple regional and national real estate developers across its various business lines in the Southeastern and Southwestern U.S. Crescent’s residential division sells developed lots to regional and national home builders and retail buyers, competing with other developers and home builders who have inventories of developed lots. Crescent’s commercial division leases office, industrial and retail space, competing with other public and private developers and owners of commercial property, including national real estate investment trusts (REITs). Similarly, Crescent’s multi-family division leases apartment units primarily to individuals, competing with other private developers and multi-family REITs.
Crescent is subject to the jurisdiction of the EPA and state and local environmental agencies.
OTHER
The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, DukeNet and related telecom businesses and Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary. Additionally, Other includes the remaining portion of Duke Energy’s business formerly known as DENA that was not exited or transferred to Commercial Power, primarily DETM, which management is currently in the process of winding down. Unallocated corporate costs include certain costs not allocable to Duke Energy’s reportable business segments, primarily governance costs, costs to achieve mergers and divestitures (such as the Cinergy merger and spin-off of Spectra) and costs associated with certain corporate severance programs. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. On a limited basis, Bison also participates in reinsurance activities with certain third parties.
Competition and Regulation
The entities within Other are subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)
ENVIRONMENTAL MATTERS
Duke Energy is subject to international, federal, state and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental laws and regulations affecting Duke Energy include, but are not limited to:
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The Clean Air Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards for ozone and particulate matter. Owners and/or operators of air emission sources are responsible for obtaining permits and for annual compliance and reporting.
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The Clean Water Act which requires permits for facilities that discharge wastewaters into the environment.
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The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past may have owned or operated a disposal site, as well as transporters or generators of hazardous substances sent to a disposal site, to share in remediation costs.
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The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime.
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The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals.
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The North Carolina clean air legislation that froze electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of SO2 and NOx from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). However, Duke Energy Carolinas ended its amortization in 2007 as part of its rate case settlement with the NCUC.
(For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Notes 4 and 17 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies-Environmental,” respectively.)
Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our various business segments and is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Energy.
GEOGRAPHIC REGIONS
For a discussion of Duke Energy’s foreign operations and the risks associated with them, see “Risk Factors,” “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk-Foreign Currency Risk,” and Notes 3 and 8 to the Consolidated Financial Statements, “Business Segments” and “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” respectively.
EMPLOYEES
On December 31, 2007, Duke Energy had approximately 17,800 employees. A total of approximately 4,500 operating and maintenance employees were represented by unions.
EXECUTIVE OFFICERS OF DUKE ENERGY
STEPHEN G. DE MAY, 45, Vice President and Treasurer. Mr. De May assumed his current position in November 2007. Prior to that, he served as Assistant Treasurer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. De May served as Vice President, Energy and Environmental Policy of Duke Energy since February 2004. Prior to that Mr. De May served as Vice President, Business Unit Finance from November 2000 to February 2004.
LYNN J. GOOD, 48, Group Executive and President, Commercial Businesses. Ms. Good assumed her current position in November 2007. Prior to that, she served as Senior Vice President and Treasurer since December 2006; prior to that she served as Treasurer and Vice President, Financial Planning since October 2006; and prior to that she served as Vice President and Treasurer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Ms. Good served as Executive Vice President and Chief Financial Officer of Cinergy from August 2005, Vice President, Finance and Controller of Cinergy from November 2003 to August 2005 and Vice President, Financial Project Strategy of Cinergy from May 2003 to November 2003. Prior to that, Ms. Good was a partner with the international accounting firm Deloitte & Touche LLP in Cincinnati, Ohio from May 2002 to May 2003.
DAVID L. HAUSER, 56, Group Executive and Chief Financial Officer. Mr. Hauser assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Hauser served as Group Vice President and Chief Financial Officer of Duke Energy since March 2004 and as Acting Chief Financial Officer of Duke Energy from December 2003 to March 2004. Prior to that, he served as Senior Vice President and Treasurer of Duke Energy from July 1998 to December 2003.
DHIAA M. JAMIL, 51, Group Executive and Chief Nuclear Officer. Mr. Jamil assumed his current position in February 2008. Prior to that he served as Senior Vice President, Nuclear Support, Duke Energy Carolinas, LLC since March 2007; and prior to that he served as Vice President, Catawba Nuclear Station, Duke Energy Carolinas, LLC since April 2006, upon the merger of Duke Energy and Cinergy.
PART I
Until the merger of Duke Energy and Cinergy, Mr. Jamil served as Vice President Catawba Nuclear Station, Duke Power from March 2004 to April 2006, and prior to that he served as Nuclear Station Vice President, Duke Power of Duke Energy from September 2003 to March 2004. Prior to that he served as Vice President, McGuire Nuclear Station Duke Power from September 2002 to September 2003.
JULIA S. JANSON, 43, Senior Vice President, Ethics and Compliance and Corporate Secretary. Ms. Janson assumed her current position in December 2006. Prior to that she served as Vice President, Corporate Secretary and Chief Ethics and Compliance Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Ms. Janson served as Chief Compliance Officer of Cinergy since 2004 and Corporate Secretary of Cinergy since 2000.
MARC E. MANLY, 55, Group Executive and Chief Legal Officer. Mr. Manly assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Manly served as Executive Vice President and Chief Legal Officer of Cinergy since November 2002.
JAMES E. ROGERS, 60, Chairman, President and Chief Executive Officer. Mr. Rogers assumed the role of Chief Executive Officer and President in April 2006, upon the merger of Duke Energy and Cinergy and assumed the role of Chairman on January 2, 2007. Until the merger of Duke Energy and Cinergy, Mr. Rogers served as Chairman of the Board of Cinergy since 2000 and as Chief Executive Officer of Cinergy since 1995.
CHRISTOPHER C. ROLFE, 57, Group Executive and Chief Administrative Officer. Mr. Rolfe assumed his current position in November 2006. Prior to that, he served as Group Executive and Chief Human Resources Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Rolfe served as Vice President, Human Resources of Duke Energy since January 2005. Prior to that, Mr. Rolfe served as Senior Vice President, Strategy, Planning & Human Resources of Duke Energy from March 2003 to January 2005 and Senior Vice President, Human Resources of Duke Energy from January 2001 to March 2003.
B. KEITH TRENT, 48, Group Executive and Chief Strategy, Policy and Regulatory Officer. Mr. Trent assumed his current position in May 2007. Prior to that he served as Group Executive and Chief Strategy and Policy Officer since October 2006 and prior to that he served as Group Executive and Chief Development Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Trent served as Executive Vice President, General Counsel and Secretary of Duke Energy since March 2005. Prior to that he served as General Counsel, Litigation of Duke Energy from May 2002 to March 2005.
JAMES L. TURNER, 48, Group Executive; President and Chief Operating Officer, U.S. Franchised Electric and Gas. Mr. Turner assumed his current position in May 2007. Prior to that he served as Group Executive and President, U.S. Franchised Electric and Gas since October 2006, and prior to that he served as Group Executive and Chief Commercial Officer, U.S. Franchised Electric and Gas since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Turner served as President of Cinergy since 2005, Executive Vice President and Chief Financial Officer of Cinergy from 2004 to 2005 and Executive Vice President and Chief Executive Officer, Regulated Business Unit of Cinergy from 2001 to 2004.
STEVEN K. YOUNG, 49, Senior Vice President and Controller. Mr. Young assumed his current position in December 2006. Prior to that he served as Vice President and Controller since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Young served as Vice President and Controller of Duke Energy since June 2005. Prior to that Mr. Young served as Senior Vice President and Chief Financial Officer of Duke Energy Carolinas from March 2003 to June 2005 and as Vice President, Rates and Regulatory Affairs of Duke Energy Carolinas from March 1998 to March 2003.
Executive officers serve until their successors are duly elected.
There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.
Item 1A.
Item 1A. Risk Factors.
Duke Energy may be unable to achieve some or all of the benefits that are expected to be achieved in connection with the spin-off of its natural gas businesses in January 2007.
Duke Energy may not be able to achieve the full strategic and financial benefits that are expected to result from the spin-off transaction or such benefits may be delayed or may not occur at all.
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Duke Energy’s franchised electric revenues, earnings and results are dependent on state legislation and regulation that affect electric generation, transmission, distribution and related activities, which may limit Duke Energy’s ability to recover costs.
Duke Energy’s franchised electric businesses are regulated on a cost-of-service/rate-of-return basis subject to the statutes and regulatory commission rules and procedures of North Carolina, South Carolina, Ohio, Indiana and Kentucky. If Duke Energy’s franchised electric earnings exceed the returns established by the state regulatory commissions, Duke Energy’s retail electric rates may be subject to review by the commissions and possible reduction, which may decrease Duke Energy’s future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, Duke Energy’s future earnings could be negatively impacted.
Duke Energy may incur substantial costs and liabilities due to Duke Energy’s ownership and operation of nuclear generating facilities.
Duke Energy’s ownership interest in and operation of three nuclear stations subject Duke Energy to various risks including, among other things: the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.
Duke Energy’s ownership and operation of nuclear generation facilities requires Duke Energy to meet licensing and safety-related requirements imposed by the NRC. In the event of non-compliance, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending upon its assessment of the severity of the situation. Revised security and safety requirements promulgated by the NRC, which could be prompted by, among other things, events within or outside of Duke Energy’s control, such as a serious nuclear incident at a facility owned by a third-party, could necessitate substantial capital and other expenditures at Duke Energy’s nuclear plants, as well as assessments against Duke Energy to cover third-party losses. In addition, if a serious nuclear incident were to occur, it could have a material adverse effect on Duke Energy’s results of operations and financial condition.
Duke Energy’s ownership and operation of nuclear generation facilities also requires Duke Energy to maintain funded trusts that are intended to pay for the decommissioning costs of Duke Energy’s nuclear power plants. Poor investment performance of these decommissioning trusts’ holdings and other factors impacting decommissioning costs could unfavorably impact Duke Energy’s liquidity and results of operations as Duke Energy could be required to significantly increase its cash contributions to the decommissioning trusts.
Duke Energy’s plans for future expansion and modernization of its generation fleet subject it to risk of failure to adequately execute and manage its significant construction plans, as well as the risk of recovering such costs in an untimely manner, which could materially impact Duke Energy’s results of operations, cash flows or financial position.
During the five-year period from 2008 to 2012, Duke Energy anticipates cumulative capital expenditures of approximately $23 billion. The completion of Duke Energy’s anticipated capital investment projects in existing and new generation facilities is subject to many construction and development risks, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Moreover, Duke Energy’s ability to recover these costs in a timely manner could materially impact Duke Energy’s consolidated financial position, results of operations or cash flows.
Duke Energy’s sales may decrease if Duke Energy is unable to gain adequate, reliable and affordable access to transmission assets.
Duke Energy depends on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity Duke Energy sells to the wholesale market. FERC’s power transmission regulations require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. If transmission is disrupted, or if transmission capacity is inadequate, Duke Energy’s ability to sell and deliver products may be hindered.
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The different regional power markets have changing regulatory structures, which could affect Duke Energy’s growth and performance in these regions. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of Duke Energy’s wholesale power marketing and trading business.
Duke Energy may be unable to secure long term power sales agreements or transmission agreements, which could expose Duke Energy’s sales to increased volatility.
In the future, Duke Energy may not be able to secure long-term power sales agreements for Duke Energy’s unregulated power generation facilities. If Duke Energy is unable to secure these types of agreements, Duke Energy’s sales volumes would be exposed to increased volatility. Without the benefit of long-term customer power purchase agreements, Duke Energy cannot assure that it will be able to sell the power generated by Duke Energy’s facilities or that Duke Energy’s facilities will be able to operate profitably. The inability to secure these agreements could materially adversely affect Duke Energy’s results and business.
Competition in the unregulated markets in which Duke Energy operates may adversely affect the growth and profitability of Duke Energy’s business.
Duke Energy may not be able to respond in a timely or effective manner to the many changes designed to increase competition in the electricity industry. To the extent competitive pressures increase, the economics of Duke Energy’s business may come under long-term pressure.
In addition, regulatory changes have been proposed to increase access to electricity transmission grids by utility and non-utility purchasers and sellers of electricity. These changes could continue the disaggregation of many vertically-integrated utilities into separate generation, transmission, distribution and retail businesses. As a result, a significant number of additional competitors could become active in the wholesale power generation segment of Duke Energy’s industry.
Duke Energy may also face competition from new competitors that have greater financial resources than Duke Energy does, seeking attractive opportunities to acquire or develop energy assets or energy trading operations both in the United States and abroad. These new competitors may include sophisticated financial institutions, some of which are already entering the energy trading and marketing sector, and international energy players, which may enter regulated or unregulated energy businesses. This competition may adversely affect Duke Energy’s ability to make investments or acquisitions.
Duke Energy must meet credit quality standards. If Duke Energy or its rated subsidiaries are unable to maintain an investment grade credit rating, Duke Energy would be required under credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect Duke Energy’s liquidity. Duke Energy cannot be sure that it and its rated subsidiaries will maintain investment grade credit ratings.
Each of Duke Energy’s and its rated subsidiaries senior unsecured long-term debt is currently rated investment grade by various rating agencies. Duke Energy cannot be sure that the senior unsecured long-term debt of Duke Energy or its rated subsidiaries will be rated investment grade in the future.
If the rating agencies were to rate Duke Energy or its rated subsidiaries below investment grade, the entity’s borrowing costs would increase, perhaps significantly. In addition, Duke Energy or its rated subsidiaries would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Further, if its short-term debt rating were to fall, the entity’s access to the commercial paper market could be significantly limited. Any downgrade or other event negatively affecting the credit ratings of Duke Energy’s subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase Duke Energy’s need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
A downgrade below investment grade could also trigger termination clauses in some interest rate and foreign exchange derivative agreements, which would require cash payments. All of these events would likely reduce Duke Energy’s liquidity and profitability and could have a material adverse effect on Duke Energy’s financial position, results of operations or cash flows.
PART I
Duke Energy relies on access to short-term money markets and longer-term capital markets to finance Duke Energy’s capital requirements and support Duke Energy’s liquidity needs, and Duke Energy’s access to those markets can be adversely affected by a number of conditions, many of which are beyond Duke Energy’s control.
Duke Energy’s business is financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from Duke Energy’s assets. Accordingly, Duke Energy relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from Duke Energy’s operations and to fund investments originally financed through debt instruments with disparate maturities. If Duke Energy is not able to access capital at competitive rates, Duke Energy’s ability to finance Duke Energy’s operations and implement Duke Energy’s strategy will be adversely affected.
Market disruptions may increase Duke Energy’s cost of borrowing or adversely affect Duke Energy’s ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity and gas; terrorist attacks or threatened attacks on Duke Energy’s facilities or unrelated energy companies; or the overall health of the energy industry. Restrictions on Duke Energy’s ability to access financial markets may also affect Duke Energy’s ability to execute Duke Energy’s business plan as scheduled. An inability to access capital may limit Duke Energy’s ability to pursue improvements or acquisitions that Duke Energy may otherwise rely on for future growth.
Duke Energy maintains revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other of Duke Energy’s affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements.
Duke Energy’s investments and projects located outside of the United States expose Duke Energy to risks related to laws of other countries, taxes, economic conditions, political conditions and policies of foreign governments. These risks may delay or reduce Duke Energy’s realization of value from Duke Energy’s international projects.
Duke Energy currently owns and may acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, regulatory, market and political conditions in some of the countries where Duke Energy has interests or in which Duke Energy may explore development, acquisition or investment opportunities could present risks related to, among others, Duke Energy’s ability to obtain financing on suitable terms, Duke Energy’s customers’ ability to honor their obligations with respect to projects and investments, delays in construction, limitations on Duke Energy’s ability to enforce legal rights, and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law, regulations, market rules or tax policy.
Duke Energy’s investments and projects located outside of the United States expose Duke Energy to risks related to fluctuations in currency rates. These risks, and Duke Energy’s activities to mitigate such risks, may adversely affect Duke Energy’s cash flows and results of operations.
Duke Energy’s operations and investments outside the United States expose Duke Energy to risks related to fluctuations in currency rates. As each local currency’s value changes relative to the U.S. dollar-Duke Energy’s principal reporting currency-the value in U.S. dollars of Duke Energy’s assets and liabilities in such locality and the cash flows generated in such locality, expressed in U.S. dollars, also change.
Duke Energy selectively mitigates some risks associated with foreign currency fluctuations by, among other things, indexing contracts to the U.S. dollar and/or local inflation rates, hedging through debt denominated or issued in the foreign currency and hedging through foreign currency derivatives. These efforts, however, may not be effective and, in some cases, may expose Duke Energy to other risks that could negatively affect Duke Energy’s cash flows and results of operations.
Duke Energy’s primary foreign currency rate exposure is expected to be to the Brazilian Real. A 10% devaluation in the currency exchange rate in all of Duke Energy’s exposure currencies would result in an estimated net loss on the translation of local currency earnings of approximately $10 million. The consolidated balance sheets would be negatively impacted by such a devaluation by approximately $145 million through cumulative currency translation adjustments.
PART I
Duke Energy is exposed to credit risk of counterparties with whom Duke Energy does business.
Adverse economic conditions affecting, or financial difficulties of, counterparties with whom Duke Energy does business could impair the ability of these counterparties to pay for Duke Energy’s services or fulfill their contractual obligations, including loss recovery payments under insurance contracts, or cause them to delay such payments or obligations. Duke Energy depends on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect Duke Energy’s cash flows, financial position or results of operations.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact Duke Energy’s liquidity and results of operations.
Duke Energy’s costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and Duke Energy’s required or voluntary contributions made to the plans. While Duke Energy complied with the minimum funding requirements as of December 31, 2007, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $240 million. Without sustained growth in the pension investments over time to increase the value of Duke Energy’s plan assets and depending upon the other factors impacting Duke Energy’s costs as listed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations could have a material impact on Duke Energy’s cash flows, financial position or results of operations.
Duke Energy is subject to numerous environmental laws and regulations that require significant capital expenditures, can increase Duke Energy’s cost of operations, and which may impact or limit Duke Energy’s business plans, or expose Duke Energy to environmental liabilities.
Duke Energy is subject to numerous environmental laws and regulations affecting many aspects of Duke Energy’s present and future operations, including air emissions (such as reducing NOx, SO2 and mercury emissions in the U.S., or potential future control of greenhouse-gas emissions), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs. These laws and regulations generally require Duke Energy to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for clean up costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets. The steps Duke Energy takes to ensure that its facilities are in compliance could be prohibitively expensive. As a result, Duke Energy may be required to shut down or alter the operation of its facilities, which may cause Duke Energy to incur losses. Further, Duke Energy’s regulatory rate structure and Duke Energy’s contracts with customers may not necessarily allow Duke Energy to recover capital costs Duke Energy incurs to comply with new environmental regulations. Also, Duke Energy may not be able to obtain or maintain from time to time all required environmental regulatory approvals for Duke Energy’s operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if Duke Energy fails to obtain and comply with them or if environmental laws or regulations change and become more stringent, then the operation of Duke Energy’s facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on Duke Energy’s cash flows, financial position or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.
There is growing consensus that some form of regulation will be forthcoming at the federal level with respect to greenhouse gas emissions (including carbon dioxide (CO2)) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances.
In addition, Duke Energy is generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of Duke Energy’s power generation facilities and natural gas assets which Duke Energy has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, Duke Energy may obtain, or be required to provide, indemnification against some environmental liabilities. If Duke Energy incurs a material liability, or the other party to a transaction fails to meet its indemnification obligations to Duke Energy, Duke Energy could suffer material losses.
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Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect Duke Energy’s results of operations, cash flows or financial position and Duke Energy’s utilities’ businesses.
Increased competition resulting from deregulation or restructuring efforts, including from the Energy Policy Act of 2005, could have a significant adverse financial impact on Duke Energy and Duke Energy’s utility subsidiaries and consequently on Duke Energy’s results of operations, financial position, or cash flows. Increased competition could also result in increased pressure to lower costs, including the cost of electricity. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on Duke Energy and Duke Energy’s subsidiaries due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Duke Energy cannot predict the extent and timing of entry by additional competitors into the electric markets. Duke Energy cannot predict when Duke Energy will be subject to changes in legislation or regulation, nor can Duke Energy predict the impact of these changes on its financial position, results of operations or cash flows.
Duke Energy is involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to Duke Energy could negatively affect Duke Energy’s results of operations, cash flows or financial position.
Duke Energy is subject to numerous legal proceedings, including claims for damages for bodily injuries alleged to have arisen prior to 1985 from the exposure to or use of asbestos at electric generation plants of Duke Energy Carolinas. Litigation is subject to many uncertainties and Duke Energy cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which Duke Energy is involved could require Duke Energy to make additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on Duke Energy’s cash flows and results of operations. Similarly, it is reasonably possible that the terms of resolution could require Duke Energy to change Duke Energy’s business practices and procedures, which could also have a material effect on Duke Energy’s cash flows, financial position or results of operations.
Duke Energy’s results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond Duke Energy’s control.
Sustained downturns or sluggishness in the economy generally affect the markets in which Duke Energy operates and negatively influence Duke Energy’s energy operations. Declines in demand for electricity as a result of economic downturns in Duke Energy’s franchised electric service territories will reduce overall electricity sales and lessen Duke Energy’s cash flows, especially as Duke Energy’s industrial customers reduce production and, therefore, consumption of electricity and gas. Although Duke Energy’s franchised electric business is subject to regulated allowable rates of return and recovery of fuel costs under a fuel adjustment clause, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations.
Duke Energy also sells electricity into the spot market or other competitive power markets on a contractual basis. With respect to such transactions, Duke Energy is not guaranteed any rate of return on Duke Energy’s capital investments through mandated rates, and Duke Energy’s revenues and results of operations are likely to depend, in large part, upon prevailing market prices in Duke Energy’s regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time and could reduce Duke Energy’s revenues and margins and thereby diminish Duke Energy’s results of operations.
Factors that could impact sales volumes, generation of electricity and market prices at which Duke Energy is able to sell electricity are as follows:
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weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, and periods of low rainfall that decrease Duke Energy’s ability to operate its facilities in an economical manner;
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supply of and demand for energy commodities;
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illiquid markets including reductions in trading volumes which result in lower revenues and earnings;
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general economic conditions, including downturns in the U.S. or other economies which impact energy consumption particularly in which sales to industrial or large commercial customers comprise a significant portion of total sales;
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transmission or transportation constraints or inefficiencies which impact Duke Energy’s non-regulated energy operations;
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availability of competitively priced alternative energy sources, which are preferred by some customers over electricity produced from coal, nuclear or gas plants, and of energy-efficient equipment which reduces energy demand;
•
natural gas, crude oil and refined products production levels and prices;
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•
ability to procure satisfactory levels of inventory, such as coal;
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electric generation capacity surpluses which cause Duke Energy’s non-regulated energy plants to generate and sell less electricity at lower prices and may cause some plants to become non-economical to operate;
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capacity and transmission service into, or out of, Duke Energy’s markets;
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natural disasters, acts of terrorism, wars, embargoes and other catastrophic events to the extent they affect Duke Energy’s operations and markets, as well as the cost and availability of insurance covering such risks; and
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federal, state and foreign energy and environmental regulation and legislation.
These factors have led to industry-wide downturns that have resulted in the slowing down or stopping of construction of new power plants and announcements by Duke Energy and other energy suppliers and gas pipeline companies of plans to sell non-strategic assets, subject to regulatory constraints, in order to boost liquidity or strengthen balance sheets. Proposed sales by other energy suppliers could increase the supply of the types of assets that Duke Energy is attempting to sell. In addition, recent FERC actions addressing power market concerns could negatively impact the marketability of Duke Energy’s electric generation assets.
Duke Energy’s operating results may fluctuate on a seasonal and quarterly basis.
Electric power generation is generally a seasonal business. In most parts of the United States and other markets in which Duke Energy operates, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, demand for power peaks during the winter. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. As a result, in the future, the overall operating results of Duke Energy’s businesses may fluctuate substantially on a seasonal and quarterly basis and thus make period comparison less relevant.
Duke Energy’s business is subject to extensive regulation that will affect Duke Energy’s operations and costs.
Duke Energy is subject to regulation by FERC and the NRC, by federal, state and local authorities under environmental laws and by state public utility commissions under laws regulating Duke Energy’s businesses. Regulation affects almost every aspect of Duke Energy’s businesses, including, among other things, Duke Energy’s ability to: take fundamental business management actions; determine the terms and rates of Duke Energy’s transmission and distribution businesses’ services; make acquisitions; issue equity or debt securities; engage in transactions between Duke Energy’s utilities and other subsidiaries and affiliates; and pay dividends. Changes to these regulations are ongoing, and Duke Energy cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on Duke Energy’s business. However, changes in regulation (including re-regulating previously deregulated markets) can cause delays in or affect business planning and transactions and can substantially increase Duke Energy’s costs.
New laws or regulations could have a negative impact on Duke Energy’s results of operations.
Changes in laws and regulations affecting Duke Energy, including new accounting standards that could change the way Duke Energy is required to record revenues, expenses, assets and liabilities. These types of regulations could have a negative impact on Duke Energy’s financial position, cash flows or results of operations or access to capital.
Potential terrorist activities or military or other actions could adversely affect Duke Energy’s business.
The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in prices for natural gas and oil which may materially adversely affect Duke Energy in ways Duke Energy cannot predict at this time. In addition, future acts of terrorism and any possible reprisals as a consequence of action by the United States and its allies could be directed against companies operating in the United States. Infrastructure and generation facilities such as Duke Energy’s nuclear plants could be potential targets of terrorist activities. The potential for terrorism has subjected Duke Energy’s operations to increased risks and could have a material adverse effect on Duke Energy’s business. In particular, Duke Energy may experience increased capital and operating costs to implement increased security for its plants, including its nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security, additional security personnel or additional capability following a terrorist incident.
The insurance industry has also been disrupted by these potential events. As a result, the availability of insurance covering risks Duke Energy and Duke Energy’s competitors typically insure against may decrease. In addition, the insurance Duke Energy is able to obtain may have higher deductibles, higher premiums, lower coverage limits and more restrictive policy terms.
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Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
U.S. FRANCHISED ELECTRIC AND GAS
As of December 31, 2007, U.S. Franchised Electric and Gas operated three nuclear generating stations with a combined net capacity of 5,020 MW (including a 12.5% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with a combined net capacity of 13,552 MW, thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined net capacity of 3,213 MW, fifteen CT stations with a combined net capacity of 5,241 MW and two CC stations with a combined net capacity of 560 MW. The stations are located in North Carolina, South Carolina, Indiana, Ohio and Kentucky. The MW displayed in the table below are based on summer capacity.
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(A) Duke Energy Indiana owns and operates Gibson Station Units 1-4 and owns 50.05% of Unit 5, but is the operator.
(B) Includes Cayuga Internal Combustion (IC)
(C) Includes Wabash River IC
(D) Wabash River Unit 1 is included in Assets Held for Sale
In addition, as of December 31, 2007, U.S. Franchised Electric and Gas owned approximately 20,900 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 1,800 miles of 345 kilovolts, 3,300 miles of 230 kilovolts, 8,800 miles of 100 to 161 kilovolts, and 6,400 miles of 13 to 69 kilovolts. U.S. Franchised Electric and Gas also owned approximately 148,700 conductor miles of electric distribution lines, including 102,900 miles of overhead lines and 45,800 miles of underground lines, as of December 31, 2007 and approximately 7,100 miles of gas mains and service lines. As of December 31, 2007, the electric transmission and distribution systems had approximately 2,300 substations. U.S. Franchised Electric and Gas also owns two underground caverns with a total storage capacity of approximately 16 million gallons of liquid propane. In addition, U.S. Franchised Electric and Gas has access to nine million gallons of liquid propane through a storage agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.
Substantially all of U.S. Franchised Electric and Gas’ electric plant in service is mortgaged under the indenture relating to Duke Energy Carolinas’, Duke Energy Ohio’s and Duke Energy Indiana’s various series of First and Refunding Mortgage Bonds.
(For a map showing U.S. Franchised Electric and Gas’ properties, see “Business-U.S. Franchised Electric and Gas” earlier in this section.)
COMMERCIAL POWER
The following table provides information about Commercial Power’s non-regulated generation portfolio as of December 31, 2007. The MW displayed in the table below are based on summer capacity.
(A) These generation facilities are jointly owned by Duke Energy Ohio and subsidiaries of American Electric Power, Inc. and Dayton Power and Light, Inc.
(For a map showing Commercial Power’s properties, see “Business-Commercial Power” earlier in this section.)
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INTERNATIONAL ENERGY
The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2007.
International Energy also owns a 25% equity interest in NMC. In 2007, NMC produced approximately 840 thousand metric tons of methanol and 1 million metric tons of MTBE. Approximately 40% of methanol is normally used in the MTBE production. Additionally, International Energy owns a 25% equity interest in Attiki, which is a natural gas distributor that has an exclusive 30 year license to supply natural gas to residential and commercial customers within the geographical area of Athens, Greece. (For additional information and a map showing International Energy’s properties, see “Business-International Energy” earlier in this section.)
CRESCENT
(For information regarding Crescent’s properties, see “Business-Crescent” earlier in this section.)
OTHER
Duke Energy owns approximately 5.7 million square feet of corporate, regional and district office space spread throughout its service territories in the Carolinas and the Midwest. Additionally, Duke Energy leases approximately 1.5 million square feet of office space throughout the Carolinas, Midwest and in Houston, Texas.
Item 3.
Item 3. Legal Proceedings.
For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies-Litigation” and “Commitments and Contingencies-Environmental.”
Brazilian Regulatory Citations. On September 5, 2007, the State Environmental Agency of Parana assessed fines against International Energy of approximately $10 million for failure to comply with reforestation measures allegedly required by state regulations in Brazil. International Energy believes that federal law is controlling and has challenged the assessment. In addition, International Energy was assessed a fine by the federal environmental agency, IBAMA, in the amount of approximately $150 thousand for improper maintenance of existing reforested areas. International Energy believes that it has properly maintained all reforested areas and will also contest this assessment.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of Duke Energy’s security holders during the fourth quarter of 2007.
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Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Duke Energy’s common stock is listed for trading on the New York Stock Exchange (ticker symbol DUK). As of February 22, 2008, there were approximately 170,099 common stockholders of record.
Common Stock Data by Quarter
(a) Stock prices represent the intra-day high and low stock price.
(b) Dividends paid in September 2007 and December 2007 increased from $0.21 per share to $0.22 per share and dividends paid in September 2006 and December 2006 increased from $0.31 per share to $0.32 per share.
On January 2, 2007, Duke Energy consummated the spin-off of the natural gas businesses to shareholders. In connection with this transaction, Duke Energy distributed all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock. Subsequent to the distribution, the market price of Duke Energy common stock was significantly less than the trading ranges in 2006 due to the fact that a proportionate share of the value of Duke Energy stock prior to the spin-off was transferred to Spectra Energy. Additionally, dividends paid on Duke Energy common stock during 2007 of $0.86 per share were less than the 2006 dividend of $1.26 per share as dividends subsequent to the spin-off were split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximated the former total dividend of Duke Energy, subject to future adjustment by each company’s Board of Directors. In the second quarter of 2007, the Board of Directors increased the common stock dividend from $0.21 per share to $0.22 per share. Duke Energy expects to continue its policy of paying regular cash dividends; however, there is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition, and are subject to declaration by the Board of Directors.
Issuer Purchases of Equity Securities for Fourth Quarter of 2007
There were no repurchases of equity securities during the fourth quarter of 2007.
In 2005, Duke Energy announced plans to execute up to approximately $2.5 billion of stock repurchases over a three year period. From the inception of the plan through December 31, 2007, Duke Energy has repurchased approximately $1.4 billion of common stock. As of December 31, 2007, the dollar value of shares that may yet be purchased under the plan is approximately $1.1 billion; however, Duke Energy does not currently anticipate future shares repurchases under this plan.
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Stock Performance Graph
The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in Duke Energy Corporation common stock, as compared with the Standard & Poor’s (S&P) 500 Stock Index and the Philadelphia Utility Index for the period 2002 through 2007.
This performance chart assumes $100 invested on December 31, 2002 in Duke Energy common stock, in the S&P 500 Stock Index and in the Philadelphia Utility Index and that all dividends are reinvested.
NYSE CEO Certification
Duke Energy has filed the certification of its Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits to this Annual Report on Form 10-K for the year ended December 31, 2007. In June 2007, Duke Energy’s Chief Executive Officer, as required by Section 303A.12(a) of the NYSE Listed Company Manual, certified to the NYSE that he was not aware of any violation by Duke Energy of the NYSE’s corporate governance listing standards.
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Item 6.
Item 6. Selected Financial Data.(a)
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(a) Significant transactions reflected in the results above include: 2007 spin-off of the natural gas businesses (see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”), 2006 merger with Cinergy (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2005 DENA disposition (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 deconsolidation of DCP Midstream effective July 1, 2005 (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 DEFS sale of TEPPCO (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) and 2004 sale of the former DENA Southeast plants.
(b) Earnings were inadequate to cover fixed charges by $746 million for the year ended December 31, 2003.
(c) As of January 1, 2003, Duke Energy adopted the remaining provisions of Emerging Issues Task Force (EITF) 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03) and SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). In accordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles.
(d) 2006 increase primarily attributable to issuance of approximately 313 million shares in connection with Duke Energy’s merger with Cinergy (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).
(e) 2007 decrease due to the spin-off of the natural gas businesses to shareholders on January 2, 2007 as dividends subsequent to the spin-off were split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximated the former total dividend of Duke Energy prior to the spin-off.
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Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
INTRODUCTION
Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2007, 2006 and 2005.
On January 2, 2007, Duke Energy completed the spin-off of its natural gas business to shareholders, as discussed below. Accordingly, the results of operations of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DCP Midstream have been reclassified to discontinued operations for all periods presented. Additionally, in April 2006, Duke Energy consummated the merger with Cinergy.
EXECUTIVE OVERVIEW
2007 Objectives. During 2007, management of Duke Energy focused on the following objectives, as outlined in the 2007 Charter:
•
Establish the identity and culture of the new Duke Energy, unifying its people, values, strategy, processes and systems;
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Optimize its operations by focusing on safety, simplicity, accountability, inclusion, customer satisfaction, cost management and employee development;
•
Achieve public policy, regulatory and legislative outcomes that balance customers’ needs for reliable energy at competitive prices with shareholders’ expectation of superior returns;
•
Invest in energy infrastructure that meets rising customer demands for reliable energy in an energy efficient and environmentally sound manner; and
•
Achieve 2007 financial objectives and position Duke Energy to meet future growth targets.
With the completion of the spin-off of the natural gas businesses on January 2, 2007, Duke Energy began its first year as primarily an electric utility and met or exceeded most of its financial and non-financial objectives established for 2007. See “2007 Financial Results” below for discussion of Duke Energy’s 2007 financial results. Overall, during a year of record-breaking heat and an exceptional drought in the Carolinas, Duke Energy was able to meet its productivity challenges as the coal fleet experienced superior operational performance and three of Duke Energy’s nuclear units set new capacity factor records. Additionally, Duke Energy focused on regulatory and legislative initiatives that will allow Duke Energy to balance the need for cleaner, more efficient power sources with future energy needs of its customers.
Planning for future capital expansion was a primary focus in 2007. Over the next five years, Duke Energy plans to spend approximately $23 billion on capital expenditures, with approximately $19 billion anticipated to support the U.S. Franchised Electric and Gas segment. Of this amount, approximately 25% of this capital is expected to go towards new pulverized coal, IGCC, gas and renewable generation resources to meet growing customer demand. During 2007 and early 2008, Duke Energy achieved important milestones with various state and federal regulators related to future capital projects. In the Carolinas, the NCUC approved the construction of one state of the art coal generation unit at Duke Energy Carolinas’ existing Cliffside Steam Station and Duke Energy Carolinas entered into an engineering, procurement, construction and commissioning services agreement with an affiliate of The Shaw Group, Inc. related to participation in the construction of Cliffside Unit 6, which has a current cost estimate of approximately $2.4 billion, which includes approximately $0.6 billion of AFUDC. In January 2008, the North Carolina Department of Environment and Natural Resources issued the final air permit for Cliffside Unit 6, which was the last regulatory hurdle before construction could begin. Additionally, in December 2007, CPCN’s to build two 620 MW combined cycle natural gas-fired generating facilities, one each at the existing Dan River and Buck steam stations, were filed with the NCUC. Duke Energy Carolinas is also continuing to seek all necessary regulatory approvals for the proposed William States Lee III Nuclear Station, including December 2007 filings of a COL application with the NRC, which was approved in February 2008, and an Integrated Resource Plan with the NCUC and PSCSC. Duke Energy Carolinas also currently plans to file a CPCN related to the nuclear project in South Carolina during 2008. Although these actions are necessary steps as management continues to pursue the option of building a new nuclear plant, submitting these applications does not commit Duke Energy Carolinas to build a nuclear unit. In Indiana, the IURC issued an order in November 2007 granting Duke Energy Indiana CPCN’s for the proposed 630 MW IGCC power plant at the Edwardsport Generating Station, which has an estimated cost of construction of approximately $2 billion, including AFUDC. The order also approved the timely recovery of costs related to the project. In January 2008, the Indiana Department of Environmental Management approved the air permit for the project, and major construction is expected to begin in the Spring of 2008. Duke Energy is assessing the potential for a joint owner for the facility, but could retain all of the plant capacity if a joint owner is not identified.
The continued development of renewable energy as part of Duke Energy’s generating portfolio was another primary focus of management during 2007. Climate change concerns, as well as the high price of oil, have sparked increased support for renewable
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energy legislation at both the federal and state level. For example, the new energy legislation passed in North Carolina in 2007 establishes a renewable portfolio standard for electric utilities at 3% of output by 2012, rising gradually to 12.5% by 2021. In response to this legislation, during 2007, Duke Energy Carolinas issued Request for Proposals (RFP) seeking bids for power generate from renewable energy sources, including sun, wind, water, organic matter and other sources. A similar RFP has also been issued by Duke Energy Ohio and Duke Energy Indiana. Additionally, in support of a strategy to increase its renewable energy portfolio in its unregulated businesses, Duke Energy acquired the wind power development assets of Energy Investor Funds from Tierra Energy in May 2007. Three of the development projects acquired from Tierra Energy are anticipated to be in commercial operation in late 2008 or 2009 and Duke Energy has already contracted to purchase wind turbines that are capable of generating approximately 240 MW when placed in commercial operation.
Management is also making progress on increasing the role energy efficiency will have in meeting customers’ growing energy needs. Energy efficiency is considered a “fifth fuel” in the portfolio available to meet customers’ growing needs for electricity, along with coal, nuclear, natural gas and renewable energy. During 2007, new energy efficiency plans were filed in North Carolina, South Carolina and Indiana and energy efficiency programs were expanded in both Kentucky and Ohio. The energy efficiency plans filed in North Carolina, South Carolina and Indiana are save-a-watt programs that would compensate Duke Energy for verified reductions in energy use and be available to all customer groups. The PSCSC and IURC have scheduled evidentiary hearings in 2008 to review these filings for South Carolina and Indiana, respectively. In advance of the evidentiary hearing held February 5-6, 2008 related to the South Carolina energy efficiency filing, a settlement agreement was reached with the South Carolina Office of Regulatory Staff, Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allow for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.
Duke Energy also participated in the development of energy legislation in various jurisdictions in 2007. Both North Carolina and South Carolina passed comprehensive energy legislation during 2007. This legislation includes provisions that will allow Duke Energy to recover new plant financing costs during the construction phase and allows recovery of costs of certain reagents used in emission removal. The North Carolina legislation also includes a renewable energy portfolio standard discussed above. Additionally, the Ohio Senate introduced Senate Bill 221 (SB 221), which proposes a comprehensive change to Ohio’s 1999 electric energy industry restructuring legislation. If enacted, SB 221 provides a workable framework for the development of new technologies, the building of new generation, environmental improvement, as well as energy efficiency. SB 221 is currently pending before the Ohio House of Representatives and could be enacted during the first quarter of 2008.
In the fourth quarter of 2007, Duke Energy Carolinas completed its first comprehensive rate case in North Carolina since 1991. Duke Energy Carolinas reached a settlement with interveners and the NCUC approved it. Overall, the rate settlement reduces customer rates in North Carolina without significantly impacting current earning levels. Although earnings levels will not be significantly impacted as a result of the rate settlement, future cash flows will be reduced as a result of a reduction in customer rates effective January 1, 2008. The decrease in revenues from the decrease in customer rates will be mostly offset by the discontinuance of amortization of clean air expenditures. Future clean air expenditures of approximately $700 million through 2010 will be capitalized as a component of rate base. Additionally, the PUCO affirmed Duke Energy Ohio’s RSP, which had been remanded by the Ohio Supreme Court to the PUCO for further consideration. The ruling maintained the current price and provided for continuation of the existing rate components, including the recovery of costs related to new pollution control equipment and capacity costs associated with power purchase contracts to meet customer demand, but provided customers an enhanced opportunity to avoid certain pricing components if they are served by a competitive supplier.
Overall, the regulatory and legislative accomplishments during 2007 have positioned Duke Energy well for 2008 and beyond.
2007 Financial Results. For the year-ended December 31, 2007, Duke Energy reported net income of $1,500 million and basic and diluted earnings per share (EPS) of $1.19 and $1.18, respectively, as compared to reported net income of $1,863 million and basic and diluted EPS of $1.59 and $1.57, respectively, for the year-ended December 31, 2006. EPS (basic and diluted) decreased for 2007 as compared to 2006, primarily due to lower net income, which is discussed below, and 2007 earnings per share being impacted by the dilutive effect of the issuance of approximately 313 million shares in April 2006 related to the Cinergy merger.
Income from continuing operations was $1,522 million for 2007, as compared to $1,080 million for 2006 due largely to the inclusion of Cinergy operations for a full year in 2007 versus nine months in the prior year. Total reportable segment EBIT increased from $2,553 million to $3,009 million. An increase for U.S. Franchised Electric and Gas of $494 million was primarily related to $218 million of first quarter 2007 EBIT contributed by Cinergy’s regulated Midwest operations for which there was zero in the comparable period of the prior year, as well as improved results in both the Carolinas and Midwest in 2007 due largely to favorable weather and additional long-term wholesale contracts, partially offset by higher operations and maintenance expense. Segment EBIT for Commercial Power increased
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$231 million due to improved retail electric margins resulting largely from timing of fuel and purchased power recoveries, higher overall prices and favorable weather, favorable mark-to-market results, and improved results from the Midwest gas-fired assets as a result of higher generation and capacity revenues, partially offset by higher operations and maintenance expense. Higher segment results at International Energy of $225 million are primarily a result of higher equity earnings at National Methanol Company (NMC), higher prices in Latin America and favorable foreign currency exchange impacts, as well as the absence of a $100 million litigation reserve and a $50 million impairment charge recorded in 2006. Segment results for Crescent decreased from $532 million in 2006 to $38 million in 2007, reflecting the $246 million gain on sale of an effective 50% interest in Crescent and the subsequent reduction in ownership from 100% to an effective 50% in September 2006, two large sales that occurred in the second quarter of 2006, lower residential developed lot sales in 2007 and an impairment charge on certain residential developments in 2007. In addition, losses at Other decreased as a result of lower costs related to captive insurance, lower merger costs, lower corporate governance costs and a benefit in 2007 related to contract settlement negotiations, partially offset by convertible debt costs of approximately $21 million related to the spin-off of Spectra Energy.
In addition to the increase in total reportable segment and Other EBIT, income from continuing operations for 2007 as compared to 2006 was negatively impacted by higher income tax expense from continuing operations and higher interest expense. Income tax expense from continuing operations increased as a result of higher pre-tax income and a higher effective tax rate in 2007 compared to 2006 largely due to certain favorable tax matters in 2006 that lowered the effective tax rate in 2006. Interest expense increased due primarily to the debt assumed from Cinergy. Partially offsetting these unfavorable results was higher interest income, largely as a result of increased earnings from higher average invested cash and short-term investment balances during 2007 as compared to 2006, including a $19 million favorable impact related to the inclusion of amounts for legacy Cinergy for the first quarter of 2007 with no comparable amount in 2006.
More than offsetting the increase in income from continuing operations was a decrease in income from discontinued operations for 2007 as compared to 2006, primarily attributable to the classification of the results of operations for the natural gas businesses spun off on January 2, 2007 as discontinued operations for periods prior to the spin-off.
Duke Energy’s Direction in 2008 and Beyond. Management of Duke Energy is focusing on the following objectives in 2008 and beyond:
•
Pursue a balanced approach to meeting future energy needs by pursuing new supply options, including energy efficiency, coal gasification, advanced pulverized coal, nuclear, natural gas-fired generation and renewable energy, while considering whether they are available, affordable, reliable and clean;
•
Accept the reality of a carbon-constrained world and pursue low-carbon and no-carbon solutions for meeting future energy needs;
•
Finding a path to success during this era of rising costs by striving to control costs, run the businesses efficiently and provide excellent customer service; and
•
Meet 2008 financial objectives and, for the long-term, deliver on its promise to shareholders by steadily growing earnings and dividends
The majority of future earnings are anticipated to be contributed from U.S. Franchised Electric and Gas, which consists of Duke Energy’s regulated businesses that currently own a capacity of approximately 28,000 megawatts of generation. The regulated generation portfolio consists of a mix of coal, nuclear, natural gas and hydroelectric generation, with the substantial majority of all of the sales of electricity coming from coal and nuclear generation facilities. While the drought conditions in the Carolinas did not significantly impact earnings in 2007, continued or sustained drought conditions could have a negative impact on earnings in 2008. Commercial Power has net capacity of approximately 8,000 megawatts of unregulated generation, of which approximately 4,000 megawatts serves retail customers under the RSP in Ohio. Approximately 75% of International Energy’s net capacity of approximately 4,000 megawatts of installed generation capacity in Latin America consists of base load hydroelectric capacity that carries a low level of dispatch risk; in addition, for 2008 over 90% of International Energy’s contractible capacity in Latin America is either currently contracted or receives a system capacity payment.
As mentioned earlier, during the five-year period from 2008 to 2012, Duke Energy anticipates total capital expenditures of approximately $23 billion. Annual capital expenditures are currently estimated at approximately $5 billion in 2008-2011 and approximately $3 billion in 2012. These expenditures are principally related to expansion plans, maintenance costs, environmental spending related to Clean Air Act requirements and nuclear fuel. Current estimates are that Duke Energy’s regulated generation capacity will need to increase by approximately 7,700 megawatts over the next ten years, with the majority being in the Carolinas. Duke Energy is committed to adding base load capacity at a reasonable price while modernizing the current generation facilities by replacing older, less efficient plants with cleaner, more efficient plants. Significant expansion projects include the new IGCC plant at Duke Energy Indiana’s Edwardsport Generating Station, a new 800 MW coal unit at Duke Energy Carolinas’ existing Cliffside facility in North Carolina and new gas-fired generation units at Duke Energy Carolinas’ existing Dan River and Buck Steam Stations, as well as other additions due to system growth.
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Additionally, Duke Energy is evaluating the potential construction of a new nuclear power plant in Cherokee County, South Carolina. Costs related to environmental spending are expected to decrease over the five-year period as the upgrades to comply with the new environmental regulations are completed.
Duke Energy anticipates capital expenditures at Commercial Power will primarily relate to growth opportunities, such as renewable energy generation projects and environmental control equipment, as well as maintenance on existing plants. Capital expenditures at International Energy, which will be funded with cash held or raised by International Energy, will primarily be for strategic growth opportunities, such as new hydro plants in Brazil, as well as maintenance on existing plants. Duke Energy does not anticipate any additional capital investment related to its investment in the Crescent JV.
Duke Energy does not currently anticipate funding capital expenditures with the issuance of common equity in the foreseeable future, but rather through the use of available cash and cash equivalents as well as the issuance of incremental debt.
As the majority of Duke Energy’s anticipated future capital expenditures are related to its regulated operations, a risk to Duke Energy is the ability to recover costs related to such expansion in a timely manner. Energy legislation passed in North Carolina and South Carolina in 2007 provides, among other things, mechanisms for Duke Energy to recover financing costs for new nuclear or coal base load generation during the construction phase. In Indiana, Duke Energy has received approval to recover its development costs for the new IGCC plant at the Edwardsport Generating Station. Duke Energy has received approval for nearly $260 million of future federal tax credits related to costs to be incurred for the modernization of the Cliffside facility as well as the IGCC plant in Indiana. In addition, Duke Energy has received general assurances from the NCUC that the North Carolina allocable portion of development costs associated with the William States Lee III nuclear station will be recoverable through a future rate case proceeding as long as the costs are deemed prudent and reasonable. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state legislators or regulators.
In response to concerns over climate change, the U.S. Congress has been discussing various proposals to reduce or cap CO2 and other greenhouse gas emissions. Any legislation enacted as a result of these efforts could involve a market based cap and trade program. In anticipation, Duke Energy is increasing focus on renewable energy and energy efficiency initiatives in an effort to reduce emissions. In addition to the wind assets purchased during 2007, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana have issued RFP’s for renewable energy sources that can be operational as early as 2012. Additionally, new energy efficiency plans were filed in North Carolina, South Carolina and Indiana and energy efficiency programs were expanded in both Kentucky and Ohio. Energy efficiency filings are expected to be made in Ohio and Kentucky in 2008. The energy efficiency plans filed in North Carolina, South Carolina and Indiana are save-a-watt programs that would compensate Duke Energy for verified reductions in energy use and be available to all customer groups. The PSCSC and IURC have scheduled evidentiary hearings in 2008 to review these filings for South Carolina and Indiana, respectively. In advance of the evidentiary hearing held February 5-6, 2008 related to the South Carolina energy efficiency filing, a settlement agreement was reached with the South Carolina Office of Regulatory Staff, Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allow for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.
In summary, Duke Energy is coordinating its future capital expenditure requirements with regulatory initiatives in order to ensure adequate and timely cost recovery while continuing to provide low cost energy to its customers.
Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable, less cyclical businesses like U.S. Franchised Electric and Gas, and the traditionally higher-growth and more cyclical energy businesses like Commercial Power and International Energy. Additionally, Crescent’s portfolio strategy is diversified between residential, commercial and multi-family development. All of Duke Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market prices of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2008 and beyond.
Declines in demand for electricity as a result of economic downturns would reduce overall electricity sales and lessen Duke Energy’s cash flows, especially as industrial customers reduce production and, thus, consumption of electricity. A portion of U.S. Franchised Electric and Gas’ business risk is mitigated by its regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses.
If negative market conditions should persist over time and estimated cash flows over the lives of Duke Energy’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. A change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also result in impairments or losses.
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Duke Energy’s 2008 goals can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in the United States are subject to regulation on the federal and state level. Regulations, applicable to the electric power industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Energy cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.
Duke Energy’s earnings are impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as there are timing differences as to when such costs are recovered in rates. To mitigate these risks, Duke Energy enters into derivative instruments to effectively hedge known exposures.
Additionally, Duke Energy’s investments and projects located outside of the United States expose Duke Energy to risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. Changes in these factors are difficult to predict and may impact Duke Energy’s future results.
Duke Energy also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by cash flow from operations. An inability to access capital at competitive rates could adversely affect Duke Energy’s ability to implement its strategy. Market disruptions or a downgrade of Duke Energy’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity.
For further information related to management’s assessment of Duke Energy’s risk factors, see Item 1A. “Risk Factors.”
RESULTS OF OPERATIONS
Consolidated Operating Revenues
Year Ended December 31, 2007 as Compared to December 31, 2006. Consolidated operating revenues for 2007 increased $2,113 million, compared to 2006. This change was driven primarily by approximately $1,408 million of revenues generated during the first quarter of 2007 related to legacy Cinergy operations (reflected in the results for U.S. Franchised Electric and Gas and Commercial Power) for which no revenues were recognized in the comparable period of the prior year since the Cinergy merger occurred effective April 2006. Also contributing to the increase in revenues were:
•
A $576 million increase at U. S. Franchised Electric and Gas due primarily to increased fuel revenue from retail customers, higher sales volume as a result of favorable weather, increased wholesale power revenues due to increased sales volumes primarily due to additional long-term wholesale contracts in 2007, increase in retail rates and rate riders primarily related to new electric base rates implemented in the first quarter of 2007 for Duke Energy Kentucky and the recovery of environmental compliance costs from retail customers in Indiana, and an increase related to the sharing of anticipated merger savings through rate decrement riders which was substantially completed prior to the third quarter of 2007;
•
A $208 million increase at Commercial Power due primarily to increased retail electric revenues principally related to the timing of collections on fuel and purchased power and increased retail demand resulting from favorable weather, and increased wholesale revenues due primarily to higher generation volumes resulting from favorable weather and higher tolling and capacity revenues, partially offset by net unfavorable mark-to-market results on non-qualifying power and capacity hedge contracts; and
•
A $117 million increase at International Energy due primarily to higher sales prices in Brazil and Peru, and favorable foreign currency exchange impacts compared to the prior year, primarily in Brazil.
Partially offset by:
•
A $221 million decrease at Crescent as a result of the deconsolidation of Crescent in September 2006 and the subsequent accounting for Duke Energy’s investment in Crescent as an equity method investment.
Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating revenues for 2006 increased $3,701 million, compared to 2005. This change was driven by:
•
An approximate $3,820 million increase due to the merger with Cinergy; and
•
A $216 million increase at International Energy due primarily to higher revenues in Peru from increased ownership and resulting consolidation of Aguaytia, higher energy prices in El Salvador, favorable results in Brazil, primarily foreign exchange rate impacts and higher electricity volumes and prices in Argentina.
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Partially offset by:
•
A $274 million decrease at Crescent due primarily to the deconsolidation of Crescent, effective September 7, 2006 and softening in the residential real estate market; and
•
A $69 million decrease in Other due primarily to the sale of Duke Project Services Group, Inc. (DPSG) in February 2006 and a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast.
For a more detailed discussion of operating revenues, see the segment discussions that follow.
Consolidated Operating Expenses
Year Ended December 31, 2007 as Compared to December 31, 2006. Consolidated operating expenses for 2007 increased $1,012 million, compared to 2006. This change was driven primarily by an approximate $1,160 million of expenses incurred during the first quarter of 2007 related to legacy Cinergy operations (reflected in the results for U.S. Franchised Electric and Gas and Commercial Power) for which no expenses were incurred in the comparable period of the prior year since the Cinergy merger occurred effective April 2006. Excluding the above, consolidated operating expenses increased as a result of the following:
•
A $317 million increase at U.S. Franchised Electric and Gas due primarily to increased operating and maintenance expenses driven by higher wage and benefits costs, including increased short-term incentive costs, maintenance costs at fossil and nuclear generating plants, increased fuel expense driven by higher demand from retail customers resulting from favorable weather, and an increase in depreciation due to additional capital spending; and
•
An $18 million increase at Commercial Power due primarily to increased fuel expense and operating and maintenance expenses from the Midwest gas-fired generation assets due primarily to increased generation volumes in 2007 compared to 2006 and higher fuel and purchased power expenses due to increased retail sales volumes and plant outages in 2007, partially offset by net mark-to-market gains on non-qualifying fuel hedge contracts in 2007 compared to net losses in 2006 and lower losses from sales of fuel.
Partially offset by:
•
A $240 million decrease in Other due primarily to a 2006 charge and 2007 credits related to contract settlement negotiations, lower costs to achieve related to the Cinergy merger, lower costs related to Duke Energy’s captive insurance company driven by lower charges for mutual insurance exit obligations, and lower governance and other corporate costs, partially offset by a donation to the Duke Foundation;
•
A $160 million decrease at Crescent as a result of the deconsolidation of Crescent in September 2006 and the subsequent accounting for Duke Energy’s investment in Crescent as an equity method investment; and
•
A $62 million decrease at International Energy due primarily to a prior year reserve related to a settlement made in conjunction with the Citrus Trading Corporation (Citrus) litigation, a contract dispute between Citrus and Spectra Energy LNG Sales Inc. (formerly known as Duke Energy LNG Sales Inc.), an impairment charge on notes receivable from Campeche recorded in 2006, partially offset by unfavorable foreign currency exchange impacts, increased purchased power, general and administrative costs in Brazil, and higher fuel consumption in Guatemala due to higher generation and higher maintenance costs as a result of unplanned outages.
Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating expenses for 2006 increased $3,624 million, compared to 2005. The change was primarily driven by:
•
An approximate $3,326 million increase due to the merger with Cinergy;
•
A $312 million increase at International Energy due primarily to higher costs in Peru, driven primarily by increased ownership and resulting consolidation of Aguaytia, a reserve related to a settlement made in conjunction with the Citrus litigation, higher fuel prices and increased consumption in El Salvador, unfavorable exchange rates, increased regulatory fees and higher purchased power costs in Brazil and an impairment charge on notes receivable from a Mexican investment recorded in 2006;
•
A $132 million increase in Other due primarily to costs to achieve the Cinergy merger, a reserve charge related to contract settlement negotiations, partially offset by decreases due to the continued wind-down of the former DENA businesses; and
•
An approximate $115 million increase at Duke Energy Carolinas driven primarily by increased fuel expenses, due primarily to higher coal costs and increased purchase power expense resulting primarily from less generation availability during 2006 as a result of outages at base load stations, partially offset by lower regulatory amortization, due primarily to reduced amortization of compliance costs related to clean air legislation, and lower operating and maintenance expense, due primarily to a December 2005 ice storm.
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Partially offset by:
•
A $239 million decrease at Crescent due primarily to the deconsolidation of Crescent, effective September 7, 2006 and softening in the residential real estate market.
For a more detailed discussion of operating expenses, see the segment discussions that follow.
Consolidated Gains on Sales of Investments in Commercial and Multi-Family Real Estate
Consolidated gains on sales of investments in commercial and multi-family real estate were zero in 2007, as a result of the deconsolidation of Crescent in September 2006 and the subsequent accounting for Duke Energy’s investment in Crescent as an equity method investment, $201 million in 2006, and $191 million in 2005. The gain in 2006 was driven primarily by pre-tax gains from the sale of two office buildings at Potomac Yard in Washington, D.C. and a gain on a land sale at Lake Keowee in northwestern South Carolina. The gain in 2005 was driven primarily by pre-tax gains from the sales of surplus legacy land, particularly a large sale in Lancaster, South Carolina, commercial land sales, including a large sale near Washington, D.C. and multi-family project sales in North Carolina and Florida.
Consolidated (Losses) Gains on Sales of Other Assets and Other, net
Consolidated (losses) gains on sales of other assets and other, net was a loss of $5 million for 2007, a gain of $223 million for 2006, and a loss of $55 million for 2005. The loss in 2007 was due primarily to losses related to Commercial Power’s sale of emission allowances. The gain in 2006 was due primarily to the pre-tax gains resulting from the sale of an effective 50% interest in Crescent, creating a joint venture between Duke Energy and MSREF (approximately $246 million), partially offset by Commercial Power’s losses on sales of emission allowances (approximately $29 million). The loss in 2005 was due primarily to net losses at Commercial Power, principally the termination of DENA structured power contracts in the Southeast region (approximately $75 million).
Consolidated Operating Income
Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated operating income increased $672 million compared to 2006. Increased operating income was partially driven by an approximate $237 million favorable impact generated during the first quarter of 2007 related to legacy Cinergy operations (reflected in the results for U.S. Franchised Electric and Gas and Commercial Power) for which there was zero in the comparable period of the prior year since the Cinergy merger occurred effective April 2006, as well as factors discussed above.
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated operating income increased $365 million, compared to 2005. Increased operating income was primarily related to approximately $465 million of operating income generated by legacy Cinergy in 2006 as a result of the merger and an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent, partially offset by approximately $128 million of cost in 2006 to achieve the Cinergy merger and approximately $165 million of charges in 2006 related to settlements and contract negotiations.
Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.
Consolidated Other Income and Expenses
Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated other income and expenses increased $74 million, compared to 2006. This increase was primarily driven by an increase in equity earnings of $34 million due primarily to the deconsolidation of Crescent in September 2006 and the subsequent accounting for Crescent as an equity method investment and increased equity earnings from International Energy of approximately $22 million primarily related to its investment in National Methanol Company (NMC) primarily as a result of higher margins, approximately $34 million increase in interest income, largely as a result of increased earnings from higher average invested cash and short-term investment balances during 2007 as compared to 2006 (of which approximately $19 million of the increase relates to interest income of legacy Cinergy in the first quarter 2007 with no comparable amount in 2006), partially offset by lower interest income related to income taxes resulting primarily from favorable income tax settlements in 2006, a $17 million impairment charge at International Energy recorded during the second quarter of 2006, and convertible debt costs of approximately $21 million related to the spin-off of Spectra Energy.
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated other income and expenses increased $137 million, compared to 2005. The increase was due primarily to an increase of approximately $125 million of interest income resulting primarily from favorable income tax settlements in 2006.
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Consolidated Interest Expense
Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated interest expense increased $53 million, compared to 2006. This increase was due primarily to the debt assumed from the merger with Cinergy, higher interest on debt in Brazil and interest expense recorded on tax items primarily as a result of the adoption of FIN No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109” (FIN 48), partially offset by debt reductions and financing activities and an increase in the debt component of AFUDC resulting from increased capital spending.
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated interest expense increased $251 million, compared to 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy (approximately $227 million impact).
Consolidated Minority Interest Expense
Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated minority interest expense decreased $11 million, compared to 2006. This decrease was due primarily to lower earnings at Aguaytia in 2007 and the deconsolidation of Crescent.
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated minority interest expense decreased $11 million, compared to 2005. This decrease was due primarily to lower earnings at Crescent’s LandMar affiliate in Florida, as a result of softening in the residential real estate market.
Consolidated Income Tax Expense from Continuing Operations
Year Ended December 31, 2007 as Compared to December 31, 2006. For 2007, consolidated income tax expense from continuing operations increased $262 million, compared to 2006. The increase is primarily the result of higher pre-tax income in 2007 as compared to 2006. Additionally, the effective tax rate increased for the year ended December 31, 2007 (32%) compared to 2006 (29%), due primarily to prior year favorable tax settlements on research and development costs and nuclear decommissioning costs, and tax benefits related to the impairment of an investment in Bolivia, partially offset by an increase in the manufacturing deduction in 2007 and higher foreign taxes accrued in 2006.
Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated income tax expense from continuing operations increased $75 million, compared to 2005. This increase primarily resulted from higher pre-tax earnings, partially offset by favorable tax settlements on research and development costs and nuclear decommissioning costs, and tax benefits related to the impairment of an investment in Bolivia.
Consolidated (Loss) Income from Discontinued Operations, net of tax
Consolidated (loss) income from discontinued operations was a loss of $22 million for 2007, income of $783 million for 2006, and income of $935 million for 2005. The 2006 and 2005 amounts include the after-tax earnings of Duke Energy’s natural gas businesses that were spun off to shareholders on January 2, 2007. The 2007, 2006 and 2005 amounts include results of operations and gains (losses) on dispositions related primarily to former DENA’s assets and contracts outside the Midwestern and Southeastern United States as a result of the 2005 decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, which are included in Other. The 2007 and 2006 amounts also include Cinergy commercial marketing and trading operations and synfuel operations, which are both included in Commercial Power. See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”.
The 2007 amount is primarily comprised of an after-tax loss of approximately $18 million associated with former DENA contract settlements, an after-tax loss of approximately $8 million related to Cinergy commercial marketing and trading operations and after-tax earnings of approximately $23 million related to Commercial Power’s synfuel operations.
The 2006 amount is primarily comprised of after-tax earnings of approximately $953 million related to the natural gas businesses, approximately $140 million of after-tax losses associated with certain contract terminations or sales at former DENA, and the recognition of approximately $17 million of after-tax losses associated with exiting the Cinergy commercial marketing and trading operations.
The 2005 amount is primarily comprised of after-tax earnings of approximately $1,623 million related to the natural gas businesses, which includes $1,245 million of pre-tax gains on sales of equity investments, primarily associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP and an approximate $575 million gain resulting from the DEFS disposition transaction, an approximate $550 million non-cash, after-tax charge (approximately $900 million pre-tax) for the impairment of assets, and the dis-
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continuance of hedge accounting and the discontinuance of the normal purchase/normal sale exception for certain positions as a result of the decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Additionally, during 2005, Duke Energy recognized after-tax losses of approximately $250 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts related to the former DENA operations. These charges were offset by the recognition of after-tax gains of approximately $125 million (approximately $200 million pre-tax) related to the recognition of deferred gains in Accumulated Other Comprehensive Income (AOCI) related to discontinued cash flow hedges related to the former DENA operations.
Consolidated Cumulative Effect of Change in Accounting Principle, net of tax and minority interest
During 2005, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principle of $4 million as a reduction in earnings. The change in accounting principle related to the implementation of FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.
Segment Results
Management evaluates segment performance based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Energy’s ownership interest in operations without regard to financing methods or capital structures.
See Note 3 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s segment structure.
As discussed above and in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, the continuing operations of the former DENA segment (which primarily include the operations of the Midwestern generation assets, former DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Commercial Power, except for DETM, which is in Other.
Duke Energy’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.
EBIT by Business Segment
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(a) Amounts associated with former DENA’s operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.
(b) In September 2006, Duke Energy completed a joint venture transaction of Crescent. As a result, Crescent segment data includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.
(c) Interest income and other includes foreign currency transaction gains and losses and additional minority interest expense not allocated to the segment results.
Minority interest expense presented below includes only minority interest expense related to EBIT of Duke Energy’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures.
The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.
U.S. Franchised Electric and Gas
(a) Gigawatt-hours (GWh)
(b) Relates to operations of former Cinergy from the date of acquisition and thereafter
(c) Megawatt (MW)
The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Carolinas.
(a) Major components of Duke Energy Carolinas’ retail sales.
(b) Consists of all components of Duke Energy Carolinas’ sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.
The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Midwest for the nine months ended December 31, 2007 compared to the same period in the prior year.
(a) Major components of Duke Energy Midwest’s retail sales.
(b) Consists of all components of Duke Energy Midwest’s sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.
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Year Ended December 31, 2007 as Compared to December 31, 2006
Operating Revenues. The increase was driven primarily by:
•
A $1,066 million increase in regulated revenues for the first quarter of 2007 due to the merger with Cinergy;
•
A $212 million increase in fuel revenues, including emission allowances, driven by increased fuel rates for retail customers and increased GWh sales to retail customers;
•
A $188 million increase in GWh sales to retail customers due to favorable weather conditions. For the Carolinas and Midwest, cooling degree days for 2007 were approximately 27% and 48% above normal, respectively, compared to close to normal in both regions during 2006;
•
An $82 million increase in wholesale power revenues, net of sharing, due to increased sales volumes primarily due to additional long-term contracts;
•
A $57 million increase in retail rates and rate riders primarily related to the new electric base rates implemented in the first quarter of 2007 for Duke Energy Kentucky and the recovery of environmental compliance costs from retail customers in Indiana; and
•
A $40 million increase related to the sharing of anticipated merger savings through rate decrement riders with regulated customers, which was substantially completed prior to the third quarter of 2007.
Operating Expenses. The increase was driven primarily by:
•
An $852 million increase in regulated operating expenses for the first quarter of 2007 due to the merger with Cinergy;
•
A $137 million increase in operating and maintenance expense primarily due to higher wage and benefit costs, including increased short-term incentive costs, and maintenance costs at fossil and nuclear generating plants, partially offset by a one time $12 million donation in the second quarter 2006 ordered by the NCUC as a condition of the Cinergy merger;
•
A $133 million increase in fuel expense (including purchased power) primarily due to increased retail demand resulting from favorable weather conditions. Generation fueled by coal and natural gas, as well as purchases to meet retail customer requirements, increased significantly during the year ended December 31, 2007 compared to the same period in the prior year. These increases were partially offset by a $21 million reimbursement for previously incurred fuel expenses resulting from a settlement between Duke Energy Carolinas and the U.S. Department of Justice resolving Duke Energy’s used nuclear fuel litigation against the Department of Energy (DOE). The settlement between the parties was finalized on March 6, 2007; and
•
A $40 million increase in depreciation due primarily to additional capital spending in the Carolinas.
Partially offset by:
•
A $6 million net decrease in regulatory amortization expense primarily due to decreased amortization of compliance costs related to North Carolina clean air legislation during 2007 as compared to the prior year. Regulatory amortization expenses related to clean air were approximately $187 million for the year ended December 31, 2007 compared to approximately $225 million during the same period in 2006. This decrease was partially offset by the write-off of a portion of the investment in the GridSouth RTO (approximately $17 million) per a rate order from the NCUC and Ohio’s regulatory amortization related to the rate transition charge rider and new demand side management (DSM) rider.
Other Income and Expenses, net. The increase is primarily attributable to the equity component of AFUDC earned from additional capital spending for on-going construction projects.
EBIT. The increase resulted primarily from the merger with Cinergy, favorable weather conditions, additional long-term wholesale contracts, increase in retail rates and rate riders and the substantial completion of the required rate reductions due to the merger with Cinergy. These increases were partially offset by increased operating and maintenance expenses and additional depreciation as rate base increased during 2007.
Matters Impacting Future U.S. Franchised Electric and Gas Results
U.S. Franchised Electric and Gas continues to increase its customer base, maintain low costs and deliver high-quality customer service in the Carolinas and Midwest. The residential and general service sectors are expected to grow. The industrial sector, particularly textile and housing related, was soft in 2007 and that trend is expected to continue in 2008. U.S. Franchised Electric and Gas will continue to provide strong cash flows from operations to Duke Energy, which will help fund the capital spending program in 2008. Changes in weather, wholesale power market prices, service area economy, generation availability and changes to the regulatory environment would impact future financial results for U.S. Franchised Electric and Gas.
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The impact of the North Carolina rate order resulting from the 2007 rate review ordered by the NCUC will also affect income for 2008 and future years. Particularly, retail base rates were lowered by $287 million, which was primarily offset by the elimination of clean air legislation amortization. For 2008 only, the NCUC also allowed a one time increment rider of $80 million related to merger savings. Legislation enacted in both North and South Carolina in 2007 will allow Duke Energy Carolinas to recover from retail customers more of the costs incurred for purchases of power and reagents needed to meet customer demand. Various regulatory activities will continue in 2008, including a review of Duke Energy Carolinas’ and Duke Energy Indiana’s proposed cost recovery methodology related to energy efficiency programs. Decisions on 2007 filings for certification for new generation are also expected. Duke Energy Ohio’s pending gas rate case could also impact future results through the increase of base rates.
The Southeastern United States continues to experience severe drought conditions brought about by a significant shortage of rainfall in the past several months. As a result of these conditions, water supplies in the reservoirs and lake systems that support many of Duke Energy Carolinas’ hydroelectric, nuclear, and fossil electric generation plants have declined and could continue to decline in the absence of more normal levels of rainfall. Duke Energy is analyzing long-term weather forecasts and developing plans to mitigate any potential operational impacts that continued severe drought conditions could cause; however, at this time we cannot determine if such impacts will have a material effect on Duke Energy.
Year Ended December 31, 2006 as Compared to December 31, 2005
Operating Revenues. The increase was driven primarily by:
•
A $2,651 million increase in regulated revenues due to the acquisition of Cinergy;
•
A $203 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs. The delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005, representing an approximately 20% increase; and
•
A $27 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in Duke Energy Carolinas’ service territory. The number of customers in 2006 increased by approximately 45,000 compared to 2005.
Partially offset by:
•
A $91 million decrease in wholesale power sales, net of the impact of sharing of profits from wholesale power sales with industrial customers in North Carolina ($40 million). Sales volumes decreased by approximately 39% primarily due to production constraints caused by generation outages and pricing;
•
A $77 million decrease related to the sharing of anticipated merger savings by way of a rate decrement rider with regulated customers in North Carolina and South Carolina. As a requirement of the merger, Duke Energy Carolinas is required to share anticipated merger savings of approximately $118 million with North Carolina customers and approximately $40 million with South Carolina customers over a one year period; and
•
A $32 million decrease in GWh sales to retail customers due to unfavorable weather conditions compared to the same period in 2005. Weather statistics in 2006 for heating degree days were approximately 9% below normal as compared to 2% above normal in 2005. Overall weather statistics for both heating and cooling periods in 2006 were unfavorable compared to the same periods in 2005.
Operating Expenses. The increase was driven primarily by:
•
A $2,245 million increase in regulated operating expenses due to the acquisition of Cinergy;
•
A $188 million increase in fuel expenses, due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation for year to date December 31, 2006 and 2005 and the delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005;
•
A $42 million increase in purchased power expense, due primarily to less generation availability during 2006 as a result of outages at base load stations; and
•
A $24 million increase in depreciation expense, due to additional capital spending.
Partially offset by:
•
An $86 million decrease in regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during 2006 as compared to the same period in 2005. Regulatory amortization expenses were approximately $225 million for the year ended December 31, 2006 as compared to approximately $311 million during the same period in 2005;
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•
A $39 million decrease in operating and maintenance expenses, due primarily to a December 2005 ice storm; and
•
A $15 million decrease in donations related to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina. For the year ended December 31, 2006, donations totaled $13 million, while for the same period in 2005, donations totaled $28 million.
Other income and expenses. The increase in Other income and expenses resulted primarily from an increase in AFUDC due mainly to the acquisition of the regulated operations of Cinergy.
EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy, lower regulatory amortization in North Carolina, increased demand from retail customers due to continued growth in the number of residential and general service customers and decreased operating and maintenance expense in the Carolinas. These changes were partially offset by lower wholesale power sales, net of sharing, rate reductions due to the merger, unfavorable weather conditions and increased purchased power expense in the Carolinas.
Commercial Power
(a) Excludes discontinued operations
During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, Commercial Power includes the operations of former DENA’s Midwestern generation assets and remaining Southeastern operations related to the assets which were disposed of in 2004. The results of former DENA’s discontinued operations, which are comprised of assets sold to LS Power, are presented in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in consolidated Results of Operations section titled “Consolidated (Loss) Income from Discontinued Operations, net of tax.”
Year Ended December 31, 2007 as compared to December 31, 2006
Operating Revenues. The increase was primarily driven by:
•
A $387 million increase related to the non-regulated generation assets of former Cinergy, including the impacts of purchase accounting, which reflects the first quarter 2007 operating revenues for which there was zero in the comparable period in the prior year as a result of the merger in April 2006;
•
A $185 million increase in retail electric revenues due to higher retail pricing principally related to the time of collections on fuel and purchased power (FPP) rider and increased retail demand resulting from favorable weather in 2007 compared to 2006; and
•
A $134 million increase in revenues due to higher generation volumes and capacity revenues from the Midwest gas-fired assets resulting from favorable weather in 2007 compared to 2006.
Partially offset by:
•
A $111 million decrease in net mark-to-market revenues on non-qualifying power and capacity hedge contracts, consisting of mark-to-market losses of $52 million in 2007 compared to gains of $59 million in 2006; and
•
A $35 million decrease in revenues from sales of fuel due to lower volumes in 2007 compared to 2006.
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Operating Expenses. The increase was primarily driven by:
•
A $327 million increase related to the non-regulated generation assets of former Cinergy, including the impacts of purchase accounting, which reflects the first quarter 2007 operating expenses for which there was zero in the comparable period in the prior year as a result of the merger with Cinergy in April 2006;
•
A $116 million increase in fuel expenses for the Midwest gas-fired assets primarily due to increased generation volumes in 2007 compared to 2006; and
•
A $36 million increase in operating expenses primarily due to increased plant maintenance in 2007.
Partially offset by:
•
A $114 million decrease in net mark-to-market expenses on non-qualifying fuel hedge contracts, consisting of mark-to-market gains of $65 million in 2007 compared to losses of $49 million in 2006; and
•
A $30 million decrease in expenses associated with sales of fuel due to lower volumes in 2007 compared to 2006.
(Losses) Gains on Sales of Other Assets and Other, net. Decrease in 2007 compared to 2006 is attributable to lower losses on emission allowance sales in 2007 due to lower sales activity in 2007 compared to 2006.
Other Income and Expenses, net. The decrease is driven by lower equity earnings of unconsolidated affiliates.
EBIT. The improvement is primarily attributable to higher retail margins resulting largely from favorable timing of fuel and purchase power recoveries, increased retail demand as a result of favorable weather and improved results from the Midwest gas-fired assets as a result of higher generation volumes and increased capacity revenues. These favorable variances were partially offset by higher expenses from increased plant maintenance in 2007.
Matters Impacting Future Commercial Power Results
Commercial Power’s current strategy is focused on maximizing the returns and cash flows from its current portfolio, as well as growing Duke Energy’s non-regulated renewable energy portfolio. Results for Commercial Power are sensitive to changes in power supply, power demand, fuel prices and weather, as well as dependent upon completion of energy asset construction projects and tax credits on renewable energy production. Future results for Commercial Power are subject to volatility due to the over or under-collection of fuel and purchased power costs since Commercial Power’s Rate Stabilization Plan (RSP) market based standard service offer (MBSSO) is not subject to regulatory accounting pursuant to SFAS No. 71, “Accounting for Certain Types of Regulation” (SFAS No. 71). In addition, Commercial Power’s RSP expires on December 31, 2008. Duke Energy is currently working with the PUCO and the Ohio legislature to establish a rate structure beyond 2008. The outcome of this rate structure could impact the results of operations in future periods. Compared to 2006 and 2007, Commercial Power’s 2008 results will also be favorably impacted by the reduced impact of purchase accounting adjustments recorded in connection with the 2006 merger with Cinergy.
Year Ended December 31, 2006 as compared to December 31, 2005
Operating Revenues. The increase was primarily driven by the acquisition of Cinergy non-regulated generation assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005 (approximately $1,169 million). Operating revenues associated with the former DENA Midwest plants were approximately $14 million higher in 2006 compared to 2005 due primarily to higher average prices and slightly higher volumes.
Operating Expenses. The increase was primarily driven by the acquisition of Cinergy non-regulated generation assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005 (approximately $1,082 million). Operating expenses associated with the former DENA Midwest plants were approximately $10 million higher in 2006 compared to 2005 due primarily to higher fuel prices and slightly higher volumes.
(Losses) Gains on Sales of Other Assets and Other, net. The increase was driven primarily by an approximate $75 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region, partially offset by net losses of approximately $29 million on sales of emission allowances in 2006.
Other Income and Expenses, net. The increase is driven primarily by equity earnings of unconsolidated affiliates related to investments acquired in connection with the Cinergy merger in 2006.
EBIT. The increase was due primarily to the approximate $75 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region and the acquisition of Cinergy assets (approximately $95 million).
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International Energy
(a) Excludes discontinued operations
Year Ended December 31, 2007 as Compared to December 31, 2006
Operating Revenues. The increase was driven primarily by:
•
An $81 million increase in Brazil due to higher sales prices and favorable exchange rates;
•
A $37 million increase in Guatemala due to higher prices and volumes as a result of increased thermal dispatch; and
•
A $27 million increase in Peru due to higher spot prices as a result of transmission line congestion.
Partially offset by:
•
An $18 million decrease in Ecuador due to decreased sales as a result of lower thermal dispatch; and
•
A $5 million decrease in Argentina due to lower sales volumes resulting from unfavorable hydrology, partially offset by higher average sales prices.
Operating Expenses. The decrease was driven primarily by:
•
A $100 million decrease due to a prior year reserve established as a result of a settlement made in conjunction with the Citrus litigation;
•
A $43 million decrease in Mexico due primarily to a $33 million impairment charge on the notes receivable from the Campeche equity investment in 2006; and
•
An $11 million decrease in Ecuador due to lower fuel used as a result of lower generation.
Partially offset by:
•
A $50 million increase in Brazil primarily due to higher exchange rates and higher regulatory and purchased power costs;
•
A $37 million increase in Guatemala due to increased fuel used as a result of higher dispatch and higher maintenance costs as a result of unplanned outages; and
•
An $8 million increase in Argentina due to higher maintenance costs.
Other Income and Expenses, net. The increase was driven primarily by a $26 million increase in equity earnings at National Methanol Company (NMC) as a result of higher methanol and methyl tertiary butyl ether (MTBE) margins, as well as the absence of a $17 million impairment of the Campeche equity investment recorded in 2006.
EBIT. The increase in EBIT was primarily due to a prior year reserve established as a result of a settlement made in conjunction with the Citrus litigation, a prior year impairment of the Campeche equity investment and note receivable reserve, favorable prices in Peru due to transmission line congestion, favorable prices and net foreign exchange impacts offset by higher regulatory costs in Brazil and higher equity earnings at National Methanol, partially offset by higher maintenance costs and unfavorable hydrology in Argentina.
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Matters Impacting Future International Energy Results
International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand, and fuel and commodity prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.
Certain of International Energy’s long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy’s outstanding local currency debt.
Year Ended December 31, 2006 as Compared to December 31,
Operating Revenues. The increase was driven primarily by:
•
A $118 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) and an increase in Egenor due to higher sales volumes, offset by lower prices;
•
A $40 million increase in El Salvador due to higher energy prices;
•
A $31 million increase in Brazil due to the strengthening of the Brazilian Real against the U.S. dollar and higher average energy prices, partially offset by lower volumes; and
•
A $27 million increase in Argentina primarily due to higher electricity generation, prices and increased gas marketing sales.
Operating Expenses. The increase was driven primarily by:
•
A $109 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia and increased purchased power and fuel costs in Egenor;
•
A $100 million increase due to a reserve established as a result of a settlement made in conjunction with the Citrus litigation;
•
A $38 million increase in El Salvador primarily due to higher fuel prices and increased fuel consumption;
•
A $34 million increase in Brazil due to the strengthening of the Brazilian Real against the U.S. dollar, increased regulatory fees, and purchased power costs; and
•
A $33 million increase in Mexico due to an impairment of a note receivable from Campeche.
Other Income and expenses, net. The decrease was primarily driven by a $26 million decrease in NMC due to lower MTBE margins and unplanned outages and a $12 million decrease as a result of consolidation of Aguaytia in 2006.
EBIT. The decrease in EBIT was primarily due to a litigation provision, an impairment in Mexico, lower margins at NMC, higher purchased power costs in Egenor, offset by favorable hydrology and pricing in Argentina.
Crescent(a)
(a) In September 2006, Duke Energy completed a joint venture transaction at Crescent and deconsolidated its investment in Crescent due to reduction in ownership and its inability to exercise control. As a result, Crescent segment data includes Crescent as a consolidated wholly-owned subsidiary of Duke Energy for periods prior to September 7, 2006, and as an equity investment for the periods subsequent to September 7, 2006 and represents Duke Energy’s 50% of equity earnings in Crescent.
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EBIT. The decrease was due primarily to a $246 million gain on the sale of ownership interests in Crescent in the third quarter 2006 (see Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”); significant gains in the second quarter 2006, primarily an approximate $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. and an approximate $52 million gain on a land sale at Lake Keowee in northwestern South Carolina; lower residential developed lot sales; a $32 million impairment charge recorded in equity earnings for the fourth quarter 2007 related to certain of Crescent’s residential developments; and the inclusion of approximately $29 million of interest expense in Crescent’s equity earnings for 2007 compared to $6 million for 2006. Prior to the deconsolidation of Crescent, interest expense was not included in Crescent’s segment EBIT.
Matters Impacting Future Crescent Results
Crescent’s results are subject to volatility due to factors including its management’s portfolio allocation decisions, the strength of the real estate markets, the cost of construction materials and changes in interest rates. As discussed above, during 2007 Crescent recorded impairment charges on certain of its properties. The impairment charges reflect the current economic conditions in Crescent’s markets and its management’s current plans for the properties in its portfolio. Changes in factors such as further or prolonged deterioration in market conditions or changes regarding the timing or method for disposition of properties could result in future impairments being recorded by Crescent.
Year Ended December 31, 2006 as Compared to December 31, 2005
Operating Revenues. The decrease was driven primarily by the deconsolidation of Crescent effective September 7, 2006, as well as a $272 million decrease in residential developed lot sales, primarily due to decreased sales at the LandMar division in Florida.
Operating Expenses. The decrease was driven primarily by the deconsolidation of Crescent effective September 7, 2006, as well as a $187 million decrease in the cost of residential developed lot sales as noted above and a $16 million impairment charge in 2005 related to a residential community in South Carolina (Oldfield).
Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by an $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. along with a $52 million land sale at Lake Keowee in northwestern South Carolina in 2006, partially offset by a $41 million land sale at Catawba Ridge in South Carolina in 2005, a $15 million gain on a land sale in Charlotte, North Carolina in 2005 and a $19 million gain on a project sale in Jacksonville, Florida in 2005.
(Losses) Gains on Sales of Other Assets and Other, net. The increase was due to an approximate $246 million pre-tax gain resulting from the sale of an effective 50% interest in Crescent.
Other Income and Expenses, net. The decrease is primarily due to $45 million in income related to a distribution from an interest in a portfolio of commercial office buildings in the third quarter of 2005.
EBIT. The increase was primarily due to the gain on sale of an ownership interest in Crescent, as noted above, as well as the sale of the Potomac Yard office buildings, partially offset by land and project sales in 2005 as discussed above.
Supplemental Data
Below is supplemental condensed summary financial information for Crescent stand-alone operating results subsequent to deconsolidation on September 7, 2006:
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Other
Year Ended December 31, 2007 as Compared to December 31, 2006
Operating Revenues. The increase was driven primarily by:
•
A $15 million increase related to revenues earned for services performed for Spectra Energy; and
•
A $14 million increase related to DETM, primarily driven by mark-to-market activity.
Operating Expenses. The decrease was driven primarily by:
•
A $110 million decrease related to contract settlement negotiations. Duke Energy was party to an agreement with a third party service provider related to certain future purchases. The agreement contained certain damage payment provisions if qualifying purchases were not initiated by September 2008. In the fourth quarter of 2006, Duke Energy initiated early settlement discussions regarding this agreement and recorded a reserve of approximately $65 million. During the year ended December 31, 2007, Duke Energy paid the third party service provider approximately $20 million, which directly reduced Duke Energy’s future exposure under the agreement, and further reduced the reserve by $45 million based upon qualifying purchase commitments that fulfilled Duke Energy’s obligations under the agreement;
•
A $74 million decrease in costs to achieve related to the Cinergy merger;
•
A $50 million decrease at Bison due primarily to lower charges for mutual insurance exit obligations of approximately $76 million, partially offset by higher operating expenses of approximately $26 million;
•
A $42 million decrease in governance and other corporate costs, including prior year shared services cost allocations to Spectra Energy not classified as discontinued operations; and
•
A $22 million decrease in amortization costs related to Crescent capitalized interest.
Partially offset by:
•
A $25 million increase due to a donation to the Duke Foundation, a non-profit organization funded by Duke Energy shareholders that makes charitable contributions to selected non-profits and governmental subdivisions; and
•
A $12 million increase related to employee severance costs.
Other Income and Expenses, net. The decrease was driven primarily by convertible debt charges of approximately $21 million related to the spin-off of Spectra Energy, partially offset by an increase in investment returns related to executive life insurance of $8 million.
EBIT. The improvement was due primarily to contract settlement negotiations, lower charges for mutual insurance exit obligations, the reduction of costs to achieve related to the Cinergy merger, lower governance and other corporate costs and a decrease in amortization costs related to Crescent capitalized interest, partially offset by an increase in captive insurance expenses, a donation to the Duke Foundation, convertible debt charges related to the spin-off of Spectra Energy and employee severance charges.
Matters Impacting Future Other Results
Future Other results may be subject to volatility as a result of losses insured by Bison and changes in liabilities associated with mutual insurance companies and the wind-down of DETM.
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Year Ended December 31, 2006 as Compared to December 31, 2005
Operating Revenues. The decrease was driven primarily by:
•
A $43 million decrease due to the sale of DPSG in February 2006; and
•
A $21 million decrease due to a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast.
Operating Expenses. The increase was driven primarily by:
•
A $128 million increase due to costs-to-achieve in 2006 related to the Cinergy merger;
•
A $65 million increase due to a charge in 2006 related to contract settlement negotiations; and
•
A $14 million increase in corporate governance and other costs due primarily to the merger with Cinergy in April 2006.
Partially offset by:
•
A $47 million decrease due to the continued wind-down of the former DENA businesses; and
•
A $45 million decrease due to the sale of DPSG.
EBIT. The decrease was due primarily to the increase in charges in 2006 associated with Cinergy merger and a charge for contract settlement negotiations.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The application of accounting policies and estimates is an important process that continues to evolve as Duke Energy’s operations change and accounting guidance evolves. Duke Energy has identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.
Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about Duke Energy’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Energy discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Energy’s critical accounting policies and estimates are discussed below.
Regulatory Accounting
Duke Energy accounts for certain of its regulated operations (primarily U.S. Franchised Electric and Gas) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. Generally Accepted Accounting Principles (GAAP) for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment, nuclear decommissioning costs and amortization of regulatory assets. Total regulatory assets were $2,645 million as of December 31, 2007 and $4,072 million as of December 31, 2006. Total regulatory liabilities were $2,674 million as of December 31, 2007 and $3,058 million as of December 31, 2006. Amounts at December 31, 2006 include balances related to the natural gas businesses that were spun off on January 2, 2007. For further information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”
Goodwill Impairment Assessments
At December 31, 2007 and 2006, Duke Energy had goodwill balances of $4,642 million and $8,175 million, respectively. Duke Energy evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). The majority of Duke Energy’s goodwill at December 31, 2007 relates to the acquisition of Cinergy in April 2006, whose assets are primarily included in
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the U.S. Franchised Electric and Gas and Commercial Power segments. The remainder relates to International Energy’s Latin American operations. Goodwill at December 31, 2006 included approximately $3,523 million which primarily related to the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002 and was included in the spin-off of the natural gas businesses in January 2007. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Duke Energy performs an annual goodwill impairment test and updates the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts, as well as other factors, into its revenue and expense forecasts. Duke Energy did not record any impairment on its goodwill as a result of the 2007, 2006 or 2005 impairment tests required by SFAS No. 142.
Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.
Revenue Recognition
Revenues on sales of electricity and gas, primarily at U.S. Franchised Electric and Gas, are recognized when either the service is provided or the product is delivered. Unbilled revenues are estimated by applying an average revenue/kilowatt hour or per thousand cubic feet (Mcf) for all customer classes to the number of estimated kilowatt hours or Mcf’s delivered but not billed. The amount of unbilled revenues can vary significantly period to period as a result of factors including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are recorded as Receivables in Duke Energy’s Consolidated Balance Sheets at December 31, 2007 and 2006 was approximately $380 million and $330 million, respectively. The amount at December 31, 2006 excludes unbilled revenues related to the natural gas businesses transferred in January 2007, as discussed above.
Accounting for Loss Contingencies
Duke Energy is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its consolidated financial statements, management makes judgments regarding the future outcome of contingent events and records a loss contingency based on the accounting guidance set forth in SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5), which requires a loss contingency to be recognized when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. Management regularly reviews current information available to determine whether such accruals should be adjusted and whether new accruals are required. Estimating probable losses requires analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, state and local courts and other regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the consolidated financial statements may differ from the actual outcome once the contingency is resolved, which could have a material impact on future results of operations, financial position and cash flows of Duke Energy.
Duke Energy has experienced numerous claims for indemnification and medical cost reimbursement relating to damages for bodily injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas on its electric generation plants prior to 1985.
Amounts recognized as asbestos-related reserves related to Duke Energy Carolinas in the Consolidated Balance Sheets totaled approximately $1,082 million and $1,159 million as of December 31, 2007 and 2006, respectively, and are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities. These reserves are based upon the minimum amount in Duke Energy’s best estimate of the range of loss of $1,082 million to $1,350 million for current and future asbestos claims through 2027. The reserves balance of $1,082 million as of December 31, 2007 consists of approximately $182 million related to known claimants and approximately $900 million related to unknown claimants. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe that we can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change our estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters
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into the future and numerous other factors outside Duke Energy Carolinas’ control, management believes that it is reasonably possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves. While it is reasonably possible that such excess liabilities could be material to operating results in any given quarter or year, management does not believe that such excess liabilities would have a material adverse effect on Duke Energy’s long-term results of operations, liquidity, or consolidated financial position.
Duke Energy has a third-party insurance policy to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Through December 31, 2007, Duke Energy has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy considers the existence of uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier, and is not aware of such uncertainties as of December 31, 2007.
For further information, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”
Accounting for Income Taxes
Duke Energy accounts for income taxes under SFAS No. 109, “Accounting For Income Taxes,” (SFAS No. 109) and FIN 48. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the book basis and tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. If future utilization of deferred tax assets is uncertain, Duke Energy may record a valuation allowance against certain deferred tax assets.
Prior to the adoption of FIN 48 on January 1, 2007, Duke Energy recorded tax contingencies based on the accounting guidance set forth in SFAS No. 5, which requires a contingency to be both probable and reasonably estimable for a loss to be recorded. Upon adoption of FIN 48, Duke Energy began recording unrecognized tax benefits for positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, when a more-likely-than-not threshold is met for a tax position and management believes that the position will be sustained upon examination by the taxing authorities. In accordance with FIN 48, Duke Energy records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in the Consolidated Financial Statements. Management reevaluates tax positions each period in which new information about recognition or measurement becomes available.
Significant management judgment is required in determining Duke Energy’s provision for income taxes, deferred tax assets and liabilities and the valuation recorded against Duke Energy’s net deferred tax assets, if any. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, Duke Energy’s forecasted financial condition and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. Although management believes current estimates are reasonable, actual results could differ from these estimates.
For further information, see Note 6 to the Consolidated Financial Statements, “Income Taxes.”
Pension and Other Post-Retirement Benefits
Duke Energy accounts for its defined benefit pension plans using SFAS No. 87, “Employers’ Accounting for Pensions,” (SFAS No. 87) and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” (SFAS No. 158). Under SFAS No. 87, pension income/expense is recognized on an accrual basis over employees’ approximate service periods. Other post-retirement benefits are accounted for using SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (SFAS No. 106).
In accordance with the measurement date provision of SFAS No. 158, in 2007, Duke Energy changed its measurement date from September 30 to December 31.
Funding requirements for defined benefit (DB) plans are determined by government regulations, not SFAS No. 87. Duke Energy made voluntary contributions to its DB retirement plans of $350 million in 2007, $124 million in 2006 and zero in 2005. Duke Energy does not anticipate making a contribution to its DB retirement plans in 2008. Additionally, during 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans.
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The calculation of pension expense, other post-retirement benefit expense and Duke Energy’s pension and other post-retirement liabilities require the use of assumptions. Changes in these assumptions can result in different expense and reported liability amounts, and future actual experience can differ from the assumptions. Duke Energy believes that the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate. Additionally, medical and prescription drug cost trend rate assumptions are critical to Duke Energy’s estimates of other post-retirement benefits. The prescription drug trend rate assumption resulted from the effect of the Medicare Prescription Drug Improvement and Modernization Act (Modernization Act).
Duke Energy Plans
Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain non-contributory defined benefit retirement plans (Plans). The Plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain executives.
Duke Energy and most of its subsidiaries also provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
Duke Energy recognized pre-tax qualified pension cost of $80 million, pre-tax non-qualified pension cost of $14 million and pre-tax other post-retirement benefits cost of $85 million in 2007. In 2008, Duke Energy’s qualified pension cost is expected to be approximately $40 million lower than in 2007 as a result of the 2007 contribution to the qualified plans, non-qualified pension cost is expected to remain approximately the same as 2007 and other post-retirement benefits cost is expected to be approximately $27 million lower than in 2007 as a result of the aforementioned voluntary contribution to the other post-retirement benefit plans.
For both pension and other post-retirement plans, Duke Energy assumed that its plan’s assets would generate a long-term rate of return of 8.5% as of December 31, 2007. The assets for Duke Energy’s pension and other post-retirement plans are maintained in a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate.
The expected long-term rate of return of 8.5% for the plan’s assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.3% for U.S. equities, 1.7% for Non U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.
If Duke Energy had used a long-term rate of 8.25% in 2007, pre-tax pension expense would have been higher by approximately $9 million and pre-tax other post-retirement expense would have been higher by less than $1 million. If Duke Energy had used a long-term rate of 8.75% pre-tax pension expense would have been lower by approximately $9 million and pre-tax other post-retirement expense would have been lower by less than $1 million.
Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 6.00% as of December 31, 2007. Duke Energy discounted its future U.S. pension and other post-retirement obligations using rates of 5.75% as of September 30, 2006 for its non-legacy Cinergy business pension plans and 6.00% as of April 1, 2006 for its legacy Cinergy business pension plans. For legacy Cinergy plans, the discount rate reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy. Duke Energy determines the appropriate discount based on AA bond yields. The yield is selected based on bonds with cash flows that are similar to the timing and amount of the expected benefit payments under the plan. Lowering the discount rates by 0.25% would have decreased Duke Energy’s 2007 pre-tax pension expense by approximately $2 million. Increasing the discount rates by 0.25% would have increased Duke Energy’s 2007 pre-tax pension expense by approximately $2 million. Lowering the discount rates by 0.25% would have increased Duke Energy’s 2007 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% would have decreased Duke Energy’s 2007 pre-tax other post-retirement expense by less than approximately $1 million.
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Duke Energy’s U.S. post-retirement plan uses a medical care trend rate which reflects the near and long-term expectation of increases in medical health care costs. Duke Energy’s U.S. post-retirement plan uses a prescription drug trend rate which reflects the near and long-term expectation of increases in prescription drug health care costs. As of December 31, 2007, the medical care trend rates were 8.00%, which grades to 5.00% by 2013. As of December 31, 2007, the prescription drug trend rate was 12.50%, which grades to 5.00% by 2022. If Duke Energy had used health care trend rates one percentage point higher, pre-tax other post-retirement expense would have been higher by $5 million. If Duke Energy had used health care trend rates one percentage point lower, pre-tax other post-retirement expense would have been lower by $4 million.
Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact Duke Energy’s future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future.
For further information, see Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans.”
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
At December 31, 2007, Duke Energy had cash, cash equivalents and short-term investments of approximately $1.1 billion, partially offset by approximately $742 million of short-term notes payable and commercial paper. During 2008, Duke Energy will rely primarily upon cash flows from operations, borrowings and its existing cash, cash equivalents and short-term investments to fund its liquidity and capital requirements. The relatively stable operating cash flows of the U.S. Franchised Electric and Gas business segment compose a substantial portion of Duke Energy’s cash flows from operations and it is anticipated that they will continue to do so for the next several years. A material adverse change in operations, or in available financing, could impact Duke Energy’s ability to fund its current liquidity and capital resource requirements.
Ultimate cash flows from operations are subject to a number of factors, including, but not limited to, regulatory constraints, economic trends, and market volatility (see Item 1A. “Risk Factors” for details).
Duke Energy projects 2008 capital and investment expenditures of approximately $5.1 billion, primarily consisting of:
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$3.9 billion at U.S. Franchised Electric and Gas
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$0.6 billion at Commercial Power
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$0.4 billion at International Energy and
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$0.2 billion at Other
Duke Energy continues to focus on reducing risk and positioning its business for future success and will invest principally in its strongest business sectors with an overall focus on positive net cash generation. Based on this goal, approximately 75 percent of total projected 2008 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2008 capital and investment expenditures include approximately $1.7 billion for system growth, $1.5 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.5 billion of environmental expenditures, and approximately $0.2 billion of nuclear fuel.
As a result of Duke Energy’s significant commitment to modernize its generating fleet through the construction of new units, as well as its focus on increasing its renewable energy portfolio, the ability to cost effectively manage the construction phase of current and future projects is critical to ensuring full and timely recovery of costs of construction. Should Duke Energy encounter significant cost overruns above amounts approved by the various state commissions, and those amounts are disallowed for recovery in rates, future cash flows could be adversely impacted.
Duke Energy anticipates its debt to total capitalization ratio to be approximately 40% by the end of 2008, as compared to approximately 35% at the end of 2007. This increase is primarily due to expected debt issuances in 2008, primarily to fund capital expenditures. Duke Energy expect its total debt balance (including outstanding commercial paper balances) to increase approximately $2.6 billion in 2008. Additionally, Duke Energy has expected debt retirements of approximately $2.0 billion in 2008, which includes scheduled maturities of approximately $1.5 billion and approximately $0.5 billion of early retirements of long-term debt that are expected to be refinanced. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage bonds. Proceeds from the issuance will be used to fund capital expenditures and general corporate purposes, including the repayment of commercial paper.
Based upon anticipated 2008 cash flows from operations, capital expenditure and dividend payments, Duke Energy expects to increase outstanding commercial paper balances during 2008; however, Duke Energy expects that the current total available capacity under its commercial paper facilities to be sufficient to meet any additional commercial paper requirements.
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Due to recent financial market developments, including certain liquidity issues within the short-term investment markets and a series of write-downs by some companies in the values of their investments in subprime U.S. mortgage-related assets, Duke Energy performed an assessment to determine the impact, if any, of current market developments on Duke Energy’s financial position.
As of December 31, 2007 and late February 2008, there were no investments in subprime mortgage-related assets within Duke Energy’s short-term investment balances. As of December 31, 2007, Duke Energy held approximately $430 million of investments in auction rate debt securities, substantially all of which were sold at auction in January 2008 at full principal amounts. Duke Energy made new investments in auction rate debt securities in January and February 2008, and as of late-February 2008, Duke Energy holds approximately $300 million of investments in auction rate debt securities. The vast majority of these investments are in U.S. Federal government backed student loans. As a result of the aforementioned credit market developments, these investments, which historically have provided short-term liquidity through a periodic auction process, have become increasingly illiquid as a result of failed auctions. Auction rate securities are designed such that interest rates on these instruments reset periodically through an auction process, so long as demand for the debt at the auction date is sufficient to cover the amount being submitted by the existing holders for auction. In the event demand is less than the amount being auctioned, a failed auction would occur and Duke Energy would begin receiving a higher interest rate on its investments in the auction rate debt at the failed-auction interest rate. As a result of recent auction failures, it is necessary for Duke Energy to hold these investments for longer periods of time than the historical short-term holding periods. However, Duke Energy does not currently believe there is any significant risk of credit default by the issuers and Duke Energy expects to be able to liquidate its holdings in the future at amounts approximating their current book value.
Duke Energy also performed an assessment of its investments held in trusts, including those that will be used to satisfy future obligations under its pension and other post-retirement benefit plans and future obligations to decommission Duke Energy Carolinas nuclear plants. Based on this assessment, it has been determined that an insignificant portion of the holdings within the trusts are directly invested in subprime mortgage-related assets or auction rate debt securities. Duke Energy does not believe that any decline in the fair value of these subprime mortgage-related assets or auction rate debt securities will have a material impact on its results of operations or its future cash funding requirements. Refer to Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information on the investment objectives of Duke Energy with respect to its pension and other post-retirement benefit plan assets, and to Item 1A. Risk Factors.
As of December 31, 2007 and mid-February 2008, Duke Energy had approximately $880 million of auction rate pollution control bonds outstanding. While these debt instruments are long-term in nature and cannot be put back to Duke Energy prior to maturity, the interest rates on these instruments are designed to reset periodically through an auction process. In February 2008, Duke Energy began to experience failed auctions for a portion of these debt instruments. When failed auctions occur on a series of this debt, Duke Energy is required to begin paying a failed-auction interest rate on the instrument. The failed-auction interest rate for the majority of the auction rate debt is 1.75 times one-month LIBOR. Payment of the failed-auction interest rates will continue until Duke Energy is able to either successfully remarket these instruments through the auction process or refund and refinance the existing debt through the issuance of an equivalent amount of tax exempt bonds. Duke Energy is currently pursuing a refunding and refinancing plan, which is subject to approval by applicable state or county financing authorities and utility regulators. If Duke Energy is unable to successfully refund and refinance these debt instruments, the impact of paying higher interest rates on the outstanding auction rate debt is not expected to materially effect Duke Energy’s overall financial position, results of operations or cash flows.
Further, at this time, Duke Energy does not believe the recent market developments significantly impact its ability to obtain financing and fully expects to have access to liquidity in the capital markets at reasonable rates and terms. Additionally, Duke Energy has access to unsecured revolving credit facilities, which are not restricted upon general market conditions, with aggregate bank commitments of approximately $2.65 billion, of which a portion is currently committed primarily to backstop Duke Energy’s commercial paper program.
Duke Energy monitors compliance with all debt covenants and restrictions and does not currently believe it will be in violation or breach of its debt covenants during 2008. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Energy also maintains an active dialogue with the credit rating agencies.
Operating Cash Flows
Net cash provided by operating activities was $3,208 million in 2007, compared to $3,748 million in 2006, a decrease in cash provided of $540 million. The decrease in cash provided by operating activities was driven primarily by:
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The spin-off of the natural gas businesses on January 2, 2007,
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The deconsolidation of Crescent in September 2006, and
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A $250 million increase in contributions to Duke Energy’s pension plan and other post retirement benefit plans in 2007, partially offset by
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The impact of a full year of Cinergy operations in 2007 compared to nine months in 2006.
Net cash provided by operating activities was $3,748 million in 2006 compared to $2,818 million in 2005, an increase in cash provided of $930 million. The increase in cash provided by operating activities was due primarily to the following:
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The impacts of the merger with Cinergy, effective April 3, 2006, partially offset by
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An approximate $400 million decrease due to the net settlement of the remaining former DENA contracts during 2006.
Investing Cash Flows
Net cash used in investing activities was $2,151 million in 2007, $1,328 million in 2006, and $126 million in 2005.
The primary use of cash related to investing activities is capital and investment expenditures, detailed by reportable business segment in the following table.
Capital and Investment Expenditures by Business Segment
(a) Amounts include capital expenditures associated with North Carolina clean air legislation of $418 million in 2007, $403 million in 2006 and $310 million in 2005, which are included in Capital Expenditures within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows.
(b) On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses. The natural gas businesses spun off primarily consisted of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DCP Midstream, which was part of the Field Services business segment.
(c) Field Services amounts for 2005 only include capital and investment expenditures for periods prior to deconsolidation on July 1, 2005.
(d) Crescent amounts for 2006 only include capital and investment expenditures for periods prior to deconsolidation on September 7, 2006. Additionally, amounts include capital expenditures associated with residential real estate of $322 million for the period from January 1, 2006 through the date of deconsolidation and $355 million in 2005, which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows.
The increase in cash used in investing activities in 2007 as compared to 2006 is primarily due to the following:
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Approximately $1.6 billion in proceeds received from the sale of former DENA assets in 2006,
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Approximately $700 million in proceeds received from the sale of Cinergy commercial marketing and trading operations in 2006,
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Approximately $380 million in proceeds received from the sale of an effective 50% interest in Crescent in 2006,
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An approximate $250 million decrease in proceeds from the sales of commercial and multi-family real estate due to the deconsolidation of Crescent in September 2006, and
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Approximately $150 million of cash received in 2006 as part of the Cinergy merger.
These increases in cash used were partially offset by the following:
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An approximate $1.8 billion increase in proceeds from available-for sale securities, net of purchases, and
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An approximate $470 million decrease in capital and investment expenditures, in part reflecting the spin-off of the natural gas businesses on January 2, 2007.
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The increase in cash used in investing activities in 2006 as compared to 2005 is primarily due to the following:
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Increased capital and investment expenditures of $1,090 million, excluding Crescent’s residential real estate investment, primarily as a result of capital expenditures at U.S. Franchised Electric and Gas, in large part due to the acquisition of Cinergy in April 2006, the acquisition of the Rockingham facility in 2006 and increased expenditures associated with North Carolina clean air legislation, and,
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Increased purchases of short-term investments of approximately $900 million in 2006 as compared to 2005, due primarily to the proceeds from the Crescent debt financing.
These increases were partially offset by the following:
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An increase in proceeds received from asset sales in 2006 as compared to 2005. Asset sales activity in 2006 of approximately $2.9 billion primarily involved the disposal of the former DENA remaining operations outside of the Midwestern United States, CMT, as well as the Crescent JV transaction. Asset sales activity in 2005 of approximately $2.4 billion primarily involved the disposition of the investments in TEPPCO as well as the DCP Midstream disposition transaction.
Financing Cash Flows and Liquidity
Duke Energy’s consolidated capital structure as of December 31, 2007, including short-term debt, was 35% debt, 1% minority interest and 64% common equity. The fixed charges coverage ratio, calculated using SEC guidelines, was 3.7 times for 2007, 2.6 times for 2006, which includes a pre-tax gain of approximately $250 million on the sale of an effective 50% interest in Crescent, and 2.4 times for 2005.
Net cash used in financing activities was $1,327 million in 2007 compared to $1,961 million in 2006, a decrease of $634 million. The change was due primarily to the following:
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An approximate $500 million decrease in cash used due to the repurchase of common shares in 2006,
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An approximate $400 million decrease in dividends paid as a result of the spin-off of Spectra Energy, and
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An approximate $1,030 million increase in net proceeds in 2007 from the issuance of notes payable and commercial paper.
These increases were partially offset by:
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An approximate $700 million decrease in proceeds from issuances of long-term debt, net of redemptions,
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An approximate $400 million distribution of cash in 2007 as a result of the spin-off of Spectra Energy,
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An approximate $110 million decrease in cash due to the repurchase of senior convertible notes in 2007, and
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An approximate $100 million decrease in proceeds from the Duke Energy Income Fund.
Net cash used in financing activities was $1,961 million in 2006 compared to $2,717 million in 2005, a decrease of $756 million. The change was due primarily to the following:
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An approximate $1.1 billion increase in proceeds from the issuance of long-term debt in 2006, net of redemptions, due primarily to the approximate $1.2 billion of debt proceeds from the Crescent JV transaction, and
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An approximate $400 million decrease in share repurchases under Duke Energy’s share repurchase plan.
These increases were partially offset by:
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An approximate $400 million increase in dividends paid due to the increase in the quarterly dividend paid per share combined with a larger number of shares outstanding, primarily attributable to the 313 million shares issued in connection with the Cinergy merger, and
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The repayment of approximately $400 million of notes payable and commercial paper in 2006 due primarily to proceeds received from asset sales.
At December 31, 2007, Duke Energy had cash, cash equivalents and short-term investments of approximately $1.1 billion, partially offset by approximately $742 million of short-term notes payable and commercial paper. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, the proceeds from which will be used to fund capital expenditures and general corporate purposes, including the repayment of commercial paper.
Significant Financing Activities-Year Ended 2007. On January 2, 2007, Duke Energy completed the spin-off of the natural gas businesses. In connection with this transaction, Duke Energy distributed all the shares of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy stock for each share of Duke
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Energy stock. Additionally, dividends paid on Duke Energy common stock during 2007 of approximately $1,089 million were less than the 2006 dividends paid of approximately $1,488 million as dividends subsequent to the spin-off were split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximated the former total dividend of Duke Energy.
On May 15, 2007, substantially all of the holders of the Duke Energy convertible senior notes required Duke Energy to repurchase the balance then outstanding at a price equal to 100% of the principal amount plus accrued interest. In May 2007, Duke Energy repurchased approximately $110 million of the convertible senior notes.
In June 2007, Duke Energy Carolinas issued $500 million principal amount of 6.10% senior unsecured notes due June 1, 2037. The net proceeds from the issuance were used to redeem commercial paper that was issued to repay the outstanding $249 million 6.6% Insured Quarterly Senior Notes due 2022 on April 30, 2007, and approximately $110 million of convertible debt discussed above. The remainder was used for general corporate purposes.
In November 2007, Duke Energy Carolinas issued $100 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2040. The initial interest rate was set at 3.65%. The bonds were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Belews Creek and Allen Steam Stations.
In December 2007, Duke Energy Ohio issued $140 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2041. The initial interest rate was set at 4.85%. The bonds were issued through the Ohio Air Quality Development Authority to fund a portion of the environmental capital expenditures at the Conesville, Stuart and Killen Generation Stations in Ohio.
Significant Financing Activities-Year Ended 2006. During the year ended December 31, 2006, Duke Energy increased the portion of outstanding commercial paper and pollution control bond balances classified as long-term from $472 million to $929 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these balances along with Duke Energy’s intent to refinance such balances on a long-term basis.
During 2006, Duke Energy repurchased approximately 17.5 million shares of its common stock for approximately $500 million and paid dividends of approximately $1,488 million. Also, during the year ended December 31, 2006, approximately $632 million of convertible senior notes were converted into approximately 27 million shares of Duke Energy Common Stock.
In November 2006, Union Gas Limited (Union Gas) issued 4.85% fixed-rate debenture bonds denominated in 125 million Canadian dollars (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022. This debt was included in the spin-off of the natural gas businesses in January 2007.
In October 2006, Duke Energy Carolinas issued $150 million in tax-exempt floating-rate bonds. The bonds are structured as variable-rate demand bonds, subject to weekly remarketing and bear a final maturity of 2031. The initial interest rate was set at 3.72%. The bonds are supported by an irrevocable 3-year direct-pay letter of credit and were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Marshall and Belews Creek Steam Stations.
In September 2006, prior to the completion of the partial sale of Crescent to the MS Members as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” Crescent issued approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a Financing Activity on the Consolidated Statements of Cash Flows. As a result of Duke Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’s Consolidated Balance Sheets.
In September 2006, Union Gas entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%. This debt was included in the spin-off of the natural gas businesses in January 2007.
In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units at a price of 12.15 Canadian dollars per Trust Unit for total proceeds of 104 million Canadian dollars, net of commissions and expenses of other expenses of issuance. The sale of approximately 9 million Trust Units reduced Duke Energy’s ownership interest in the Income Fund to approximately 46% at December 31, 2006. The Income Fund was included in the spin-off of the natural gas businesses in January 2007.
In August 2006, Duke Energy Kentucky issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio. Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.
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In June 2006, Duke Energy Indiana issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.
Significant Financing Activities-Year Ended 2005. During 2005, Duke Energy repurchased approximately 32.6 million shares of its common stock for approximately $933 million and paid dividends of approximately $1,105 million. Also, during the year ended December 31, 2005, approximately $28 million of convertible senior notes were converted into approximately 1 million shares of Duke Energy Common Stock.
In December 2005, the Income Fund, a Canadian income trust fund, was created which sold approximately 40% ownership in the Canadian Midstream operations for proceeds, net of underwriting discount, of approximately $110 million. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million. As discussed above, the Income Fund was included in the spin-off of the natural gas businesses in January 2007.
In December 2005, Duke Energy redeemed all Preferred and Preference stock without Sinking Fund Requirements for approximately $137 million and recognized an immaterial loss on the redemption.
In November 2005, International Energy issued floating rate debt in Guatemala for $87 million and in El Salvador for $75 million. These debt issuances have variable interest rate terms and mature in 2015.
On September 21, 2005, Union Gas entered into a fixed-rate financing agreement denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016 with an interest rate of 4.64%. This debt was included in the spin-off of the natural gas businesses in January 2007.
In August 2005, International Energy issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.
On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.
In December 2004, Duke Energy reached an agreement to sell its partially completed Gray’s Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC. In 2004, Duke Energy terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.
Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2007, Duke Energy’s consolidated credit capacity decreased by approximately $1,468 million as a result of the spin-off of the natural gas businesses on January 2, 2007. In June 2007, Duke Energy closed on the syndication of an amended and restated credit facility, replacing the existing credit facilities totaling $2.65 billion with a 5-year, $2.65 billion master credit facility. Concurrent with the syndication of the master credit facility, Duke Energy established a new $1.5 billion commercial paper program at Duke Energy and terminated Cinergy’s previously existing commercial paper program. In addition, the commercial paper program at Duke Energy Carolinas was increased from $650 million to $700 million. For further information on Duke Energy’s credit facilities as of December 31, 2007, see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.”
Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2007, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.
Credit Ratings. Duke Energy and certain subsidiaries each hold credit ratings by S&P and Moody’s Investors Service (Moody’s).
In May 2007, S&P upgraded Duke Energy and all its subsidiaries as a result of Duke Energy’s significant reduction in business risk, primarily through the disposal of its trading and marketing operations and merchant generation. In addition, S&P withdrew its rating on DETM.
In January 2008, Moody’s changed the rating outlook on Duke Energy, Duke Energy Carolinas, Cinergy, Duke Energy Ohio and Duke Energy Kentucky to stable from positive, while affirming the existing ratings in the below table of each of these entities.
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The following table summarizes the February 1, 2008 credit ratings from the agencies retained by Duke Energy and its principal funding subsidiaries.
Credit Ratings Summary as of February 1, 2008
Standard
and
Poor’s
Moody’s
Investors
Service
Duke Energy Corporation(a)
A-
Baa2
Duke Energy Carolinas, LLC(b)
A-
A3
Cinergy Corp.(b)
BBB+
Baa2
Duke Energy Ohio, Inc.(b)
A-
Baa1
Duke Energy Indiana, Inc.(b)
A-
Baa1
Duke Energy Kentucky, Inc.(b)
A-
Baa1
(a) Represents corporate credit rating and issuer rating for S&P and Moody’s respectively
(b) Represents senior unsecured credit rating
Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and pay dividends on its common stock, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted.
Clauses. Duke Energy may be required to repay certain debt should the credit ratings of Duke Energy Carolinas fall to a certain level at S&P or Moody’s. As of December 31, 2007, Duke Energy had $10 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $21 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s.
Other Financing Matters. In October 2007, Duke Energy filed a registration statement (Form S-3) with the SEC. Under this Form S-3, which is uncapped, Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana may issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings. The registration statement also allows for the issuance of common stock by Duke Energy.
Duke Energy has paid quarterly cash dividends for 82 consecutive years and expects to continue its policy of paying regular cash dividends in the future. There is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, financial condition and are subject to the discretion of the Board of Directors. It is currently anticipated that dividends per share will increase $0.01 per share beginning in the third quarter of 2008.
Duke Energy issues shares of its common stock to meet certain employee benefit and long-term incentive obligations. Proceeds from issuances of common stock related to employee benefits, primarily employee exercises of stock options, were approximately $50 million in 2007, approximately $127 million in 2006 and approximately $41 million for 2005.
Off-Balance Sheet Arrangements
Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, guarantees of debt, surety bonds and indemnifications. In contemplation of the spin-off of the natural gas businesses on January 2, 2007, certain guarantees that had been issued by Spectra Energy Capital were transferred to Duke Energy prior to the consummation of the spin-off. This resulted in Duke Energy recording an immaterial liability for certain guarantees that were previously grandfathered under the provisions of FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others,” and, therefore, had not been recognized in the Consolidated Balance Sheets. Guarantees issued by Spectra Energy Capital or its subsidiaries on or prior to December 31, 2006 remained with Spectra Energy Capital subsequent to the spin-off, except for certain guarantees that are in the process of being assigned to Duke Energy. During this assignment period, Duke Energy has indemnified Spectra Energy Capital against any losses incurred under these guarantee obligations. See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.
Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke
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Energy, either on its own or on behalf of Spectra Energy Capital through the aforementioned indemnification agreements, having to honor its contingencies is largely dependent upon the future operations of the subsidiaries, investees and other third parties, or the occurrence of certain future events.
Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.
Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky have an agreement to sell certain of their accounts receivable and related collections to Cinergy Receivables Company LLC (Cinergy Receivables), which purchases, on a revolving basis, nearly all of the retail accounts receivable and related collections of Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. Cinergy Receivables is not consolidated by Duke Energy since it meets the requirements to be accounted for as a qualifying special purpose entity (SPE). Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky each retain an interest in the receivables transferred to Cinergy Receivables. The transfers of receivables are accounted for as sales, pursuant to SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” For a more detailed discussion of the sale of certain accounts receivable, see Note 22 to the Consolidated Financial Statements, “Variable Interest Entities.”
Duke Energy also holds interests in variable interest entities (VIEs), consolidated and unconsolidated, as defined by FIN No. 46R, “Consolidation of Variable Interest Entities.” For further information, see Note 22 to the Consolidated Financial Statements, “Variable Interest Entities”.
Other than the guarantee arrangements discussed above and normal operating lease arrangements, Duke Energy does not have any material off-balance sheet financing entities or structures. For additional information on these commitments, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”
Contractual Obligations
Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations for each of the periods presented. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2008.
Contractual Obligations as of December 31, 2007
(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount includes interest payments over life of debt or capital lease. Payment amounts exclude $900 million of debt issued by Duke Energy Carolinas in January 2008. Interest payments on variable rate debt instruments were calculated using interest rates derived from examination of the forward interest rate curve. In addition, a spread was placed on top of the interest rates to aid in capturing the volatility inherent in projecting future interest rates.
(b) See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”.
(c) Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity, and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some power locations throughout North America. Also includes firm capacity payments under electric power agreements entered into to meet U.S. Franchised Electric and Gas’ native load requirements.
(d) Includes contractual obligations to purchase physical quantities of electricity, coal and nuclear fuel. Amount includes certain normal purchases, energy derivatives and hedges per SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2007. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties.
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(e) Includes U.S. Franchised Electric and Gas’ obligation to purchase an additional ownership interest in the Catawba Nuclear Station (see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating and Transmission Facilities”), as well as contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for new generation plants and nuclear plant refurbishments, environmental projects on fossil facilities, and major maintenance of certain non-regulated plants. Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase can not be determined.
(f) Includes certain estimated executive benefit payments and contributions to the NDTF (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations”). The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Duke Energy may use internal resources or external resources to perform retirement activities. As a result, cash obligations for asset retirement activities are excluded. Asset retirement obligations recognized on the Consolidated Balance Sheets total $2,351 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,929 million at December 31, 2007. Amount excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing of when cash payments will be required. Additionally, amount excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of other post-employment benefits (see Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Additionally, amounts related to uncertain tax positions are excluded from the table due to uncertainty of timing of future payments.
(g) Current liabilities, except for current maturities of long-term debt, and purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table.
(h) Includes approximately $1.2 billion of anticipated remaining costs associated with an engineering, procurement and construction services agreement executed during 2007 with an affiliate of The Shaw Group, Inc., for participation in the construction of Cliffside Unit 6 and a flue gas desulfurization system at an existing unit at Cliffside. Duke Energy has the right to terminate this agreement at any time for its convenience, subject to customary cancellation and demobilization charges in accordance with terms of the agreement.
Quantitative and Qualitative Disclosures About Market Risk
Risk Management Policies
Duke Energy is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Finance and Risk Management Committee of the Board of Directors receives periodic updates from the Treasurer and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The Treasurer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.
Commodity Price Risk
Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy related assets. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including swaps, futures, forwards and options. For additional information, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”
Validation of a contract’s fair value is performed by an internal group separate from Duke Energy’s deal origination areas. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.
Hedging Strategies. Duke Energy closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, coal and natural gas forward contracts to mitigate the effect of such fluctuations on operations. Duke Energy’s primary use of energy commodity derivatives is to hedge the generation portfolio against exposure to the prices of power and fuel.
Certain derivatives used to manage Duke Energy’s commodity price exposure are accounted for as either cash flow hedges or fair value hedges. To the extent that instruments accounted for as hedges are effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations until delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. Several factors influence the effectiveness of a hedge contract, including the use of contracts with different commodities or unmatched terms and counterparty credit risk. Hedge effectiveness is monitored regularly and measured each month.
In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Energy enters into other contracts that qualify for the normal purchases and sales exception described in paragraph 10 of SFAS No. 133, as amended and interpreted by Derivatives Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments
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and Hedging Activities.” For contracts qualifying for the scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract unless the contract is designated as the hedged item in a fair value hedge. On a limited basis, U.S. Franchised Electric and Gas and Commercial Power apply the normal purchase and normal sales exception to certain contracts. Recognition for the contracts in the Consolidated Statements of Operations will be the same regardless of whether the contracts are accounted for as cash flow hedges or as normal purchases and sales, unless designated as the hedged item in a fair value hedge, assuming no hedge ineffectiveness.
Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. However, Duke Energy’s decision to reduce former DENA’s interest in partially completed plants and the decision in 2005 to sell or otherwise dispose of substantially all of former DENA’s remaining physical and commercial assets outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Normal Purchases and Normal Sales below) required the reassessment of all associated derivatives, including normal purchases and normal sales. This required a change from the application of the Accrual Model to the Mark-to-Market (MTM) Model for these contracts and resulted in recording substantial unrealized losses that had not previously been recognized in the Consolidated Statements of Operations.
Other derivatives used to manage Duke Energy’s commodity price exposure are either not designated as a hedge or do not qualify for hedge accounting and are therefore accounted for using the MTM Model. These instruments are referred to as undesignated contracts (see Undesignated Contracts below).
Generation Portfolio Risks. Duke Energy is primarily exposed to market price fluctuations of wholesale power, natural gas, and coal prices in the U.S. Franchised Electric and Gas and Commercial Power segments. Duke Energy optimizes the value of its bulk power marketing and non-regulated generation portfolios. The portfolios include generation assets (power and capacity), fuel, and emission allowances. The component pieces of the portfolio are bought and sold based on models and forecasts of generation in order to manage the economic value of the portfolio in accordance with the strategies of the business units. The generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations, although the impact on the Consolidated Statements of Operations reported earnings is partially offset by mechanisms in the regulated jurisdictions that result in the sharing of net profits from these activities with retail customers. Based on a sensitivity analysis as of December 31, 2007 and 2006, it was estimated that a ten percent price change per mega-watt hour in forward wholesale power prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $24 million in 2008 and would have had a $38 million impact in 2007, excluding the impact of mark-to-market changes on non-qualifying or undesignated hedges relating to periods in excess of one year from the respective date. Based on a sensitivity analysis as of December 31, 2007 and 2006, it was estimated that a ten percent price change per MMBtu in natural gas prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $9 million in 2008 and would have had a $15 million impact in 2007, excluding the impact of mark-to-market changes on undesignated hedges relating to periods in excess of one year from the respective date.
Normal Purchases and Normal Sales. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States, approximately 6,100 megawatts of power generation, and certain contractual positions related to the Midwestern assets (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). As a result of this decision, Duke Energy recognized a pre-tax loss of approximately $1.9 billion in the third quarter of 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss was partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges.
Undesignated Contracts. Undesignated contracts executed to manage generation portfolio risks are exposed to changes in fair value due to market price fluctuations of wholesale power and coal. Based on a sensitivity analysis as of December 31, 2007 and 2006, it was estimated that a ten percent price change in the forward price per megawatt hour of wholesale power would have a corresponding effect on Duke Energy’s pre-tax income of approximately $16 million in 2008 and would have had a $22 million impact in 2007, resulting from the impact of mark-to-market changes on non-qualifying and undesignated power contracts pertaining to periods in excess of one year from the respective date. Based on a sensitivity analysis as of December 31, 2007 and 2006, it was estimated that a ten percent change in the forward price per ton of coal would have a corresponding effect on Duke Energy’s pre-tax income of approximately $14 million in 2008 and would have had a $12 million impact in 2007, resulting from the impact of mark-to-market changes on non-qualifying and undesignated coal contracts pertaining to periods in excess of one year from the respective date.
Other Commodity Risks. At December 31, 2007 and 2006, pre-tax income in 2008 and 2007 was not expected to be materially impacted for exposures to other commodities’ price changes.
The commodity price sensitivity calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.
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Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.
Credit Risk
Credit risk represents the loss that Duke Energy would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Energy seeks to enter into netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. Duke Energy attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Duke Energy may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Energy’s counterparties’ obligations.
Duke Energy’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S. and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.
Duke Energy has a third-party insurance policy to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Through December 31, 2007, Duke Energy has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy is not aware of any uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier.
Based on Duke Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy does not anticipate a materially adverse effect on its consolidated financial position or results of operations as a result of non-performance by any counterparty.
During 2006, Duke Energy finalized the sale of the former DENA portfolio of derivative contracts to Barclays Bank PLC and sold the Cinergy commercial marketing and trading business to Fortis, which eliminated Duke Energy’s credit, collateral, market and legal risk associated with these related trading positions.
In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Spectra Energy Capital. Spectra Energy Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Spectra Energy Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of December 31, 2006 is approximately $200 million, including principal and interest payments. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2007, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2007. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Spectra Energy Capital has certain rights which should allow it to mitigate such loss. Subsequent to the spin-off the natural gas businesses, this guarantee remained with Spectra Energy Capital. However, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee. In January 2008, Calpine Corporation announced that it had successfully emerged from Chapter 11 bankruptcy protection and officially concluded its Chapter 11 reorganization.
Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.
Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
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Interest Rate Risk
Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable and fixed rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate exposures to a percentage of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, which may include instruments such as, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. See Notes 1, 8, and 15 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” and “Debt and Credit Facilities.”
Based on a sensitivity analysis as of December 31, 2007, it was estimated that if market interest rates average 1% higher (lower) in 2008 than in 2007, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $22 million. Comparatively, based on a sensitivity analysis as of December 31, 2006, had interest rates averaged 1% higher (lower) in 2006 than in 2005, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $3 million. These amounts were estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, short-term investments, cash and cash equivalents outstanding as of December 31, 2007 and 2006. The increase in interest rate sensitivity is primarily due to a decrease in cash and short-term investment balances and a net increase in commercial paper borrowings. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Energy’s financial structure.
Equity Price Risk
Duke Energy maintains trust funds, as required by the NRC and the NCUC, to fund the costs of nuclear decommissioning (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations.”) As of December 31, 2007 and 2006, these funds were invested primarily in domestic and international equity securities, debt securities, fixed-income securities, cash and cash equivalents and short-term investments. Per NRC and NCUC requirements, these funds may be used only for activities related to nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Accounting for nuclear decommissioning recognizes that costs are recovered through U.S. Franchised Electric and Gas’ rates, and fluctuations in equity prices or interest rates do not affect Duke Energy’s Consolidated Statements of Operations as changes in the fair value of these investments are deferred as regulatory assets or regulatory liabilities pursuant to an Order by the NCUC. Earnings or losses of the fund will ultimately impact the amount of costs recovered through U.S. Franchised Electric and Gas’ rates.
Bison, Duke Energy’s wholly owned captive insurance subsidiary, maintains investments to fund various business risks and losses, such as workers compensation, property, business interruption and general liability. Those investments are exposed to price fluctuations in equity markets and changes in interest rates.
Duke Energy maintains investments to help fund the costs of providing non-contributory defined benefit retirement and other post-retirement benefit plans. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Fluctuations in equity prices or interest rates could adversely affect Duke Energy’s consolidated financial position, results of operations and cash flows in future periods. See Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information on pension plan assets.
Foreign Currency Risk
Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations that are denominated in foreign currencies. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. Dollar and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.
In 2008, Duke Energy’s primary foreign currency rate exposures are expected to be the Brazilian Real and the Peruvian New Sol. A 10% devaluation in the currency exchange rates as of December 31, 2007 in all of Duke Energy’s exposure currencies would result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $10 million to Duke Energy’s Consolidated Statements of Operations in 2008. The Consolidated Balance Sheet would be negatively impacted by approximately $145 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2007 as a result of a 10% devaluation in the
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currency exchange rates. As of December 31, 2006, a 10% devaluation in the currency exchange rates in all of Duke Energy’s exposure currencies was expected to result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $7 million to Duke Energy’s Consolidated Statements of Operations and a reduction of approximately $120 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2007.
OTHER ISSUES
Energy Policy Act of 2005. The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 repeals the PUHCA of 1935, directs FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear reactors, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission projects, streamlines the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. In late 2005 and early 2006, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. Duke Energy is currently evaluating these proposals and does not anticipate that these rulemakings will have a material adverse effect on its consolidated results of operations, cash flows or financial position.
Global Climate Change. A body of scientific evidence now accepted by a growing majority of the public and policymakers suggests that the Earth’s climate is changing, caused in part by greenhouse gases emitted into the atmosphere from human activities. Although there is still much to learn about the causes and long-term effects of climate change, many advocate taking steps now to begin reducing emissions with the aim of stabilizing the atmospheric concentration of greenhouse gases at a level that avoids the potentially worst-case effects of climate change.
Greenhouse gas emissions are produced from a wide variety of human activities. The U.S. EPA publishes an inventory of these emissions annually. CO2, an essential trace gas, is a by-product of fossil fuel combustion and currently accounts for about 85% of U.S. greenhouse gas emissions. Duke Energy currently accounts for about 1.5% of total U.S. CO2 emissions, and about 1.3% of total U.S. greenhouse gas emissions.
Duke Energy is adding approximately 60,000 new customers annually to its customer base of nearly four million in the Carolinas and the Midwest and making long-term decisions for how best to meet its customers’ growing demand for electricity. Duke Energy is moving ahead on multiple fronts - energy efficiency, renewable energy, advanced nuclear power, advanced clean-coal and high-efficiency natural gas electric generating plants, and retirement of older less efficient coal-fired power plants. Duke Energy needs regulatory certainty regarding U.S. climate change policy as it makes these investment decisions.
Duke Energy’s cost of complying with any federal greenhouse gas emissions law that may be enacted will depend on the design details of the program. The major design elements of a greenhouse gas cap-and-trade program that will most influence Duke Energy’s compliance costs include the required levels and timing of the cap, which will drive emission allowance prices, the emission sources covered under the cap, the number of allowances that Duke Energy is allocated on a year-to-year basis, the type of and effectiveness of the cost control mechanism employed by the program, and the availability and cost of technologies that Duke Energy can deploy to lower its emissions. Although it is likely that Congress will adopt some form of mandatory greenhouse gas emission reduction legislation in the future, the timing and specific requirements of any such legislation are highly uncertain, which means that potential future compliance costs for Duke Energy are also highly uncertain.
The 110th Congress is currently considering several potential U.S. policy responses to the climate change issue. In 2007, nearly a dozen bills were introduced in the Senate calling for mandatory limits on U.S. greenhouse gas emissions through use of a cap-and-trade program. The key differences in the bills are the sources whose emissions would be regulated, the rate at which emissions would be required to be reduced, the number of emission allowances that would be distributed at no cost to sources whose emissions would be regulated, and the method of protecting the economy from potentially high and unexpected program costs.
On December 5, 2007, the Senate Environment and Public Works Committee reported out S. 2191 - America’s Climate Security Act of 2007 - sponsored by Senators Joseph Lieberman of Connecticut and John Warner of Virginia. The bill, which now awaits Senate floor action, proposes an economy-wide greenhouse gas reduction program to begin in 2012. Several bills have also been introduced in the House of Representatives but none has yet received subcommittee or committee approval. It is unlikely that legislation establishing a mandatory federal greenhouse gas emission reduction program will be enacted in 2008.
Duke Energy supports the enactment of federal greenhouse gas cap-and-trade legislation that would apply to all parts of the economy, including power generation, industrial and commercial sources, and motor vehicles. To permit the economy to adjust rationally to the policy, legislation should establish a long-term program that first slows the growth of emissions, stops them and then transitions to a gradually declining emissions cap as new lower-and non-emitting technologies are developed and become ready for wide-scale deployment.
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New technologies for reducing CO2 emissions from coal - chief among them carbon capture and sequestration - are not expected to be developed and ready for deployment by 2012 when the Lieberman-Warner legislation, if passed, would take effect. This would pose a challenge to Duke Energy’s ability to utilize all of its current coal-fired generating capacity if the legislation is enacted in its current form. This could challenge Duke Energy’s ability to meet the growing electricity demand of its customers at a reasonable cost. Duke Energy’s deployment of renewable generation, along with its customer energy-efficiency initiative would help, but would not be enough. If the cap is too stringent in the early years of the program, Duke Energy’s compliance options could be limited to purchasing emission allowances and/or relying on existing natural gas generation to replace coal generation. Achieving a large fuel switch from coal to natural gas in less than four years is not practical and, on a national scale, is not good public policy. Such a shift would significantly increase natural gas prices, posing an economic hardship to millions of natural gas customers.
Compliance cost estimates are very sensitive to various highly uncertain assumptions, including allowance prices. Under the proposed S. 2191 legislation, in addition to allowances allocated at no cost, Duke Energy currently estimates the costs of purchasing needed allowances to cover Duke Energy’s projected emissions in 2012 could range from approximately $930 million to $2.8 billion. Actual costs could be higher or lower than these estimates. Duke Energy would seek to recover its compliance costs through appropriate regulatory mechanisms in the jurisdictions in which it operates. Under a compliance scenario where Duke Energy continues to purchase allowances to meet its compliance obligation, annual allowance purchase costs would increase over time as the number of allowances Duke Energy is allocated under the proposed legislation decreases and allowance prices increase as the cap tightens.
At some point in the future it would be expected that Duke Energy would begin replacing existing coal-fired generation with new lower-and zero-emitting generation technologies, and/or installing new carbon capture and sequestration technology on existing coal-fired generating plants to reduce emissions when technologies become available. It is not possible at this time, however, to predict with certainty what new technologies might be developed, when they will be ready to be deployed, or what their costs will be. There is also uncertainty as to how or when certain non-technical issues that could affect the cost and availability of new technologies might be resolved by regulators. Duke Energy currently is focused on advanced nuclear generation, integrated gasification combined cycle generation with carbon capture and sequestration, and capture and storage retrofit technology for existing pulverized coal-fired generation as promising new technologies for generating electricity with lower or no CO2 emissions.
In addition to relying on new technologies to reduce its CO2 emissions, Duke Energy is seeking regulatory approval for a first-of-its-kind innovative approach in the utility industry to help meet growing customer demand with new and creative ways to increase energy efficiency, thereby reducing demand (save-a-watt) instead of relying almost exclusively on new power plants to generate electricity.
(For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”)
New Accounting Standards
The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of December 31, 2007:
SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. The application of SFAS No. 157 may change Duke Energy’s current practice for measuring fair values under other accounting pronouncements that require fair value measurements. For Duke Energy, SFAS No. 157 is effective as of January 1, 2008. In February 2008, the FASB issued FASB Staff Position (FSP) No. 157-2, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. Duke Energy does not expect to report any material cumulative-effect adjustment to beginning retained earning as is required by SFAS No. 157 for certain limited matters. Duke Energy continues to monitor additional proposed interpretative guidance regarding the application of SFAS No. 157. To date, no matters have been identified regarding implementation of SFAS No. 157 that would have any material impact on Duke Energy’s consolidated results of operations or financial position.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159). In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Duke Energy does not currently have any financial assets or financial liabilities for which the provisions of SFAS No. 159 have been elected. However, in the future, Duke Energy may elect to measure certain financial instruments at fair value in accordance with this standard.
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EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11). In June 2007, the EITF reached a consensus that would require realized income tax benefits from dividends or dividend equivalents that are charged to retained earnings and paid to employees for equity-classified nonvested equity shares, nonvested equity share units, and outstanding equity share options to be recognized as an increase to additional paid-in capital. In addition, EITF 06-11 would require that dividends on equity-classified share-based payment awards be reallocated between retained earnings (for awards expected to vest) and compensation cost (for awards not expected to vest) each reporting period to reflect current forfeiture estimates. For Duke Energy, EITF 06-11 must be applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning January 1, 2008, as well as interim periods within those fiscal years. Early application would be permitted as of the beginning of a fiscal year for which interim or annual financial statements have not yet been issued. Duke Energy is currently evaluating the impact of applying EITF 06-11, and cannot currently estimate the impact of EITF 06-11 on its consolidated results of operations, cash flows or financial position.
SFAS No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). In December 2007, the FASB issued SFAS No. 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting be used for all business combinations and that an acquirer be identified for each business combination. This statement also establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling (minority) interests in an acquiree, and any goodwill acquired in a business combination or gain recognized from a bargain purchase. For Duke Energy, SFAS No. 141R must be applied prospectively to business combinations for which the acquisition date occurs on or after January 1, 2009. The impact to Duke Energy of applying SFAS No. 141(R) for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of SFAS No. 141(R).
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS No. 160). In December 2007, the FASB issued SFAS No. 160, which amends ARB No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in a consolidated entity that should be reported as equity in the consolidated financial statements. This statement also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. In addition, SFAS No. 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. For Duke Energy, SFAS No. 160 is effective as of January 1, 2009, and must be applied prospectively, except for certain presentation and disclosure requirements which must be applied retrospectively. Duke Energy is currently evaluating the impact of adopting SFAS No. 160.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”
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Item 8.
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Duke Energy Corporation
Charlotte, North Carolina
We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, common stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Duke Energy Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As discussed in Note 1 to the consolidated financial statements, the Company’s spin-off of the natural gas business was completed on January 2, 2007.
/s/ DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 29, 2008
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DUKE ENERGY CORPORATION
Consolidated Statements of Operations
(In millions, except per-share amounts)
See Notes to Consolidated Financial Statements
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DUKE ENERGY CORPORATION
Consolidated Balance Sheets
(In millions)
See Notes to Consolidated Financial Statements
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DUKE ENERGY CORPORATION
Consolidated Balance Sheets-(Continued)
(In millions, except per-share amounts)
See Notes to Consolidated Financial Statements
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DUKE ENERGY CORPORATION
Consolidated Statements of Cash Flows
(In millions)
See Notes to Consolidated Financial Statements
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DUKE ENERGY CORPORATION
Consolidated Statements of Common Stockholders' Equity
and Comprehensive Income
(In millions)
(a) Foreign currency translation adjustments, net of $62 tax benefit in 2005. The 2005 tax benefit related to the settled net investment hedges. Substantially all of the 2005 tax benefit is a correction of an immaterial accounting error related to prior periods.
(b) Net unrealized gains (losses) on cash flow hedges, net of $9 tax benefit in 2007, $3 tax expense in 2006 and $233 tax expense in 2005.
(c) Reclassification into earnings from cash flow hedges, net of $19 tax expense in 2006, and $583 tax benefit in 2005. Reclassification into earnings from cash flow hedges in 2006 is due primarily to the recognition of former Duke Energy North America's (DENA) unrealized net gains related to hedges on forecasted transactions which did not occur as a result of the sale to LS Power of substantially all of former DENA's assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see notes 8 and 13).
(d) Minimum pension liability adjustment, net of $0 tax benefit in 2006 and $228 tax expense in 2005.
(e) SFAS No. 158 adjustment, net of $144 tax benefit in 2006. Excludes $595 reflected as regulatory assets (see note 21).
(f) Net of $9 tax benefit in 2006, and $10 tax expense in 2005.
(g) SFAS No. 158 net actuarial gain net of $54 tax expense in 2007. Excludes $204 reflected as regulatory assets (see note 21).
See Notes to Consolidated Financial Statements
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements
For the Years Ended December 31, 2007, 2006 and 2005
1. Summary of Significant Accounting Policies
Nature of Operations and Basis of Consolidation. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is an energy company located in the Americas. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. These Consolidated Financial Statements also reflect Duke Energy’s proportionate share of certain generation and transmission facilities in the Carolinas and the Midwest.
Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). As a result of the merger transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the year ended December 31, 2005. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 2). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy herein.
Shares of common stock of New Duke Energy carry a stated par value of $0.001, while shares of common stock of Old Duke Energy had been issued at no par. In April 2006, as a result of the conversion of all outstanding shares of Old Duke Energy common stock to New Duke Energy common stock, the par value of the shares issued was recorded in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets and the excess of issuance price over stated par value was recorded in Additional Paid-in Capital within Common Stockholders’ Equity in the Consolidated Balance Sheets. Prior to the conversion of common stock from shares of Old Duke Energy to New Duke Energy, all proceeds from issuances of common stock were solely reflected in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets.
On September 7, 2006, Duke Energy deconsolidated Crescent Resources, LLC (Crescent) due to a reduction in ownership causing an inability to exercise control over Crescent (see Note 2). Crescent has been accounted for as an equity method investment since the date of deconsolidation.
On January 2, 2007, Duke Energy completed the spin-off to shareholders of its natural gas businesses. The new natural gas business, which is named Spectra Energy Corp. (Spectra Energy), consists principally of certain operations of Spectra Energy Capital, LLC (Spectra Energy Capital, formerly Duke Capital LLC), primarily Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former Field Services business segment, which represented Duke Energy’s 50% ownership interest in DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) (DCP Midstream). See Note 13 for discussion of the deconsolidation of DCP Midstream effective July 1, 2005 due to a reduction in ownership interest. Excluded from the spin-off were certain operations which were transferred from Spectra Energy Capital to Duke Energy in December 2006, primarily International Energy and Duke Energy’s effective 50% interest in the Crescent JV. Subsequent to the spin-off, the results of operations of the spun off businesses are presented as discontinued operations in the accompanying Consolidated Statements of Operations for all periods prior to the spin-off. The primary businesses remaining in Duke Energy post-spin are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV. See Note 3 for further information on Duke Energy’s business segments.
Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. No gain or loss was recognized on the distribution of these operations to Duke Energy shareholders. Approximately $20.5 billion of assets, $14.9 billion of liabilities (which includes approximately $8.6 billion of debt) and $5.6 billion of common stockholders’ equity (which includes approximately $1.0 billion of accumulated other comprehensive income) were dis-
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
tributed from Duke Energy as of the date of the spin-off. Assets, liabilities and stockholders’ equity amounts at December 31, 2006 included in the accompanying Consolidated Balance Sheets and the corresponding Notes include balances that were transferred to Spectra Energy as part of the spin-off. Additionally, cash flows related to the businesses included in the spin-off are included in the Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005.
Use of Estimates. To conform to generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.
Reclassifications and Revisions. Certain prior period amounts have been reclassified within the Consolidated Financial Statements to conform to current year presentation.
Cash and Cash Equivalents. All highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents.
Restricted Cash. At December 31, 2007 and 2006, Duke Energy had approximately $166 million and $212 million, respectively, of restricted cash related primarily to proceeds from debt issuances that are held in trust for the purpose of funding future environmental construction or maintenance expenditures. This amount is reflected in Other Investments and Other Assets on the Consolidated Balance Sheets.
Short-term Investments. Duke Energy actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments have historically provided for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Energy intends to sell these instruments within one year or less, generally within 30 days from the balance sheet date, they are classified as current assets. Duke Energy has classified all short-term investments that are debt securities as available-for-sale under the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” (SFAS No. 115), and they are carried at fair market value. Investments in money-market preferred securities that do not have stated redemptions are accounted for at their cost, as the carrying values approximate market values due to their short-term maturities and minimal credit risk. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings as incurred. Purchases and sales of available-for-sale securities are presented on a gross basis within investing cash flows in the accompanying Consolidated Statements of Cash Flows.
Inventory. Inventory consists primarily of materials and supplies and natural gas held in storage for transmission, processing and sales commitments, and coal held for electric generation. Inventory is recorded primarily using the average cost method. The decrease in inventory at December 31, 2007 as compared to December 31, 2006 is primarily attributable to the spin-off of the natural gas businesses discussed above.
Components of Inventory
Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Energy uses a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities, including swaps, futures, forwards, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
amended (SFAS No. 133), are recorded on the Consolidated Balance Sheets at their fair value. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net investment hedges and other investing activities, are a component of operating cash flows in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are a component of financing cash flows in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows related to net investment hedges and derivatives related to other investing activities are a component of investing cash flows in the accompanying Consolidated Statements of Cash Flows.
Duke Energy designates all energy commodity derivatives as either trading or non-trading. Gains and losses for all derivative contracts that do not represent physical delivery contracts are reported on a net basis in the Consolidated Statements of Operations. For each of Duke Energy’s physical delivery contracts that are derivatives, the accounting model and presentation of gains and losses, or revenue and expense in the Consolidated Statements of Operations is shown below.
(a) An accounting term used by Duke Energy to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations. This term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within GAAP, Duke Energy’s application of this term could differ from that of other companies.
(b) An accounting term used by Duke Energy to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided, the associated delivery period occurs or there is hedge ineffectiveness. As discussed further below, this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within GAAP, Duke Energy’s application of this term could differ from that of other companies.
Where Duke Energy’s derivative instruments are subject to a master netting agreement and the criteria of the FASB Interpretation (FIN) No. 39, “Offsetting of Amounts Related to Certain Contracts-An Interpretation of Accounting Principles Board (APB) Opinion No. 10 and FASB Statement No. 105” (FIN 39), are met, Duke Energy presents its derivative assets and liabilities, and accompanying receivables and payables, separately on a net basis in the accompanying Consolidated Balance Sheets.
Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all contracts accounted for as a hedge, Duke Energy prepares formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and at least every three months thereafter, Duke Energy formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Energy documents hedging activity by transaction type (futures/swaps) and risk management strategy (commodity price risk/interest rate risk).
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged item. Duke Energy discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the Mark-to-Market model of accounting (MTM Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur, at which time associated deferred amounts in AOCI are immediately recognized in earnings.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
For derivatives designated as fair value hedges, Duke Energy recognizes the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings, to the extent effective, in the current period. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.
Normal Purchases and Normal Sales. On a limited basis, Duke Energy applies the normal purchase and normal sales exception to certain contracts. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for using the MTM Model unless immediately designated as a cash flow or fair value hedge.
As a result of the September 2005 decision to pursue the sale or other disposition of substantially all of former Duke Energy North America’s (DENA) remaining physical and commercial assets outside the Midwestern United States, Duke Energy discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges related to the former DENA operations and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September 2005. As discussed further in Note 13, the impacts of the discontinuance of hedge accounting are included in (Loss) Income from Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
Valuation. When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed valuation techniques or models. For derivatives recognized under the MTM Model, valuation adjustments are also recognized in the Consolidated Statements of Operations.
Goodwill. Duke Energy evaluates goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Under this provision, goodwill is subject to an annual test for impairment. Duke Energy has designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, Duke Energy performs the annual review for goodwill impairment at the reporting unit level, which Duke Energy has determined to be an operating segment or one level below.
Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the determined fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.
Duke Energy primarily uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts as well as other factors into its revenue and expense forecasts. See Note 10 for further information.
Other Long-term Investments. Other long-term investments, primarily marketable securities held in the Nuclear Decommissioning Trust Funds (NDTF) and the captive insurance investment portfolio, are classified as available-for-sale securities as management does not have the intent or ability to hold the securities to maturity, nor are they bought and held principally for selling them in the near term. The securities are reported at fair value on Duke Energy’s Consolidated Balance Sheets. Realized and unrealized gains and losses, net of tax, on the NDTF holdings are reflected in regulatory assets or liabilities on Duke Energy’s Consolidated Balance Sheets as Duke Energy expects to recover all costs for decommissioning its nuclear generation assets through regulated rates. Unrealized holding gains and losses, net of tax, on all other available-for-sale securities are reflected in AOCI in Duke Energy’s Consolidated Balance Sheets until they are realized, at which time they are reclassified to earnings. Cash flows from purchases and sales of long-term investments (including the NDTF) are presented on a gross basis within investing cash flows in the accompanying Consolidated Statements of Cash Flows.
Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Duke Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the estimated useful life of the asset using the straight-line method. The
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
composite weighted-average depreciation rates, excluding nuclear fuel, were 3.19% for 2007, 3.51% for 2006, and 3.34% for 2005. Also, see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” discussed below.
When Duke Energy retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When it sells entire regulated operating units, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.
Duke Energy recognizes asset retirement obligations (ARO’s) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations” (SFAS No. 143), for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), for conditional ARO’s. The term conditional asset retirement obligation as used in SFAS No. 143 and FIN 47 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Both SFAS No. 143 and FIN 47 require that the fair value of a liability for an ARO be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the estimated useful life of the asset. See Note 7 for further information.
Investments in Residential, Commercial, and Multi-Family Real Estate. Prior to the deconsolidation of Crescent in September 2006, investments in residential, commercial and multi-family real estate were carried at cost, net of any related depreciation. However, any properties meeting the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (SFAS No. 144), to be presented as Assets Held for Sale, were carried at lower of cost or fair value less costs to sell in the Consolidated Balance Sheets. Proceeds from sales of residential properties prior to September 2006 are presented within Operating Revenues and the costs of properties sold prior to the date of deconsolidation are included in Operation, Maintenance and Other in the Consolidated Statements of Operations. Cash flows related to the acquisition, development and disposal of residential properties prior to the date of deconsolidation are included in Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Gains and losses on sales of commercial and multi-family properties as well as “legacy” land sales prior to the date of deconsolidation are presented as such in the Consolidated Statements of Operations, and cash flows related to these activities are included in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.
Long-Lived Asset Impairments, Assets Held For Sale and Discontinued Operations. Duke Energy evaluates whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the carrying value of the asset over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.
Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset, or a change in management’s intent to utilize the asset may generally require management to re-assess the cash flows related to the long-lived assets.
Duke Energy uses the criteria in SFAS No. 144 to determine when an asset is classified as “held for sale.” Upon classification as “held for sale,” the long-lived asset or asset group is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset or asset group is separately presented on the Consolidated Balance Sheets. When an asset or asset group meets the SFAS No. 144 criteria for classification as held for sale within the Consolidated Balance Sheets, Duke Energy does not retrospectively adjust prior period balance sheets to conform to current year presentation.
Duke Energy uses the criteria in SFAS No. 144 and Emerging Issues Task Force (EITF) 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (EITF 03-13), to determine whether compo-
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nents of Duke Energy that are being disposed of, are classified as held for sale or have been wound down are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Energy must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the operations being disposed of must have been eliminated from Duke Energy’s ongoing operations (i.e. Duke Energy does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected as (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as (Losses) Gains on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets are recorded as Impairments and Other Charges in the Consolidated Statements of Operations. See Note 13 for discussion of discontinued operations.
Captive Insurance Reserves. Duke Energy has captive insurance subsidiaries which provide insurance coverage, on an indemnity basis, to Duke Energy entities as well as certain third parties, on a limited basis, for various business risks and losses, such as workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred but not yet reported (IBNR), as well as provisions for known claims which have been estimated on a claims-incurred basis. IBNR reserve estimates involve the use of assumptions and are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience.
Duke Energy’s captive insurance entities also have reinsurance coverage, which provides reimbursement to Duke Energy for certain losses above a per incident and/or aggregate retention. Duke Energy recognizes a reinsurance receivable for recovery of incurred losses under its captive’s reinsurance coverage once realization of the receivable is deemed probable by its captive insurance companies.
Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate. The amortization expense is recorded in continuing operations as interest expense in the Consolidated Statements of Operations. The amortization expense is reflected as Depreciation and amortization within Net cash provided by operating activities on the Consolidated Statements of Cash Flows.
Loss Contingencies. Duke Energy is involved in certain legal and environmental matters that arise in the normal course of business. Loss contingencies are accounted for under SFAS No. 5, “Accounting for Contingencies,” (SFAS No. 5). Under SFAS No. 5, contingent losses are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Duke Energy records a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred. See Note 17 for further information.
Environmental Expenditures. Duke Energy expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded on an undiscounted basis when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.
Severance and Special Termination Benefits. Duke Energy has an ongoing severance plan that is accounted for primarily under SFAS No. 112, “Employers’ Accounting for Postemployment Benefits” (SFAS No. 112). In general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits under this ongoing severance plan. Under SFAS No. 112, Duke Energy records a liability for severance once a plan is committed to by management, or sooner if severances are probable and the related severance benefits can be reasonably estimated. Duke Energy accounts for involuntary severance benefits that are incremental to its ongoing severance plan benefits in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS No. 146). Under SFAS No. 146, Duke Energy measures the obligation when all the criteria of SFAS No. 146 are met and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the service period. From time to time, Duke Energy offers special termination benefits under
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voluntary severance programs. These voluntary severance programs may or may not include severance payments accounted for under the ongoing severance plan. Special termination benefits are accounted for under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (SFAS No. 88). Under SFAS No. 88, special termination benefits are measured upon employee acceptance and recorded immediately absent a significant retention period. If a significant retention period exists, the cost of the special termination benefits are recorded ratably over the remaining service periods of the affected employees. Employee acceptance of voluntary severance benefits is determined by management based on the facts and circumstances of the special termination benefits being offered. See Note 12 for further information on Duke Energy’s severance programs.
Cost-Based Regulation. Duke Energy accounts for certain of its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers in a future period or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. Additionally, management continually assesses whether any regulatory liabilities have been incurred. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery and that no regulatory liabilities, other than those recorded, have been incurred. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. Duke Energy periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, Duke Energy may have to reduce its asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. For further information see Note 4.
Guarantees. Duke Energy accounts for guarantees and related contracts, for which it is the guarantor, under FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Duke Energy recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee, if any. Fair value is estimated using a probability-weighted approach. Duke Energy reduces the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation. Any additional contingent loss for guarantee contracts outside the scope of FIN 45 is accounted for and recognized in accordance with SFAS No. 5.
Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’s potential exposure under these indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. See Note 18 for further information.
Stock-Based Compensation. Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)). SFAS No. 123(R) establishes accounting for stock-based awards, including stock options, exchanged for employee and certain non-employee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Share-based awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted. See Note 20 for further information.
Duke Energy elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts for periods prior to January 1, 2006 in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS No. 123(R).
Prior to 2006, Duke Energy applied Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25)” and provided the
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required pro forma disclosures of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all stock options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005.
Revenue Recognition and Unbilled Revenue. Revenues on sales of electricity and gas are recognized when either the service is provided or the product is delivered. Unbilled revenues are estimated by applying an average revenue per kilowatt hour or per thousand cubic feet (Mcf) for all customer classes to the number of estimated kilowatt hours or Mcf’s delivered but not billed. The amount of unbilled revenues can vary significantly period to period as a result of factors including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are recorded as Receivables in Duke Energy’s Consolidated Balance Sheets at December 31, 2007 and 2006, were approximately $380 million and $330 million, respectively. The amount at December 31, 2006 excludes unbilled revenues related to the natural gas businesses transferred in January 2007, as discussed above.
Prior to the deconsolidation of Crescent in September 2006, profit from the sale of residential developed lots was recognized at closing under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs were allocated to land sold based on relative sales values. Crescent recognized revenues from commercial and multi-family project sales at closing, or later using a deferral method when the criteria for sale accounting had not been met. Profit was recognized based on the difference between the sales price and the carrying cost of the project. Revenue was recognized under the completed contract method for condominium units that Crescent developed and sold in Florida.
Nuclear Fuel. Amortization of nuclear fuel purchases is included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. The amortization is recorded using the units-of-production method.
Deferred Returns and Allowance for Funds Used During Construction (AFUDC). Deferred returns, recorded in accordance with SFAS No. 71, represent the estimated financing costs associated with funding certain regulatory assets or liabilities of U.S. Franchised Electric and Gas. The amount of deferred return expense included in Other Income and Expenses, net was $15 million in 2007, $14 million in 2006, and $13 million in 2005.
AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, Duke Energy is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $109 million in 2007, which consisted of an after-tax equity component of $69 million and a before-tax interest expense component of $40 million. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $75 million in 2006, which consisted of an after-tax equity component of $46 million and a before-tax interest expense component of $29 million. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $31 million in 2005, which consisted of an after-tax equity component of $22 million and a before-tax interest expense component of $9 million. The preceding amounts exclude AFUDC of approximately $22 million and $17 million for the years ended December 31, 2006 and 2005, respectively, which is included in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
Accounting For Sales of Stock by a Subsidiary. Duke Energy accounts for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary” (SAB No. 51). Under SAB No. 51, companies may elect, via an accounting policy decision, to record a gain or loss on the sale of stock of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the shares or to record such gain or loss as an adjustment to paid-in capital. Duke Energy has elected to treat such differences as gains or losses in earnings, which would be reflected in Gain on Sale of Subsidiary Stock in the Consolidated Statements of Operations. During the year ended December 31, 2006, Duke Energy recognized a gain of approximately $15 million related to the sale of securities of the Duke Energy Income Fund (Income Fund), which is reflected in (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. See Note 13 for further information.
Accounting For Purchases and Sales of Emission Allowances. Duke Energy recognizes emission allowances in earnings as they are consumed or sold. Gains or losses on sales of emission allowances for non-regulated businesses are presented on a net basis in (Losses) Gains on Sales of Other Assets and Other, net, in the accompanying Consolidated Statements of Operations. For regulated businesses that provide for direct recovery of emission allowances, any gains or losses on sales of recoverable emission allowances are
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included in the rate structure of the regulated entity and are deferred as a regulatory asset or liability. Future rates charged to retail customers are impacted by any gain or loss on sales of recoverable emission allowances and, therefore, as the recovery of the gain or loss is recognized in operating revenues, the regulatory asset or liability related to the emission allowance activity is recognized as a component of Fuel Used in Electric Generation and Purchased Power in the Consolidated Statements of Operations. For regulated businesses that do not provide for direct recovery of emission allowances through a cost tracking mechanism, gains and losses on sales of emission allowances are included in (Losses) Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations, or are deferred, depending on level of regulatory certainty. Purchases and sales of emission allowances are presented gross as investing activities on the Consolidated Statements of Cash Flows.
Income Taxes. Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns as required. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.
Management evaluates and records uncertain tax positions in accordance with FIN 48, “Accounting For Uncertainty in Income Taxes-an Interpretation of FASB Statement 109,” (FIN 48), which was adopted by Duke Energy on January 1, 2007. Duke Energy records unrecognized tax benefits for positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, when a more-likely-than-not threshold is met for a tax position and management believes that the position will be sustained upon examination by the taxing authorities. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. In accordance with FIN 48, Duke Energy records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement or effective settlement. Management considers a tax position effectively settled for the purpose of recognizing previously unrecognized tax benefits when the following conditions exist: (i) the taxing authority has completed its examination procedures, including all appeals and administrative reviews that the taxing authority is required and expected to perform for the tax positions, (ii) Duke Energy does not intend to appeal or litigate any aspect of the tax position included in the completed examination, and (iii) it is remote that the taxing authority would examine or reexamine any aspect of the tax position. See Note 6 for further information.
Duke Energy records, as it relates to taxes, interest expense as Interest Expense and interest income and penalties in Other Income and Expenses, net, in the Consolidated Statements of Operations.
Excise Taxes. Certain excise taxes levied by state or local governments are collected by Duke Energy from its customers. These taxes, which are required to be paid regardless of Duke Energy’s ability to collect from the customer, are accounted for on a gross basis. When Duke Energy acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Duke Energy’s excise taxes accounted for on a gross basis and recorded as revenues in the accompanying Consolidated Statements of Operations for years ended December 31, 2007, 2006, and 2005 were as follows:
Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131), establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. There is no aggregation within Duke Energy’s reportable business segments. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, including products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Energy’s reportable segments, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, is presented in Note 3.
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Foreign Currency Translation. The local currencies of Duke Energy’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation, in accordance with SFAS No. 52, “Foreign Currency Translation.” Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at the exchange rates at period end. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of AOCI. Revenue and expense accounts of these operations are translated at average exchange rates prevailing during the year. Gains and losses arising from transactions denominated in currencies other than the functional currency, which were immaterial for all periods presented, are included in the results of operations of the period in which they occur. Deferred taxes are not provided on translation gains and losses where Duke Energy expects earnings of a foreign operation to be permanently reinvested. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in foreign currency translation as a separate component of AOCI.
Statements of Consolidated Cash Flows. Duke Energy has made certain classification elections within its Consolidated Statements of Cash Flows related to discontinued operations, cash received from insurance proceeds, debt restricted for qualified capital and maintenance expenditures and cash overdrafts. Cash flows from discontinued operations are combined with cash flows from continuing operations within operating, investing and financing cash flows within the Consolidated Statements of Cash Flows. Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds (for example, general liability insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities). Proceeds from debt issued with restrictions to fund future capital and maintenance expenditures are presented on a gross basis, with the debt proceeds classified as a financing cash inflow and the changes in the restricted funds held in trust presented as a component of investing activities. With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts are included within financing cash flows.
Distributions from Equity Investees. Duke Energy considers dividends received from equity investees which do not exceed cumulative equity in earnings subsequent to the date of investment a return on investment and classifies these amounts as operating activities within the accompanying Consolidated Statements of Cash Flows. Cumulative dividends received in excess of cumulative equity in earnings subsequent to the date of investment are considered a return of investment and are classified as investing activities within the accompanying Consolidated Statements of Cash Flows.
Cumulative Effect of Changes in Accounting Principles. As of December 31, 2005, Duke Energy adopted the provisions of FIN 47. In accordance with the transition guidance of this standard, Duke Energy recorded a net-of-tax cumulative effect adjustment of approximately $4 million. The cumulative effect adjustment had an immaterial impact on earnings-per-share (EPS).
New Accounting Standards. The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2007 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (SFAS No. 140). SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 was effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that had been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. The adoption of SFAS No. 155 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.
SFAS No. 156, “Accounting for Servicing of Financial Assets-an amendment of FASB Statement No. 140” (SFAS No. 156). In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 was effective for Duke Energy as
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of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. The adoption of SFAS No. 156 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.
SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan-measured as the difference between plan assets at fair value and the benefit obligation-in its statement of financial position, (2) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. SFAS No. 158 does not change the amounts recognized in the income statement as net periodic benefit cost. Duke Energy recognized the funded status of its defined benefit pension and other postretirement plans and provided the required additional disclosures as of December 31, 2006. The adoption of SFAS No. 158 recognition and disclosure provisions resulted in an increase in total assets of approximately $211 million (consisting of an increase in regulatory assets of $595 million, an increase in deferred tax assets of $144 million, offset by a decrease in pre-funded pension costs of $522 million and a decrease in intangible assets of $6 million), an increase in total liabilities of approximately $461 million and a decrease in AOCI, net of tax, of approximately $250 million as of December 31, 2006. The adoption of SFAS No. 158 did not have a material impact on Duke Energy’s consolidated results of operations or cash flows.
Under the measurement date requirements of SFAS No. 158, an employer is required to measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Historically, Duke Energy has measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. Duke Energy adopted the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of SFAS No. 158. See Note 21.
FIN No. 48. In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Duke Energy has concluded there is a level of uncertainty with respect to the recognition of a tax benefit in Duke Energy’s financial statements. FIN 48 prescribes the minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Duke Energy adopted FIN 48 effective January 1, 2007. See Note 6 for additional information.
FASB Staff Position (FSP) No. FIN 48-1, Definition of “Settlement” in FASB Interpretation No. 48 (FSP No. FIN 48-1). In May, 2007, the FASB staff issued FSP No. FIN 48-1 which clarifies the conditions under FIN 48 that should be met for a tax position to be considered effectively settled with the taxing authority. Duke Energy’s adoption of FIN 48 as of January 1, 2007 was consistent with the guidance in this FSP.
FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230-A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable GAAP. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP was effective for Duke Energy as of January 1, 2007. As discussed in Note 20, effective with the spin-off of Spectra Energy on January 2, 2007, all previously granted Duke Energy long-term incentive plan equity awards were modified to equitably adjust the awards. As the modifications to the equity awards were made solely to reflect the spin-off, no change in the recognition or the measurement (due to a change in classification) of those instruments resulted.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2006 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
SFAS No. 123(R) “Share-Based Payment” (SFAS No. 123(R)). In December 2004, the FASB issued SFAS No. 123(R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy, timing for implementation of SFAS No. 123(R) was January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an acceptable alternative. Instead, Duke Energy is required to determine an appropriate expense for stock options and record compensation expense in the Consolidated Statements of Operations for stock options. Duke Energy implemented SFAS No. 123(R) using the modified prospective transition method, which required Duke Energy to record compensation expense for all unvested awards beginning January 1, 2006.
Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Duke Energy is required to recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Share-based awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.
The adoption of SFAS No. 123(R) did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. See Note 20.
Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006 the Securities and Exchange Commission (SEC) issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement-including the reversing effect of prior year misstatements-but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.
SAB No. 108 was effective for Duke Energy’s year ending December 31, 2006. SAB No. 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been used or (ii), under certain circumstances, recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. Duke Energy has historically used a dual approach for quantifying identified financial statement misstatements. Therefore, the adoption of SAB No. 108 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.
The following new accounting standard was adopted by Duke Energy during the year ended December 31, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
FIN No. 47. In March 2005, the FASB issued FIN No. 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN No. 47 were effective for Duke Energy as of December 31, 2005, and resulted in an increase in assets of $31 million, an increase in liabilities of $35 million and a net-of-tax cumulative effect adjustment to earnings of approximately $4 million.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The following new accounting standards have been issued, but have not yet been adopted by Duke Energy as of December 31, 2007:
SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. The application of SFAS No. 157 may change Duke Energy’s current practice for measuring fair values under other accounting pronouncements that require fair value measurements. For Duke Energy, SFAS No. 157 is effective as of January 1, 2008. In February 2008, the FASB issued FSP No. 157-2, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. Duke Energy does not expect to report any material cumulative-effect adjustment to beginning retained earnings as is required by SFAS No. 157 for certain limited matters. Duke Energy continues to monitor additional proposed interpretative guidance regarding the application of SFAS No. 157. To date, no matters have been identified regarding implementation of SFAS No. 157 that would have any material impact on Duke Energy’s consolidated results of operations or financial position.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159). In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Duke Energy does not currently have any financial assets or financial liabilities for which the provisions of SFAS No. 159 have been elected. However, in the future, Duke Energy may elect to measure certain financial instruments at fair value in accordance with this standard.
EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11). In June 2007, the EITF reached a consensus that would require realized income tax benefits from dividends or dividend equivalents that are charged to retained earnings and paid to employees for equity-classified nonvested equity shares, nonvested equity share units, and outstanding equity share options to be recognized as an increase to additional paid-in capital. In addition, EITF 06-11 would require that dividends on equity-classified share-based payment awards be reallocated between retained earnings (for awards expected to vest) and compensation cost (for awards not expected to vest) each reporting period to reflect current forfeiture estimates. For Duke Energy, EITF 06-11 must be applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning January 1, 2008, as well as interim periods within those fiscal years. Early application would be permitted as of the beginning of a fiscal year for which interim or annual financial statements have not yet been issued. Duke Energy is currently evaluating the impact of applying EITF 06-11, and cannot currently estimate the impact of EITF 06-11 on its consolidated results of operations, cash flows or financial position.
SFAS No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). In December 2007, the FASB issued SFAS No. 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting be used for all business combinations and that an acquirer be identified for each business combination. This statement also establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling (minority) interests in an acquiree, and any goodwill acquired in a business combination or gain recognized from a bargain purchase. For Duke Energy, SFAS No. 141R must be applied prospectively to business combinations for which the acquisition date occurs on or after January 1, 2009. The impact to Duke Energy of applying SFAS No. 141(R) for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of SFAS No. 141(R).
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS No. 160). In December 2007, the FASB issued SFAS No. 160, which amends ARB No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in a consolidated entity that should be reported as equity in the consolidated financial statements. This statement also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. In addition, SFAS No. 160 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. For Duke Energy, SFAS No. 160 is effective as of January 1, 2009, and must be applied prospectively, except for certain presentation and disclosure requirements which must be applied retrospectively. Duke Energy is currently evaluating the impact of adopting SFAS No. 160.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
2. Acquisitions and Dispositions
Acquisitions. Duke Energy consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” (EITF 98-3), is recorded as goodwill. The allocation of the purchase price may be adjusted if additional, requested information is received during the allocation period, which generally does not exceed one year from the consummation date; however, it may be longer for certain income tax items.
Cinergy Merger. On April 3, 2006, the merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). For accounting purposes, the effective date of the merger was April 1, 2006. The merger combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the midwestern United States. The merger was accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes. As a result, the assets and liabilities of Cinergy were recorded at their respective fair values as of April 3, 2006 and the results of Cinergy’s operations are included in the Duke Energy consolidated financial statements beginning as of the effective date of the merger.
Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction was valued at approximately $9.1 billion and resulted in goodwill of approximately $4.5 billion, none of which is deductible for tax purposes. Approximately $135 million of the goodwill was allocated to Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (collectively CMT), which was sold in October 2006 (see Note 13).
The following unaudited consolidated pro forma financial results are presented as if the Cinergy merger had occurred at the beginning of each of the periods presented:
Unaudited Consolidated Pro Forma Results
Pro forma results for the year ended December 31, 2006 include approximately $128 million of charges related to costs to achieve the merger and related synergies, which are recorded within Operating Expenses on the Consolidated Statements of Operations. Pro forma results for the years ended December 31, 2006 and 2005 do not reflect the pro forma effects of any significant transactions completed by Duke Energy other than the merger with Cinergy.
Other Acquisitions. In May 2007, Duke Energy acquired the wind power development assets of Energy Investor Funds from Tierra Energy. The purchase includes more than 1,000 megawatts of wind assets in various stages of development in the Western and Southwestern U.S. and supports Duke Energy’s strategy to increase its investment in renewable energy. A significant portion of the purchase price was for intangible assets (see Note 10). Three of the development projects, totaling approximately 240 megawatts, are located in Texas and Wyoming and are anticipated to be in commercial operation in late 2008 or 2009. Duke Energy anticipates capital expenditures of approximately $430 million through 2009 to complete the first three projects.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
During the first quarter of 2006, International Energy closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). In December 2007, International Energy closed on a transaction to acquire an additional 10% interest in Aguaytia for approximately $16 million, which consisted of approximately $8 million of cash and a short-term note payable of approximately $8 million. The acquisitions during 2006 increased International Energy’s ownership in Aguaytia to 66% and resulted in Duke Energy accounting for Aguaytia as a consolidated entity. Prior to the acquisition of the additional interest in 2006, Aguaytia was accounted for as an equity method investment. The December 2007 acquisition of an additional interest in Aguaytia increased Duke Energy’s ownership interest to 76% at December 31, 2007. The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas and natural gas liquids (NGL) and the generation, transmission and sale of electricity from a 177 megawatt power plant. No goodwill was recorded in connection with these transactions.
In the fourth quarter of 2006, Duke Energy acquired an 825 megawatt power plant located in Rockingham County, North Carolina, from Dynegy for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 megawatt combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy’s plan to meet customers’ electric needs for the foreseeable future. The transaction required approvals by the North Carolina Utilities Commission (NCUC), the Federal Energy Regulatory Commission (FERC) and the U.S. Federal Trade Commission (FTC). No goodwill was recorded as a result of this acquisition.
The pro forma results of operations for Duke Energy as if those acquisitions (other than the Cinergy merger) which closed prior to December 31, 2006 occurred as of the beginning of the periods presented do not materially differ from reported results.
See Note 13 for acquisitions related to discontinued operations.
Dispositions. On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses. See Note 1 and Note 13 for additional information.
In December 2006, Duke Energy Indiana, Inc. (Duke Energy Indiana) agreed to sell one unit of its Wabash River Power Station (Unit 1) to the Wabash Valley Power Association (WVPA). The sale was approved by the Indiana Utility Regulatory Commission (IURC), the FERC, the FTC and the Department of Justice during 2007. On December 31, 2007, Duke Energy Indiana received proceeds of approximately $114 million, which was equivalent to the net book value of Unit 1 at the time of sale. Since, pursuant to the terms of the purchase and sale agreement, the effective date of the sale was January 1, 2008, the assets of Unit 1 are reflected as Assets Held for Sale within Investments and Other Assets on the Consolidated Balance Sheets at December 31, 2007 and a corresponding liability equal to the cash received is included in Liabilities Associated with Assets Held for Sale within Current Liabilities on the Consolidated Balance Sheets at December 31, 2007. Since the sales price was equal to the net book value of Unit 1 at the transaction date, no gain or loss was recognized on the sale.
In February 2008, Duke Energy entered into an agreement to sell its 480 megawatt natural gas-fired peaking generating station located near Brownsville, Tennessee to Tennessee Valley Authority for approximately $55 million. This transaction, which is subject to FERC and other regulatory approvals, is expected to close in the second quarter of 2008. Duke Energy anticipates to recognize an approximate $20 million gain at the time of sale.
For the year ended December 31, 2007, the sale of other assets resulted in approximately $32 million in proceeds and net pre-tax losses of $5 million recorded in (Losses) Gains on Sales of Other Assets and Other, net.
For the year ended December 31, 2006, the sale of other assets and businesses resulted in approximately $2 billion in proceeds and net pre-tax gains of $223 million recorded in (Losses) Gains on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 13, and sales by Crescent prior to deconsolidation, which are discussed separately below. Significant sales of other assets during 2006 are detailed as follows:
•
On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the “MS Members”). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.21 billion, net of trans-
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
action costs, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. A 2% interest in the Crescent JV was also issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this 2% interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes. In conjunction with this transaction, Duke Energy recognized a pre-tax gain on the sale of approximately $246 million, which has been classified as a component of (Losses) Gains on Sales of Other Assets and Other, net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006. As a result of the Crescent transaction, Duke Energy no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently has accounted for its investment in the Crescent JV utilizing the equity method of accounting. The proceeds from the sale were recorded on the Consolidated Statements of Cash Flows as follows: approximately $1.2 billion in long-term debt proceeds, net of issuance costs, were classified as Proceeds from the issuance of long-term debt within Financing Activities, and approximately $380 million, which represents cash received from the MS Members net of cash held by Crescent as of the transaction date, were classified as Net proceeds from the sales of and distributions from equity investments and other assets, and sales of and collections on notes receivable within Investing Activities.
•
Commercial Power’s sale of emission allowances resulted in proceeds of $136 million and pre-tax losses on sales of approximately $29 million (see Note 10), which was recorded in (Losses) Gains on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations.
For the period from January 1, 2006 to September 7, 2006, Crescent commercial and multi-family real estate sales resulted in $254 million of proceeds and $201 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales primarily consisted of two office buildings at Potomac Yard in Washington, D.C. for a pre-tax gain of $81 million and land at Lake Keowee in northwestern South Carolina for a pre-tax gain of $52 million, as well as several other large land tract sales.
For the year ended December 31, 2005, the sale of other assets resulted in approximately $10 million in proceeds, pre-tax losses of $55 million recorded in (Losses) Gains on Sales of Other Assets and Other, net, on the accompanying Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 13, and commercial and multi-family real estate sales by Crescent which are discussed separately below. These losses primarily relate to Commercial Power’s $75 million charge related to the termination of structured power contracts in the Southeast, which was recorded in (Losses) Gains on Sales of Other Assets and Other, net on the accompanying Consolidated Statements of Operations.
For the year ended December 31, 2005, Crescent’s commercial and multi-family real estate sales resulted in $372 million of proceeds and $191 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales included a large land sale in Lancaster County, South Carolina that resulted in $42 million of pre-tax gains, and several other “legacy” land sales. Additionally, Crescent had $45 million in pre-tax income related to a distribution from an interest in a portfolio of commercial office buildings which was recognized in Other Income and Expenses, net, in the accompanying Consolidated Statements of Operations (see Note 23).
3. Business Segments
Duke Energy operates the following business segments, which are all considered reportable business segments under SFAS No. 131: U.S. Franchised Electric and Gas, Commercial Power, International Energy and Crescent. There is no aggregation of operating segments within Duke Energy’s reportable business segments. Prior to Duke Energy’s sale of an effective 50% ownership interest in Crescent in September 2006 (see below), this segment represented Duke Energy’s 100% ownership of Crescent. Duke Energy’s management believes these reportable business segments properly align the various operations of Duke Energy with how the chief operating decision maker views the business. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these reportable business segments in deciding how to allocate resources and evaluate performance. As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, which primarily consisted of Duke Energy’s
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Notes To Consolidated Financial Statements-(Continued)
former Natural Gas Transmission business segment and Duke Energy’s former Field Services business segment, which represented Duke Energy’s 50% ownership interest in DCP Midstream. Accordingly, results of operations for these former business segments are included in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for all periods presented.
U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, southwestern Ohio, central, north central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Inc. (Duke Energy Ohio), Duke Energy Indiana and Duke Energy Kentucky, Inc. (Duke Energy Kentucky). These electric and gas operations are subject to the rules and regulations of the FERC, the NCUC, the Public Service Commission of South Carolina (PSCSC), the Public Utilities Commission of Ohio (PUCO), the IURC and the Kentucky Public Service Commission (KPSC).
Commercial Power owns, operates and manages non-regulated power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio and the five Midwestern gas-fired non-regulated generation assets that were a portion of former DENA. Commercial Power’s assets comprise approximately 8,020 megawatts (MW) of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with base-load and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the Rate Stabilization Plan (RSP). Commercial Power also develops and implements customized energy solutions. Commercial Power, through Duke Energy Generation Services, Inc. and its affiliates (DEGS), develops, owns and operates electric generation for large energy consumers, municipalities, utilities and industrial facilities. DEGS currently manages more than 6,600 megawatts of power generation at 23 facilities through the U.S. Additionally, DEGS has 240 megawatts of wind energy under construction and more than 1,500 megawatts of wind energy projects in development.
International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through Duke Energy International, LLC and its activities target power generation in Latin America. Additionally, International Energy owns equity investments in National Methanol Company (NMC), located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE), and Attiki Gas Supply S.A. (Attiki), which is a natural gas distributor located in Athens, Greece.
Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina. On September 7, 2006, Duke Energy deconsolidated Crescent due to a reduction in ownership and its inability to exercise control over Crescent (see Note 2). Crescent has been accounted for as an equity method investment since the date of deconsolidation.
The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, and DukeNet Communications, LLC (DukeNet) and related telecommunications. Additionally, Other includes the remaining portion of the former DENA businesses that were not exited or transferred to Commercial Power, primarily Duke Energy Trading and Marketing, LLC (DETM), which management is currently in the process of winding down. Unallocated corporate costs include certain costs not allocable to Duke Energy’s reportable business segments, primarily governance costs, costs to achieve mergers and divestitures (such as the Cinergy merger and spin-off of Spectra) and costs associated with certain corporate severance programs. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. On a limited basis, Bison also participates in reinsurance activities with certain third parties. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations.
Duke Energy’s reportable business segments offer different products and services and are managed separately. Accounting policies for Duke Energy’s segments are the same as those described in Note 1. Management evaluates segment performance based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT.
Transactions between reportable business segments are accounted for on the same basis as revenues and expenses in the accompanying Consolidated Financial Statements.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Business Segment Data(a)
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Notes To Consolidated Financial Statements-(Continued)
(a) Segment results exclude results of entities classified as discontinued operations
(b) Includes assets held for sale and assets of entities in discontinued operations
(c) Capital expenditures for residential real estate are included in operating cash flows and were $322 million for the period from January 1, 2006 through the date of deconsolidation (September 7, 2006) and $355 million in 2005.
(d) Interest income and other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.
(e) Amounts associated with former DENA operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.
(f) In September 2006, Duke Energy completed a joint venture transaction of Crescent (see Note 2). As a result, Crescent segment data includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.
(g) Both the former Natural Gas Transmission business segment and former Field Services business segment were included in the spin-off of Spectra Energy on January 2, 2007.
Geographic Data
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
4. Regulatory Matters
Regulatory Assets and Liabilities. Duke Energy’s regulated operations are subject to SFAS No. 71. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further information. Amounts at December 31, 2006 include regulatory assets and regulatory liabilities of $959 million and $569 million, respectively, related to the natural gas businesses that were spun off to shareholders on January 2, 2007.
Duke Energy’s Regulatory Assets and Liabilities:
(a) All regulatory assets and liabilities are excluded from rate base unless otherwise noted.
(b) All December 31, 2007 balances relate to U.S. Franchised Electric and Gas. At December 31, 2006, approximately $513 million related to U.S. Franchised Electric and Gas and approximately $848 million related to Duke Energy’s former Natural Gas Transmission business, which was spun off as part of Spectra Energy on January 2, 2007.
(c) Included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets.
(d) Included in rate base.
(e) Earns a negative return.
(f) Included in Other Current Assets on the Consolidated Balance Sheets.
(g) Included in Accounts Payable on the Consolidated Balance Sheets.
(h) Included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.
(i) Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.
(j) Refund period will be determined by the volume of sales as U.S. Franchised Electric and Gas is currently refunding the liability through retail sales.
(k) Recovery/refund is over the life of the associated asset or liability.
(l) Incurred costs were deferred and are being recovered in rates. U.S. Franchised Electric and Gas is currently over-recovered for these costs in the South Carolina jurisdiction. Refund period is dependent on volume of sales and cost incurrence.
(m) Liability is extinguished over the lives of the associated assets.
(n) Recovery/Refund period currently unknown.
(o) North Carolina portion of approximately $13 million to be recovered in rates through 2012. See “Duke Energy Carolinas Rate Case” discussion below. South Carolina portion to be recovered through future rates, although ultimate recovery period is currently unknown.
(p) The 2006 amount includes $595 million related to adoption of SFAS No. 158 (see Note 21) and $380 million related to impacts of purchase accounting as a result of the merger with Cinergy (see Note 2).
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Regulatory Merger Approvals. As discussed in Note 1 and Note 2, on April 3, 2006, the merger between Duke Energy and Cinergy was consummated to create a newly formed company, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the PUCO, the KPSC, the PSCSC and the NCUC required that certain merger related savings be shared with consumers in Ohio, Kentucky, South Carolina, and North Carolina, respectively. The commissions also required Duke Energy Holding Corp., Cinergy, Duke Energy Ohio, Duke Energy Kentucky and/or Duke Energy Carolinas to meet additional conditions. While the merger itself was not subject to approval by the IURC, the IURC approved certain affiliate agreements in connection with the merger subject to similar conditions. Key elements of these conditions include:
•
The PUCO required that Duke Energy Ohio provide (i) a rate reduction of approximately $15 million for one year to facilitate economic development in a time of increasing rates and market prices and (ii) a reduction of approximately $21 million to its gas and electric consumers in Ohio for one year, with both credits beginning January 1, 2006. During the first quarter of 2007, Duke Energy Ohio completed its merger related rate reductions and filed a report with the PUCO to terminate the merger credit riders. Approximately $2 million and $34 million of these rate reductions were passed through to customers during the years ended December 31, 2007 and 2006, respectively.
•
The KPSC required that Duke Energy Kentucky provide $8 million in rate reductions to its customers over five years, ending when new rates are established in the next rate case after January 1, 2008. Approximately $2 million of the rate reduction was passed through to customers during each of the years ended December 31, 2007 and 2006, respectively.
•
The PSCSC required that Duke Energy Carolinas provide a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing (BPM) profit sharing arrangement. The rate reduction ended May 31, 2007. Approximately $16 million and $23 million of the rate reduction was passed through to customers during the years ended December 31, 2007 and 2006, respectively.
•
The NCUC required that Duke Energy Carolinas provide (i) a rate reduction of approximately $118 million for its North Carolina customers through a credit rider to existing base rates for a one-year period following the close of the merger, and (ii) $12 million to support various low income, environmental, economic development and educationally beneficial programs, the cost of which was incurred in the second quarter of 2006. The rate reduction ended June 30, 2007. Approximately $63 million and $54 million of the rate reduction was passed through to customers during the years ended December 31, 2007 and 2006, respectively.
•
In its order approving Duke Energy’s merger with Cinergy, the NCUC stated that the merger will result in a significant change in Duke Energy’s organizational structure which constitutes a compelling factor that warrants a general rate review. Therefore, as a condition of its merger approval and no later than June 1, 2007, Duke Energy Carolinas was required to file a general rate case or demonstrate that Duke Energy Carolinas’ existing rates and charges should not be changed (see discussion under “Duke Energy Carolinas Rate Case” below).
•
The IURC required that Duke Energy Indiana provide a rate reduction of $40 million to its customers over a one year period and $5 million over a five year period for low-income energy assistance and clean coal technology. In April 2006, Citizens Action Coalition of Indiana, Inc., an intervenor in the merger proceeding, filed a Verified Petition for Rehearing and Reconsideration claiming that Duke Energy Indiana should be ordered to provide an additional $5 million in rate reduction to customers to be consistent with the terms of the NCUC’s order approving the merger. In May 2006, the IURC denied the petition for rehearing and reconsideration. As of April 30, 2007, Duke Energy Indiana had completed its merger related reductions and filed a notice with the IURC to terminate the merger credit rider. Approximately $13 million and $27 million of the rate reduction was passed through to customers during the years ended December 31, 2007 and 2006, respectively.
•
The FERC approved the merger without conditions.
Used Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the Department of Energy (DOE) for the disposal of used nuclear fuel. The DOE failed to begin accepting used nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. Duke Energy will continue to safely manage its used nuclear fuel until the DOE accepts it. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial used nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional used fuel storage capacity. The matter was stayed pending the result of ongoing settlement negotiations between Duke Energy and the DOE. Payments made to the DOE for expected future disposal costs are based on nuclear output and are included in the Consolidated State-
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ments of Operations as Fuel Used in Electric Generation and Purchased Power. On March 5, 2007, Duke Energy Carolinas and the U.S. Department of Justice reached a settlement resolving Duke Energy’s used nuclear fuel litigation against the DOE. The agreement provides for an initial payment to Duke Energy of approximately $56 million for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs. The settlement agreement resulted in a pre-tax earnings impact of approximately $26 million during the year ended December 31, 2007, of which approximately $19 million and $7 million were recorded as an offset to Fuel Used in Electric Generation and Purchased Power, and Operation, Maintenance and Other, respectively, in the Consolidated Statements of Operations, with the remaining impact reflected within Inventory and Property, Plant and Equipment in the Consolidated Balance Sheets.
U.S. Franchised Electric and Gas. Rate Related Information. The NCUC, PSCSC, IURC and KPSC approve rates for retail electric and gas services within their states. The PUCO approves rates for retail gas and electric service within Ohio, except that non-regulated sellers of gas and electric generation also are allowed to operate in Ohio (see “Commercial Power” below). The FERC approves rates for electric sales to wholesale customers served under cost-based rates.
NC Clean Air Act Compliance. In 2002, the state of North Carolina passed clean air legislation that froze electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy Carolinas, to significantly reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy Carolinas, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). Duke Energy Carolinas’ amortization expense related to this clean air legislation totals approximately $1,050 million from inception, with approximately $187 million, $225 million and $311 million recorded during the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, cumulative expenditures totaled approximately $1,246 million, with $418 million, $403 million and $310 million incurred during the years ended December 31, 2007, 2006 and 2005, respectively, which are included within capital expenditures in Net Cash Used In Investing Activities on the Consolidated Statements of Cash Flows. In filings with the NCUC, Duke Energy Carolinas has estimated the costs to comply with the legislation as approximately $2.0 billion. Actual costs may be higher or lower than the estimate based on changes in construction costs and Duke Energy Carolinas’ continuing analysis of its overall environmental compliance plan. As required by the legislation, the NCUC considered the reasonableness of Duke Energy Carolinas’ environmental compliance plan and the method for recovery of the remaining costs in a proceeding it initiated and consolidated with a review of Duke Energy Carolinas’ base rates (see “Duke Energy Carolinas Rate Case” below). Additionally, federal and state environmental regulations, including, among other things, the Clean Air Interstate Rule (CAIR), and the Clean Air Mercury Rule (CAMR) could result in additional costs to reduce emissions from Duke Energy’s coal-fired power plants.
Duke Energy Carolinas Rate Case. In June 2007, Duke Energy Carolinas filed an application with the NCUC seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008. This application complied with a condition imposed by the NCUC in approving the Cinergy merger. On October 5, 2007, Duke Energy Carolinas filed an Agreement and Stipulation of Partial Settlement (Partial Settlement), a settlement agreement among Duke Energy Carolinas, the NCUC Public Staff, the North Carolina Attorney General’s Office, Carolina Utility Customers Association Inc., Carolina Industrial Group for Fair Utility Rates III and Wal-Mart Stores East LP, for consideration by the NCUC. The Partial Settlement, which includes Duke Energy Carolinas and all intervening parties to the rate case, reflected agreements on all but a few issues in these matters, including two significant issues. The two significant issues related to the treatment of ongoing merger cost savings resulting from the Cinergy merger and the proposed amortization of Duke Energy Carolinas’ development costs related to GridSouth Transco, LLC (GridSouth), a Regional Transmission Organization (RTO) planned by Duke Energy Carolinas and other utility companies as a result of previous FERC rulemakings, which was suspended in 2002 and discontinued in 2005 as a result of regulatory uncertainty. The Partial Settlement and the remaining disputed issues were presented to the NCUC for a ruling.
The Partial Settlement reflected an agreed to reduction in net revenues and pre-tax cash flows of approximately $210 million and corresponding rate reductions of 12.7% to the industrial class, 5.05% - 7.34% to the general class and 3.85% to the residential class of customers with an effective date of January 1, 2008. Under the Partial Settlement, effective January 1, 2008, Duke Energy Carolinas discontinued the amortization of the environmental compliance costs pursuant to North Carolina clean air legislation discussed above and began capitalizing all environmental compliance costs above the cumulative amortization charge of $1.05 billion as of December 31,
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2007. Over the past five years, the average annual clean air amortization was $210 million. The Partial Settlement was designed to enable Duke Energy Carolinas to earn a rate of return of 8.57% on a North Carolina retail jurisdictional rate base and an 11% return on the common equity component of the approved capital structure, which consists of 47% debt and 53% common equity. As part of the settlement, Duke Energy Carolinas agreed to alter the then existing BPM profit sharing arrangement that currently included a provision to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Energy Carolinas’ generating units at market based rates. Under the Partial Settlement, Duke Energy Carolinas will share 90% of the North Carolina retail allocation of the profits from BPM transactions beginning January 1, 2008.
The NCUC issued its Order Approving Stipulation and Deciding Non-Settled Issues on December 20, 2007. The NCUC approved the Partial Settlement in its entirety. The merger savings rider and GridSouth cost matters are discussed in detail below. For the remaining non-settled issues, the NCUC decided in Duke Energy Carolinas’ favor. With respect to the non-settled issues, the Order required that Duke Energy Carolinas’ test period operating costs reflect an annualized level of the merger cost savings actually experienced in the test period in keeping with traditional principles of ratemaking. The NCUC explained that because rates should be designed to recover a reasonable and prudent level of ongoing expenses, Duke Energy Carolinas’ annual cost of service and revenue requirement should reflect, as closely as possible, Duke Energy Carolinas’ actual costs. However, the NCUC recognized that its treatment of merger savings would not produce a fair result. Therefore, the NCUC preliminarily concluded that it would reconsider certain language in its 2006 merger order in order to allow it to authorize a 12-month increment rider of approximately $80 million designed to provide a more equitable sharing of the actual merger savings achieved on an ongoing basis. Additionally, the NCUC concluded that approximately $30 million of costs incurred through June 2002 in connection with GridSouth and deferred by Duke Energy Carolinas, were reasonable and prudent and approved a ten-year amortization, retroactive to June 2002. As a result of the retroactive impact of the Order, Duke Energy Carolinas recorded an approximate $17 million charge to write-off a portion of the Gridsouth costs in 2007. The NCUC did not allow Duke Energy Carolinas a return on the GridSouth investments. As a result of its decision on the non-settled issues, the NCUC ordered an additional reduction in annual revenues of approximately $54 million, offset by its preliminary authorization of a 12-month, $80 million increment rider, as discussed above. The Order ultimately resulted in an overall average rate decrease of 5% in 2008, increasing to 7% upon expiration of this one-time rate rider. On February 18, 2008, the NCUC issued an order confirming their preliminary conclusion regarding the merger savings rider. This order reaffirmed the prior tentative conclusion that the provisions of the Merger Order will not produce a fair sharing of the benefits of estimated merger savings between ratepayers and shareholders and that, for that reason, Duke Energy should be authorized to implement a 12-month increment rider to collect $80 million.
On December 12, 2007, the PSCSC directed the South Carolina Office of Regulatory Staff (ORS) to provide a written report concerning the NCUC’s resolution of Duke Energy Carolinas’ rate application and its relevance to Duke Energy Carolinas’ rates in South Carolina. On January 31, 2008, the ORS filed its report with the PSCSC, which concluded that the outcome of the North Carolina rate case had no bearing on Duke Energy Carolinas rates in South Carolina. The PSCSC has not yet responded to the report filed by the ORS.
The NCUC has requested that the Public Staff perform a review of Duke Energy Carolinas pension and other post-retirement benefit plan costs, as well as Duke Energy’s funding of the plans. At this time, Duke Energy Carolinas does not anticipate that the outcome of this review will have a material impact on its financial position, results of operations or cash flows.
Duke Energy Ohio Electric Rate Filings. Duke Energy Ohio operates under a RSP, a market based standard service offer (MBSSO) approved by the PUCO in November 2004. In March 2005, the Office of the Ohio Consumers’ Council (OCC) appealed the PUCO’s approval of the MBSSO to the Supreme Court of Ohio and the Court issued its decision in November 2006. It upheld the MBSSO in virtually every respect but remanded to the PUCO on two issues. The Court ordered the PUCO to support a certain portion of its order with reasoning and record evidence and to require Duke Energy Ohio to disclose certain confidential commercial agreements with other parties previously requested by the OCC. Duke Energy Ohio has complied with the disclosure order.
In October 2007, the PUCO issued its ruling affirming the MBSSO, with certain modifications, and maintained the current price. The ruling provides for continuation of the existing rate components, including the recovery of costs related to new pollution control equipment and capacity costs associated with power purchase contracts to meet customer demand, but provided customers an enhanced opportunity to avoid certain pricing components if they are served by a competitive supplier. The ruling also rescinded the requirement that Duke Energy Ohio transfer its generating assets to an exempt wholesale generator (EWG) and required Duke Energy Ohio to retain ownership for the remainder of the RSP period. The ruling also incorrectly implied that Duke Energy Ohio’s nonresidential regulatory transition charge (RTC) will terminate at the end of 2008. On November 23, 2007, Duke Energy Ohio filed an application for rehearing on the portions of the PUCO’s ruling relating to whether certain pricing components may be avoided by customers, the right to transfer generating assets, and the termination date of the RTC. On December 19, 2007, the PUCO issued its Entry on Rehearing granting in part and denying in part Duke Energy Ohio’s Application for Rehearing. Among other things, the Commission modified and clarified the applicability
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of various rate riders during customer shopping situations. It also clarified that the residential RTC terminates at the end of 2008 and that the nonresidential RTC terminates at the end of 2010 and agreed to give further consideration to whether Duke Energy Ohio may transfer its generating assets to an EWG.
On February 15, 2008, Duke Energy Ohio filed a notice of appeal with the Ohio Supreme Court challenging a portion of a decision by the PUCO regarding Duke Energy Ohio’s RSP. The appeal relates to the PUCO’s order in October 2007 addressing certain issues remanded from the Ohio Supreme Court after review of an earlier PUCO decision on the RSP. The October 2007 order permits non-residential customers to avoid certain charges associated with the costs of Duke Energy Ohio standing ready to serve such customers if they return after being served by another supplier. Duke Energy Ohio believes the PUCO exceeded its authority in modifying the charges that may be avoided, resulting in Duke Energy Ohio having to subsidize Ohio’s competitive electric market. Duke Energy Ohio has asked the Supreme Court to reverse the PUCO ruling and require that non-residential customers pay the charges associated with Duke Energy Ohio standing ready to serve them should they return from a competitive suppler. The OCC also has filed a notice of appeal challenging the PUCO’s October 2007 decision as unlawful and unreasonable. Pending the Ohio Supreme Court’s consideration of its appeal, the OCC has requested that the PUCO stay implementation of the Infrastructure Maintenance Fund charge approved in the October 2007 order to be collected from customers. At this time, Duke Energy Ohio cannot predict whether the Ohio Supreme Court will reverse the PUCO’s decision or whether the PUCO will grant the OCC’s request for a stay. However, Duke Energy Ohio does not anticipate the resolution of this matter will have a material impact on its results of operations, cash flows or financial position.
In August 2006, Duke Energy Ohio filed an application with the PUCO to amend its MBSSO through 2010. The proposal provides for continued electric system reliability, a simplified market price structure and clear price signals for customers, while helping to maintain a stable revenue stream for Duke Energy Ohio. On November 30, 2007, due to new legislation pending in the Ohio General Assembly regarding the pricing of competitive retail generation services, Duke Energy Ohio voluntarily withdrew its application to amend its MBSSO. Upon approval of the new legislation, Duke Energy Ohio will likely file a new generation pricing formula.
Duke Energy Ohio’s MBSSO price includes a fuel clause, System Reliability Tracker to recover for reserve capacity, and an Annually Adjusted Component (AAC) to recover changes in environmental, tax and homeland security costs. These price components are audited annually by the PUCO. In April 2007, Duke Energy Ohio entered into a settlement resolving all open issues identified in the 2006 audits and application to amend the 2007 AAC market price with some of the parties. After an evidentiary hearing, the PUCO issued its order approving the partial settlement on November 20, 2007.
Duke Energy Ohio Gas Rate Case. In July 2007, Duke Energy Ohio filed an application with the PUCO for an increase in its base rates for gas service. Duke Energy Ohio sought an increase of approximately $34 million in revenue, or approximately 5.7%, to be effective in the spring of 2008. The application also requests approval to continue tracker recovery of costs associated with an accelerated gas main replacement program. The PUCO accepted the application for filing in September 2007. The staff of the PUCO issued a Staff Report in December 2007 recommending an increase of approximately $14 to $20 million in revenue. The Staff Report also recommended approval for Duke Energy Ohio to continue tracker recovery of costs associated with an accelerated gas main replacement program. On February 28, 2008, Duke Energy Ohio reached a settlement agreement with the PUCO Staff and all of the intervening parties on its request for an increase in natural gas base rates. The settlement calls for an annual revenue increase of approximately $18 million overall, or 3 percent, and permits continued recovery of costs through 2018 for Duke Energy Ohio’s accelerated main replacement program. The settlement is subject to the review and approval of the PUCO.
Duke Energy Kentucky Gas Rate Cases. In 2002, the KPSC approved Duke Energy Kentucky’s gas base rate case which included, among other things, recovery of costs associated with an accelerated gas main replacement program. The approval authorized a tracking mechanism to recover certain costs including depreciation and a rate of return on the program’s capital expenditures. The Kentucky Attorney General appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism as well as the KPSC’s subsequent approval of annual rate adjustments under this tracking mechanism. In 2005, both Duke Energy Kentucky and the KPSC requested that the court dismiss these cases.
In February 2005, Duke Energy Kentucky filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism and for a $14 million annual increase in base rates. A portion of the increase is attributable to recovery of the current cost of the accelerated main replacement program in base rates. In December 2005, the KPSC approved an annual rate increase of $8 million and re-approved the tracking mechanism through 2011. In February 2006, the Kentucky Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows Duke Energy Kentucky to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows Duke Energy Kentucky to earn a return on investment for the costs recovered under the tracking mechanism which permits Duke Energy Kentucky to recover its gas main replacement costs.
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In August 2007 the Franklin Circuit Court consolidated all the pending appeals and ruled that the KPSC lacks legal authority to approve the gas main replacement tracking mechanism, and any other annual rate adjustments under the tracking mechanism. To date, Duke Energy Kentucky has collected approximately $9 million in annual rate adjustments under the tracking mechanism. Duke Energy Kentucky and the KPSC have appealed these cases to the Kentucky Court of Appeals and continues to utilize tracking mechanisms in its billed rates to customers. At this time, Duke Energy Kentucky cannot predict the outcome of these proceedings.
Energy Efficiency. In May 2007, Duke Energy Carolinas filed an energy efficiency plan with the NCUC that recognizes energy efficiency as a reliable, valuable resource that is a “fifth fuel,” that should be part of the portfolio available to meet customers’ growing need for electricity along with coal, nuclear, natural gas, or renewable energy. The plan would compensate Duke Energy Carolinas for verified reductions in energy use and be available to all customer groups. The plan contains proposals for several different energy efficiency programs, and links energy savings to retiring older coal plants. Customers would pay for energy efficiency programs with an energy efficiency rider that would be included in their power bill and adjusted annually. The energy efficiency rider would be based on the avoided cost of generation not needed as a result of the success of Duke Energy Carolinas’ energy efficiency efforts. The plan is consistent with Duke Energy Carolinas’ public commitment to invest 1% of its annual retail revenues from the sale of electricity in energy efficiency programs subject to the appropriate regulatory treatment of Duke Energy Carolinas’ energy efficiency investments. A hearing is expected in 2008.
On September 28, 2007, Duke Energy Carolinas filed an application with the PSCSC seeking approval to implement new energy efficiency programs in South Carolina. Duke Energy Carolinas’ South Carolina application is based on the application filed in North Carolina. In advance of the evidentiary hearing held February 5-6, 2008, Duke Energy Carolinas reached a settlement agreement with the South Carolina ORS, Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. Certain environmental groups that were also interveners on the proceeding did not join any of the settlements. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allow for recovery of 85% of the avoided generation charges. An evidentiary hearing is expected to be scheduled by the NCUC for North Carolina in 2008.
Implementation of these plans is subject to approval from the NCUC and PSCSC. As a result, Duke Energy is not able to estimate the impact this plan might have on its consolidated results of operations, cash flows, or financial position.
On July 11, 2007, the PUCO approved Duke Energy Ohio’s Demand Side Management/ Energy Efficiency Program (DSM Program). The DSM Program consists of ten residential and two commercial programs. Implementation of the programs has begun. The programs were first proposed in 2006 and were endorsed by the Duke Energy Community Partnership, which is a collaborative group made up of representatives of organizations interested in energy conservation, efficiency and assistance to low-income customers. The program costs will be recouped through a cost recovery mechanism that will be adjusted annually to reflect the previous year’s activity. Duke Energy Ohio is permitted to recover lost revenues, program costs and shared savings (once the programs reach 65% of the targeted savings level) through the cost recovery mechanism based upon impact studies to be provided to the Staff of the PUCO.
On October 19, 2007, Duke Energy Indiana filed its petition with the IURC requesting approval of an alternative regulatory plan to increase its energy efficiency efforts in the state. Similar to the plans in North Carolina and South Carolina, Duke Energy Indiana seeks approval of a plan that will be available to all customer groups and will compensate Duke Energy Indiana for verified reductions in energy usage. Under the plan, customers would pay for energy efficiency programs through an energy efficiency rider that would be included in their power bill and adjusted annually through a proceeding before the IURC. The energy efficiency rider will be based on the avoided cost of generation not needed as a result of the success of Duke Energy Indiana’s energy efficiency programs. The IURC is expected to consider the petition in an evidentiary hearing in May 2008.
On November 15, 2007, Duke Energy Kentucky filed its annual application to continue existing energy efficiency programs, consisting of nine residential and two commercial and industrial programs, and to true-up its gas and electric tracking mechanism for recovery of lost revenues, program costs and shared savings. An order on the application is expected in the first quarter of 2008.
New Legislation. South Carolina passed new energy legislation which became effective May 3, 2007. Key elements of the legislation include expansion of the annual fuel clause mechanism to include recovery of costs of reagents (ammonia, limestone, etc.) that are consumed in the operation of Duke Energy Carolinas’ SO2 and NOx control technologies and the cost of certain emission allowances used to meet environmental requirements. The cost of reagents for Duke Energy Carolinas in 2008 is expected to be approximately $30 million. With the enactment of this legislation, Duke Energy Carolinas will be allowed to recover the South Carolina portion of these costs, incurred on or after May 3, 2007, through the fuel clause. The legislation also includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project development costs associated with nuclear baseload generation, cost recovery assurance for construction
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costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear baseload generation in rates during construction. The North Carolina General Assembly also passed comprehensive energy legislation in July 2007 that was signed into law by the Governor on August 20, 2007. The North Carolina legislation allows utilities to recover the costs of reagents and certain purchased power costs. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to construction work in progress for baseload plants in a rate case. The North Carolina legislation also establishes a renewable portfolio standard for electric utilities at 3% of energy output in 2012, rising gradually to 12.5% by 2021, and grants the NCUC authority to approve a rate rider to compensate utilities for energy efficiency programs that they implement. On August 23, 2007, the NCUC initiated a rulemaking proceeding to adopt new rules and modify existing rules, as appropriate, to implement the legislation. That proceeding is pending and final rules are expected in the first quarter 2008. At this time, Duke Energy is not able to estimate the impact these legislative initiatives might have on its consolidated results of operations, cash flows, or financial position.
On September 25, 2007, at the request of the Governor of Ohio, the Ohio Senate introduced a bill (SB 221) that proposes a comprehensive change to Ohio’s 1999 electric energy industry restructuring legislation. If enacted, SB 221 would expand the PUCO’s authority over generation to: implement the state’s revised energy policy; regulate electric distribution utility prices for standard service; and permit the PUCO to implement rules for advanced energy portfolio and energy efficiency standards, greenhouse gas emission reporting requirements, and pilot project carbon sequestration activities in conjunction with other state agencies. Under SB 221, electric distribution utilities have the ability to apply for PUCO approval of one of two generation pricing alternatives -a market option or an Electric Security Plan (ESP) option. The market option is based upon a competitive bidding process. The ESP option would allow for the recovery of specified costs . The PUCO, however, would have authority to disallow the market option and compel the ESP option. SB 221, if enacted, would limit the ability of a utility to transfer its dedicated generating assets to an exempt wholesale generator absent PUCO approval. SB 221 passed the Ohio Senate on October 31, 2007, and is currently pending before the Ohio House of Representatives.
Other. U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territories. Long-term projections indicate a need for significant capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC), coal facilities or gas-fired generation units. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. In March 2006, Duke Energy Carolinas announced that it had entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. In May 2007, Duke Energy announced its intent to purchase Southern Company’s 500 MW interest in the proposed William States Lee III Nuclear Station, making the plant’s total output available to Duke Energy Carolinas’ electric customers. On December 13, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC) for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors at the Cherokee County, South Carolina site. Each reactor is capable of producing approximately 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On February 27, 2008, Duke Energy Carolinas received confirmation from the NRC that its COL application has been accepted and docketed for the next stage of review. Also, on December 7, 2007, Duke Energy Carolinas filed applications with the NCUC and the PSCSC for approval of Duke Energy Carolinas’ decision to incur development costs associated with the proposed William States Lee III Nuclear Station. The NCUC had previously approved Duke Energy’s decision to incur the North Carolina allocable share of up to $125 million in development costs through 2007. The new requests cover a total of up to $230 million in development costs through 2009, which is comprised of $70 million incurred through December 31, 2007 plus an additional $160 million of anticipated costs in 2008 and 2009. The PSCSC has scheduled an evidentiary hearing on Duke Energy Carolinas’ application for April 17, 2008, and the NCUC has scheduled an evidentiary hearing for April 29, 2008.
On June 2, 2006, Duke Energy Carolinas filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. On March 21, 2007, the NCUC issued its Order, which explained the basis for its decision to approve construction of one unit, with an approved cost estimate of $1.93 billion (including AFUDC), and certain conditions including providing for updates on construction cost estimates. A group of environmental interveners filed a motion and supplemental motion for reconsideration in April 2007 and May 2007, respectively. Duke Energy opposed the motions and the NCUC denied the motions for reconsideration in June 2007. On January 31, 2008, Duke Energy Carolinas filed its updated cost estimate of $1.8 billion (excluding approximately $0.6 billion of AFUDC) for the approved new Cliffside Unit 6. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $125 million in
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federal advanced clean coal tax credits. On July 11, 2007, Duke Energy Carolinas entered into an engineering, procurement, construction and commissioning services agreement, valued at approximately $1.3 billion, with an affiliate of The Shaw Group, Inc., of which approximately $950 million relates to participation in the construction of Cliffside Unit 6, with the remainder related to a flue gas desulfurization system on an existing unit at Cliffside.
On January 29, 2008, the North Carolina Department of Environment and Natural Resources (DENR) issued a final air permit for the new Cliffside Unit 6. On October 11, 2007, the environmental group N.C. WARN and two individual NC WARN members filed a petition against the DENR contesting the issuance of a wastewater discharge permit to Duke Energy Carolinas for the Cliffside Steam Station. A hearing on the NPDES permit contested case is scheduled for the week of March 3, 2008.
On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 600-800 MW combined cycle natural gas-fired generating facility at its existing Dan River Steam Station, as well as updated preliminary CPCN information to construct a 600-800 MW combined cycle natural gas-fired generating facility at its existing Buck Steam Station. On December 14, 2007, Duke Energy Carolinas filed CPCN applications for the two combined cycle facilities. The NCUC has consolidated its consideration of the two CPCN applications and scheduled an evidentiary hearing on the applications for March 11, 2008.
In August 2005, Duke Energy Indiana filed an application with the IURC for approval of study and preconstruction costs related to the joint development of an IGCC project with Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (Vectren). Duke Energy Indiana and Vectren reached a Settlement Agreement with the Indiana Office of Utility Consumer Counselor providing for the recovery of such costs if the IGCC project is approved and constructed and for the partial recovery of such costs if the IGCC project does not go forward. The IURC issued an order on July 26, 2006 approving the Settlement Agreement in its entirety.
On September 7, 2006, Duke Energy Indiana and Vectren filed a joint petition with the IURC seeking CPCN’s for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. The petition describes the applicants’ need for additional baseload generating capacity and requests timely recovery of all construction and operating costs related to the proposed generating station, including financing costs, together with certain incentive ratemaking treatment. Duke Energy Indiana and Vectren filed their cases in chief with the IURC on October 24, 2006. As with Duke Energy Carolinas’ Cliffside project, Duke Energy Indiana’s estimated costs for the potential IGCC project have increased. Duke Energy Indiana’s publicly filed testimony with the IURC states that industry estimates (as provided by the Electric Power Research Institute (EPRI)), of total capital requirements for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owners’ specific site costs). In April 2007, Duke Energy Indiana and Vectren filed a Front End Engineering and Design Study Report which included an updated estimated cost for the IGCC project of approximately $2 billion (including AFUDC). An evidentiary hearing was held June 18-22, 2007, and a public field hearing was held on August 29, 2007. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana CPCN’s for the proposed IGCC project and approved the timely recovery of costs related to the project. The IURC also approved Duke Energy Indiana’s proposal to initiate a proceeding in May 2008 concerning proposals for the study of partial carbon capture, sequestration and/or enhanced oil recovery for the Edwardsport IGCC Project. The Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc., all intervenors in the CPCN proceeding, have appealed the IURC Order to the Indiana Court of Appeals. That appeal is pending. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management. In August 2007, Vectren withdrew its participation in the IGCC plant. Duke Energy Indiana is currently exploring its options, including assuming 100% of the plant capacity. Absent identification of an alternative joint owner, Duke Energy Indiana would own 100% of the IGCC plant capacity.
In April 2005, the PUCO issued an order opening a statewide investigation into riser leaks in gas pipeline systems throughout Ohio. The investigation followed four explosions since 2000 caused by gas riser leaks, including an April 2000 explosion in Duke Energy Ohio’s service area. In November 2006, the PUCO Staff released the expert report, which concluded that certain types of risers are prone to leaks under various conditions, including over-tightening during initial installation. The PUCO Staff recommended that natural gas companies continue to monitor the situation and study the cause of any further riser leaks to determine whether further remedial action is warranted. Duke Energy Ohio has approximately 87,000 of these risers on its distribution system. If the PUCO orders natural gas companies to replace all of these risers, Duke Energy Ohio estimates a replacement cost of approximately $40 million. As part of the rate case filed in July 2007 (see “Duke Energy Ohio Gas Rate Case” above), Duke Energy Ohio requested approval from the PUCO to accelerate its riser replacement program; however, at this time, Duke Energy Ohio cannot predict the outcome or the impact of the statewide Ohio investigation.
FERC Issues Electric Reliability Standards. Consistent with reliability provisions of the Energy Policy Act of 2005, on July 20, 2006, FERC issued its Final Rule certifying the North American Electric Reliability Council (NERC) as the Electric Reliability Organization. NERC
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has filed over 100 proposed reliability standards with FERC. On March 16, 2007, FERC issued a final rule establishing mandatory, enforceable reliability standards for the nation’s bulk power system. In the final rule, FERC approved 83 of the 107 mandatory reliability standards submitted by the NERC and compliance with these standards became mandatory on June 18, 2007. FERC will consider the remaining 24 proposed standards for approval once the necessary criteria and procedures are submitted. In the interim, compliance with these 24 standards is expected to continue on a voluntary basis as good utility practice. Duke Energy does not believe that the issuance of these standards will have a material impact on its consolidated results of operations, cash flows, or financial position.
Open Access Transmission Tariff. On February 15, 2007, the FERC issued a Final Rule (Order 890) in its Open Access Transmission Tariff rulemaking. On March 19, 2007, Duke Energy Carolinas filed a request for rehearing and clarification with regards to this order. There are fourteen specific areas where clarification and rehearing would greatly assist Transmission Providers understanding and implementation of the new rules. Duke Energy Carolinas has also made several compliance filings with regard to Order 890. On December 28, 2007, the FERC issued Order 890-A, in which it largely reaffirmed the findings of issued Order 890. At this time, Duke Energy Carolinas does not believe that the order will have a material impact on its consolidated results of operations, cash flows, or financial position.
Midwest ISO Resource Adequacy Filing. On December 28, 2007, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) filed its Electric Tariff Filing Regarding Resource Adequacy in compliance with the FERC’s request of Midwest ISO to file Phase II of its long-term Resource Adequacy plan by December 2007. The proposal includes establishment of a resource adequacy requirement in the form of planning reserve margin. While the proposal has been filed for approval from the FERC, it currently lacks enforcement and financial settlement mechanisms. Given that the proposal has not yet been approved by the FERC, it is difficult to estimate its impact on Duke Energy, but at this time Duke Energy does not believe the resource adequacy requirement will have a material impact on its consolidated results of operations, cash flows, or financial position.
Commercial Power. Reported results for Commercial Power are subject to volatility due to the over- or under-collection of certain costs, including fuel and purchased power, since Commercial Power is not subject to regulatory accounting pursuant to SFAS No. 71. In addition, Commercial Power could be impacted by certain of the regulatory matters discussed above, including the Duke Energy Ohio electric rate filings.
5. Joint Ownership of Generating and Transmission Facilities
Duke Energy Carolinas, along with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation, Piedmont Municipal Power Agency and Saluda River Electric Cooperative, Inc., have joint ownership of Catawba Nuclear Station, which is a facility operated by Duke Energy Carolinas. Duke Energy Ohio, Columbus Southern Power Company, and Dayton Power & Light jointly own electric generating units and related transmission facilities in Ohio. Duke Energy Kentucky and Dayton Power & Light jointly own an electric generating unit. Duke Energy Ohio and WVPA jointly own Vermillion Station. Additionally, Duke Energy Indiana is a joint-owner of Gibson Station Unit No. 5 with WVPA and Indiana Municipal Power Agency (IMPA), as well as a joint-owner with WVPA and IMPA of certain Indiana transmission property and local facilities. These facilities constitute part of the integrated transmission and distribution systems, which are operated and maintained by Duke Energy Indiana.
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As of December 31, 2007, Duke Energy’s shares in jointly-owned plant or facilities were as follows:
(a) Station is not operated by Duke Energy Ohio.
(b) Included in Commercial Power segment
(c) Included in U.S. Franchised Electric and Gas segment
In December 2006, Duke Energy announced an agreement to purchase a portion of Saluda River Electric Cooperative, Inc.’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy will pay approximately $158 million for the additional ownership interest of the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy will own approximately 19 percent of the Catawba Nuclear Station. This transaction, which is expected to close prior to September 30, 2008, is subject to approval by various state and federal agencies.
Duke Energy’s share of revenues and operating costs of the above jointly owned generating facilities are included within the corresponding line on the Consolidated Statements of Operations. Each participant in the jointly owned facilities must provide its own financing.
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6. Income Taxes
The following details the components of income tax expense:
Income Tax Expense
(a) Included in the “Total current income taxes” line above is a FIN 48 benefit relating primarily to certain temporary differences of approximately $245 million.
Income from Continuing Operations before Income Taxes
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Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to the Actual Tax Expense from Continuing Operations (Statutory Rate Reconciliation)
During 2007, Duke Energy had tax benefits related to the manufacturing deduction of approximately $35 million, which is reflected in the above table in Other items, net. The manufacturing deduction was created by the American Job Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities. During the years ended December 31, 2006 and 2005, the Act provided for a 3% deduction on qualified production activities. During the year ended December 31, 2007, the deduction increased to 6% on qualified production activities.
During 2006, Duke Energy had favorable tax settlements on research and development costs and nuclear decommissioning costs of approximately $30 million, tax benefits related to the impairment of an investment in Bolivia of approximately $25 million and the manufacturing deduction of approximately $13 million. These benefits are reflected in the above table in Other items, net.
During 2005, Duke Energy recorded tax benefits of approximately $12 million related to the manufacturing deduction and $16 million related to a real estate donation. These benefits are reflected in the above table in Other items, net.
Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will be realized on a more-likely-than-not basis. The net change in the total valuation allowance is included in Tax differential on foreign earnings and State income tax, net of federal income tax effect in the above table.
Net Deferred Income Tax Liability Components
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The above amounts have been classified in the Consolidated Balance Sheets as follows:
Deferred Tax Liabilities
Deferred income taxes and foreign withholding taxes have not been provided on undistributed earnings of Duke Energy’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2007 on which Duke Energy has not provided deferred income taxes and foreign withholding taxes, is approximately $460 million.
Duke Energy or its subsidiaries file income tax returns in the U.S. with federal and various state governmental authorities, and in foreign jurisdictions. As discussed in Note 1, on January 1, 2007, Duke Energy adopted FIN 48. The following table shows the impacts of adoption of FIN 48 on Duke Energy’s Consolidated Balance Sheets.
(a) Includes liability for unrecognized tax benefits and accrued interest and penalties, including reserves against gain contingencies. These gain contingences were not recorded prior to the adoption of FIN 48.
The following table shows the accounting for the impacts of adoption of FIN 48 on January 1, 2007, along with the respective impacts related to the subsequent spin-off of Spectra Energy on January 2, 2007. See Note 1 for additional information.
(a) Reflects all interest related to income taxes.
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The following table details the changes in Duke Energy’s unrecognized tax benefits from January 1, 2007 to December 31, 2007.
(a) An increase in the liability of $157 million recorded during first quarter 2007, primarily related to the timing of certain deductions taken on tax returns in prior years, was eliminated during the third quarter of 2007.
At December 31, 2007, Duke Energy has approximately $114 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate. Additionally, at December 31, 2007, Duke Energy has approximately $16 million and $9 million that, if recognized, would affect (Loss) Income From Discontinued Operations, net of tax, and goodwill, respectively.
It is reasonably possible that Duke Energy will reflect an approximate $65 million reduction in unrecognized tax benefits within the next twelve months due to expected settlements. Also, it is reasonably possible that up to approximately $100 million in currently recorded unrecognized tax benefits related to prior open tax years could change within the next twelve months, although Duke Energy is unable to further estimate the amount of potential change at this time. Duke Energy expects in the next twelve months to decide whether or not to contest a ruling by the taxing authority that denied its position.
Duke Energy is assessing certain other tax matters which do not represent tax positions under FIN 48 and which could result in gains in future periods. However, the timing and amounts of any such potential gains are not currently estimable.
During the year ended December 31, 2007, Duke Energy recognized net interest income of approximately $38 million. At December 31, 2007, Duke Energy had approximately $27 million of interest receivable, which reflects all interest related to income taxes, and $2 million accrued for the payment of penalties.
Duke Energy has the following tax years open.
Jurisdiction
Tax Years
Federal
1999 and after (except for Cinergy and its subsidiaries, which are open for years 2000 and after)
State
Majority closed through 2001 except for certain refund claims for tax years 1978-2001 and any adjustments related to open federal years
International
2000 and after
7. Asset Retirement Obligations
In June 2001, the FASB issued SFAS No. 143, which was adopted by Duke Energy on January 1, 2003. SFAS No. 143 addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding
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adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time. Additional depreciation expense is recorded prospectively for any increases to the carrying amount of the associated asset.
Asset retirement obligations at Duke Energy relate primarily to the decommissioning of nuclear power facilities, obligations related to right-of-way agreements, asbestos removal and contractual leases for land use. In accordance with SFAS No. 143, Duke Energy identified certain assets that have an indeterminate life, and thus the fair value of the retirement obligation is not reasonably estimable. These assets included distribution facilities and some gas-fired power plants. A liability for these asset retirement obligations will be recorded when a fair value is determinable.
The adoption of SFAS No. 143 had no impact on the income of the regulated electric operations, as the effects were offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71 as Duke Energy received approval from both the NCUC and PSCSC to defer all cumulative and future income statement impacts related to SFAS No. 143. Similar approval was not granted by the PUCO, IURC and KPSC for Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky, respectively.
In March 2005, the FASB issued FIN 47. As a result of the adoption of FIN 47 in 2005, an increase in total assets of $31 million was recorded, consisting of an increase in regulatory assets of $24 million, an increase in net property, plant and equipment of $7 million and an increase in ARO liabilities of approximately $35 million. The adoption of FIN 47 had no impact on the income of the regulated electric operations, as the effects were offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71. For obligations related to other operations, a net-of-tax cumulative effect adjustment of approximately $4 million was recorded in the fourth quarter of 2005 as a reduction in earnings (see Note 1).
The pro forma effects of adopting FIN 47, including the impact on the balance sheet, net income and related basic and diluted earnings per share, are not presented due to an immaterial impact.
The asset retirement obligation is adjusted each period for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.
Reconciliation of Asset Retirement Obligation Liability
(a) As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses.
(b) Primarily related to Duke Energy’s acquisition of Cinergy in April 2006.
Accretion expense for the years ended December 31, 2007 and 2006 included approximately $153 million and $142 million, respectively, related to Duke Energy’s regulated electric operations which have been deferred as regulatory assets and liabilities in accordance with SFAS No. 71, as discussed above.
Upon adoption of SFAS No. 143, Duke Energy’s regulated electric and regulated natural gas operations classifies removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment under SFAS No. 71. Duke Energy does not accrue the estimated cost of removal when no legal obligation associated with retirement or removal exists for any non-regulated assets (including Duke Energy Ohio’s generation assets). The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $2,173 million and $2,345 million as of December 31, 2007 and 2006, respectively. At December 31, 2006, approximately $391 million of removal costs were related to obligations of the natural gas businesses that were spun off to shareholders on January 2, 2007.
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Notes To Consolidated Financial Statements-(Continued)
Nuclear Decommissioning Costs. In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2007 and 2006, Duke Energy expensed approximately $48 million and contributed cash of approximately $48 million to the NDTF for decommissioning costs. These amounts are presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Cash Flows from Investing Activities. In each of the years ended December 31, 2007 and 2006, $48 million was contributed entirely to the funds reserved for contaminated costs. Contributions were discontinued to the funds reserved for non-contaminated costs since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,929 million as of December 31, 2007 and $1,775 million as of December 31, 2006. These amounts are reflected as Nuclear Decommissioning Trust Funds within Investments and Other Assets in the Consolidated Balance Sheets. The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,551 million as of December 31, 2007 and $1,421 million as of December 31, 2006.
Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s 12.5% ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Management believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.
The operating licenses for Duke Energy’s nuclear units are subject to extension. In December 2003, Duke Energy was granted renewed operating licenses for Catawba Nuclear Station Units 1 and 2 until 2043 and McGuire Nuclear Station Unit 1 and 2 until 2041 and 2043, respectively. In 2000, Duke Energy was granted a renewed operating license for the Oconee Nuclear Station Units 1 and 2 until 2033 and Unit 3 until 2034.
8. Risk Management and Hedging Activities, Credit Risk, and Financial Instruments
Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy related assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including swaps, futures, forwards, options and swaptions.
Duke Energy’s Derivative Portfolio Carrying Value as of December 31, 2007
The amounts in the table above represent the combination of amounts presented as other current assets, other investments and other assets, other current liabilities and other deferred credits and other liabilities on Duke Energy’s Consolidated Balance Sheets.
Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their power generating and natural gas sales and transportation activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for electricity and natural gas transactions. Duke Energy is hedging exposures to the price variability of these commodities for a maximum period of 2 years.
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Notes To Consolidated Financial Statements-(Continued)
The ineffective portion of commodity cash flow hedges resulted in an immaterial amount in 2007, a pre-tax gain of $5 million in 2006 and a pre-tax loss of $12 million in 2005 and is reported primarily in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges, which is classified in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations, resulted in an immaterial amount in 2007, a loss of approximately $67 million in 2006 and a gain of approximately $1.2 billion in 2005 (see Note 13).
As of December 31, 2007, $25 million of pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheets in AOCI and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.
Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. In the former DENA business currently classified as discontinued operations, Duke Energy evaluated changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, used various instruments to hedge its market risk. Those commodity instruments, such as swaps, futures and forwards, served as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in no gain or loss in 2007, a pre-tax gain of $7 million in 2006 and a pre-tax loss of $4 million in 2005, and is reported primarily in (Loss) Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations.
Normal Purchases and Normal Sales Exception. Duke Energy has applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133, interpreted by Derivatives Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 14 years, are not included in the table above. As discussed in Note 13, during 2005, Duke Energy recognized a pre-tax loss of approximately $1.9 billion for the disqualification of certain power and gas forward sales contracts.
Certain forward power contracts related to former DENA’s Southeast Plants and the deferred plants had been primarily designated as normal purchases and normal sales in accordance with SFAS No. 133. In addition, as certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. The amount recognized for transactions that no longer qualified as hedged firm commitments was not material in 2006 and 2007.
Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Energy to risk as a result of its issuance of variable and fixed rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate exposures to a percentage of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Duke Energy’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2007, 2006, and 2005.
Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. There was no gain or loss during 2007 and 2006 and a net gain of $1 million included in the cumulative translation adjustment for hedges of net investments in foreign operations during 2005. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.
Other Derivative Contracts. Trading. Duke Energy has been exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of proprietary trading activities. During 2003, Duke Energy prospectively discontinued proprietary trading. As a result of the Cinergy merger, Duke Energy acquired natural gas and power
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Notes To Consolidated Financial Statements-(Continued)
marketing and trading operations, conducted primarily through CMT, the results of which have been reflected in (Loss) Income from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to the date of sale. In October 2006, the CMT sale transaction was completed and Duke Energy entered into a series of Total Return Swaps (TRS) with Fortis (see Note 13).
Undesignated. In addition, Duke Energy uses derivative contracts to manage the market risk exposures that arise from energy supply, structured origination, marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies, and to manage interest rate and foreign currency exposures. This category includes changes in fair value for derivatives that no longer qualify for the normal purchase and normal sales scope exception and disqualified hedge contracts, unless the derivative contract is subsequently re-designated as a hedge. The contracts in this category as of December 31, 2007 are primarily associated with forward power sales and coal purchases for the Commercial Power operations and remaining former DENA exit activity announced in 2005 (see Note 13). Duke Energy’s exposure to price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.
In connection with the Barclays Bank PLC (Barclays) transaction discussed in Note 13, Duke Energy entered into a series of TRS with Barclays, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Barclays. The fair value of the TRS as of December 31, 2007 is an asset of approximately $66 million, which offsets the net fair value of the underlying contracts, which is a liability of approximately $66 million. The remaining contracts covered by this TRS are with a single counterparty. Although Duke Energy has transferred the risks associated with these contracts to Barclay’s via the TRS, Duke Energy will continue to facilitate these contracts for their duration.
Credit Risk. Duke Energy’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S. and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.
Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its risk management operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.
Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
Financial Instruments. The fair value of financial instruments, excluding derivatives included elsewhere in this Note and in Note 13, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2007 and 2006, are not necessarily indicative of the amounts Duke Energy could have realized in current markets.
Financial Instruments
(a) Includes current maturities.
The fair value of cash and cash equivalents, short-term investments, accounts and notes receivable, accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.
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9. Marketable Securities
Short-term investments. At December 31, 2007 and 2006 Duke Energy had $437 million and $1,514 million, respectively, of short-term investments consisting primarily of highly liquid tax-exempt debt securities. As discussed in Note 1, these securities frequently have stated maturities of 20 years or more; however, these instruments have historically provided for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. The holding period for these securities is typically less than 1 year, but can be impacted by liquidity factors in the financial markets. These instruments are classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. As of December 31, 2007, the carrying value of these instruments approximated their fair value as they contain floating rates of interest. In January 2008, substantially all of these investments were sold at auction at amounts approximating their carrying values. In early 2008, Duke Energy made additional investments in these types of instruments. During the years ended December 31, 2007, 2006 and 2005, Duke Energy purchased short-term investments of approximately $21,661 million, $31,521 million and $38,535 million, respectively, and received proceeds on sales of approximately $22,685 million, $30,692 and $38,386 million, respectively.
Other Long-term investments. Duke Energy invests in debt and equity securities that are held in the NDTF (see Note 7 for further information), in Rabbi Trusts for investments related to certain executive deferred compensation plans, and in the captive insurance investment portfolio. These investments are classified as available-for-sale under SFAS No. 115 and, therefore, are carried at estimated fair value based on quoted market prices. Since management does not intend to use these investments in current operations, these investments are classified as long-term.
As of December 31, 2007 and 2006, Duke Energy’s NDTF held investments with a fair market value of apporoximately $1,929 million and $1,775 million, respectively. The NDTF is managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreement. Therefore, Duke Energy has limited oversight of the day-to-day management of the NDTF investments. Pursuant to an order from the NCUC, Duke Energy defers as a regulatory asset or regulatory liability all gains and losses associated with investments in the NDTF.
As of December 31, 2007 and 2006, Duke Energy’s other long-term investments had a fair market value of $345 million and $320, respectively.
The cost of securities sold is determined using the specific identification method. During the years ended December 31, 2007, 2006 and 2005, Duke Energy purchased long-term investments of approximately $2,007 million, $1,951 million and $1,826 million, respectively, and received proceeds on sales of approximately $1,954 million, $1,937 and $1,787 million, respectively. Most of these purchases and sales relate to the NDTF. Purchases for the years ended December 31, 2007, 2006 and 2005 include contributions to the NDTF of approximately $48 million in each year pursuant to an order by the NCUC (see Note 7). The remaining investment activity relates primarily to purchases and sales within the NDTF.
The estimated fair values of short-term and long-term investments classified as available-for-sale are as follows (in millions):
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
For the years ended December 31, 2007, 2006, and 2005 gains of less than $1 million, approximately $57 million (including $51 million reclassified to (Loss) Income from Discontinued Operations, net of tax) and approximately $3 million, respectively, were reclassified out of AOCI into earnings.
Debt securities held at December 31, 2007 mature as follows: $15 million in less than one year, $153 million in one to five years, $147 million in six to ten years and $291 million thereafter.
The fair values and gross unrealized losses of available-for-sale equity and debt securities which are in an unrealized loss position, including securities held in the NDTF, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2007 and 2006.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
10. Goodwill and Intangible Assets
Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142. There were no goodwill impairment charges in 2007, 2006 or 2005 as a result of the annual impairment tests required by SFAS No. 142. As discussed further in Note 2, in April 2006, Duke Energy and Cinergy consummated the previously announced merger, which resulted in Duke Energy recording goodwill and intangible assets of approximately $5.6 billion. The following table shows the components of goodwill at December 31, 2007:
Changes in the Carrying Amount of Goodwill
(a) As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, including the former Natural Gas Transmission business segment.
(b) Goodwill resulting from Duke Energy’s merger with Cinergy.
(c) Approximately $135 million of goodwill had been allocated to CMT, which was disposed of during 2006 (see Note 13).
(d) Reduction in goodwill at December 31, 2006 reflects the deconsolidation of Crescent in September 2006 (see Note 2).
Intangible Assets
The carrying amount and accumulated amortization of intangible assets as of December 31, 2007 and December 31, 2006, which primarily related to the intangible assets acquired as a part of the merger with Cinergy, are as follows:
(a) Increase in Intangible assets primarily related to the acquisition of the wind power development assets of Energy Investor Funds from Tierra Energy (see Note 2).
Emission allowances sold or consumed during the years ended December 31, 2007, 2006 and 2005 were $271 million, $428 million and $8 million, respectively.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Amortization expense for gas, coal and power contracts and other intangible assets for the years ended December 31, 2007, 2006 and 2005 was approximately $57 million, $56 million and $1 million, respectively.
The table below shows the expected amortization expense for the next five years for intangible assets as of December 31, 2007. The expected amortization expense includes estimates of emission allowances consumption and estimates of consumption of commodities such as gas and coal under existing contracts. The amortization amounts discussed below are estimates. Actual amounts may differ from these estimates due to such factors as changes in consumption patterns, sales or impairments of emission allowances or other intangible assets, additional intangible acquisitions and other events.
In connection with the merger with Cinergy, Duke Energy recorded an intangible liability amounting to approximately $113 million associated with the MBSSO in Ohio that will be recognized in earnings through December 31, 2008. The carrying amount of this intangible liability was approximately $67 million and $95 million at December 31, 2007 and 2006, respectively. The remaining $67 million will be amortized to income in 2008. Duke Energy also recorded approximately $56 million of intangible liabilities associated with other power sale contracts in connection with the merger with Cinergy. The carrying amount of these intangible liabilities was approximately $22 million and $39 million at December 31, 2007 and 2006, respectively. This balance will be amortized to income as follows: approximately $6 million in each of the years 2008 through 2010, and approximately $4 million in 2011.
11. Investments in Unconsolidated Affiliates and Related Party Transactions
Investments in domestic and international affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. During the years ended December 31, 2007, 2006 and 2005, Duke Energy received distributions from those investments of $147 million, $893 million and $856 million, respectively. Of these amounts, approximately $147 million, $741 million and $473 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005, respectively, and $0, $152 million and $383 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005, respectively. Duke Energy’s share of net earnings from these unconsolidated affiliates within continuing operations is reflected in the Consolidated Statements of Operations as Equity in Earnings of Unconsolidated Affiliates.
As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. Included in the assets distributed to Spectra Energy were investments in unconsolidated affiliates with an approximate carrying value of $1,618 million as of the distribution date, which primarily consisted of Duke Energy’s 50% ownership interest in DCP Midstream and a 50% ownership interest in Gulfstream Natural Gas System, LLC (Gulfstream), an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida.
As of December 31, 2007 and 2006, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets.
Significant investments in affiliates are as follows:
Commercial Power. As of both December 31, 2007 and 2006, investments primarily included a 50% interest in South Houston Green Power, L.P (Green Power). Green Power is a cogeneration facility containing three combustion turbines in Texas City, Texas. Although Duke Energy owns a significant portion of Green Power, it is not consolidated as Duke Energy does not hold a majority voting control or have the ability to exercise control over Green Power.
International Energy. As of both December 31, 2007 and 2006, investments primarily included a 25% indirect interest in NMC, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia, and a 25% indirect interest in Attiki, a natural gas distributor in Athens, Greece. Through August 2007, Duke Energy held a 50% investment interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues were generated from a gas compression services agreement (GCSA) with PEMEX. Upon the expiration of the GCSA with the Mexican National Oil Company (PEMEX) in August 2007, the operations of Campeche were transferred to PEMEX and International Energy
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
had no subsequent involvement with Campeche. See Note 12 for discussion of other than temporary impairment charges recorded during the years ended December 31, 2006 and 2005 against the carrying value of the Campeche investment and related notes receivable.
Crescent. An indirect wholly owned subsidiary of Duke Energy contributed all the membership interests in Crescent to a joint venture, causing Duke Energy to deconsolidate Crescent as of September 7, 2006 (see Note 2) as a result of a reduction in ownership to an effective 50% interest and subsequently has accounted for the investment using the equity method of accounting.
Other. As of December 31, 2007 and 2006, investments primarily include telecommunications investments.
Investments in Unconsolidated Affiliates
(a) Includes Duke Energy’s effective 50% interest in Crescent subsequent to deconsolidation of Crescent in September 2006.
(b) On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, which primarily included the former Natural Gas Transmission and Field Services business segments.
Equity in Earnings of Unconsolidated Affiliates
(a) For the year ended December 31, 2006, approximately $15 million represents Duke Energy’s effective 50% interest in Crescent earnings subsequent to deconsolidation in September 2006.
(b) Includes equity investments at the corporate level.
(c) Excludes equity in earnings of approximately $0, $609 million and $355 million for the years ended December 31, 2007, 2006 and 2005, respectively, included in (Loss) Income From Discontinued Operations, net of tax, primarily related to equity method investments held by the natural gas businesses and included in Duke Energy’s spin-off of Spectra Energy on January 2, 2007. Additionally, a 50% interest in Southwest Power Partners, LLC, which was in Other, was included in former DENA’s Western United States generation assets that were sold to LS Power during 2006 (see Note 13).
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Summarized Combined Financial Information of Unconsolidated Affiliates
(a) Amounts at December 31, 2006 include equity method investments related the natural gas businesses that were included in the spin-off to shareholders on January 2, 2007.
(a) Amounts for the years ended December 31, 2006 and 2005 include equity investments related to the natural gas businesses that were included in the spin-off to shareholders on January 2, 2007 for which equity earnings are included in (Loss) Income From Discontinued Operations, net of tax, for periods prior to the spin-off. Additionally, amounts for Crescent are included from the date of deconsolidation (September 7, 2006) and thereafter. Also, amounts related to DCP Midstream are included for the respective periods from the date of deconsolidation (July 1, 2005) through the date of the spin-off of the natural gas businesses.
Related Party Transactions. Notes receivable from unconsolidated affiliates, which are included in Receivables on the Consolidated Balance Sheets, were $299 million as of December 31, 2007, which represents Duke Energy Ohio’s and Duke Energy Indiana’s notes receivable from Cinergy Receivables Company LLC (Cinergy Receivables) (see Note 22). Notes receivable from unconsolidated affiliates were $226 million as of December 31, 2006, which represents Duke Energy Ohio’s and Duke Energy Indiana’s $210 million notes receivable from Cinergy Receivables and International Energy’s $16 million note receivable from the Campeche project, a 50% owned joint venture that International Energy ceased involvement with in August 2007. Outstanding notes receivable have interest rates approximating current market rates.
Duke Energy Ohio and Duke Energy Indiana sell their receivables to Cinergy Receivables. During 2007, Duke Energy Ohio and Duke Energy Indiana collectively sold approximately $5.3 billion of receivables to Cinergy Receivables and received approximately $5.1 billion in proceeds from the sales, including the notes receivable. During 2006 (subsequent to the closing of the Cinergy merger in April 2006), Duke Energy Ohio and Duke Energy Indiana collectively sold approximately $3.5 billion of receivables to Cinergy Receivables and received approximately $3.5 billion in proceeds from the sales, including the notes receivable. See Note 22 for further information.
Prior to August 2007, International Energy loaned money to Campeche to assist in the costs to build. International Energy received principal and interest payments of approximately $28 million, $11 million and $5 million from Campeche during 2007, 2006 and 2005, respectively.
Advance SC LLC, which provides funding for economic development projects, educational initiatives, and other programs, was formed during 2004. U.S. Franchised Electric and Gas made donations of approximately $8 million and $24 million to the unconsolidated subsidiary during the years ended December 31, 2007 and 2006, respectively. Additionally, at December 31, 2007 and 2006, U.S. Franchised Electric and Gas had a trade payable to Advance SC LLC of approximately $11 million and $8 million, respectively.
The following related party transactions relate to activity with and among businesses included in the spin-off of the natural gas businesses in January 2007 and are included in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, except where noted:
Natural Gas Transmission had a 50% ownership in two pipeline companies, Gulfstream, an operating pipeline, and Islander East, LLC, a development stage pipeline as well as a 50% ownership in a power plant, McMahon Cogeneration Plant, a cogeneration natural gas fired facility transferred to Natural Gas Transmission from former DENA during 2005. Natural Gas Transmission provided certain administrative
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
and other services to the pipeline companies and the power plant. Natural Gas Transmission recorded recoveries of costs from these affiliates of $19 million, and $12 million during 2006, and 2005, respectively.
In October 2005, Gulfstream issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. The proceeds were used by Gulfstream to pay off a construction loan and the balance of the proceeds, net of transaction costs, of approximately $620 million were distributed to the partners based upon their ownership percentage. Duke Energy received approximately $310 million, which is included in Distributions from Equity Investments within Cash Flows from Investing Activities in the accompanying Consolidated Statements of Cash Flows.
In December 2005, Duke Energy completed a 140 million Canadian dollars initial public offering on its Canadian income trust fund (the Income Fund) and sold 14 million Trust Units at an offering price of 10 Canadian dollars per Trust Unit. In January 2006, a subsequent greenshoe sale of 1.4 million additional Trust Units, pursuant to an overallotment option, were sold at a price of 10 Canadian dollars per Trust Unit. Subsequent to the January 2006 sale of additional Trust Units, Duke Energy held an approximate 58% ownership interest in the businesses of the Income Fund. Proceeds of approximately 14 million Canadian dollars are included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units at a price of 12.15 Canadian dollars per Trust Unit for total proceeds of 104 million Canadian dollars, net of commissions and expenses of other expenses of issuance, which is included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. The sale of approximately 9 million Trust Units reduced Duke Energy’s ownership interest in the businesses of the Income Fund to approximately 46% at December 31, 2006. The Income Fund was included in the spin-off of the natural gas businesses on January 2, 2007. As a result of the sale of additional Trust Units, Duke Energy recognized an approximate $15 million pre-tax gain on the sale of subsidiary stock during the year ended December 31, 2006. The proceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. There were no deferred taxes recorded as a result of this transaction.
In 2005, DCP Midstream formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an initial public offering (IPO) transaction in December 2005 that resulted in net proceeds of approximately $210 million. As a result, DCP Midstream had a 42 percent ownership interest in DCPLP, consisting of a 40 percent limited partner ownership interest and a 2 percent general partner ownership interest. DCP Midstream’s ownership interest in the general partner of DCPLP is 100 percent. The gain on the IPO transaction was deferred by DCP Midstream until DCP Midstream converts its subordinated units in DCPLP to common units.
Field Services sold a portion of its residue gas and NGLs to, purchased raw natural gas and other petroleum products from, and provided gathering and transportation services to unconsolidated affiliates (primarily TEPPCO GP, which was sold in February 2005). Total revenues, purchases and operating expenses from these affiliates were approximately $98 million, $77 million and $1 million, respectively, for the six months ended June 30, 2005.
In July 2005, DCP Midstream was deconsolidated due to the transfer of a 19.7% interest to ConocoPhillips and was subsequently accounted for as an equity method investment (see Note 1). Duke Energy’s 50% of equity in earnings of DCP Midstream for the year ended December 31, 2006 and the period from July 1, 2005 through December 31, 2005 was $574 million and $292 million, respectively. Duke Energy’s investment in DCP Midstream as of December 31, 2006 was $1,166 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets and was included in the spin-off of the natural gas businesses on January 2, 2007. For the year ended December 31, 2006, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DCP Midstream of approximately $137 million, $41 million and $12 million, respectively. As of December 31, 2006, Duke Energy had trade receivables from and trade payables to DCP Midstream amounting to approximately $71 million and $56 million, respectively. Between July 1, 2005 and December 31, 2005, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DCP Midstream of approximately $67 million, $65 million and $12 million, respectively. Additionally, Duke Energy received approximately $725 million and $360 million for its share of distributions paid by DCP Midstream in 2006 and 2005, respectively. Duke Energy recognized an approximate $64 million receivable as of December 31, 2006 due to its share of quarterly tax distributions declared by DCP Midstream in 2006, which was received in the first quarter of 2007. Of these distributions $573 million and $287 million were included in Other, assets within Cash Flows from Operating Activities for the years ended 2006 and 2005, respectively, and approximately $152 million and $73 million were included in Distributions from Equity Investments within Cash Flows from Investing Activities for the years ended 2006 and 2005, respectively, within the accompanying Consolidated Statements of Cash Flows.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Summary Condensed Financial Information
In February 2005, DCP Midstream sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of approximately $1.8 billion. For the three months ended March 31, 2005, TEPPCO LP reported operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61 million, income from continuing operations of approximately $46 million, and net income of approximately $47 million.
Summary financial information for DCP Midstream, which had been accounted for under the equity method from July 1, 2005 through the spin-off of the natural gas businesses on January 2, 2007 is as follows:
DCP Midstream is a limited liability company which is a pass-through entity for U.S. income tax purposes. DCP Midstream also owns corporations who file their own respective federal, foreign and state income tax returns and income tax expense related to these corporations is included in the income tax expense of DCP Midstream. Therefore, DCP Midstream’s net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy recognized the tax impacts of its share of DCP Midstream’s pass-through earnings in (Loss) Income From Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.
Summary financial information for Crescent, which has been accounted for under the equity method since September 7, 2006 is as follows:
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
During the year ended December 31, 2007, Crescent recorded impairment charges on certain of its residential development for which Duke Energy’s proportionate share was approximately $32 million.
Also see Notes 2, 12, 15, 18 and 22 for additional related party information.
12. Impairments, Severance, and Other Charges
International Energy. During the years ended December 31, 2006 and 2005, International Energy recorded other than temporary impairment charges of approximately $50 million and $20 million respectively, related to an investment in Campeche. Campeche project revenues were generated from a GCSA with PEMEX. The charges for the year ended December 31, 2006 consist of a $17 million impairment of the carrying value of the equity method investment, which has been classified within Losses on Sales and Impairments of Equity Investments in the accompanying Consolidated Statements of Operations and a $33 million reserve against notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the accompanying Consolidated Statements of Operations. The charge for the year ended December 31, 2005 consists of a $20 million impairment of the carrying value of the equity method investment, which has been classified within Losses on Sales and Impairments of Equity Investments in the accompanying Consolidated Statements of Operations.
The GCSA expired in August 2007 and ownership of the facility transferred to PEMEX.
Crescent. In the third quarter of 2005, Crescent recognized pre-tax impairment charges of approximately $16 million related to a residential community near Hilton Head Island, South Carolina, that includes both residential lots and a golf club, to reduce the carrying value of the community to its estimated fair value. This impairment was recognized as a component of Impairments and Other Charges in the accompanying Consolidated Statements of Operations. This community incurred higher than expected costs and had been impacted by lower than anticipated sales volume. The fair value of the remaining community assets was determined based upon management’s estimate of discounted future cash flows generated from the development and sale of the community.
Other. See Note 8 for a discussion of the impacts of the DENA exit plan on certain cash flow hedges.
See Note 13 for impairments related to discontinued operations.
Severance and Other Charges. During the year ended December 31, 2007, Duke Energy recorded approximately $20 million of severance charges, primarily under its ongoing severance plan. Of this amount, approximately $12 million related to a voluntary termination program whereby eligible employees were provided a window during which to accept termination benefits. A total of 117 employees accepted the termination benefits during the voluntary window period, which closed in June 2007. Future severance costs under Duke Energy’s ongoing severance plan, if any, are not currently estimable.
During the year ended December 31, 2006, Duke Energy recorded severance liabilities of approximately $134 million related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 2), of which approximately $89 million was charged to expense within income from continuing operations and approximately $45 million was recorded as a component of goodwill. Additionally, in connection with Duke Energy’s spin-off of Spectra Energy, Duke Energy recognized approximately $12 million of severance costs under its ongoing severance plan, which is included in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
As discussed further in Note 13, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, during the year ended December 31, 2005, Duke Energy recorded a severance accrual of approximately $22 million, under its ongoing severance plan, related to the anticipated involuntary termination of former DENA employees. Approximately $2 million of the related pre-tax expense is reflected in Operation, Maintenance and Other and approximately $20 million is reflected in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005. Additionally, Duke Energy offered certain enhanced severance benefits to employees involuntarily terminated in connection with the disposition plan, which were recognized over the remaining service period. Approximately $3 million of enhanced severance benefits were accrued during the fourth quarter of 2005. During 2006, Duke Energy reversed approximately $9 million of previously recorded severance amounts due to a change in estimate. As a result of this exit plan, Duke Energy terminated approximately 210 employees.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
(a) Liability was transferred as part of the spin-off of the natural gas businesses on January 2, 2007.
(b) Severance provisions are expected to be paid within one year from the date that the provision was recorded.
(c) Severance expense included in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations was $0, $3 million and $24 million for 2007, 2006, and 2005, respectively.
(d) Includes minority interest.
Post-Retirement Benefits. In July 2007, Duke Energy offered a voluntary early retirement incentive plan to approximately 1,100 eligible employees. The special termination benefit that was offered was a healthcare reimbursement account that could be used by participants for reimbursement of qualifying medical expenses. There were no severance benefits offered in connection with this plan. The window for acceptance of these voluntary termination benefits closed on August 15, 2007. During the three months ended September 30, 2007, approximately 170 employees accepted the offer and, pursuant to SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Duke Energy recorded a charge of approximately $6 million related to this voluntary plan.
13. Discontinued Operations and Assets Held for Sale
Spin-off of Natural Gas Businesses
As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of Spectra Energy, which principally consisted of Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former 50% ownership interest in DCP Midstream, to Duke Energy shareholders. The results of operations of these businesses are presented in the accompanying Consolidated Statements of Operations as discontinued operations for all periods prior to the spin-off. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. No gain or loss was recognized on the distribution of these operations to Duke Energy shareholders. Approximately $20.5 billion of assets, $14.9 billion of liabilities (which includes approximately $8.6 billion of debt) and $5.6 billion of common stockholders’ equity (which includes approximately $1.0 billion of accumulated other comprehensive income) were distributed from Duke Energy as of the date of the spin-off.
(Loss) Income From Discontinued Operations, net of tax, for the years ended December 31, 2006 and 2005 includes pre-tax interest expense of approximately $600 million and $650 million, respectively, associated with the debt distributed in the spin-off of Spectra Energy. Additionally, (Loss) Income From Discontinued Operations, net of tax, for Duke Energy’s former Spectra Energy operations for the
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
years ended December 31, 2006 and 2005 includes losses of approximately $19 million and $194 million, respectively, which were previously classified in Other, resulting from mark-to-market movements in discontinued hedges at DCP Midstream.
Included in (Loss) Income From Discontinued Operations, net of tax, for the years ended December 31, 2007 and 2006 is a pre-tax amount of approximately $18 million and $60 million, respectively, related to costs to achieve the Spectra Energy spin-off, primarily fees to outside service providers. In the table below, these amounts are included in Other for the year ended December 31, 2007 and in Spectra Energy for the year ended December 31, 2006.
Effective with the spin-off, Duke Energy and Spectra Energy entered into a Transition Services Agreement (TSA), which expired on December 31, 2007, whereby Duke Energy provided certain support services to Spectra Energy. The amount received by Duke Energy during the year ended December 31, 2007 under this TSA was approximately $15 million. Additionally, Duke Energy anticipates that there will be very limited commercial business activities between Duke Energy and Spectra Energy subsequent to the spin-off and Duke Energy does not anticipate significant continuing involvement in the transferred businesses.
Additionally, effective with the spin-off, Duke Energy and Spectra Energy entered into various reinsurance and other related agreements that allocated certain assets to Spectra Energy and DCP Midstream created under insurance coverage provided prior to the spin-off by Duke Energy’s captive insurance subsidiary and third party reinsurance companies. Under these agreements, Spectra Energy’s captive insurance subsidiary reinsured 100% of Duke Energy’s retained risk under the insurance coverage provided prior to the spin-off. Consistent with the terms of the reinsurance agreement entered into while all parties were under the common control of Duke Energy, Duke Energy paid approximately $95 million in cash to Spectra Energy’s captive insurance company, which was placed in a grantor trust to secure Spectra Energy’s obligation to Duke Energy under the Spectra Energy reinsurance agreements. This transfer is reflected in Cash distributed to Spectra Energy within financing activities on the Consolidated Statements of Cash Flows. As of December 31, 2007, Duke Energy has a total liability to Spectra Energy and DCP Midstream related to these agreements of approximately $120 million, which is reflected in both Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. This liability is offset by a corresponding receivable, of which approximately $60 million is due from Spectra Energy’s captive insurance subsidiary under the Spectra Energy reinsurance agreement and approximately $60 million is due from third party reinsurance companies. These amounts are reflected in both Other Current Assets and Other Investments and Other Assets in the Consolidated Balance Sheets. In the event any of the reinsurance companies deny coverage for any of the claims covered under these agreements, Duke Energy is not obligated to pay Spectra Energy or DCP Midstream. Further, Duke Energy is providing no insurance coverage to Spectra Energy or DCP Midstream for events which occur subsequent to the spin-off date.
At December 31, 2007, Duke Energy has an approximate $44 million receivable from Spectra Energy related to certain income tax items.
Also refer to Notes 3, 4, 6, 10, 11, 12, 14, 15, 16, 17, 18, 20 and 21 for additional information related to the spin-off transaction.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The following table summarizes the results classified as (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.
Discontinued Operations (in millions)
(a) Other includes the results for former DENA’s discontinued operations, which were previously reported in the DENA segment.
Amounts in the table above are net of intercompany eliminations between Spectra Energy and the former DENA business, which is included in Other. Intercompany revenues and expenses in 2006 were not material. In 2005, Spectra Energy had intercompany revenues of approximately $36 million, which were expenses of the former DENA business, which is included in Other. All of these amounts eliminate in consolidation.
The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2007 and 2006. Assets held for sale and Liabilities associated with assets held for sale as of December 31, 2007 and 2006 relate to Duke Energy Indiana’s Wabash River Power Station (see Note 2). Additionally, assets held for sale as of December 31, 2006 include certain Duke Energy Ohio trading contracts related to CMT that were sold in 2006 and novated in 2007.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale
As discussed above, the results of operations for all of the businesses transferred to Spectra Energy are presented as discontinued operations for all periods presented. Significant transactions occurring during the years ended December 31, 2007, 2006, and 2005 related to the operations transferred to Spectra Energy and significant transactions within the other operations of Duke Energy that resulted in discontinued operations presentation are discussed below. Transactions under Spectra Energy primarily include transactions at Duke Energy’s former Natural Gas Transmission and Field Services business segments.
Year Ended December 31, 2007
Commercial Power
Due to the expiration of certain tax credits (see Note 17), Duke Energy ceased all synthetic fuel (synfuel) operations as of December 31, 2007. Accordingly, the results of operations for synfuel have been reclassified to discontinued operations for all periods presented. For the year ended December 31, 2007, synfuel operations had after-tax earnings of approximately $23 million, which includes tax credits of approximately $84 million.
International Energy
In February 2007, International Energy finalized the approximate $20 million sale of it 50-percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International. As discussed below, International Energy recorded an impairment charge in 2006 related to certain assets in Bolivia in connection with this sale. As a result of the sale, International Energy no longer has any assets in Bolivia and the results of operations for Bolivia have been reclassified to discontinued operations for all periods presented.
Year Ended December 31, 2006
Spectra Energy
As discussed further below under “Year Ended December 31, 2005,” as a result of the transfer of 19.7% interest in DCP Midstream to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DCP Midstream, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. As a result, approximately $19 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy for the year ended December 31, 2006. Cash settlements on these contracts since the deconsolidation of DCP Midstream on July 1, 2005 of approximately $163 million are classified as a component of Net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2006.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million. In addition, the sale of shares of stock, received as consideration for the settlement of a customer’s transportation contract, resulted in proceeds of approximately $29 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain equivalent to the proceeds received from the sale of stock.
As a result of a settlement of a property insurance claim, proceeds of approximately $30 million were received and a pre-tax gain of $10 million was recognized.
Commercial Power
In June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as certain Duke Energy Ohio trading contracts, to Fortis, a Benelux-based financial services group. In October 2006, the sale transaction was completed. Under the purchase and sale agreement, Fortis purchased CMT at a base price of approximately $210 million. In addition, Fortis paid approximately $200 million for the portfolio of contracts and an amount equal to the estimated net working capital associated with these companies at the time of close. In October 2006, Duke Energy received total pre-tax cash proceeds of approximately $700 million and recorded an approximate $25 million pre-tax gain on the sale. Income tax expense recorded as a result of this transaction relates to the approximate $135 million of goodwill that was not deductible for tax purposes, thus creating a taxable gain that was greater than the gain for book purposes. Results of operations for CMT, as well as certain Duke Energy Ohio trading contracts, have been reflected in (Loss) Income from Discontinued Operations, net of tax, from the date of the Cinergy merger through the date of sale.
In October 2006, in connection with this transaction, Duke Energy entered into a series of TRS with Fortis, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Fortis. The TRS will be cancelled for each underlying contract as each is transferred to Fortis. All economic and credit risk associated with the contracts has been transferred to Fortis as of the date of the sale through the TRS.
As discussed above, due to the expiration of certain tax credits, Duke Energy ceased all synfuel operations as of December 31, 2007. Accordingly, the results of operations for synfuel have been reclassified to discontinued operations for all periods presented. For the year ended December 31, 2006, synfuel operations had after-tax earnings of approximately $3 million, which includes tax credits of approximately $20 million.
International Energy
International Energy had a receivable from Norsk Hydro ASA (Norsk) that related to purchase price adjustments on the 2003 sale of International Energy’s European business. During the first quarter of 2006, International Energy recorded an allowance of approximately $19 million pre-tax ($12 million after-tax) against this receivable. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million pre-tax (approximately $5 million after-tax) write-up of the receivable through a reduction in the valuation allowance. This receivable was collected in July 2006.
In December 2006, International Energy engaged in discussions with a potential buyer of its assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, as discussed above, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International for approximately $20 million. Based upon the agreed selling price of the assets, in December 2006, International Energy recorded pre-tax impairment charges of approximately $28 million. The impairment charges reduced the carrying value of the assets to the estimated selling price pursuant to the aforementioned agreement. International Energy recorded an approximate $25 million income tax benefit associated with the impairment charge, which was recorded within continuing operations as prescribed by SFAS No. 109, “Accounting for Income Taxes.”
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Other
In January 2006, Duke Energy signed an agreement to sell to LS Power former DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 megawatts of power generation located in the Western and northeastern United States. In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments. Additional proceeds of up to approximately $40 million were subject to LS Power obtaining certain state regulatory approvals. On July 20, 2006 the Public Utilities Commission of the State of California approved a toll arrangement related to the Moss Landing facility previously sold to LS Power. In August 2006, LS Power made an additional payment to Duke Energy of approximately $40 million, which was recorded as an additional gain on the sale of assets.
During the first quarter of 2006, Duke Energy acquired the remaining 33 1/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC for approximately $71 million. The assets and liabilities of Bridgeport were included as part of former DENA’s power generation assets, which were sold to a subsidiary of LS Power, as discussed above.
As discussed further below under “Year Ended December 31, 2005,” during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Approximately $700 million was incurred from the announcement date through December 31, 2006, of which approximately $230 million was incurred during the year ended December 31, 2006. As of December 31, 2006 the former DENA exit activities had been substantially complete and no additional material charges were incurred.
In the fourth quarter of 2006, the last remaining contract related to Duke Energy Merchants, LLC (DEM) expired, which completed Duke Energy’s exit from DEM’s operations and triggered presentation within discontinued operations for the years ended December 31, 2006 and 2005.
Year Ended December 31, 2005
Spectra Energy
In August 2005, natural gas storage and pipeline assets in Southwest Virginia, as well as an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage), were acquired from units of AGL Resources for approximately $62 million. This transaction increased the ownership percentage of Saltville Storage to 100%. No goodwill was recorded as a result of this acquisition.
In August 2005, the Empress System natural gas processing and NGL marketing business was acquired from ConocoPhillips for approximately $230 million as part of the transaction with ConocoPhillips discussed further below. No goodwill was recorded as a result of this acquisition.
As a result of the transfer of 19.7% interest in DCP Midstream to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DCP Midstream, Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and were retained as undesignated derivatives until their settlement dates, which had occurred for all instruments prior to December 31, 2006. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. As a result, approximately $314 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy for the year ended December 31, 2005. Of this amount, approximately $120 million was originally recorded in the Field Services segment and approximately $194 million was recorded in Other. Cash settlements on these contracts since the deconsolidation of DCP Midstream on July 1, 2005 of approximately $133 million are classified as a component of Net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2005.
In February 2005, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which was the general partner of TEPPCO Partners, LP (TEPPCO LP), was sold for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP (EPCO), an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion. Minority Interest Expense of $343 million was recorded in the accompanying Consolidated Statements of Operations to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of TEPPCO GP. Additionally, in July 2005, Duke Energy completed the agreement with ConocoPhillips, Duke Energy’s co-equity owner in DCP Midstream, to reduce Duke Energy’s ownership interest in DCP
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Midstream from 69.7% to 50% (the DCP Midstream disposition transaction), which resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DCP Midstream. Duke Energy received, directly and indirectly through its ownership interest in DCP Midstream, a total of approximately $1.1 billion from ConocoPhillips and DCP Midstream, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DCP Midstream disposition transaction resulted in a pre-tax gain of approximately $575 million. The DCP Midstream disposition transaction included the transfer to Duke Energy of DCP Midstream’s Canadian natural gas gathering and processing facilities. Additionally, the DCP Midstream disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DCP Midstream disposition transaction, effective on July 1, 2005, DCP Midstream was no longer consolidated into Duke Energy’s consolidated financial statements and was accounted for by Duke Energy as an equity method investment up until the spin-off of the natural gas businesses on January 2, 2007. The Canadian natural gas gathering and processing facilities and the Empress System were included in the former Natural Gas Transmission segment.
In December 2005, the Duke Energy Income Fund (Income Fund), a Canadian income trust fund, was created to acquire all of the common shares of Duke Energy Midstream Services Canada Corporation (Duke Midstream) from a subsidiary of Duke Energy. The Income Fund sold an approximate 40% ownership interest in Duke Midstream for approximately $110 million, which was included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities on the Consolidated Statements of Cash Flows. In January 2006, a subsequent sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund was sold for approximately $10 million.
Crescent
Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. In 2005, Crescent sold three commercial properties resulting in sales proceeds of approximately $44 million. The $6 million after-tax gain on these sales was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. In September 2006, Duke Energy deconsolidated its investment in Crescent (see Note 2) and subsequently accounts for its investment in the Crescent JV under the equity method of accounting. Prior to the date of deconsolidation, if Crescent did not retain any significant continuing involvement after the sale, Crescent classified the project as “discontinued operations” as required by SFAS No. 144.
Other
In the first quarter of 2005, Duke Energy’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million.
In the third quarter of 2005, Duke Energy completed the sale of Bayside Power L.P. (Bayside) to affiliates of Irving Oil Limited (Irving), under which Irving would purchase Duke Energy’s 75% interest in Bayside. Bayside was consolidated with the adoption of FIN 46R on March 31, 2004. Therefore, operating results for Bayside subsequent to March 31, 2004 are included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.
During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The former DENA assets divested included:
•
Approximately 6,100 MW of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,
•
All remaining commodity contracts related to former DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to former DENA’s Midwestern power generation facilities, and
•
Contracts related to former DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.
The results of operations of former DENA’s Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to former DENA’s energy marketing and management activities and certain general and administrative costs, are required to be classified as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Management retained former DENA’s Midwestern generation assets, consisting of approximately 3,600 MW of power generation, and certain contracts related to the Midwestern generating facilities, as the merger with Cinergy provided a sustainable business model for those assets (see Note 2 for further details on the Cinergy merger). Accordingly, these assets do not qualify for discontinued operations classification and remain in continuing operations as a component of the Commercial Power segment. Also transferred to Commercial Power were the remnants of former DENA’s Southeastern generation operations, including related commodity contracts, which did not meet the requirements for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, management is continuing to wind down the limited remaining operations of DETM, the results of which will be reported in Other’s continuing operations until the wind down of the operations is complete.
In connection with this exit plan, Duke Energy recognized pre-tax losses of approximately $1.1 billion in 2005. These losses principally related to:
•
The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge)
•
The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan
•
Pre-tax impairments of approximately $0.2 billion to reduce the carrying value of the plants that were sold at their estimated fair value less cost to sell. Fair value of the assets sold was estimated based upon the signed agreement with LS Power, as previously discussed.
•
Pre-tax losses of approximately $0.4 billion as the result of selling certain gas transportation and structured contracts (as discussed further below), and
•
Pre-tax deferred gains in AOCI of approximately $0.2 billion related to the discontinued cash flow hedges of forecasted gas purchase and power sale transactions, which were recognized as the forecasted transactions occurred.
As of the September 2005 exit announcement date, management anticipated that additional charges would be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts of approximately $600 million to $800 million, which included approximately $40 million to $60 million of severance, retention and other transaction costs (see Note 12). Included in these amounts were the effects of former DENA’s November 2005 agreement to sell substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to former DENA’s Midwestern power generation facilities, and contracts related to former DENA’s energy marketing and management activities. Excluded from the contracts sold to Barclays were commodity contracts associated with the near-term value of former DENA’s West and Northeastern generation assets and with remaining gas transportation and structured power contracts. Approximately $470 million was incurred during the year ended December 31, 2005, approximately $400 million of which was recognized in (Loss) Income From Discontinued Operations, net of tax.
Among other things, the agreement with Barclays provided that all economic benefits and burdens under the contracts were transferred to Barclays. Cash consideration paid to Barclays amounted to approximately $100 million in 2005 and approximately $600 million in January 2006. Additionally, in January 2006 Barclays provided Duke Energy with cash equal to the net cash collateral posted by former DENA under the contracts of approximately $540 million. The novation or assignment of physical power contracts was subject to FERC approval, which was received in January 2006.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
14. Property, Plant and Equipment
(a) Includes capitalized leases of approximately $183 million for 2007 and $165 million for 2006.
(b) Includes accumulated amortization of nuclear fuel: $485 million for 2007 and $541 million for 2006.
(c) Includes accumulated amortization of capitalized leases: $38 million for 2007 and $33 million for 2006.
(d) Approximately $15.6 billion of gross property, plant and equipment and $3.2 billion of accumulated depreciation was distributed from Duke Energy as part of the spin-off the natural gas businesses on January 2, 2007.
Capitalized interest, which includes the interest expense component of AFUDC, amounted to $71 million for 2007, $56 million for 2006, and $23 million for 2005.
15. Debt and Credit Facilities
Summary of Debt and Related Terms
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
(a) Includes $1,569 million and $1,329 million of Duke Energy pollution control bonds as of December 31, 2007 and 2006, respectively. As of December 31, 2007 and 2006, $361 million and $408 million, respectively, was secured by first and refunding mortgage bonds and $344 million was secured by a letter of credit for both years.
(b) Includes $300 million as of both December 31, 2007 and 2006 that was classified as Long-term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted-average days to maturity were 17 days as of December 31, 2007 and 25 days as of December 31, 2006.
(c) As of December 31, 2007, $571 million of debt was denominated in Brazilian Reals. As of December 31, 2006, $508 million of debt was denominated in Brazilian Reals and $3,820 million of debt was denominated in Canadian dollars.
(d) Weighted-average rates on outstanding short-term notes payable and commercial paper was 5.3% and 5.4% as of December 31, 2007 and December 31, 2006, respectively.
(e) Approximately $8.6 billion of debt included on Duke Energy’s balance sheet at December 31, 2006 was distributed from Duke Energy as part of the spin-off the natural gas businesses on January 2, 2007.
Unsecured Debt. At both December 31, 2007 and 2006, approximately $629 million of pollution control bonds and approximately $300 million of commercial paper, which are short-term obligations by nature, were classified as Long-Term Debt on the Consolidated Balance Sheets due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. Duke Energy’s credit facilities with non-cancelable terms in excess of one year as of the balance sheet date give Duke Energy the ability to refinance these short-term obligations on a long-term basis.
In June 2007, Duke Energy Carolinas issued $500 million principal amount of 6.10% senior unsecured notes due June 1, 2037. The net proceeds from the issuance were used to redeem commercial paper that was issued to repay the outstanding $249 million 6.6% Insured Quarterly Senior Notes due 2022 on April 30, 2007, and approximately $110 million of convertible senior notes discussed below. The remainder was used for general corporate purposes.
In November 2007, Duke Energy Carolinas issued $100 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2040. The initial interest rate was set at 3.65%. The bonds were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Belews Creek and Allen Steam Stations.
In December 2007, Duke Energy Ohio issued $140 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2041. The initial interest rate was set at 4.85%. The bonds were issued through the Ohio Air Quality Development Authority to fund a portion of the environmental capital expenditures at the Conesville, Stuart and Killen Generation Stations in Ohio.
In November 2006, Union Gas Limited (Union Gas) issued 4.85% fixed-rate debenture bonds denominated in 125 million Canadian dollars (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022.This debt was distributed from Duke Energy as part of the spin-off of the natural gas businesses on January 2, 2007 (see Note 1).
In October 2006, Duke Energy Carolinas issued $150 million in tax-exempt floating rate bonds. The bonds are structured as variable rate demand bonds, subject to weekly remarketing and bear a final maturity of 2031. The initial interest rate was set at 3.72%. The bonds are supported by an irrevocable 3-year direct-pay letter of credit and were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Marshall and Belews Creek Steam Stations.
In September 2006, prior to the completion of the joint venture transaction of Crescent, as discussed in Note 2, the Crescent JV, Crescent and Crescent’s subsidiaries borrowed approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a cash inflow within Financing Activities on the Consolidated Statements of Cash Flows and were distributed to Duke Energy. As a result of Duke Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’s Consolidated Balance Sheets.
In September 2006, Union Gas entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%. This debt was included in the spin-off of Spectra Energy on January 2, 2007 (see Note 1). This debt was distributed from Duke Energy as part of the spin-off of the natural gas businesses on January 2, 2007.
In August 2006, Duke Energy Kentucky issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio. Approximately $27 million of floating rate debt was swapped to a fixed rate concurrent with closing.
In June 2006, Duke Energy Indiana issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Convertible Senior Notes. In May 2003, Duke Energy issued approximately $770 million of 1.75% convertible senior notes that were convertible into Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. The conversion of these senior notes into shares of Duke Energy common stock was contingent upon the occurrence of certain events during specified periods. These events included whether the price of Duke Energy common stock reached specified thresholds, the credit rating of Duke Energy fell below certain thresholds, the convertible notes were called for redemption by Duke Energy, or specified transactions had occurred. In addition to the aforementioned events that could trigger early redemption, holders of the senior notes could require Duke Energy to purchase all or a portion of their senior notes for cash on May 15, 2007, May 15, 2012, and May 15, 2017, at a price equal to the principal amount of the senior notes plus accrued interest, if any. Additionally, Duke Energy could redeem, for cash, all or a portion of the senior notes at any time on or after May 20, 2007, at a price equal to the sum of the issue price plus accrued interest, if any, on the redemption date.
During 2006, as a result of the market price of Duke Energy common stock achieving a specified threshold, approximately 27 million shares of common stock were issued related to conversions by holders of the convertible senior notes, which resulted in the retirement of approximately $632 million of convertible senior notes. At December 31, 2006, unsecured debt included approximately $110 million of these convertible senior notes, which were potentially convertible into approximately 4.7 million shares of common stock and included as outstanding shares in the diluted EPS calculation (see Note 19).
On May 15, 2007, pursuant to the terms of the debt agreement, substantially all of the holders of the Duke Energy convertible senior notes required Duke Energy to repurchase the balance then outstanding at a price equal to 100% of the principal amount plus accrued interest. In May 2007, Duke Energy repurchased approximately $110 million of the convertible senior notes. At December 31, 2007, all convertible senior notes had been redeemed.
In connection with the spin-off of Spectra Energy on January 2, 2007 (see Note 1), Duke Energy distributed approximately 2 million shares of Spectra Energy common stock to the holders of the convertible senior notes pursuant to the antidilution provisions of the indenture agreement, resulting in a pre-tax charge of approximately $21 million during the three months ended March 31, 2007, which is recorded in Other Income and Expenses, net in the Consolidated Statements of Operations.
Secured Debt. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $400 million carries an interest rate of 5.25% due January 15, 2018 and $500 million carries an interest rate of 6.00% and matures January 15, 2038. Proceeds from the issuance will be used to fund capital expenditures and for general corporate purposes, including the repayment of commercial paper.
Accounts Receivable Securitization. Duke Energy securitizes certain accounts receivable through Duke Energy Receivables Finance Company, LLC (DERF), a bankruptcy remote, special purpose subsidiary. DERF is a wholly owned limited liability company with a separate legal existence from its parent, and its assets are not intended to be generally available to creditors of Duke Energy. As a result of the securitization, on a daily basis Duke Energy sells certain accounts receivable, arising from the sale of electricity and/or related services as part of Duke Energy’s franchised electric business, to DERF. In order to fund its purchases of accounts receivable, DERF has a $300 million secured credit facility with a commercial paper conduit administered by Citicorp North America, Inc., which terminates in September 2009. The credit facility and related securitization documentation contain several covenants, including covenants with respect to the accounts receivable held by DERF, as well as a covenant requiring that the ratio of Duke Energy consolidated indebtedness to Duke Energy consolidated capitalization not exceed 65%. As of December 31, 2007 and 2006, the interest rate associated with the credit facility, which is based on commercial paper rates, was 5.3% and 5.8%, respectively, and $300 million was outstanding under the credit facility as of both dates. The securitization transaction was not structured to meet the criteria for sale treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and accordingly is reflected as a secured borrowing in the Consolidated Balance Sheets. As of December 31, 2007 and 2006, the $300 million outstanding balance of the credit facility was secured by approximately $532 million and $476 million, respectively, of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy.
Other Assets Pledged as Collateral. As of December 31, 2007, substantially all of U.S. Franchised Electric and Gas’ electric plant in service is mortgaged under the indenture relating to Duke Energy Carolinas’; Duke Energy Ohio’s and Duke Energy Indiana’s various series of first and refunding mortgage bonds.
Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $2.4 billion and $2.7 billion of floating-rate debt as of December 31, 2007 and 2006, respectively, which excludes approximately $571 million and $500 million of Brazilian
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
debt at December 31, 2007 and 2006, respectively, that is indexed annually to Brazilian inflation. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars. As of December 31, 2007 and 2006, the average interest rate associated with floating-rate debt was approximately 4.9% and 4.8%, respectively.
At December 31, 2006, Other debt included approximately $326 million of notes payable related to Cinergy’s Trust Preferred Securities (see Note 22), which matured and was repaid in full in February 2007. The entire outstanding balance of the debt was classified within Current Maturities of Long-term Debt on the Consolidated Balance Sheets at December 31, 2006.
Maturities, Call Options and Acceleration Clauses.
Annual Maturities as of December 31, 2007
(a) Excludes short-term notes payable and commercial paper of $742 million.
Duke Energy has the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than the above as a result of Duke Energy’s ability to repay these obligations prior to their scheduled maturity.
Duke Energy may be required to repay certain debt should the credit ratings at Duke Energy Carolinas fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investors Service (Moody’s). As of December 31, 2007, Duke Energy had $10 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $21 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 1, 2008, Duke Energy Carolinas’ senior unsecured credit rating was A- at S&P and Baa2 at Moody’s.
Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2007, Duke Energy’s consolidated credit capacity decreased by approximately $1,468 million as a result of the spin-off of the natural gas businesses on January 2, 2007. In June 2007, Duke Energy closed on the syndication of an amended and restated credit facility, replacing the existing credit facilities totaling $2.65 billion with a 5-year, $2.65 billion master credit facility. See table below for the borrowing sub limits for specific Duke Energy entities. Concurrent with the syndication of the master credit facility, Duke Energy established a new $1.5 billion commercial paper program at Duke Energy and terminated Cinergy’s previously existing commercial paper program. In addition, the commercial paper program at Duke Energy Carolinas was increased from $650 million to $700 million.
The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.
Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2007, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Credit Facilities Summary as of December 31, 2007 (in millions)
(a) Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.
(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower.
(c) Contains $850 million sub limit for Duke Energy, $800 million sub limit for Duke Energy Carolinas, $500 million sub limit for Duke Energy Ohio, $400 million sub limit for Duke Energy Indiana and a $100 million sub limit for Duke Energy Kentucky, Inc.
(d) This summary excludes certain demand facilities and committed facilities that are immaterial in size or which generally support very specific requirements.
Other Loans. During 2007 and 2006, Duke Energy had loans outstanding against the cash surrender value of the life insurance policies that it owns on the lives of its executives. The amounts outstanding were $367 million as of December 31, 2007 and $594 million as of December 31, 2006. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other Assets on the Consolidated Balance Sheets.
16. Preferred and Preference Stock at Duke Energy
As of December 31, 2007 and 2006, there were 44 million authorized shares of preferred stock, par value $0.001 per share, with no such preferred shares outstanding.
Preferred and Preference Stock of Duke Energy’s Subsidiaries. In connection with the Westcoast Energy, Inc. (Westcoast) acquisition in 2002, Duke Energy assumed approximately $411 million of authorized and issued redeemable preferred and preference shares at Westcoast and Union Gas. Since these preferred and preference shares were redeemable at the option of holder, as well as Westcoast and Union Gas, these preferred and preference shares did not meet the definition of a mandatorily redeemable instrument under SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” As such, these preferred and preference shares were considered contingently redeemable shares and the balance of approximately $225 million was included in Minority Interests on the Consolidated Balance Sheets at December 31, 2006. The obligation associated with these preferred and preference shares was transferred to Spectra Energy in connection with the spin-off of the natural gas businesses on January 2, 2007.
Additionally, in May 2006, Duke Energy redeemed, at par plus accrued and unpaid dividends, approximately $11 million of authorized and issued Duke Energy Indiana preferred stock, which had been acquired by Duke Energy in connection with the Cinergy merger in April 2006.
17. Commitments and Contingencies
General Insurance
Duke Energy carries insurance and reinsurance coverages either directly or through its captive insurance company, Bison, and its affiliates, consistent with companies engaged in similar commercial operations with similar type properties. Duke Energy’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Energy’s operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Duke Energy’s by-laws and (5) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
In 2006, Bison was a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provided property and business interruption reinsurance coverage respectively for Duke Energy’s non-nuclear facilities. Duke Energy accounts for these memberships under the cost method, as it did not have the ability to exert significant influence over these investments. Bison terminated its membership in OIL effective December 31, 2006 and paid a withdrawal premium during 2007 as a result of this decision. sEnergy ceased insuring events subsequent to May 15, 2006 and is currently winding down its operations and settling its outstanding claims. Bison will continue to pay additional premiums to sEnergy as it settles its outstanding claims during its wind-down; however, Duke Energy does not anticipate that the payments associated with the settlement of these outstanding claims will have a material impact on its consolidated results of operations, cash flows or financial position.
Duke Energy also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.
The cost of Duke Energy’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.
Nuclear Insurance
Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to insure against public liability claims resulting from nuclear incidents to the full limit of liability, approximately $10.8 billion.
Primary Liability Insurance. Duke Energy has purchased the maximum available private primary liability insurance as required by law, which is $300 million.
Excess Liability Program. This program currently provides approximately $10.5 billion of coverage through the Price-Anderson Act’s mandatory industry-wide excess secondary financial protection program of risk pooling. The $10.5 billion is the sum of the current potential cumulative retrospective premium assessments of $101 million per licensed commercial nuclear reactor. This would be increased by $101 million for each additional commercial nuclear reactor licensed, or reduced by $101 million for nuclear reactors no longer operational and may be exempted from the risk pooling program. Under this program, licensees could be assessed retrospective premiums to compensate for public liability damages in the event of a nuclear incident at any licensed facility in the U.S. If such an incident should occur and public liability damages exceed primary liability insurance, licensees may be assessed up to $101 million for each of their licensed reactors, payable at a rate not to exceed $15 million a year per licensed reactor for each incident. The assessment and rate are subject to indexing for inflation and may be subject to state premium taxes.
Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which provides property and accidental outage insurance coverage for Duke Energy’s nuclear facilities under three policy programs:
Primary Property Insurance. This policy provides $500 million of primary property damage coverage for each of Duke Energy’s nuclear facilities.
Excess Property Insurance. This policy provides excess property, decontamination and decommissioning liability insurance: $2.25 billion for the Catawba Nuclear Station and $1.0 billion each for the Oconee and McGuire Nuclear Stations. The Oconee and McGuire Nuclear Stations also share an additional $1.0 billion insurance limit above this excess. This shared limit is not subject to reinstatement in the event of a loss.
Accidental Outage Insurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each McGuire and Catawba unit is insured for up to $3.5 million per week, and the Oconee units are insured for up to $2.8 million per week. Coverage amounts decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period for Catawba and a 26-week deductible period for McGuire and Oconee and continues at 100% for 52 weeks and 80% for the next 110 weeks. The McGuire and Catawba policy limit is $490 million and the Oconee policy limit is $392 million.
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In the event of large industry losses, NEIL’s Board of Directors may assess Duke Energy for amounts up to 10 times its annual premiums. The current potential maximum assessments are: Primary Property Insurance-$38 million, Excess Property Insurance-$43 million and Accidental Outage Insurance-$22 million.
Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident, and second, to decontaminate before any proceeds can be used for decommissioning, plant repair or restoration.
In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material adverse effect on Duke Energy’s results of operations, cash flows or financial position.
The maximum assessment amounts include 100% of Duke Energy’s potential obligation to NEIL for the Catawba Nuclear Station. However, the other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of liability for retrospective premiums and other premium assessments resulting from the Price-Anderson Act’s excess secondary financial protection program of risk pooling, or the NEIL policies.
Environmental
Duke Energy is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on Duke Energy.
Remediation activities. Duke Energy and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy operations, sites formerly owned or used by Duke Energy entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Energy or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Duke Energy believes that completion or resolution of these matters will have no material adverse effect on its consolidated results of operations, cash flows or financial position.
Clean Water Act 316(b). The U.S. Environmental Protection Agency (EPA) finalized its cooling water intake structures rule in July 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Fourteen of the 23 coal and nuclear-fueled generating facilities in which Duke Energy is either a whole or partial owner are affected sources under that rule. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) et. al. (2d Cir. 2007) remanding most aspects of EPA’s rule back to the agency. The court effectively disallowed those portions of the rule most favorable to industry, and the decision creates a great deal of uncertainty regarding future requirements and their timing. Duke Energy is still unable to estimate costs to comply with the EPA’s rule, although it is expected that costs will increase as a result of the court’s decision. The magnitude of any such increase cannot be estimated at this time.
Clean Air Mercury Rule (CAMR) and Clean Air Interstate Rule (CAIR). The EPA finalized its CAMR and CAIR in May 2005. The CAMR was to have limited total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program beginning in 2010. The CAIR limits total annual and summertime NOx emissions and annual SO2 emissions from electric generating facilities across the Eastern United States through a two-phased cap-and-trade program. Phase 1 begins in 2009 for NOx and in 2010 for SO2. Phase 2 begins in 2015 for both NOx and SO2.
The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with CAIR requirements (see Note 4). In addition, Duke Energy currently estimates that its Midwest electric operations will spend approximately $300 million between 2008 and 2012 to comply with Phase 1 of CAIR and approximately $200 million for CAIR Phase 2 compliance costs over the period 2008-2017. The IURC issued an order in 2006 granting Duke Energy Indiana approximately
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$1.07 billion in rate recovery to cover its estimated Phase 1 compliance costs of CAIR/CAMR in Indiana. Duke Energy Ohio receives partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its RSP.
On February 8, 2008 the U.S. Court of Appeals for the District of Columbia issued its opinion in New Jersey v. EPA, No. 05-1097 vacating the CAMR. The decision creates uncertainty regarding future mercury emission reduction requirements and their timing. Barring reversal of the decision if appealed, there will be a delay in the implementation of federal mercury requirements for existing coal-fired power plants while EPA conducts a new rulemaking. Duke Energy is unable to estimate the costs to comply with a new EPA rule, although it is expected that costs will increase as a result of the court’s decision. The magnitude of any such increase cannot be estimated at this time.
Coal Combustion Product (CCP) Management. Duke Energy currently estimates that it will spend approximately $300 million over the period 2008-2012 to install synthetic caps and liners at existing and new CCP landfills and to convert CCP handling systems from wet to dry systems.
Extended Environmental Activities and Accruals. Included in Other Deferred Credits and Other Liabilities and Other Current Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $52 million and $73 million as of December 31, 2007 and 2006, respectively. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Duke Energy believes that completion or resolution of these matters will have no material impact on its consolidated results of operations, cash flows or financial position.
Litigation
As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. Accordingly, contingent litigation and claims associated with the natural gas businesses were transferred to Spectra Energy effective with the spin-off and Duke Energy has no future obligation associated with such matters.
New Source Review (NSR). In 1999-2000, the U.S. Justice Department, acting on behalf of the EPA, filed a number of complaints and notices of violation against multiple utilities across the country for alleged violations of the NSR provisions of the Clean Air Act (CAA). Generally, the government alleges that projects performed at various coal-fired units were major modifications, as defined in the CAA, and that the utilities violated the CAA when they undertook those projects without obtaining permits and installing the best available emission controls for SO2, NOx and particulate matter. The complaints seek injunctive relief to require installation of pollution control technology on various allegedly violating generating units, and unspecified civil penalties in amounts of up to $27,500 per day for each violation. A number of Duke Energy’s owned and operated plants have been subject to these allegations and lawsuits. Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions.
In 2000, the government brought a lawsuit against Duke Energy in the U.S. District Court in Greensboro, North Carolina. The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units in the Carolinas violate these NSR provisions. In August 2003, the trial court issued a summary judgment opinion adopting Duke Energy’s legal positions on the standard to be used for measuring an increase in emissions, and granted judgment in favor of Duke Energy. The trial court’s decision was appealed and ultimately reversed and remanded for trial by the United States Supreme Court. At trial, Duke Energy will continue to assert that the projects were routine or not projected to increase emissions. No trial date has been set.
In November 1999, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana against Cinergy, Duke Energy Ohio, and Duke Energy Indiana alleging various violations of the CAA for various projects at six of Duke Energy owned and co-owned generating stations in the Midwest. Additionally, the suit claims that Duke Energy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s State Implementation Plan (SIP) provisions governing particulate matter at Unit 1 at Duke Energy Ohio’s W.C. Beckjord Station. In addition, three northeast states and two environmental groups have intervened in the case. In June 2007, the trial court ruled, as a matter of law, that 11 of 23 projects undertaken at the units do not qualify for the “routine” exception in the regulations. The court ruled further that the defendants had “fair notice” of EPA’s interpretation of the applicable regulations. The defendants filed motions for reconsideration, which were denied. A jury trial has been set to commence on May 5, 2008.
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In March 2000, the United States also filed suit in the United States District Court for the Southern District of Ohio an amended complaint in a separate lawsuit alleging violations of the CAA regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and Duke Energy Ohio. This suit is being defended by CSP (the CSP case). A trial on liability issues was conducted in July 2005. On October 9, 2007, CSP announced a settlement of its case. The settlement includes commitments by CSP to construct environmental equipment or otherwise to reduce emissions at certain plants and the payment of penalties and money to various environmental projects. Duke Energy does not expect the settlement to have a material impact on its consolidated results of operations, cash flows, or financial position. In addition, Cinergy and Duke Energy Ohio have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of CAA requirements at a station operated by DP&L and jointly-owned by DP&L, CSP, and Duke Energy Ohio. The NOV indicated the EPA may issue an order requiring compliance with the requirements of the Ohio SIP, or bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against Duke Energy Ohio, DP&L and CSP for alleged violations of the CAA at this same generating station. On December 14, 2007, the Court ordered a stay of the litigation for sixty days pending settlement negotiations among the parties. A trial has been set to commence in August 2008.
Other than the CSP case, it is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these matters. Ultimate resolution of these matters, even in settlement, could have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position. However, Duke Energy will pursue appropriate regulatory treatment for any costs incurred in connection with such resolution.
Carbon Dioxide (CO2) Litigation. In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. A similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO2 from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO2. The plaintiffs are seeking an injunction requiring each defendant to cap its CO2 emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the District Court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. Oral arguments were held before the Second Circuit Court of Appeals on June 7, 2006. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.
Hurricane Katrina Lawsuit. In April 2006, Duke Energy and Cinergy were named in the third amended complaint of a purported class action lawsuit filed in the United States District Court for the Southern District of Mississippi. Plaintiffs claim that Duke Energy and Cinergy, along with numerous other utilities, oil companies, coal companies and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that defendants’ greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. In October 2006, Duke Energy and Cinergy were served with this lawsuit. On August 30, 2007, the court dismissed the case. The plaintiffs have filed their appeal to the Fifth Circuit Court of Appeals. Briefing is ongoing in the Fifth Circuit. It is not possible to predict with certainty whether Duke Energy or Cinergy will incur any liability or to estimate the damages, if any, that Duke Energy or Cinergy might incur in connection with this matter.
San Diego Price Indexing Cases. Duke Energy and several of its affiliates, as well as other energy companies, have been parties to 25 lawsuits which have been coordinated as the “Price Indexing Cases” in San Diego, California. Twelve of the lawsuits sought class-action certification. The plaintiffs allege that the defendants conspired to manipulate the price of natural gas in violation of state and/or federal antitrust laws, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information, resulted in artificially high energy prices. In December 2006, Duke Energy executed an agreement to settle the 12 class action cases. In June 2007, judgment granting final approval to the class action settlement was entered. The settlement did not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position. In December 2007, Duke Energy reached a settlement in principle to settle the remaining 13 cases, subject to the negotiation and execution of a settlement agreement, which was executed in February 2008. The proposed settlement will not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.
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Other Price Reporting Cases. A total of 12 lawsuits have been filed against Duke Energy affiliates and other energy companies. Seven of these cases were dismissed on filed rate and/or federal preemption grounds, and the plaintiffs in each of these dismissed cases appealed their respective rulings. On September 24, 2007, the Ninth Circuit reversed the prior rulings and remanded four of the cases to the District Court for further proceedings. Defendants request for reconsideration was denied. In July 2007, the judge in two of the cases reconsidered and reversed his prior ruling dismissing the cases. The seventh case was appealed to the Tennessee Court of Appeals, where oral argument was heard in November 2007 and a decision is pending. In February 2008, the judge in one of the cases granted a motion to dismiss and entered judgment in favor of DETM. Each of these cases contains similar claims, that the respective plaintiffs, and the classes they claim to represent, were harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and entering into unlawful arrangements and agreements in violation of the antitrust laws of the respective states. Plaintiffs seek damages in unspecified amounts. Duke Energy is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to these matters at this time.
Western Electricity Litigation. Plaintiffs, on behalf of themselves and others, in three lawsuits allege that Duke Energy affiliates, among other energy companies, artificially inflated the price of electricity in certain western states. Two of the cases were dismissed and plaintiffs appealed to the U.S. Court of Appeal for the Ninth Circuit. Of those two cases, one was dismissed by agreement in March 2007. Oral arguments in the other case was heard before the U.S. Ninth Circuit Court of Appeals in April 2007. In November 2007 the court issued an opinion affirming dismissal and plaintiffs filed a motion for rehearing. In December 2006, a fourth case, the single remaining electricity case pending in California state court was dismissed. Plaintiffs in these cases seek damages in unspecified amounts. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but Duke Energy does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.
Trading Related Investigations. Beginning in February 2004, Duke Energy has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Energy has cooperated with the government in this investigation and is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to this matter at this time.
ExxonMobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, ExxonMobil) filed a Demand for Arbitration against Duke Energy, DETMI Management Inc. (DETMI), DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Energy. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, ExxonMobil alleged that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. ExxonMobil sought to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were specified at the arbitration hearing and totaled approximately $125 million (excluding interest). Duke Energy denied these allegations and filed counterclaims asserting that ExxonMobil breached its Venture obligations and other contractual obligations. In March 2007, Duke Energy and ExxonMobil executed a settlement agreement for global settlement of both parties’ claims. The resolution of this matter did not have a material effect on Duke Energy’s consolidated results of operations, cash flows or financial position. The gas supply agreements with other parties, under which DEMLP continues to remain obligated, are currently estimated to result in losses of up to approximately $70 million through 2011. As Duke Energy has an ownership interest of approximately 60% in DEMLP, only 60% of any losses would impact pre-tax earnings for Duke Energy. However, these losses are subject to change in the future in the event of changes in market conditions and underlying assumptions.
Cherokee County Property Litigation. Duke Energy Carolinas filed suit in July 2005 seeking specific performance of its asserted contract to purchase approximately 2,000 acres of land in Cherokee County, South Carolina and asking for a declaratory judgment to establish that a contract for sale existed. Defendants counterclaimed for slander of title and abuse of process. In December 2005, the court dismissed Duke Energy Carolinas’ claims and Defendants’ amended their counterclaims. As amended, Defendants’ counterclaims alleged slander of title, abuse of process, tortuous interference with prospective contracts of others in the energy market and tortuous interference with contract. A hearing on Duke Energy Carolinas’ Motion for Summary Judgment was held in April 2007 and the judge ruled in May 2007 dismissing Defendants’ slander of title claims. On May 30, 2007, the parties settled this matter. The resolution of this matter did not have a material effect on Duke Energy’s consolidated results of operations, cash flows or financial position.
Duke Energy Retirement Cash Balance Plan. A class action lawsuit was filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan, alleging violations of Employee Retirement Income Security Act (ERISA) and the Age
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Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Energy Company Employees’ Retirement Plan into the Duke Energy Retirement Cash Balance Plan. The case also raises some Plan administration issues, alleging errors in the application of Plan provisions (e.g., the calculation of interest rate credits in 1997 and 1998 and the calculation of lump-sum distributions). The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. The plaintiffs also seek to divide the putative class into sub-classes based on age. Six causes of action are alleged, ranging from age discrimination, to various alleged ERISA violations, to allegations of breach of fiduciary duty. The plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. Duke Energy filed its answer in March 2006. A second class action lawsuit was filed in federal court in South Carolina, alleging similar claims and seeking to represent the same class of defendants. The second case has been voluntarily dismissed, without prejudice, effectively consolidating it with the first case. A portion of this contingent liability was assigned to Spectra Energy in connection with the spin-off in January 2007. A hearing on the plaintiffs’ motion to amend the complaint to add additional age discrimination claim, defendant’s motion to dismiss and the respective motions for summary judgment was held in December 2007 and a decision is pending. The matter is currently in discovery with a tentative trial date in July 2008. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.
Ohio Antitrust Lawsuit. In January, 2008, four plaintiffs, including individual, industrial and non-profit customers, filed a lawsuit against Duke Energy in federal court in the Southern District of Ohio. Plaintiffs allege that Duke Energy (then Cinergy and The Cincinnati Gas & Electric Company (CG&E)), conspired to provide inequitable and unfair price advantages for certain large business consumers by entering into non-public option agreements with such consumers in exchange for their withdrawal of challenges to Duke Energy Ohio’s (then CG&E’s) pending RSP, which was implemented in early 2005. Duke Energy strongly denies the allegations made in the lawsuit and intends to defend itself vigorously. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.
Alaskan Global Warming Lawsuit. On February 26, 2008, plaintiffs filed suit against Peabody Coal and various oil and power company defendants, including Duke Energy and certain of its subsidiaries. Plaintiffs, the governing bodies of an Inupiat village in Alaska, brought the action on their own behalf and on behalf of the village’s approximately 400 residents. The lawsuit alleges that defendants’ emissions of carbon dioxide contributed to global warming and constitute a private and public nuisance. Plaintiffs also allege that certain defendants, including Duke Energy, conspired to mislead the public with respect to the global warming. Plaintiffs seek unspecified monetary damages, attorneys fees and expenses. Duke Energy has not yet been served with this lawsuit. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.
Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims for indemnification and medical cost reimbursement relating to damages for bodily injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas on its electric generation plants prior to 1985.
Amounts recognized as asbestos-related reserves related to Duke Energy Carolinas in the Consolidated Balance Sheets totaled approximately $1,082 million and $1,159 million as of December 31, 2007 and 2006, respectively, and are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities. These reserves are based upon the minimum amount in Duke Energy’s best estimate of the range of loss of $1,082 million to $1,350 million for current and future asbestos claims through 2027. The reserves balance of $1,082 million as of December 31, 2007 consists of approximately $182 million related to known claimants and approximately $900 million related to unknown claimants. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe that they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change our estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside our control, management believes that it is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.
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Duke Energy has a third-party insurance policy to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Through December 31, 2007, Duke Energy has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy is not aware of any uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier.
Duke Energy Indiana and Duke Energy Ohio have also been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. The impact on Duke Energy’s consolidated results of operations, cash flows, or financial position of these cases to date has not been material. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana and Duke Energy Ohio generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the foreseeable future is not material. This estimated range of exposure may change as additional settlements occur and claims are made and more case law is established.
EI UK Holdings, Inc. Settlement. In March, 2004, EI UK Holdings, Inc., a subsidiary of FirstEnergy Corp, filed a complaint in Ohio State Court. The complaint alleged that Cinergy, and an affiliate, had breached certain agreements and sought indemnification from Cinergy. The case went to trial and on February 14, 2008, the jury returned a verdict in favor of EI UK Holdings and against Cinergy and its affiliate and awarded EI UK Holdings $15 million, plus interest.
Other Litigation and Legal Proceedings. Duke Energy and its subsidiaries are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve substantial amounts. Duke Energy believes that the final disposition of these proceedings will not have a material adverse effect on its consolidated results of operations, cash flows or financial position.
Duke Energy has exposure to certain legal matters that are described herein. As of December 31, 2007 and 2006, Duke Energy has recorded reserves, including reserves related to the aforementioned asbestos-related injuries and damages claims, of approximately $1.1 billion and $1.3 billion, respectively, for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of December 31, 2007, Duke Energy has recognized approximately $1,040 million of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”
Duke Energy expenses legal costs related to the defense of loss contingencies as incurred.
Litigation Matters Transferred to Spectra Energy
As previously discussed, contingent litigation and claims associated with the natural gas businesses were transferred to Spectra Energy effective with the spin-off and Duke Energy has no future obligation associated with such matters. The following matters, which were transferred by Duke Energy as part of the spin-off and subsequently settled by Spectra Energy in 2007, impacted Duke Energy’s consolidated results of operations during the year ended December 31, 2006:
Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG) claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach, on the other hand, claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $250 million. In 2003, an arbitration tribunal issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The final hearing on damages was concluded in March 2006, and the tribunal issued its award on damages on November 30, 2006. Duke LNG was awarded approximately $20 million, plus interest, for Sonatrach’s breach of its shipping obligations. Sonatrach and Sonatrading were awarded an unspecified amount that management believes will, when calculated, be substantially less than the amount awarded to Duke LNG, and result ultimately in a net positive, but immaterial, award to Duke LNG. This matter was assigned to Spectra Energy in connection with the spin-off in January 2007.
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Notes To Consolidated Financial Statements-(Continued)
Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $190 million (excluding interest). This matter and the financial obligation of any settlement or judgment were assigned to Spectra Energy in connection with the spin-off in January 2007. In January 2007 Spectra Energy and Citrus settled this litigation for a payment by Spectra Energy to Citrus of $100 million. As a result, in 2006, Duke Energy recognized a reserve of $100 million related to the settlement offer.
Other Commitments and Contingencies
Commercial Power produced synfuel from facilities that qualified for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code if certain requirements were satisfied. Section 29/45K provided for a phase-out of the credit if the average price of crude oil during a calendar year exceeded a specified threshold. The phase-out was based on a prescribed calculation and definition of crude oil prices. The exposure to synfuel tax credit phase-out was monitored as Duke Energy was able to reduce or cease synfuel production based on the expectation of any potential tax credit phase-out. The objective of these activities was to reduce potential losses incurred if the reference price in a year exceeded a level triggering a phase-out of synfuel tax credits.
These credits reduced Duke Energy’s income tax liability and, therefore, Duke Energy’s tax expense recorded in (Loss) Income From Discontinued Operations, net of tax (see Note 13). Commercial Power’s sale of synfuel had generated $339 million in tax credits through December 31, 2005. After reducing for the possibility of phase-out, the amount of additional credits generated during the years ended December 31, 2007 and 2006 were approximately $84 million and $20 million, respectively. Duke Energy ceased production of synfuel upon the expiration of the tax credits at the end of 2007.
The Internal Revenue Service (IRS) has completed the audit of Cinergy for the 2002, 2003, and 2004 tax years, including the synfuel facility owned during that period, which represents $222 million of tax credits generated during the aforementioned audit period. The IRS has not proposed any adjustment that would disallow the credits claimed during that period. Subsequent periods are still subject to audit. Duke Energy believes that it operated in conformity with all the necessary requirements to be allowed such credits under Section 29/45K.
Duke Energy was party to an agreement with a third party service provider related to certain future purchases. The agreement, which was amended and extended in September 2007, contained certain damage payment provisions if qualifying purchases were not initiated by September 2008. In the fourth quarter of 2006, Duke Energy initiated early settlement discussions regarding this agreement and recorded a reserve of approximately $65 million. During the year ended December 31, 2007, Duke Energy paid the third party service provider approximately $20 million, which directly reduced Duke Energy’s future exposure under the agreement, and further reduced the reserve by $45 million based upon qualifying purchase commitments that, once satisfied, fulfills Duke Energy’s obligations under the agreement. Accordingly, at December 31, 2007, there was no remaining reserve associated with this agreement.
In October 2006, Duke Energy began an internal investigation into improper data reporting to the EPA regarding air emissions under the NOx Budget Program at Duke Energy’s DEGS of Narrows, L.L.C. power plant facility in Narrows, Virginia. The investigation has revealed evidence of falsification of data by an employee relating to the quality assurance testing of its continuous emissions monitoring system to monitor heat input and NOx emissions. In December 2006, Duke Energy voluntarily disclosed the potential violations to the EPA and Virginia Department of Environmental Quality (VDEQ), and in January 2007, Duke Energy made a full written disclosure of the investigation’s findings to the EPA and the VDEQ. In December 2007, the EPA issued a notice of violation. Duke Energy has taken appropriate disciplinary action, including termination, with respect to the employees involved with the false reporting. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Other. As part of its normal business, Duke Energy is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. For further information see Note 18.
In addition, Duke Energy enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions.
See Note 18 for discussion of Calpine guarantee obligation.
Operating and Capital Lease Commitments
Duke Energy leases assets in several areas of its operations. Consolidated rental expense for operating leases included in income from continuing operations was $138 million in 2007, $110 million in 2006 and $66 million in 2005, which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Consolidated rental expense for operating leases included in (Loss) Income From Discontinued Operations, net of tax, was $36 million in 2006 and $53 million in 2005. Amortization of assets recorded under capital leases was included in Depreciation and Amortization on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases, which at inception had a noncancelable term of more than one year, and capital leases as of December 31, 2007:
18. Guarantees and Indemnifications
Duke Energy and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Energy and its subsidiaries enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.
As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. Guarantees that were issued by Duke Energy, Cinergy or International Energy or were assigned to Duke Energy prior to the spin-off remained with Duke Energy subsequent to the spin-off. Guarantees issued by Spectra Energy Capital or its affiliates prior to the spin-off remained with Spectra Energy Capital subsequent to the spin-off, except for certain guarantees discussed below that are in the process of being assigned to Duke Energy. During this assignment period, Duke Energy has indemnified Spectra Energy Capital against any losses incurred under these guarantee obligations.
Duke Energy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly-owned entities, as well as guarantees of debt of certain non-consolidated entities and less than wholly-owned consolidated entities. If such entities were to default on payments or performance, Duke Energy would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. The maximum potential amount of future payments Duke Energy could have been required to make under these guarantees as of December 31, 2007 was approximately $547 million. Approximately $404 million of the guarantees expire between 2008 and 2039, with the remaining performance guarantees having
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Notes To Consolidated Financial Statements-(Continued)
no contractual expiration. In addition, Spectra Energy Capital is in the process of assigning performance guarantees with maximum potential amounts of future payments of approximately $123 million to Duke Energy, as discussed above. Duke Energy has indemnified Spectra Energy Capital for any losses incurred as a result of these guarantees during the assignment period.
Duke Energy uses bank-issued stand-by letters of credit to secure the performance of non-wholly-owned entities to a third party or customer. Under these arrangements, Duke Energy has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly-owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Energy could have been required to make under these letters of credit as of December 31, 2007 was approximately $20 million. Substantially all of these letters of credit were issued on behalf of less than wholly-owned consolidated entities and non-consolidated entities and expire in 2008.
Duke Energy has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly-owned entity to honor its obligations to a third party. As of December 31, 2007, Duke Energy had guaranteed approximately $141 million of outstanding surety bonds related to obligations of non-wholly-owned entities, of which approximately $136 million relates to projects at Crescent. The majority of these bonds expire in various amounts in 2008; however, Duke Energy has a bond indemnity obligation through September 2009 for the Crescent projects related to these outstanding bonds.
Additionally, Duke Energy has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Energy but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Energy related to the DukeSolutions guarantees. Further, Duke Energy granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2008 to 2019, with others having no specific term. The maximum potential amount of future payments under these guarantees as of December 31, 2007 was approximately $72 million.
In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Energy. A subsidiary of Duke Energy unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and a subsidiary of Duke Energy remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of December 31, 2007 is approximately $200 million, including principal and interest payments. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2007, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2007. No demands for payment of principal and interest have been made under the guarantee. This guarantee remained with Spectra Energy Capital subsequent to the spin-off and will not be assigned to Duke Energy; however, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee. In January 2008, Calpine Corporation announced that it had successfully emerged from Chapter 11 bankruptcy protection and officially concluded its Chapter 11 reorganization.
Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’s potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Energy is unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.
At December 31, 2007, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
19. Earnings Per Share
Basic EPS is computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing earnings available for common stockholders, as adjusted, by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards, contingently convertible debt and phantom stock awards, were exercised, settled or converted into common stock.
The following tables illustrate Duke Energy’s basic and diluted EPS calculations and reconcile the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2007, 2006, and 2005.
The increase in weighted-average shares outstanding for the year ended December 31, 2007 compared to the same period in 2006 was due primarily to the April 2006 issuance of approximately 313 million shares in conjunction with the merger with Cinergy (see Note 1), the conversion of debt into approximately 27 million shares of Duke Energy common stock during the year ended December 31, 2006 (see Note 15), and the repurchase and retirement of approximately 17.5 million shares of Duke Energy common stock during the year ended December 31, 2006.
As of December 31, 2007, 2006 and 2005, approximately 13 million, 14 million and 19 million, respectively, of options, unvested stock, performance and phantom stock awards were not included in the “effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.
20. Stock-Based Compensation
Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
the requisite service period. Prior to the adoption of SFAS No. 123(R), Duke Energy applied APB 25 and FIN 44, and provided the required pro forma disclosures of SFAS No. 123. Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.
Duke Energy elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts from the year ended December 31, 2005 presented in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS No. 123(R).
The following table shows what earnings available for common stockholders, basic earnings per share and diluted earnings per share would have been if Duke Energy had applied the fair value recognition provisions of SFAS No. 123(R) to all stock-based compensation awards during the year ended December 31, 2005.
Pro Forma Stock-Based Compensation
Duke Energy’s 2006 Long-term Incentive Plan (the 2006 Plan), approved by shareholders in October 2006, reserved 60 million shares of common stock for awards to employees and outside directors. The 2006 Plan supersedes Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), and no additional grants will be made from the 1998 Plan. Under the 2006 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards. In 2008, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards which are exercised or vested. Duke Energy has not determined with certainty the amount of such new share issuances or open market repurchases.
Impact of Spin-off on Equity Compensation Awards
As discussed in Note 1, on January 2, 2007, Spectra Energy was spun off by Duke Energy to its shareholders. In connection with this transaction, Duke Energy distributed substantially all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock.
Effective with the spin-off, all previously granted Duke Energy long-term incentive plan equity awards were split into Duke Energy and Spectra Energy equity-related awards, consistent with the spin-off conversion ratio. Each equity award (stock option, phantom share, performance share and restricted stock award) was split into two awards: a Duke Energy award (issued by Duke Energy in Duke Energy shares) and a Spectra Energy award (issued by Spectra Energy in Spectra Energy shares). The number of shares covered by the adjusted Duke Energy award equals the number of shares covered by the original award, and the number of shares covered by the Spectra Energy award equals the number of shares that would have been received in the spin-off by a non-employee shareholder (which reflected the one-half share of Spectra Energy common stock for every share of Duke Energy common stock distribution ratio for Spectra Energy shares).
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Stock option exercise prices were adjusted using a formula approved by the Duke Energy Compensation Committee that was designed to preserve the exercise versus market price spread (whether “in the money” or “out of the money”) of each option. All equity award adjustments were designed to equalize the fair value of each award before and after the spin-off. Accordingly, no material incremental compensation expense was recognized as a result of the equity award adjustments.
Duke Energy’s future stock-based compensation expense will not be significantly impacted by the equity award adjustments that occurred as a result of the spin-off. Stock-based compensation expense recognized in future periods will correspond to the unrecognized compensation expense as of the date of the spin-off. Unrecognized compensation expense as of the date of the spin-off reflects the unamortized balance of the original grant date fair value of the equity awards held by Duke Energy employees (regardless of whether those awards are linked to Duke Energy stock or Spectra Energy stock). No future compensation cost will be recognized by Duke Energy for equity awards held by Spectra Energy employees.
Duke Energy recorded pre-tax stock-based compensation expense included in Income From Continuing Operations for the years ended December 31, 2007, 2006 and 2005 as follows, the components of which are further described below:
The tax benefit associated with the recorded expense in Income From Continuing Operations for the years ended December 31, 2007, 2006 and 2005 was approximately $15 million, $24 million and $14 million, respectively. There were no material differences in income from continuing operations, income tax expense, net income, cash flows, or basic and diluted earnings per share from the adoption of SFAS No. 123(R). As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to its shareholders, and the results of these businesses are presented as discontinued operations. Accordingly, pre-tax stock-based compensation expense of approximately $18 million and $10 million for the years ended December 31, 2006 and 2005, respectively, are included in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. A corresponding tax benefit of approximately $7 million and $3 million for the years ended December 31, 2006 and 2005, respectively, are included in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.
Stock Option Activity
(a) Weighted-average exercise prices reflect the adjusted prices that resulted from the spin-off of Spectra Energy, as discussed above.
On December 31, 2006 and 2005, Duke Energy had approximately 22 million exercisable options with a weighted-average exercise price of $17 and $18, respectively. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was approximately $26 million, $46 million and $17 million, respectively. Cash received from options exercised during the year
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
ended December 31, 2007 was approximately $50 million, with a related tax benefit of approximately $10 million. Cash received from options exercised during the year ended December 31, 2006 was approximately $127 million, with a related tax benefit of approximately $17 million. Cash received from options exercised during the year ended December 31, 2005 was approximately $40 million, with a related tax benefit of approximately $6 million. At December 31, 2007, Duke Energy had approximately $2 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.1 years.
There were no option grants during the twelve months ended December 31, 2007. Duke Energy granted 1,877,646 options (fair value of approximately $10 million based on a Black-Scholes model valuation) during the year ended December 31, 2006. There were no options granted during the year ended December 31, 2005. Remaining compensation expense to be recognized for unvested converted Cinergy options was determined using a Black-Scholes model.
Weighted-Average Assumptions for Option Pricing
(1) The risk free rate is based upon the U.S. Treasury Constant Maturity rates as of the grant date.
(2) The expected dividend yield is based upon annualized dividends and the 1-year average closing stock price.
(3) The expected term of options is derived from historical data.
(4) Volatility is based upon 50% historical and 50% implied volatility. Historic volatility is based on the weighted average between Duke Energy and Cinergy historical volatility over the expected life using daily stock prices. Implied volatility is the average for all option contracts with a term greater than six months using the strike price closest to the stock price on the valuation date.
The 2006 Plan allows for a maximum of 15 million shares of common stock to be issued under various stock-based awards other than options and stock appreciation rights. Payments for cash settled awards during the year ended December 31, 2007 were immaterial.
Phantom Stock Awards
Phantom stock awards outstanding under the 2006 Plan generally vest over periods from immediate to three years. Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 1,163,180 shares (fair value of approximately $23 million) based on the market price of Duke Energy’s common stock at the grant dates in the year ended December 31, 2007, 1,181,370 shares (fair value of approximately $34 million) in the year ended December 31, 2006, and 1,139,880 shares (fair value of approximately $31 million) in the year ended December 31, 2005. Converted Cinergy phantom stock awards are paid in cash and are measured and recorded as liability awards.
The following table summarizes information about phantom stock awards outstanding at December 31, 2007:
The total fair value of the shares vested during the years ended December 31, 2007, 2006 and 2005 was approximately $31 million, $23 million and $10 million, respectively. As of December 31, 2007, Duke Energy had approximately $14 million of future compensation cost which is expected to be recognized over a weighted-average period of 2.4 years.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Performance Awards
Stock-based awards outstanding under both the 2006 Plan and the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2007 and 2006 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock relative to a pre-defined peer group (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards with the adoption of SFAS No. 123(R). The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other awards not containing market conditions are measured at grant date price. Duke Energy awarded 1,534,510 shares (fair value of approximately $23 million) in the year ended December 31, 2007, 1,610,350 shares (fair value of approximately $32 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2006, and 1,275,020 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2005.
The following table summarizes information about stock-based performance awards outstanding at December 31, 2007:
The total fair value of the shares vested during the years ended December 31, 2007, 2006 and 2005 was approximately $34 million, $3 million and $3 million, respectively. As of December 31, 2007, Duke Energy had approximately $21 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.1 years.
Other Stock Awards
Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. There were no other stock awards issued during the year ended December 31, 2007. Duke Energy awarded 279,000 shares (fair value of approximately $8 million) based on the market price of Duke Energy’s common stock at the grant dates in the year ended December 31, 2006, and 47,000 shares (fair value of approximately $1 million) in the year ended December 31, 2005.
The following table summarizes information about other stock awards outstanding at December 31, 2007:
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The total fair value of the shares vested during the years ended December 31, 2007, 2006 and 2005 was approximately $2 million, $2 million and $1 million, respectively. As of December 31, 2007, Duke Energy had approximately $4 million of future compensation cost which is expected to be recognized over a weighted-average period of 2.3 years.
21. Employee Benefit Plans
Duke Energy Retirement Plans. Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain qualified, non-contributory defined benefit retirement plans. The plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which varies with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy U.S. employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of the their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain executives.
Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. Duke Energy made contributions of approximately $350 million and $124 million to the legacy Cinergy qualified pension plans during the years ended December 31, 2007 and 2006, respectively. Duke Energy did not make any contributions to its defined benefit retirement plans in 2005.
Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of active employees covered by the qualified retirement plans is 11 years. The average remaining service period of active employees covered by the non-qualified retirement plans is 10 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets in a particular year on a straight line basis over the next five years.
Duke Energy adopted the funded status disclosure and recognition provisions of SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158), effective December 31, 2006. Duke Energy adopted the change in measurement date transition requirements of SFAS No. 158 effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date. Previously, Duke Energy used a September 30 measurement date for its defined benefit and other post-retirement plans. Additionally, as discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. As a result, the Westcoast Canadian retirement plans and Westcoast other post-retirement benefit plans were transferred to Spectra Energy. The benefit obligation for the Westcoast Canadian retirement plans and Westcoast other post-retirement benefit plans was $832 million at December 31, 2006. The fair value of plan assets for the Westcoast Canadian retirement plans and Westcoast other post-retirement benefit plans was $525 million at December 31, 2006. The remaining pension and other post-retirement plan assets and liabilities distributed to Spectra Energy as part of the spin-off are disclosed in the table below.
As a result of the change in measurement date, net periodic benefit cost of approximately $28 million for the three month period between September 30, 2006 and December 31, 2006 was recognized, net of tax, as a separate reduction of retained earnings as of January 1, 2007. In addition, as reflected in the table below, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost were recognized, net of tax, as an adjustment to AOCI and regulatory assets.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The table below identifies significant changes to the individual line items in Duke Energy’s Consolidated Balance Sheets during the year ended December 31, 2007 due to the factors above, for the Duke Energy retirement and other post-retirement plans (amounts in brackets represent credits).
(a) These amounts are in addition to the assets and liabilities of the Westcoast plans that were also distributed to Spectra Energy.
(b) Amounts in the “Spin-off of the natural gas businesses” column exclude approximately $109 million, net of tax, related to accumulated other comprehensive losses of Westcoast that were transferred in connection with the spin-off.
Qualified Pension Plans
Components of Net Periodic Pension Costs: Qualified Pension Plans
(a) These amounts exclude approximately $17 million and $14 million for the years ended December 31, 2007 and 2006, respectively, of regulatory asset amortization resulting from purchase accounting.
(b) These amounts exclude pre-tax qualified pension cost of approximately $21 million and $12 million for the years ended December 31, 2006 and 2005, respectively, primarily related to the Westcoast plans transferred to Spectra Energy, which is included in (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
Qualified Pension Plans-Other Changes in Plan Assets and Projected Benefit Obligations
Recognized in Accumulated Other Comprehensive Income and Regulatory Assets and Regulatory Liabilities(a)
(a) Excludes actuarial gains recognized in other comprehensive income of approximately $14 million, net of tax, associated with a Brazilian retirement plan.
(b) Excludes approximately $91 million of losses, net of tax, in AOCI as of the date of the spin-off of the natural gas businesses related to Westcoast plans, which were included in the spin-off, thus resulting in an increase in AOCI.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Reconciliation of Funded Status to Net Amount Recognized: Qualified Pension Plans
The accumulated benefit obligation was $4,004 million at December 31, 2007 and $4,408 million at September 30, 2006.
Qualified Pension Plans-Amounts Recognized in the Consolidated Balance Sheets Consist of:
As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income, Deferred Income Taxes and Regulatory Assets as of December 31, 2006.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The following table provides the amounts related to Duke Energy’s qualified pension plans that are reflected in Other Regulatory Assets and Deferred Debits, Deferred Credits and Other Liabilties and AOCI on the Consolidated Balance Sheets at December 31, 2007 and 2006:
Of the amounts above, approximately $14 million of unrecognized losses and approximately $7 million of unrecognized prior service cost will be recognized in net periodic pension costs in 2008.
Additional Information:
Qualified Pension Plans-Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets
Qualified Pension Plans-Assumptions Used for Pension Benefits Accounting
The discount rate used to determine the pension obligation is based on AA bond yields. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used in 2006 to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.
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DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Qualified Pension Plan Assets
Assets for both the pension and other post retirement benefits are maintained in a Master Trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.
The long-term rate of return of 8.5% as of December 31, 2007 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 4.3% for U.S. equities, 1.7% for Non-U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.
Non-Qualified Pension Plans
Components of Net Periodic Pension Costs: Non-Qualified Pension Plans
(a) These amounts exclude pre-tax non-qualified pension cost of approximately $7 million and $6 million for the years ended December 31, 2006 and 2005, respectively, primarily related to the Westcoast plans transferred to Spectra Energy, which is included in (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Nonqualified Pension Plans-Other Changes in Plan Assets and Projected Benefit Obligations
Recognized in Accumulated Other Comprehensive Income and Regulatory Assets
(a) Excludes approximately $16 million of losses, net of tax, in AOCI as of the date of the spin-off of the natural gas businesses related to Westcoast plans, which were included in the spin-off, thus resulting in an increase in AOCI.
Reconciliation of Funded Status to Net Amount Recognized: Non-Qualified Pension Plans
The accumulated benefit obligation was $160 million at December 31, 2007 and $184 million at September 30, 2006.
Non-Qualified Pension Plans-Amounts Recognized in the Consolidated Balance Sheets
Consist of:
(a) Includes approximately $15 million and $41 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2007 and 2006, respectively.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income, Deferred Income Taxes and Regulatory Assets as of December 31, 2006. The table below details the components of these balances.
The following table provides the amounts related to Duke Energy’s non-qualified pension plans that are reflected in Other Regulatory Assets and Deferred Debits and AOCI on the Consolidated Balance Sheets at December 31, 2007 and 2006:
Of the amounts above, approximately $3 million of unrecognized prior service cost will be recognized in net periodic pension costs in 2008.
Additional Information:
Non-Qualified Pension Plans-Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets
Non-Qualified Pension Plans-Assumptions Used for Pension Benefits Accounting
The discount rate used to determine the pension obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used in 2006 to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy. Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Most employees participate in a matching contribution formula where Duke Energy provides a matching contribution generally equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per pay period. Duke Energy expensed employer matching contributions of $68 million in 2007, $67 million in 2006 and $54 million in 2005. These amounts exclude pre-tax expenses of $8 million and $7 million for the years ended 2006 and 2005, respectively, related to Spectra Energy, which is included in (Loss) Income from Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Dividends on Duke Energy shares held by the savings plans are charged to retained earnings when declared and shares held in the plans are considered outstanding in the calculation of basic and diluted earnings per share.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Other Post-Retirement Benefit Plans
Duke Energy Other Post-Retirement Benefits. Duke Energy and most of its subsidiaries provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
During the year ended December 31, 2007, Duke Energy contributed approximately $62 million to its other post-retirement plans.
These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation is amortized over approximately 20 years. Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the plan is 12 years.
Components of Net Periodic Other Post-Retirement Benefit Costs
(a) These amounts exclude approximately $10 million and $5 million for the years ended December 31, 2007 and 2006, respectively, of regulatory asset amortization resulting from purchase accounting.
(b) These amounts exclude pre-tax qualified pension cost of approximately $21 million and $18 million for the years ended December 31, 2006 and 2005, respectively, primarily related to the Westcoast plans transferred to Spectra Energy, which is included in (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.
Other Post-Retirement Benefit Plans-Other Changes in Plan Assets and Projected Benefit Obligations
Recognized in Accumulated Other Comprehensive Income and Regulatory Assets
(a) Excludes approximately $2 million of losses, net of tax, in AOCI as of the date of the spin-off of the natural gas businesses related to Westcoast plans, which were included in the spin-off, thus resulting in an increase in AOCI.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs
Other Post-Retirement Benefit Plans- Amounts Recognized in the Consolidated Balance Sheets Consist of:
(a) Includes approximately $2 million and $26 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2007 and 2006, respectively.
As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income, Deferred Income Taxes and Regulatory Assets as of December 31, 2006. The table below details the components of these balances.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The following table provides the amounts related to Duke Energy’s other post-retirement benefit plans that are reflected in Other Regulatory Assets and Deferred Debits and AOCI on the Consolidated Balance Sheets at December 31, 2007 and 2006:
Of the amounts above, approximately $10 million of unrecognized transition liability, approximately $6 million of unrecognized losses and approximately $7 million of unrecognized prior service credit (which will reduce pension expense) will be recognized in net periodic pension costs in 2008.
For measurement purposes, plan assets were valued as of December 31 for Duke Energy U.S. plan. In May 2004, the FASB staff issued FSP No. FAS 106-2. The Modernization Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. The FSP provides guidance on the accounting for the subsidy. Duke Energy adopted this FSP and retroactively applied this FSP as of the date of issuance. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $3 million in 2007, $8 million in 2006 and $7 million in 2005. Duke Energy has recognized an approximate $5 million subsidy receivable as of December 31, 2007, which is included in Receivables on the Consolidated Balance Sheets.
Assumptions Used for Other Post-Retirement Benefits Accounting
(a) Applicable to the health care portion of funded post-retirement benefits
The discount rate used to determine the post-retirement obligation is based on AA bond yields. The yield is selected based on bonds with cash flows that are similar to the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used to determine expense in 2006 reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Other Post-Retirement Plan Assets
Assets for both the pension and other post-retirement benefits are maintained in a Master Trust. The investment objective of the trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate. The long-term rate of return of 8.5% as of December 31, 2007 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 4.3% for U.S. equities, 1.7% for Non-U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.
Duke Energy also invests other post-retirement assets in the Duke Energy Corporation Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBA’s is to achieve sufficient returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBA trusts are passively managed. VEBA I has a target allocation of 30% U.S. equities, 45% fixed income securities and 25% cash. VEBA II has a target allocation of 50% U.S. equities and 50% fixed income securities.
Assumed Health Care Cost Trend Rates(a)
(a) Health care cost trend rates include prescription drug trend rate due to the effect of the Modernization Act.
Sensitivity to Changes in Assumed Health Care Cost Trend Rates (millions)
Duke Energy expects to make the future benefit payments, which reflect expected future service, as appropriate. Duke Energy expects to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Expected Benefit Payments
The following table presents Duke Energy’s expected benefit payments to participants in its qualified, non-qualified and other post-retirement benefit plans over the next 10 years. These benefit payments reflect expected future service, as appropriate.
(a) Duke Energy expects to receive future subsidies under Medicare Part D of approximately $4 million in each of the years 2008 - 2010, approximately $5 million in each of the years 2011-2012 and a total of approximately $27 million during the years 2013-2017.
22. Variable Interest Entities
Power Sale Special Purpose Entities (SPEs). In accordance with FIN 46R, Duke Energy consolidates two SPEs that have individual power sale agreements with Central Maine Power Company (CMP) for approximately 45 megawatts (MW) of capacity, ending in 2009, and 35 MW of capacity, ending in 2016. In addition, these SPEs have individual power purchase agreements with Cinergy Capital & Trading, Inc. (Capital & Trading), a wholly owned subsidiary of Duke Energy, to supply the power. Capital & Trading also provides various services, including certain credit support facilities. The transactions between Capital & Trading and the two SPEs are eliminated in consolidation. As a result of the consolidation of these two SPEs, approximately $146 million and $171 million of notes receivable is included on Duke Energy’s Consolidated Balance Sheets at December 31, 2007 and 2006, respectively. Of these amounts, $29 million and $25 million are included in Receivables on the Consolidated Balance Sheets and $117 million and $146 million are included in Notes Receivable on the Consolidated Balance Sheets at December 31, 2007 and 2006, respectively. Approximately $136 million and $160 million of non-recourse debt is included on the Consolidated Balance Sheets, of which $28 million and $24 million is included in Current Maturities of Long-Term Debt on the Consolidated Balance Sheets and $108 million and $136 million is included in Long-Term Debt on the Consolidated Balance Sheets at December 31, 2007 and 2006, respectively. In addition, miscellaneous other assets and liabilities are included on Duke Energy’s Consolidated Balance Sheets at December 31, 2007 and 2006. The debt was incurred by the SPEs to finance the buyout of the existing power contracts that CMP held with the former suppliers. The notes receivable is comprised of two separate notes with one counterparty, whose credit rating is BBB+. The cash flows from the notes receivable are designed to repay the debt. The first note receivable, with a balance of $40 million and $62 million at December 31, 2007 and 2006, respectively, bears an effective interest rate of 7.81 % and matures in August 2009. The second note receivable, with a balance of $106 million and $109 million at December 31, 2007 and 2006, respectively, bears an effective interest rate of 9.23 % and matures in December 2016.
The following table reflects the maturities of the Notes Receivable as of December 31, 2007:
Notes Receivable Maturities
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
Subsidiary Trust Preferred Securities. In 2001, Cinergy issued approximately $316 million notional amount of 6.9 % trust preferred securities, due February 2007. The trust preferred securities were issued through a trust whose common stock was 100 % owned by Cinergy. The trust loaned the proceeds from the issuance of the securities to Cinergy in exchange for a note payable to the trust. Each trust preferred security unit received quarterly cash payments of 6.9 % per annum of the notional amount, which represented a trust preferred security dividend. The trust’s ability to pay dividends on the trust preferred securities was solely dependent on its receipt of interest payments from Cinergy on the note payable. However, Cinergy had fully and unconditionally guaranteed the trust preferred securities. The trust preferred securities were not included in Duke Energy’s Balance Sheets. In addition, the note payable of approximately $326 million owed to the trust was included in Current Maturities of Long-Term Debt on the Consolidated Balance Sheets at December 31, 2006. In February 2007, these trust preferred securities were redeemed on their scheduled maturity date and the note payable was settled.
Accounts Receivable Securitization. During 2002, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky entered into an agreement to sell certain of their accounts receivable and related collections through Cinergy Receivables, a bankruptcy remote, special purpose entity. Cinergy Receivables is a wholly owned limited liability company of Cinergy. As a result of the securitization, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky sell, on a revolving basis, nearly all of their retail accounts receivable and related collections. The securitization transaction was structured to meet the criteria for sale treatment under SFAS No. 140 and, accordingly, Duke Energy does not consolidate Cinergy Receivables and the transfers of receivables are accounted for as sales.
The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25% of the total proceeds). The note, which amounts to approximately $299 million and $210 million at December 31, 2007 and 2006, respectively, is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions. Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables. However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time. As such, these senior loans do not have recourse to all assets of Cinergy Receivables. These loans provide the cash portion of the proceeds paid to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky.
This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under SFAS No. 140 and is classified within Receivables in the accompanying Consolidated Balance Sheets at December 31, 2007 and 2006. In addition, Duke Energy’s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the retained interests held by Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky.
The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions used in estimating the fair value for 2007 were an anticipated credit loss ratio of 0.6%, a discount rate of 7.7% and a receivable turnover rate of 11.7%. The key assumptions used in estimating the fair value for 2006 were an anticipated credit loss ratio of 0.7%, a discount rate of 7.4% and a receivable turnover rate of 12.0%. Because (a) the receivables generally turnover in less than two months, (b) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration, and (c) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated bases of the subordinated notes are not materially different than their face value. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history. Interest accrues to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. Duke Energy records income from Cinergy Receivables in a similar manner. An impairment charge is recorded against the carrying value of both the retained interests and purchased beneficial interest whenever it is determined that an other-than-temporary impairment has occurred (which is unlikely unless credit losses on the receivables far exceed the anticipated level).
Duke Energy Ohio retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky in the event of a loss. While no direct recourse to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky exists, these entities risk loss in the event collections are not sufficient to allow for full recovery of their retained interests. No servicing asset or liability is recorded since the servicing fee paid to Duke Energy Ohio approximates a market rate.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
The following table shows the gross and net receivables sold, retained interests, purchased beneficial interest, sales, and cash flows during the year ended December 31, 2007 and the period from the date of acquisition (April 1, 2006) through December 31, 2006:
Cash flows from the sale of receivables for the year ended December 31, 2007 and the period from the date of acquisition through December 31, 2006 are reflected within Operating Activities on the Consolidated Statements of Cash Flows.
23. Other Income and Expenses, net
The components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005 are as follows:
24. Subsequent Events
For information on subsequent events related to acquisitions and dispositions, regulatory matters, marketable securities, debt and credit facilities and commitments and contingencies, see Notes 2, 4, 9, 15 and 17, respectively.
PART II
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements-(Continued)
25. Quarterly Financial Data (Unaudited)
(a) Operating revenues and operating income for each of the quarters in the year ended December 31, 2007 and for the last three quarters in the year ended December 31, 2006 reflect the reclassification of the synfuel operations to discontinued operations. Accordingly, operating revenues and operating income for these periods differ from those that appeared in previously filed Form 10-Q’s for each of the respective periods. There was no change to net income or earnings per share as a result of this reclassification.
(b) Quarterly EPS amounts are meant to be stand-alone calculations and are not always additive to full-year amount due to rounding.
During the first quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $21 million pre-tax charge related to convertible debt (see Note 15) and a $22 million reduction in income tax expense due to a reduction in the unitary tax rate (see Note 1).
During the second quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $12 million pre-tax charge related to a voluntary severance program (see Note 12).
During the third quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $20 million pre-tax benefit associated with contract settlement negotiations (see Note 17).
During the fourth quarter of 2007, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $32 million pre-tax impairment charge related to losses on certain residential developments at Crescent (see Note 11), income tax expense of approximately $31 million related to an additional phase-out of the tax credits associated with the synfuel operations (see Notes 13 and 17), an approximate $25 million pre-tax gain related to reserves for contract settlement negotiations (see Note 17) and an approximate $21 million pre-tax charge related to the settlement of an outstanding litigation matter (see Note 17).
During the first quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $24 million pre-tax gain on the settlement of a customer’s transportation contract (see Note 13).
During the second quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring items: approximately $55 million pre-tax charge related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 12); an approximate $55 million pre-tax other-than-temporary impairment charge related to International Energy’s investment in Campeche (see Note 12) and the issuance of approximately 313 million shares of common stock in connection with the merger with Cinergy (see Note 1).
During the third quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $246 million pre-tax gain on the sale of an effective 50% interest in the Crescent JV (see Note 2); and an approximate $40 million additional gain on the sale of DENA’s assets to LS Power as a result of LS Power obtaining certain regulatory approvals (see Note 13).
During the fourth quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $65 million pre-tax contract settlement negotiation reserve (see Note 17); an approximate $100 million pre-tax charge to establish a settlement reserve related to the Citrus litigation (see Note 17); approximately $75 million of tax benefits (see Note 6); an approximate $25 million pre-tax gain on the sale of CMT (see Note 13); and an approximate $28 million pre-tax impairment charge at International Energy as a result of the pending sale of operations in Bolivia (see Note 13).
PART II
DUKE ENERGY CORPORATION
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(a) Principally cash payments and reserve reversals. For 2007, this also includes the effects of amounts included in the spin-off of Spectra Energy on January 2, 2007 and the impacts of adoption of FIN No. 48.
(b) Principally nuclear property insurance reserves at Duke Energy Carolinas, insurance reserves at Bison and other reserves, included in Other Current Liabilities or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.
(c) Amounts for the year ended December 31, 2006 and thereafter include balances and activity related to Duke Energy’s merger with Cinergy in April 2006.
The valuation and reserve amounts above do not include unrecognized tax benefits amounts or deferred tax asset valuation allowance amounts.
PART II
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by Duke Energy in the reports it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms.
Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by Duke Energy in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Duke Energy has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2007, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Duke Energy has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2007 and have concluded that no change has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Management’s Annual Report On Internal Control Over Financial Reporting
Duke Energy’s management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Duke Energy’s management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2007 based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2007.
Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of Duke Energy’s internal control over financial reporting.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Reference to “Executive Officers of Duke Energy” is included in “Item 1. Business” of this report. Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2008 annual meeting of shareholders.
Item 11.
Item 11. Executive Compensation.
Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2008 annual meeting of shareholders.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2008 annual meeting of shareholders.
This table shows information about securities to be issued upon exercise of outstanding options, warrants and rights under Duke Energy’s equity compensation plans, along with the weighted-average exercise price of the outstanding options, warrants and rights and the number of securities remaining available for future issuance under the plans.
Duke Energy has not granted any warrants or rights under any equity compensation plans. Amounts do not include 4,465,298 outstanding options with a weighted average exercise price of $13.80 assumed in connection with various mergers and acquisitions.
Does not include 5,979,818 shares of Duke Energy Common Stock to be issued upon vesting of phantom stock and performance share awards outstanding as of December 31, 2007.
Includes 12,280,310 shares remaining available for issuance for awards of restricted stock, performance shares or phantom stock under the Duke Energy Corporation 2006 Long-Term Incentive Plan.
Does not include 321,305 shares of Duke Energy Common Stock to be issued upon vesting of phantom stock and performance share awards outstanding as of December 31, 2007.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2008 annual meeting of shareholders.
Item 14.
Item 14. Principal Accounting Fees and Services.
Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2008 annual meeting of shareholders.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:
Duke Energy Corporation:
Consolidated Financial Statements
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005
Consolidated Balance Sheets as of December 31, 2007 and 2006
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005
Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income for the Years ended December 31, 2007, 2006 and 2005
Notes to the Consolidated Financial Statements
Quarterly Financial Data, as revised (unaudited, included in Note 25 to the Consolidated Financial Statements)
Consolidated Financial Statement Schedule II-Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2007, 2006 and 2005
Report of Independent Registered Public Accounting Firm
(b) Separate Financial Statements of Subsidiaries not Consolidated Pursuant to Rule 3-09 of Regulation S-X:
TEPPCO Partners, L.P.:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2005 and 2004
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003
Notes to Consolidated Financial Statements
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
DCP Midstream, LLC. (formerly Duke Energy Field Services, LLC):
Independent Auditors’ Report
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2006 and 2005
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006 and 2005
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2006 and 2005
Notes to Consolidated Financial Statements
Consolidated Financial Statement Schedule II of DCP Midstream, LLC-Consolidated Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2006 and 2005
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
(c) Exhibits-See Exhibit Index immediately following the signature page.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 29, 2008
DUKE ENERGY CORPORATION
(Registrant)
By:
/S/ JAMES E. ROGERS
James E. Rogers
Chairman, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
(i) James E. Rogers*
Chairman, President and Chief Executive Officer (Principal Executive Officer and Director)
(ii) /s/ David L. Hauser
Group Executive and Chief Financial Officer (Principal Financial Officer)
(iii) Steven K. Young*
Senior Vice President and Controller (Principal Accounting Officer)
(iv) William Barnet, III*
Director
G. Alex Bernhardt, Sr.*
Director
Michael G. Browning*
Director
Phillip R. Cox*
Director
Daniel R. DiMicco*
Director
Ann Maynard Gray*
Director
James H. Hance, Jr.*
Director
James T. Rhodes*
Director
Mary L. Schapiro*
Director
Philip R. Sharp*
Director
Dudley S. Taft*
Director
Date: February 29, 2008
David L. Hauser, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.
By:
/s/ DAVID L. HAUSER
Attorney-In-Fact
CONSOLIDATED FINANCIAL STATEMENTS OF
TEPPCO PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of TEPPCO Partners, L.P.:
We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 20 to the consolidated financial statements, the Partnership has restated its consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for the years ended December 31, 2004 and 2003.
KPMG LLP
Houston, Texas
February 28, 2006, except for the effects of discontinued operations,
as discussed in Note 5, which is as of June 1, 2006
TEPPCO PARTNERS, L.P.
Consolidated Balance Sheets
(in thousands)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
Consolidated Statements of Income
(in thousands, except per Unit amounts)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
Consolidated Statements of Cash Flows
(in thousands)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
Consolidated Statements of Partners’ Capital
(in thousands, except Unit amounts)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
Consolidated Statements of Comprehensive Income
(in thousands)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements
Note 1. Partnership Organization
TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.
On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our general partner was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.
Through February 23, 2005, the General Partner was an indirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%. On February 24, 2005, the General Partner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, for approximately $1.1 billion. As a result of the transaction, DFI owns and controls the 2% general partner interest in us and has the right to receive the incentive distribution rights associated with the general partner interest. In conjunction with an amended and restated administrative services agreement, EPCO performs all management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us. As a result of the sale of our General Partner, DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we assumed these services. In connection with us assuming the operations of certain of the TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005.
At formation in 1990, we completed an initial public offering of 26,500,000 units representing Limited Partner Interests (“Limited Partner Units”) at $10.00 per Limited Partner Unit. In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs were converted to Limited Partner Units, but they have not been listed for trading on the New York Stock Exchange. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Limited Partner Units for $104.0 million. As of December 31, 2005, none of these Limited Partner Units had been sold by DFI.
At December 31, 2005, 2004 and 2003, we had outstanding 69,963,554, 62,998,554 and 62,998,554 Limited Partner Units, respectively. At December 31, 2002, we had outstanding 3,916,547 Class B Limited Partner Units (“Class B Units”), which were issued to Duke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with an acquisition of assets initially acquired in 1998. On April 2, 2003, we repurchased and retired all of the 3,916,547 previously outstanding Class B Units with proceeds from the issuance of additional Limited Partner Units (see Note 11). Collectively, the Limited Partner Units and Class B Units are referred to as “Units”.
As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.
We restated our consolidated financial statements and related financial information for the years ended December 31, 2004 and 2003, for an accounting correction. In addition, the restatement adjustment impacted quarterly periods with the fiscal years ended December 31, 2005, 2004 and 2003. See Note 20 for a discussion of the restatement adjustment and the impact on previously issued financial statements.
Note 2. Summary of Significant Accounting Policies
We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.
Basis of Presentation and Principles of Consolidation. Throughout the consolidated financial statements and accompanying notes, all referenced amounts related to prior periods reflect the balances and amounts on a restated basis. The financial statements include our accounts on a consolidated basis. We have eliminated all significant intercompany items in consolidation. We have reclassified
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
certain amounts from prior periods to conform to the current presentation. Our results for the years ended December 31, 2005 and 2004 reflect the operations and activities of Jonah Gas Gathering Company’s Pioneer plant as discontinued operations.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Although we believe these estimates are reasonable, actual results could differ from those estimates.
Business Segments. We operate and report in three business segments: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and are managed separately because each requires different business strategies.
Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas in this Report, collectively, as “petroleum products” or “products.”
Revenue Recognition. Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold.
Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P. (“TCO”), which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed.
Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged.
Our Midstream Segment revenues are earned from the gathering of natural gas, transportation of NGLs and fractionation of NGLs. Gathering revenues are recognized as natural gas is received from the customer. Transportation revenues are recognized as NGLs are delivered to customers. Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream Segment marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.” Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.
Cash and Cash Equivalents. Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximate fair value because of the short term nature of these investments.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2005, 2004 and 2003 (in thousands):
Inventories. Inventories consist primarily of petroleum products and crude oil, which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at the lower of fair value or cost.
Property, Plant and Equipment. We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).
We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell.
Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. Determination of any amounts recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.
The Downstream Segment assets consist primarily of an interstate trunk pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and delivers natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionator facilities in Colorado.
We have completed our assessment of SFAS 143, and we have determined that we are obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the asset retirement obligations for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate.
In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
on those fields in which we gather crude oil and natural gas. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.
We will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of SFAS 143 did not have an effect on our financial position, results of operations or cash flows.
Capitalization of Interest. We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.73%, 5.74% and 6.50% for the years ended December 31, 2005, 2004 and 2003, respectively. During the years ended December 31, 2005, 2004 and 2003, the amount of interest capitalized was $6.8 million, $4.2 million and $5.3 million, respectively.
Intangible Assets. Intangible assets on the consolidated balance sheets consist primarily of gathering contracts assumed in the acquisition of Jonah Gas Gathering System (“Jonah”) on September 30, 2001, and the acquisition of Val Verde Gathering System (“Val Verde”) on June 30, 2002, a fractionation agreement and other intangible assets (see Note 3). Included in equity investments on the consolidated balance sheets are excess investments in Centennial Pipeline LLC (“Centennial”) and Seaway Crude Pipeline Company (“Seaway”).
In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that gather coal bed methane (“CBM”) from the San Juan Basin in New Mexico and Colorado, respectively. The value assigned to these intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production to the gathering system. These intangible assets are amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 3).
In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized on a straight-line basis over a period of 20 years, which is the term of the agreement with DEFS.
In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.7 million, which are amortized on a unit-of-production basis (see Note 5).
In connection with the formation of Centennial, we recorded excess investment, the majority of which is amortized on a unit-of-production basis over a period of 10 years. In connection with the acquisition of our interest in Seaway, we recorded excess investment, which is amortized on a straight-line basis over a period of 39 years (see Note 3).
Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001 (see Note 3). SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill.
Environmental Expenditures. We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
The following table presents the activity of our environmental reserve for the years ended December 31, 2005, 2004 and 2003 (in thousands):
Natural Gas Imbalances. Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. If the customers supply more natural gas gathering volumes than they nominated, Val Verde and Jonah record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers. To the extent that these amounts are not cashed out monthly on Val Verde, if the customers supply less natural gas gathering volumes than they nominated, Val Verde and Jonah record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers. We record natural gas imbalances using a mark-to-market approach.
Income Taxes. We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.
Use of Derivatives. We account for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative.
Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.
For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.
For derivative instruments designated as fair value hedges, gains and losses on the derivative instrument are offset against related results on the hedged item in the statement of income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
hedged item over time. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.
According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.
When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.
Fair Value of Financial Instruments. The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheets.
Net Income Per Unit. Basic net income per Unit is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 67.4 million Units, 63.0 million Units and 59.8 million Units for the years ended December 31, 2005, 2004 and 2003, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each year (see Note 11). The General Partner was allocated $47.6 million (representing 29.27%) of net income for the year ended December 31, 2005, $40.0 million (representing 28.85%) of net income for the year ended December 31, 2004, and $33.7 million (representing 27.65%) of net income for the year ended December 31, 2003. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our limited partnership agreement.
Diluted net income per Unit is similar to the computation of basic net income per Unit discussed above, except that the denominator is increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the year ended December 31, 2003, the denominator was increased by 11,878 Units. For the years ended December 31, 2005 and 2004, diluted net income per Unit equaled basic net income per Unit as all remaining outstanding Unit options were exercised during the third quarter of 2003 (see Note 13).
Unit Option Plan. We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 13), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for Unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Units on the date of the grant. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.
In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure was issued. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 13.
Assuming we had used the fair value method of accounting for our Unit option plan, pro forma net income would equal reported net income for the years ended December 31, 2005, 2004 and 2003. Pro forma net income per Unit would equal reported net income per Unit for the periods presented. The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
New Accounting Pronouncements. In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of the compensation cost is to be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards are to be re-measured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123(R) is effective for public companies as of the first interim or annual reporting period of the first fiscal year beginning after June 15, 2005. The Securities and Exchange Commission amended the implementation date of SFAS 123(R) to begin with the first interim or annual reporting period of the company’s first fiscal year beginning on or after June 15, 1005. As such, we will adopt SFAS 123(R) in the first quarter of 2006. Companies are permitted to adopt SFAS 123(R) prior to the extended date. All public companies that adopted the fair-value-based method of accounting must use the modified prospective transition method and may elect to use the modified retrospective transition method. We do not believe that the adoption of SFAS 123(R) will have a material effect on our financial position, results of operations or cash flows.
In November 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations, to clarify whether a component of an enterprise that is either disposed of or classified as held for sale qualifies for income statement presentation as discontinued operations. The FASB ratified the consensus on November 30, 2004. The consensus is to be applied prospectively with regard to a component of an enterprise that is either disposed of or classified as held for sale in reporting periods beginning after December 15, 2004. The consensus may be applied retrospectively for previously reported operating results related to disposal transactions initiated within an enterprise’s reporting period that included the date that this consensus was ratified. The adoption of EITF 03-13 did not have an effect on our financial position, results of operations or cash flows.
In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005, and early adoption of FIN 47 is encouraged. We adopted FIN 47 in the fourth quarter of 2005. The adoption of FIN 47 did not have a material effect on our financial position, results of operations or cash flows.
In June 2005, the EITF reached consensus in EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it. The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as kick-out rights, is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause. The second type, referred to as participating rights, is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005). For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We do not believe that the adoption of EITF 04-5 will have a material effect on our financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29. SFAS 153 amends APB Opinion No. 29, Accounting for Nonmonetary Exchanges, to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial
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substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We adopted SFAS 153 during the second quarter of 2005. The adoption of SFAS 153 did not have a material effect on our financial position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS 154 establishes new standards on accounting for changes in accounting principles. All such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so. SFAS 154 completely replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Periods. However, it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity, and the correction of errors. SFAS 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted for changes and corrections made in years beginning after June 1, 2005. The application of SFAS 154 does not affect the transition provisions of any existing pronouncements, including those that are in the transition phase as of the effective date of SFAS 154. We do not believe that the adoption of SFAS 154 will have a material effect on our financial position, results of operations or cash flows.
In September 2005, the EITF reached consensus in EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, to define when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction subject to APB Opinion No. 29, Accounting for Nonmonetary Transactions. Two or more inventory transactions with the same party should be combined if they are entered into in contemplation of one another. The EITF also requires entities to account for exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification. The guidance in EITF 04-13 is effective for new inventory arrangements entered into in reporting periods beginning after March 15, 2006. We are currently evaluating what impact EITF 04-13 will have on our financial statements, but at this time we do not believe that the adoption of EITF 04-13 will have a material effect on our financial position, results of operations or cash flows.
Note 3. Goodwill and Other Intangible Assets
Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. We test goodwill and intangible assets for impairment annually at December 31.
To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred. There have been no goodwill impairment losses recorded since the adoption of SFAS 142.
The following table presents the carrying amount of goodwill at December 31, 2005 and 2004, by business segment (in thousands):
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Notes To Consolidated Financial Statements-(Continued)
Other Intangible Assets. The following table reflects the components of intangible assets, including excess investments, being amortized at December 31, 2005 and 2004 (in thousands):
SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on intangible assets was $30.5 million, $32.2 million and $36.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. Amortization expense on excess investments included in equity earnings was $4.8 million, $3.8 million and $4.0 million for the years ended December 31, 2005, 2004 and 2003, respectively.
The values assigned to our intangible assets for natural gas gathering contracts on the Jonah and the Val Verde systems are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to the expected total throughput for the lives of the contracts. On a quarterly basis, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the systems, and as a result, we evaluate the remaining expected useful lives of the contract assets based on the best available information. During the fourth quarter of 2004 and the first and second quarters of 2005, certain limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the system, which resulted in extensions in the remaining lives of the intangible assets. During the fourth quarter of 2004 and the third quarter of 2005, certain limited coal bed methane production forecasts were obtained from some of the producers on the Val Verde system whose contracts are included in the intangible assets. These forecasts indicated lower coal bed methane production estimates over the contract periods, and as a result, we decreased our best estimate of future throughput on the Val Verde system, which resulted in increases to amortization expense on the intangible assets. Further revisions to these estimates may occur as additional production information is made available to us.
The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement is being amortized over its contract period of 20 years. The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years. The value of $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis (see Note 5).
The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to the life of the pipeline.
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The following table sets forth the estimated amortization expense of intangible assets and the estimated amortization expense allocated to equity earnings for the years ending December 31 (in thousands):
Note 4. Interest Rate Swaps
In July 2000, we entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. This interest rate swap matured in April 2004. We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings. During the years ended December 31, 2004 and 2003, we recognized an increase in interest expense of $2.9 million and $14.4 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.
In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2005, 2004 and 2003, we recognized reductions in interest expense of $5.6 million, $9.6 million and $10.0 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the years ended December 31, 2005, 2004 and 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap was a loss of approximately $0.9 million at December 31, 2005, and a gain of approximately $3.4 million at December 31, 2004.
During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. These swap agreements were later terminated in 2002 resulting in gains of $44.9 million. The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2005, the unamortized balance of the deferred gains was $32.4 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.
During May 2005, we executed a treasury rate lock agreement with a notional amount of $200.0 million to hedge our exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for a debt offering that was proposed to occur in the second quarter of 2005. During June 2005, the proposed debt offering was cancelled, and the treasury lock was terminated with a realized loss of $2.0 million. The realized loss was recorded as a component of interest expense in the consolidated statements of income in June 2005.
Note 5. Acquisitions, Dispositions and Discontinued Operations
Rancho Pipeline
In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners that previously held undivided interests in the pipeline. We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain
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of $3.9 million on the transactions in the second quarter of 2003. During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million. These gains are included in the gains on sales of assets in our consolidated statements of income in the 2004 period.
Genesis Pipeline
On November 1, 2003, we purchased crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”). The transaction was funded with proceeds from our August 2003 equity offering (see Note 11). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets. The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business. We have integrated these assets into our South Texas pipeline system, which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities. Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.
The following table allocates the estimated fair value of the Genesis assets acquired on November 1, 2003 (in thousands):
Mexia Pipeline
On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”). The assets include approximately 158 miles of pipeline, which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. We have integrated these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.
Crude Oil Storage and Terminaling Assets
On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. for $35.4 million. The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The storage and terminaling assets complement our existing infrastructure in Cushing and strengthen our gathering and marketing business in our Upstream Segment.
Refined Products Terminal and Truck Rack
On July 12, 2005, we purchased a refined products terminal and truck loading rack in North Little Rock, Arkansas, for $6.9 million from ExxonMobil Corporation. The assets include three storage tanks and a two-bay truck loading rack. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.
Genco Assets
On July 15, 2005, we acquired from Texas Genco, LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. The assets of the purchased companies will be integrated into our Downstream Segment ori-
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Notes To Consolidated Financial Statements-(Continued)
gin infrastructure in Texas City and Baytown, Texas. As a result of this acquisition, we initiated the expansion of refined products origin capabilities in the Houston and Texas City, Texas, areas. The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million. The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and our Texas Gulf Coast refining and logistics system.
Pioneer Plant
On January 26, 2006, we announced the execution of a letter of intent to sell our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise Products Partners L.P. (“Enterprise”). On March 31, 2006, we sold the Pioneer plant to an affiliate of Enterprise for $38.0 million in cash. The Pioneer plant, included in our Midstream Segment, was not an integral part of our operations and natural gas processing is not a core business. The Pioneer plant was constructed as part of the Phase III expansion of the Jonah system and was completed during the first quarter of 2004. We have no continuing involvement in the operations or results of this plant. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our General Partner and of the general partner of Enterprise, and a fairness opinion was rendered by an independent third-party.
Condensed statements of income for the Pioneer plant, which is classified as discontinued operations, for the years ended December 31, 2005 and 2004, are presented below (in thousands):
Assets of the discontinued operations consisted of the following at December 31, 2005 and 2004 (in thousands):
Net cash flows from discontinued operations for the years ended December 31, 2005 and 2004, are presented below (in thousands):
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Notes To Consolidated Financial Statements-(Continued)
Note 6. Equity Investments
Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway. The remaining 50% interest is owned by ConocoPhillips. We operate the Seaway assets. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway. During the years ended December 31, 2005, 2004 and 2003, we received distributions from Seaway of $24.7 million, $36.9 million and $22.7 million, respectively.
In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Petroleum Company LLC (“Marathon”) to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Through February 9, 2003, each participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial from PEPL for $20.0 million each, increasing their ownership percentages in Centennial to 50% each. During the year ended December 31, 2005, TE Products did not make any additional investments in Centennial. TE Products invested an additional $1.5 million and $24.0 million, respectively, in Centennial, in 2004 and 2003, which is included in the equity investment balance at December 31, 2005. The 2003 amount includes the $20.0 million paid for the acquisition of the additional ownership interest in Centennial. TE Products has not received any distributions from Centennial since its formation.
On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. MB Storage owns storage capacity at the Mont Belvieu fractionation and storage complex and a short haul transportation shuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coast energy marketplace. MB Storage is a service-oriented, fee-based venture serving the fractionation, refining and petrochemical industries with substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage has no commodity trading activity. TE Products operates the facilities for MB Storage. Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.1 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party. This deferred liability was also contributed and credited to the capital account of Louis Dreyfus in MB Storage.
For the year ended December 31, 2005, TE Products received the first $1.7 million per quarter (or $6.78 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense. TE Products’ share of MB Storage’s earnings is adjusted annually by the partners of MB Storage. Any amount of MB Storage’s annual income before depreciation expense in excess of $6.78 million for 2005 and $7.15 million for 2004 was allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the years ended December 31, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was 64.2%, 69.4% and 70.4%, respectively. During the years ended December 31, 2005, 2004 and 2003, TE Products received distributions of $12.4 million, $10.3 million and $5.3 million, respectively, from MB Storage. During the years ended December 31, 2005, 2004 and 2003, TE Products contributed $5.6 million, $21.4 million and $2.5 million, respectively, to MB Storage. The 2005 contribution includes a combination of non-cash asset transfers of $1.4 million and cash contributions of $4.2 million. The 2004 contribution includes $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures.
We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the years ended December 31, 2005 and 2004, is presented below (in thousands):
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Notes To Consolidated Financial Statements-(Continued)
Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of December 31, 2005 and 2004, is presented below (in thousands):
Note 7. Related Party Transactions
EPCO and Affiliates and Duke Energy, DEFS and Affiliates
The Partnership does not have any employees. We are managed by the Company, which, for all periods prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS. According to the Partnership Agreement, the Company was entitled to reimbursement of all direct and indirect expenses related to our business activities. As a result of the change in ownership of the General Partner on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees (see Note 1).
The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the periods indicated (in millions):
(1)
Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions from February 24, 2005, through December 31, 2005, as a result of the change in ownership of the General Partner (see Note 1).
(2)
Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines.
(3)
Includes revenues from LPG transportation on the TE Products pipeline.
(4)
Includes other operating revenues on TE Products.
(5)
Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries.
(6)
Includes TCO purchases of condensate and expenses related to LSI’s use of an affiliate of EPCO as a transporter.
(7)
Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions for all periods through February 23, 2005, as a result of the change in ownership of the General Partner (see Note 1).
(8)
Includes LSI sales of lubrication oils and specialty chemicals and Jonah NGL sales in connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004. Amounts related to the Pioneer plant are classified as discontinued operations in the consolidated statements of income.
(9)
Includes revenues from NGL transportation on the Chaparral, Panola, Dean and Wilcox NGL pipelines.
(10)
Includes gas gathering revenues on the Jonah system.
(11)
Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence, Rhode Island, terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. We recognized revenue from an affiliate of DEFS pursuant to this agreement.
(12)
Includes fractionation revenues and other revenues. Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Other operating revenues also include other operating revenues on TE Products and processing and other revenues on the Jonah system. Amounts related to the Pioneer plant are classified as discontinued operations in the consolidated statements of income.
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Notes To Consolidated Financial Statements-(Continued)
(13)
Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under a contractual agreement established at the time of acquisition of each asset. In connection with the change in ownership of our General Partner, we have assumed these activities.
(14)
Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS.
(15)
Includes TCO purchases of condensate.
(16)
Includes Jonah purchases of natural gas in connection with Jonah’s Pioneer processing plant operations.
At December 31, 2005, we had a receivable from EPCO and affiliates of $4.3 million related to sales and transportation services provided to EPCO and affiliates. At December 31, 2005, we had a payable to EPCO and affiliates of $9.8 million related to direct payroll, payroll related costs and other operational related charges.
At December 31, 2004, we had a receivable from DEFS and affiliates of $10.5 million related to sales and transportation services provided to DEFS and affiliates. Included in this receivable balance from DEFS and affiliates at December 31, 2004, is a gas imbalance receivable of $0.9 million. At December 31, 2004, we had a payable to DEFS and affiliates of $22.4 million related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above. Included in this payable balance at December 31, 2004, is a gas imbalance payable to DEFS and affiliates of $3.2 million.
From February 24, 2005 through December 31, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO. From February 24, 2005 through December 31, 2005, we incurred insurance expense related to premiums charged by EPCO of $9.8 million. At December 31, 2005, we had insurance reimbursement receivables due from EPCO of $1.3 million.
Through February 23, 2005, we contracted with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers’ liability insurance. Through February 23, 2005 and for the years ended December 31, 2004 and 2003, we incurred insurance expense related to premiums paid to Bison of $1.2 million, $6.5 million and $5.9 million, respectively. At December 31, 2004, we had insurance reimbursement receivables due from Bison of $5.2 million.
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 11).
Seaway
We own a 50% ownership interest in Seaway, and the remaining 50% interest is owned by ConocoPhillips (see Note 6). We operate the Seaway assets. During the years ended December 31, 2005, 2004 and 2003, we billed Seaway $8.5 million, $7.6 million and $7.4 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, for each of the years ended December 31, 2005, 2004 and 2003, we billed Seaway $2.1 million for indirect management fees for operating Seaway. At December 31, 2005 and 2004, we had payable balances to Seaway of $0.6 million and $0.5 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.
Centennial
TE Products has a 50% ownership interest in Centennial (see Note 6). TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2005, 2004 and 2003, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $3.7 million, $6.9 million and $4.4 million, respectively.
TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2005 and 2004, we had net payable balances of $1.4 million and $1.7 million, respectively, to Centennial for its share of the joint tariff deliveries and other operational related charges, partially offset by the reimbursement due to us for construction services provided to Centennial.
In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the years ended December 31, 2005, 2004 and 2003, TE Products incurred $5.9 million, $5.3 million and $3.8 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.
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Notes To Consolidated Financial Statements-(Continued)
MB Storage
Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 6). TE Products operates the facilities for MB Storage. TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2005, 2004 and 2003, TE Products recognized $0.1 million in rental revenue related to this lease agreement. During the years ended December 31, 2005, 2004 and 2003, TE Products also billed MB Storage $3.6 million, $3.2 million and $2.5 million, respectively, for direct payroll and payroll related expenses for operating MB Storage. At December 31, 2005 and 2004, TE Products had net receivable balances from MB Storage of $0.9 million and $1.3 million, respectively, for operating costs, including payroll and related expenses for operating MB Storage.
Note 8. Inventories
Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2005 and 2004. The major components of inventories were as follows (in thousands):
Note 9. Property, Plant and Equipment
Major categories of property, plant and equipment for the years ended December 31, 2005 and 2004, were as follows (in thousands):
Depreciation expense, including impairment charges, on property, plant and equipment was $80.8 million, $80.7 million and $64.5 million for the years ended December 31, 2005, 2004 and 2003, respectively. During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.
In September 2005, our Todhunter facility, near Middletown, Ohio, experienced a propane release and fire at a dehydration unit within the storage facility. The facility is included in our Downstream Segment. The dehydration unit was destroyed due to the propane release and fire, and as a result, we wrote off the remaining book value of the asset of $0.8 million to depreciation and amortization expense during the third quarter of 2005.
We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. During the third quarter of 2005, our Upstream Segment was notified by a connecting carrier that the flow of its pipeline system would be reversed, which would directly impact the viability of one of our pipeline systems. This system, located in East Texas, consists of approximately 45 miles of pipeline, six tanks of various sizes and other equipment and asset costs. As a result of changes to the connecting carrier, we performed an impairment test of the system and recorded a $1.8 million non-cash impairment charge,
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Notes To Consolidated Financial Statements-(Continued)
included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.
During the third quarter of 2005, we completed an evaluation of a crude oil system included in our Upstream Segment. The system, located in Oklahoma, consists of approximately six miles of pipelines, tanks and other equipment and asset costs. The usage of the system has declined in recent months as a result of shifting crude oil production into areas not supported by the system, and as such, it has become more economical to transport barrels by truck to our other pipeline systems. As a result, we performed an impairment test on the system and recorded a $0.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.
During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area. The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment. The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational. As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the facility.
Note 10. Debt
Senior Notes. On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at our election at the following redemption prices (expressed in percentages of the principal amount) if redeemed during the twelve months beginning January 15 of the years indicated:
and thereafter at 100% of the principal amount, together in each case with accrued interest at the redemption date.
The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank pari passu with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, TE Products was in compliance with the covenants of the TE Products Senior Notes.
On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.
On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but
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Notes To Consolidated Financial Statements-(Continued)
not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.
The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2005 and 2004 (in millions):
We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above (see Note 4).
Revolving Credit Facility. On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contained certain restrictive financial covenant ratios. During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.
On June 27, 2003, we entered into a $550.0 million unsecured revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios. Restrictive covenants in the Revolving Credit Facility limit our ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash (see Note 11) and complete mergers, acquisitions and sales of assets. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing. On February 23, 2005, we amended our Revolving Credit Facility to remove the requirement that DEFS must at all times own, directly or indirectly, 100% of our General Partner, to allow for its acquisition by DFI (see Note 1). During the second quarter of 2005, we used a portion of the proceeds from the equity offering in May 2005 to repay a portion of the Revolving Credit Facility (see Note 11). On December 13, 2005, we again amended our Revolving Credit Facility as follows:
•
Total bank commitments increased from $600.0 million to $700.0 million. The amendment also provided that the commitments under the credit facility may be increased up to a maximum of $850.0 million upon our request, subject to lender approval and the satisfaction of certain other conditions.
•
The facility fee and the borrowing rate currently in effect were reduced by 0.275%.
•
The maturity date of the credit facility was extended from October 21, 2009, to December 13, 2010. Also under the terms of the amendment, we may request up to two, one-year extensions of the maturity date. These extensions, if requested, will become effective subject to lender approval and satisfaction of certain other conditions.
•
The amendment also removed the $100.0 million limit on the total amount of standby letters of credit that can be outstanding under the credit facility.
On December 31, 2005, $405.9 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.9%. At December 31, 2005, we were in compliance with the covenants of this credit agreement.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
The following table summarizes the principal amounts outstanding under all of our credit facilities as of December 31, 2005 and 2004 (in thousands):
Letter of Credit. At December 31, 2005, we had an $11.5 million standby letter of credit in connection with crude oil purchases in the fourth quarter of 2005. This amount will be paid during the first quarter of 2006.
Note 11. Partners’ Capital and Distributions
Equity Offerings
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO. We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.
On August 7, 2003, we sold in an underwritten public offering 5.0 million Units at $34.68 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $166.0 million. On August 19, 2003, 162,900 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on August 7, 2003. Proceeds from the over-allotment sale, net of underwriting discount, totaled $5.4 million. Approximately $53.0 million of the proceeds were used to repay indebtedness under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 5). The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.
On May 5, 2005, we sold in an underwritten public offering 6.1 million Units at $41.75 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $244.5 million. On June 8, 2005, 865,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on May 5, 2005. Proceeds from the over-allotment sale, net of underwriting discount, totaled $34.7 million. The proceeds were used to reduce indebtedness under our Revolving Credit Facility, to fund revenue generating and system upgrade capital expenditures and for general partnership purposes.
Quarterly Distributions of Available Cash
We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds as follows:
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Notes To Consolidated Financial Statements-(Continued)
The following table reflects the allocation of total distributions paid during the years ended December 31, 2005, 2004 and 2003 (in thousands, except per Unit amounts):
On February 7, 2006, we paid a cash distribution of $0.675 per Unit for the quarter ended December 31, 2005. The fourth quarter 2005 cash distribution totaled $66.9 million.
General Partner Interest
As of December 31, 2005 and 2004, we had deficit balances of $61.5 million and $35.9 million, respectively, in our General Partner’s equity account. These negative balances do not represent an asset to us and do not represent an obligation of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Consolidated Statements of Partners’ Capital for a detail of the General Partner’s equity account). For the years ended December 31, 2005, 2004 and 2003, the General Partner was allocated $47.6 million (representing 29.27%), $40.0 million (representing 28.85%) and $33.7 million (representing 27.65%), respectively, of our net income and received $73.2 million, $66.9 million and $54.7 million, respectively, in cash distributions.
Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our limited partners. The Capital Account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under accounting principles generally accepted in the United States in our financial statements. Under our Partnership Agreement, the General Partner is required to make additional capital contributions to us upon the issuance of any additional Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners. At December 31, 2005 and 2004, the General Partner’s Capital Account balance substantially exceeded this requirement.
Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.
Cash distributions that we make during a period may exceed our net income for the period. We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Cash distributions in excess of net income allocations and capital contributions during the years ended December 31, 2005 and 2004, resulted in a deficit in the General Partner’s equity account at December 31, 2005 and 2004. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.
According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.
Note 12. Concentrations of Credit Risk
Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes
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Notes To Consolidated Financial Statements-(Continued)
in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.
For each of the years ended December 31, 2005, 2004 and 2003, Valero Energy Corp. accounted for 14%, 16% and 16% of our total consolidated revenues, respectively. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2005, 2004 and 2003.
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature.
Note 13. Unit-Based Compensation
1994 Long Term Incentive Plan
During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Units. These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.
When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Any unused balance previously credited is forfeited upon termination. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.
Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. At December 31, 2005, all options have been fully exercised. The Performance Unit account has a minimal liability balance which may be withdrawn by the participants after December 31, 2006.
A summary of Unit options granted under the terms of the 1994 LTIP is presented below:
We have not granted options for any periods presented. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised. For options previously outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Units on the date of grant. Accordingly, we recognized no compensation expense at the date of grant. Had compensation expense been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, no compensation expense would have been recognized for the years ended December 31, 2005, 2004 and 2003.
1999 and 2002 Phantom Unit Plans
Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 PURP”). Effective June 1, 2002, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”). The 1999 PURP and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of a Unit as reported on the New York Stock Exchange on the redemption date.
Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year. Each participant is required to
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Notes To Consolidated Financial Statements-(Continued)
redeem their phantom units as they vest. They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the amount of the cash distribution that we paid per Unit to unitholders. We accrued compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. At December 31, 2004, we had an accrued liability balance of $1.6 million for compensation related to the 1999 PURP and 2002 PURP. Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005 (see Note 1), all outstanding units under both the 1999 PURP and the 2002 PURP fully vested and were redeemed by participants. As such, there were no outstanding units at December 31, 2005 under either the 1999 PURP or the 2002 PURP.
2000 Long Term Incentive Plan
Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period. Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005, all outstanding units under the 2000 LTIP for plan years 2003 and 2004 were fully vested and redeemed by participants. As such, there were no outstanding units at December 31, 2005, for awards granted for the plan years ended December 31, 2004 and 2003. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 23,400.
Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion the Chief Executive Officer (“CEO”) of the Company may exclude gains or losses from extraordinary, unusual or non-recurring items. For the years ended December 31, 2005, 2004 and 2003, EBITDA means, in addition to the above definition of EBITDA, earnings before other income - net. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil operating oil supply and the gross value of intangibles and equity investments. Our cost of capital is approved by our CEO at the date of award grant.
In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. At December 31, 2005 and 2004, we had an accrued liability balance of $0.7 million and $2.4 million, respectively, for compensation related to the 2000 LTIP.
Phantom Unit Plan
Effective January 1, 2005, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 PURP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the grantee’s vested percentage multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s vested percentage is based upon the improvement of our EBITDA (as defined below) during a three-year performance period over the target EBITDA as defined at the beginning of each year during the three-year performance period. EBITDA means our earnings before minority interest, net interest expense, other income - net, income taxes, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements
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Notes To Consolidated Financial Statements-(Continued)
prepared in accordance with generally accepted accounting principles, except that at his discretion, our CEO may exclude gains or losses from extraordinary, unusual or non-recurring items. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 53,600.
In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2005 PURP discussed above. At December 31, 2005, we had an accrued liability balance of $0.7 million for compensation related to the 2005 PURP.
Note 14. Operating Leases
We use leased assets in several areas of our operations. Total rental expense for the years ended December 31, 2005, 2004 and 2003, was $24.0 million, $22.1 million and $18.8 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):
Note 15. Employee Benefits
Retirement Plans
The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. In addition, the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefit retirement plan, in which certain executive officers participated. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age and service. We used a December 31 measurement date for these plans.
On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended. Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date. Effective December 31, 2005, all plan benefits accrued were frozen, participants will not receive additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, subject to IRS approval of plan termination, and plan participants will have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity. For those plan participants who elect to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant owns the annuity, absolving us of any future obligation to the participant. Participants in the TEPPCO SBP received pay credits through November 30, 2005, and received lump sum benefit payments in December 2005. Both the RCBP and SBP benefit payments are discussed below.
In June 2005, we recorded a curtailment charge of $0.1 million in accordance with SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, as a result of the TEPPCO RCBP and TEPPCO SBP amendments. As of May 31, 2005, the following assumptions were changed for purposes of determining the net periodic benefit costs for the remainder of 2005: the discount rate, the long-term rate of return on plan assets, and the assumed mortality table. The discount rate was decreased from 5.75% to 5.00% to reflect rates of returns on bonds currently available to settle the liability. The expected long-term rate of return on plan assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds. The mortality table was changed to reflect overall improvements in mortality experienced by the general population. The curtailment charge arose due to the accelerated recognition of the unrecognized prior service costs. We recorded additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP. We expect to record additional settlement charges of approximately $4.0 million in 2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):
Other Postretirement Benefits
We provided certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees became eligible for these benefits if they met certain age and service requirements at retirement, as defined in the plans. We provided a fixed dollar contribution, which did not increase from year to year, towards retired employee medical costs. The retiree paid all health care cost increases due to medical inflation. We used a December 31 measurement date for this plan.
In May 2005, benefits provided to employees under the TEPPCO OPB were changed. Employees eligible for these benefits received them through December 31, 2005, however, effective December 31, 2005, these benefits were terminated. As a result of this change in benefits and in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, we recorded a curtailment credit of approximately $1.7 million in our accumulated postretirement obligation which reduced our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB. The current employees participating in this plan were transferred to DEFS, who will continue to provide postretirement benefits to these retirees. We recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits.
The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):
Effective June 1, 2005, the payroll functions performed by DEFS for our General Partner were transferred from DEFS to EPCO. For those employees who were receiving certain other postretirement benefits at the time of the acquisition of our General Partner by DFI, DEFS will continue to provide these benefits to those employees. Effective June 1, 2005, EPCO began providing certain other postretirement benefits to those employees who became eligible for the benefits after June 1, 2005, and will charge those benefit related costs to us. As a result of these changes, we recorded a $1.2 million reduction in our other postretirement obligation in June 2005.
We employed a building block approach in determining the long-term rate of return for plan assets. Historical markets were studied and long-term historical relationships between equities and fixed-income were preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates were evaluated before long-term capital market assumptions were determined. The long-term portfolio return was established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns were reviewed to check for reasonability and appropriateness.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2005 and 2004, were as follows:
The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2005 and 2004, were as follows:
(1)
Expense was remeasured on May 31, 2005, as a result of TEPPCO RCBP and TEPPCO SBP amendments. The discount rate was decreased from 5.75% to 5% effective June 1, 2005, to reflect rates of returns on bonds currently available to settle the liability.
(2)
As a result of TEPPCO RCBP and TEPPCO SBP amendments, the expected return on assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds, effective June 1, 2005.
The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2005 and 2004 (in thousands):
We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid (in thousands):
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Notes To Consolidated Financial Statements-(Continued)
Plan Assets
We employed a total return investment approach whereby a mix of equities and fixed income investments were used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance was established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contained a diversified blend of equity and fixed-income investments. Furthermore, equity investments were diversified across U.S. and non-U.S. stocks, both growth and value equity style, and small, mid and large capitalizations. Investment risk and return parameters were reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines. This comprehensive review incorporated investment portfolio performance, annual liability measurements and periodic asset/liability studies.
The following table sets forth the weighted average asset allocations for the retirement plans and other postretirement benefit plans as of December 31, 2005 and 2004, by asset category (in thousands):
We do not expect to make further contributions to our retirement plans and other postretirement benefit plans in 2006.
Other Plans
DEFS also sponsored an employee savings plan, which covered substantially all employees. Effective February 24, 2005, in conjunction with the change in ownership of our General Partner, our participation in this plan ended. Plan contributions on behalf of the Company of $0.9 million, $3.5 million and $3.2 million were recognized for the period January 1, 2005 through February 23, 2005, and during the years ended December 31, 2004 and 2003, respectively.
Note 16. Commitments and Contingencies
Litigation
In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’ claims on terms that did not have a material adverse effect on our financial position, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remain named parties in the Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all remaining claims asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.
On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The
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Notes To Consolidated Financial Statements-(Continued)
plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. On November 30, 2004, the court approved a class settlement. The time period for parties to appeal this settlement expired in March 2005, and the class settlement became final. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.
In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as a result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On August 5, 2005, we were named as a third-party defendant in a matter styled ConocoPhillips, et al. v. BP Amoco Seaway Products Pipeline Company as filed in the 55th Judicial District of Harris County, Texas. ConocoPhillips alleges a right to indemnity from BP Amoco Seaway Products Pipeline Company (“BP Amoco”) for tax liability incurred by ConocoPhillips as a result of the reverse merger of Seaway Pipeline Company (the “Original Seaway Partnership”). The reverse merger of the Original Seaway Partnership was undertaken in preparation for our purchase of ARCO Pipe Line Company pursuant to the Amended and Restated Purchase Agreement (the “Purchase Agreement”) dated May 10, 2000, between us and Atlantic Richfield Company. BP Amoco has claimed a right to indemnity from us under the Purchase Agreement should BP Amoco have any indemnity liability to ConocoPhillips. ConocoPhillips alleges the income tax liability to be approximately $4.0 million. On January 20, 2006, we entered into a settlement agreement with BP Amoco dismissing and resolving all of BP Amoco’s claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.
In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have recently pursued certification as a class and have significantly increased their demand to approximately $175.0 million. This revised demand includes amounts for environmental restoration not previously claimed by the plaintiffs. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
Regulatory Matters
Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment and various safety matters. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. We believe our operations have been and are in material compliance with applicable environmental and safety laws and regulations, and that compliance with existing environmental laws and regulations are not expected to have a material adverse effect on our competitive position, financial positions, results of operations or cash flows. However, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder, and claims
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for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. At December 31, 2005 and 2004, we have an accrued liability of $2.4 million and $5.0 million, respectively, related to sites requiring environmental remediation activities.
On March 26, 2004, a decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”). The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged. In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates. The elements identified in the decision are volume changes, allowed total return and total cost-of-service (including major cost elements such as rate base, tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rates and income tax allowances as stand-alone factors. Judicial review of that decision, which has been sought by a number of parties to the case, is currently pending before the U.S. Court of Appeals for the District of Columbia Circuit. We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.
On July 20, 2004, the District of Columbia Circuit issued an opinion in BP West Coast Products LLC v. FERC. In reviewing a series of orders involving SFPP, L.P., the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its income attributable to partnership interests owned by corporate partners. Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for the percentage of its net operating (pre-tax) income attributable to partnership units held by corporations, and was denied an income tax allowance equal to the percentage attributable to partnership units held by non-corporate partners. The court remanded the case back to the FERC for further review. As a result of the court’s remand, on May 4, 2005, the FERC issued its Policy Statement on Income Tax Allowances, which permits regulated partnerships, limited liability companies and other pass-through entities an income tax allowance on their income attributable to any owner that has an actual or potential income tax liability on that income, regardless whether the owner is an individual or corporation. If there is more than one level of pass-through entities, the regulated company income must be traced to where the ultimate tax liability lies. The Policy Statement is to be applied in individual cases, and the regulated entity bears the burden of proof to establish the tax status of its owners. On December 16, 2005, the FERC issued the first of those decisions, in an order involving SFPP (the “SFPP Order”). The SFPP Order confirmed that an MLP is entitled to a tax allowance with respect to partnership income for which there is an “actual or potential income tax liability” and determined that a unitholder that is required to file a Form 1040 or Form 1120 tax return that includes partnership income or loss is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. The FERC also established certain other presumptions, including that corporate unitholders are presumed to be taxed at the maximum corporate tax rate of 35% while individual unitholders (and certain other types of unitholders taxed like individuals) are presumed to be taxed at a 28% tax rate. The SFPP Order remains subject to further administrative proceedings (including compliance filings by SFPP and possible rehearing requests), as well as potential judicial review. The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology. However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.
In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At December 31, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.
On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order with the State of Illinois, which required us to conduct an environmental investigation. At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release. On August 30, 2005, a final settlement was reached with the State of Illinois. The settlement included the payment of a civil penalty of $0.1 million and the requirement that we make certain modifications to the equipment of the facility, none of which are expected to have a material adverse effect on our financial position, results of operations or cash flows.
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Notes To Consolidated Financial Statements-(Continued)
On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal. The released jet fuel was contained within a storm water retention pond located on the terminal property. Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”). On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.” On February 7, 2005, we entered into a Memorandum of Understanding with the USFWS, settling all aspects of this matter. The terms of this settlement did not have a material effect on our financial position, results of operations or cash flows.
On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. The maximum statutory penalty proposed by the DOJ for this alleged violation of the CWA is $2.1 million. We do not expect any civil penalty to have a material adverse effect on our financial position, results of operations or cash flows.
On September 18, 2005, a propane release and fire occurred at our Todhunter facility, near Middletown, Ohio. The incident resulted in the death of one of our employees. There were no other injuries. On or about February 22, 2006, we received verbal notification from a representative of the Occupational Safety and Health Administration that they intend to serve us with a citation arising out of this incident. At this time, we have not received any citation, and we cannot predict with certainty the amount of any fine or penalty associated with any such citation; however, we do not expect any fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.
Rates of interstate petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI - 1% to PPI. On April 22, 2003, several shippers filed a petition in the United States Court of Appeals for the District of Columbia Circuit (the “Court”), Flying J. Inc,. Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs. Federal Energy Regulatory Commission; Docket No. 03-1107, seeking a review of whether the FERC’s adoption of the PPI Index was reasonable and supported by the evidence. On April 9, 2004, the Court handed down a decision denying the shippers’ petition for review, stating the shippers failed to establish that any of the FERC’s methodological choices (or combination of choices) were both erroneous and harmful.
As an alternative to using the PPI Index, interstate petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market- Based Rates”) or agreements between shippers and petroleum products and crude oil pipeline companies that the rate is acceptable.
Other
Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2005, $150.0 million was outstanding under those credit facilities. TE Products and Marathon have each guaranteed one-half of the repayment of Centennial’s outstanding debt balance (plus interest) under a long-term credit agreement, which expires in 2024, and a short-term credit agreement, which expires in 2007. The guarantees arose in order for Centennial to obtain adequate financing, and the proceeds of the credit agreements were used to fund construction and conversion costs of its pipeline system. Prior to the expiration of the long-term credit agreement, TE Products could be relinquished from responsibility under the guarantee should Centennial meet certain financial tests. If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments for TE Products and Marathon is $75.0 million each at December 31, 2005.
TE Products, Marathon and Centennial have entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event. There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each. As a result of the catastrophic event guarantee, TE Products has recorded a $4.6 million obligation, which represents the present value of the estimated amount that we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, contributions exceeding our deductible might be covered by our insurance.
One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment. We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements. Generally, events of default would trigger our performance under the guarantee. The maximum potential amount of future payments under the
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Notes To Consolidated Financial Statements-(Continued)
guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments. We carry insurance coverage that may offset any payments required under the guarantees.
On February 24, 2005, the General Partner was acquired from DEFS by DFI. The General Partner owns a 2% general partner interest in us and is the general partner of the Partnership. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission (“FTC”) delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of the General Partner may substantially lessen competition. The General Partner is cooperating fully with this investigation.
Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2005, TCTM and TE Products had approximately 4.0 million barrels and 22.5 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control.
We carry insurance coverage consistent with the exposures associated with the nature and scope of our operations. Our current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense. For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, limits or sub-limits and policy terms and conditions.
We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are commensurate with the nature and scope of our operations. The cost of our general insurance coverages has increased over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are through EPCO (see Note 7).
Note 17. Segment Information
We have three reporting segments:
•
Our Downstream Segment, which is engaged in the transportation and storage of refined products, LPGs and petrochemicals;
•
Our Upstream Segment, which is engaged in the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and
•
Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and transportation of NGLs.
The amounts indicated below as “Partnership and Other” relate primarily to intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports, refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6).
Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway. Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.
Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM
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Notes To Consolidated Financial Statements-(Continued)
and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde. On March 31, 2006, we sold our ownership interest in the Jonah Pioneer silica gel natural gas processing plant located near Opal, Wyoming to an affiliate of Enterprise for $38.0 million in cash (see Note 5 in the Notes to the Consolidated Financial Statements). Operating results of the Pioneer plant for the years ended December 31, 2005 and 2004 are shown as discontinued operations.
The tables below include financial information by reporting segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):
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Notes To Consolidated Financial Statements-(Continued)
The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the years ended December 31, 2005, 2004 and 2003 (in thousands):
The following table reconciles the segments total earnings before interest to consolidated net income for the three years ended December 31, 2005, 2004 and 2003 (in thousands):
Note 18. Comprehensive Income
SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the year ended December 31, 2005, the components of comprehensive income were due to crude oil hedges. The crude oil hedges mature in December 2006. While the crude oil hedges are in effect, changes in the fair values of the crude oil hedges, to the extent the hedges are effective, are recognized in other comprehensive income until they are recognized in net income in future periods. As of and for the year ended December 31, 2004, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge. The interest rate swap matured in April 2004. While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedge interest costs were recognized in net income.
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The accumulated balance of other comprehensive income related to our cash flow hedges is as follows (in thousands):
Note 19. Supplemental Condensed Consolidating Financial Information
Our significant operating subsidiaries, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P., have issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”
The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting.
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Note 20. Restatement of Consolidated Financial Statements
We are restating our previously reported consolidated financial statements for the fiscal years ended December 31, 2003 and 2004. For the impact of the restated consolidated financial results for the quarterly periods during the years ended December 31, 2005 and 2004, see Note 21. We have determined that our method of accounting for the $33.4 million excess investment in Centennial, previously described as an intangible asset with an indefinite life, and the $27.1 million excess investment in Seaway, previously described as equity method goodwill, was incorrect. Through our accounting for these excess investments in Centennial and Seaway as intangible assets with indefinite lives and equity method goodwill, respectively, we have been testing the amounts for impairment on an annual basis as opposed to amortizing them over a determinable life. We determined that it would be more appropriate to account for these excess investments as intangible assets with determinable lives. As a result, we made non-cash adjustments that reduced the net value of the excess investments in Centennial and Seaway, and increased amortization expense allocated to our equity earnings. The effect of this restatement caused a $3.8 million and $4.0 million reduction to net income as previously reported for the fiscal years ended December 31, 2004 and 2003, respectively. As a result of the accounting correction, net income for the fiscal year ended December 31, 2005, includes a charge of $4.8 million, of which $3.8 million relates to the first nine months. Additionally, partners’ capital at December 31, 2002, reflects a $2.5 million reduction representing the cumulative effect of this correction for fiscal years ended December 31, 2000 through 2002.
While we believe the impacts of these non-cash adjustments are not material to any previously issued financial statements, we determined that the cumulative adjustment for these non-cash items was too material to record in the fourth quarter of 2005, and therefore it was most appropriate to restate prior periods’ results. These non-cash adjustments had no effect on our operating income, compensation expense, debt balances or ability to meet all requirements related to our debt facilities. The restatement had no impact on total cash flows from operating activities, investing activities or financing activities. All amounts in the accompanying consolidated financial statements have been adjusted for this restatement.
We will continue to amortize the $30.0 million excess investment in Centennial related to a contract using units-of-production methodology over a 10-year life. The remaining $3.4 million related to a pipeline will continue to be amortized on a straight-line basis over 35 years. We will continue to amortize the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to a pipeline.
The following tables summarize the impact of the restatement adjustment on previously reported balance sheet amounts for the year ended December 31, 2004, and income statement amounts and cash flow amounts for the years ended December 31, 2004 and 2003 (in thousands):
Balance Sheet Amounts;
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Notes To Consolidated Financial Statements-(Continued)
Income Statement Amounts:
Cash Flow Amounts;
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Partners’ Capital Amounts:
Note 21. Quarterly Financial Information (Unaudited)
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(1) The quarterly financial information for 2004 and the first three quarters of 2005 reflect the impact of the restatement.
(2) The sum of the four quarters does not equal the total year due to rounding.
(3) Per Unit calculation includes 6,965,000 Units issued in May and June 2005.
Note 22. Subsequent Events
In January 2006, we entered into interest rate swaps with a total notional amount of $200.0 million, whereby we will receive a floating rate of interest and will pay a fixed rate of interest for a two-year term. These interest rate swaps were executed to decrease the exposure to potential increases in floating interest rates. Using the balances of outstanding debt at December 31, 2005, these interest rate swaps decrease the level of floating interest rate debt from 41% to 29% of total outstanding debt.
On February 13, 2006, we and an affiliate of Enterprise entered into a letter agreement related to an additional expansion (the “Jonah Expansion”) of the Jonah system (the “Letter Agreement”). The Jonah Expansion will consist of the installation of approximately 90,000 horsepower of gas turbine compression at a new compression station, related new piping and certain related facilities, which is expected to increase capacity of the Jonah system from 1.5 billion cubic feet per day to 2.0 billion cubic feet per day. We expect to enter into a joint venture (“Joint Venture”) agreement with Enterprise relating to the construction and financing of the Jonah Expansion. Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million). Such advance will constitute a subscription for an equity interest in the proposed Joint Venture (the “Subscription”). We expect the Jonah Expansion to be put into service in late 2006. We have the option to return to Enterprise up to 100% of the amount of the Subscription. If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly. The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.
TEPPCO PARTNERS, L.P.
Notes To Consolidated Financial Statements-(Continued)
Part IV, Exhibits and Financial Statement Schedule, Exhibit No. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
The ratio of earnings to fixed charges is calculated using the Securities and Exchange Commission guidelines(a).
(a) Income Statement amounts have been adjusted for discontinued operations.
(b) Excludes minority interest expenses and income or loss from equity investees.
(c) Excludes equity costs related to Allowance for Funds Used During Construction that are included in Other Income and Expenses in the Consolidated Statements of Operations.
(d) Earnings were inadequate to cover fixed charges by $724 million for the year ended December 31, 2003.
(e) Includes pre-tax gains on the sale of TEPPCO GP and LP of approximately $0.9 billion, net of minority interest, in 2005.
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Members of DCP Midstream, LLC Denver, Colorado
We have audited the accompanying consolidated balance sheets of DCP Midstream, LLC and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for the years then ended. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DCP Midstream, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
Denver, Colorado
March 14, 2007 (February 5, 2008 as to Note 18)
FF-1
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Consolidated Balance Sheets
As of December 31, 2006 and 2005
(millions)
See Notes to Consolidated Financial Statements.
FF-2
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Consolidated Statements of Operations and Comprehensive Income
Years Ended December 31, 2006 and 2005
(millions)
See Notes to Consolidated Financial Statements.
FF-3
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Consolidated Statements of Cash Flows
Years Ended December 31, 2006 and 2005
(millions)
See Notes to Consolidated Financial Statements.
FF-4
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Consolidated Statements of Members’ Equity
Years Ended December 31, 2006 and 2005
(millions)
See Notes to Consolidated Financial Statements.
FF-5
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements
Years Ended December 31, 2006 and 2005
1. General and Summary of Significant Accounting Policies
Basis of Presentation-DCP Midstream, LLC, formerly Duke Energy Field Services, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Duke Energy Corporation, or Duke Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. The Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.
To support and facilitate our continued growth, we formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. In September 2005, DCP Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission, or SEC, to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. We own approximately 41% of the limited partnership interests in DCP Partners and a 2% general partnership interest. As the general partner of DCP Partners, we have responsibility for its operations. DCP Partners is accounted for as a consolidated subsidiary.
In July 2005, Duke Energy transferred a 19.7% interest in our Company to ConocoPhillips in exchange for direct and indirect monetary and non-monetary consideration, effectively decreasing Duke Energy’s membership interest in our Company to 50% and increasing ConocoPhillips’ membership interest in our Company to 50%, referred to as “the 50-50 Transaction.” Included in this transaction, we distributed to Duke Energy substantially all of our Canadian business, made a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO and paid a $245 million proportionate distribution to Duke Energy and ConocoPhillips. In addition, ConocoPhillips contributed cash of $398 million to our Company. Under the terms of the amended and restated LLC Agreement, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. At December 31, 2006, there was no remaining restricted investment balance related to this contribution.
On June 28, 2006, Duke Energy’s board of directors approved a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses, including its 50% ownership interest in us, to Duke Energy shareholders. This transaction occurred on January 2, 2007. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy Corp, or Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For the historical periods included in this report, references to Spectra Energy are interchangeable with Duke Energy. On a prospective basis, Spectra Energy refers to the newly formed public company.
We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.
The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.
Use of Estimates-Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.
Acquisitions-We consolidate assets and liabilities from acquisitions as of the purchase date, and include earnings from acquisitions in consolidated earnings subsequent to the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. If the acquisition constitutes a business, any excess purchase price over the estimated fair value of the acquired assets and liabilities is recorded as goodwill.
FF-6
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Reclassifications-Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.
Cash and Cash Equivalents-Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.
Short-Term and Restricted Investments-We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale under Statement of Financial Accounting Standards, or SFAS, No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheets as accumulated other comprehensive income (loss), or AOCI. No such gains or losses were deferred in AOCI at December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.
Inventories-Inventories consist primarily of natural gas and NGLs held in storage for transportation and processing and sales commitments. Inventories are valued at the lower of weighted average cost or market. Transportation costs are included in inventory on the consolidated balance sheets.
Accounting for Risk Management and Hedging Activities and Financial Instruments-Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS 133, as amended, is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.
We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statements of operations and comprehensive income are as follows:
Classification of Contract
Accounting Method
Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives
Mark-to-market methoda
Net basis in trading and marketing gains (losses)
Non-Trading Derivatives:
Cash Flow Hedge
Hedge methodb
Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item
Fair Value Hedge
Hedge methodb
Gross basis in the same consolidated statements of operations and comprehensive income category as the related hedged item
Normal Purchase or
Normal Sale
Accrual methodc
Gross basis upon settlement in the corresponding consolidated statements of operations and comprehensive income category based on purchase or sale
Non-Trading Derivatives
Mark-to-market methoda
Net basis in trading and marketing gains (losses)
a
Mark-to-market-An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations and comprehensive income in trading and marketing gains (losses) during the current period.
b
Hedge method-An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations and comprehensive income for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the changes in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations and comprehensive income in the same category as the related hedged item.
c
Accrual method-An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations and comprehensive income for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings.
Cash Flow and Fair Value Hedges-For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge in accordance with SFAS 133. In addition, we formally assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
FF-7
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as AOCI and the ineffective portion is recorded in the consolidated statements of operations and comprehensive income. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations and comprehensive income in the same accounts as the item being hedged. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.
For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting changes in value of the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the consolidated statements of operations and comprehensive income.
Valuation-When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Property, Plant and Equipment-Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability for conditional asset retirement obligations as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity.
Impairment of Unconsolidated Affiliates-We evaluate our unconsolidated affiliates for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether any impairment has occurred. Management assesses the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.
Intangible Assets-Intangible assets consist of goodwill, and commodity sales and purchases contracts. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Commodity sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 25 years.
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
FF-8
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Impairment of Long-Lived Assets, Assets Held for Sale and Discontinued Operations-We evaluate whether the carrying value of long-lived assets, excluding goodwill, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:
•
A significant adverse change in legal factors or business climate;
•
A current period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
•
An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
•
Significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;
•
A significant adverse change in the market value of an asset; and
•
A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
We use the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” or SFAS 144, to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the consolidated balance sheets.
If an asset held for sale or sold (1) has clearly distinguishable operations and cash flows, generally at the plant level, (2) has direct cash flows of the held for sale or sold component that will be eliminated (from the perspective of the held for sale or sold component), and (3) if we are unable to exert significant influence over the disposed component, then the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales are reflected as income from discontinued operations in the consolidated statements of operations and comprehensive income. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statements of operations and comprehensive income.
Unamortized Debt Premium, Discount and Expense-Premiums, discounts and expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These premiums and discounts are recorded on the consolidated balance sheets as an offset to long-term debt. These expenses are recorded on the consolidated balance sheets as other non-current assets.
Distributions-Under the terms of the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each members’ tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. Prior to January 2, 2007, the capital accounts were maintained at 50% for both Duke Energy and ConocoPhillips, and prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the years ended December 31, 2006 and 2005, we paid distributions of $650 million and $389 million, respectively, based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.
Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. During the years ended December 31, 2006 and 2005, we paid total dividends of $801 million and $1,925 million, respectively. The $1,925 million paid during the year ended December 31, 2005, is comprised of a disproportionate cash distribution of approximately $1,100 million to Duke Energy
FF-9
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
using the proceeds from the sale of our general partner interest in TEPPCO as part of the 50-50 Transaction, a $245 million proportionate distribution to Duke Energy and ConocoPhillips as part of the 50-50 Transaction, and $580 million in proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The $801 million paid during the year ended December 31, 2006, is comprised of proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The LLC Agreement restricts payment of dividends except with the approval of both members.
DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our 41% limited partner interest in DCP Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period will end on December 31, 2010 if certain distribution tests are met and earlier if certain more stringent tests are met. At such time that the subordination period ends, the subordinated units will be converted to common units. During the year ended December 31, 2006, DCP Partners paid distributions of approximately $13 million to its public unitholders. We hold general partner incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.
Foreign Currency Translation-We translated assets and liabilities of our Canadian operations, where the Canadian dollar was the functional currency, at the period-end exchange rates. Revenues and expenses were translated using average monthly exchange rates during the period, which approximates the exchange rates at the time of each transaction during the period. Foreign currency translation adjustments are included in the consolidated statements of comprehensive income. In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. As a result, there were no translation gains or losses in AOCI at December 31, 2006 and 2005.
Revenue Recognition-We generate the majority of our revenues from natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as trading and marketing of natural gas and NGLs.
We obtain access to raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.
•
Fee-based arrangements-Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, or transporting of natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase raw natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of raw natural gas from the wellhead location to the delivery point. The revenue we earn is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced.
•
Percent-of-proceeds/index arrangements-Under percentage-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs at index prices based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Under these types of arrangements, our revenues correlate directly with the price of natural gas and NGLs.
•
Keep-whole arrangements-Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, market the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas received. Under these types of contracts, we are exposed to the “frac spread.” The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices.
FF-10
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Our trading and marketing of natural gas and NGLs, consists of physical purchases and sales, as well as derivative instruments.
We recognize revenue for sales and services under the four revenue recognition criteria, as follows:
Persuasive evidence of an arrangement exists-Our customary practice is to enter into a written contract, executed by both us and the customer.
Delivery-Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.
The fee is fixed or determinable-We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.
Collectability is probable-Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, cash position and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.
We generally report revenues gross in the consolidated statements of operations and comprehensive income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statements of operations and comprehensive income as trading and marketing gains (losses). These activities include mark-to-market gains and losses on energy trading contracts, and the financial or physical settlement of energy trading contracts.
Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. There are no material differences between the actual amounts and the estimated amounts of revenues and purchases recorded at December 31, 2006 and 2005.
Gas and NGL Imbalance Accounting-Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable-other as of December 31, 2006 and 2005 were imbalances totaling $45 million and $59 million, respectively. Included in the consolidated balance sheets as accounts payable - other, as of December 31, 2006 and 2005 were imbalances totaling $42 million at both periods.
Significant Customers-ConocoPhillips, an affiliated company, was a significant customer in both of the past two years. Sales to ConocoPhillips, including its 50% owned equity method investment, ChevronPhillips Chemical Company LLC, or CP Chem, totaled approximately $2,677 million during 2006 and $2,513 million during 2005.
Environmental Expenditures-Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2006 and 2005, included in the consolidated balance sheets, totaled $6 million for both periods recorded as other current liabilities, and totaled $6 million and $7 million, respectively, recorded as other long-term liabilities.
Stock-Based Compensation-Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPU’s, Strategic Performance Units, or SPU’s, and Phantom Units. Prior to January 2, 2007, each of the above units constitutes a notional unit equal to the weighted average fair value of a common share or unit of ConocoPhillips, Duke Energy and DCP Partners, weighted 45%, 45% and 10%, respectively. Upon the Spectra spin, the 45% weighting attributable to Duke Energy will be valued as one common share of Duke Energy and one-half of one common share of Spectra Energy. The 2006 Plan also provides for the grant of DCP Partners’ Phantom Units, which constitute a notional unit equal to the fair value of DCP Partners’ common units. Each unit provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006.
FF-11
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, equity instruments may be granted to DCP Partners’ key employees. DCP Midstream GP, LLC adopted the DCP Partners’ Plan for employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ Plan provides for the grant of unvested units, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. DCP Partners first granted awards under this plan during the first quarter of 2006.
Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board, or APB, Opinion No. 25, or APB 25, “Accounting for Stock Issued to Employees,” and Financial Accounting Standards Board, or FASB, Interpretation No. 44, or FIN 44, “Accounting for Certain Transactions Involving Stock Compensation-an Interpretation of APB Opinion No. 25.” Under that method, compensation expense was measured as the intrinsic value of an award at the measurement dates. The intrinsic value of an award is the amount by which the quoted market price of the underlying stock exceeds the amount, if any, an employee would be required to pay to acquire the stock. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation expense has historically been recognized in the accompanying consolidated statements of operations and comprehensive income. Compensation expense for phantom stock awards and other stock awards was recorded from the date of grant over the required vesting period based on the market value of the awards at the date of grant. Compensation expense for stock-based performance awards was recorded over the required vesting period, and adjusted for increases and decreases in market value at each reporting date up to the measurement dates.
Under its 1998 Long-Term Incentive Plan, or 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, certain of our employees who had been issued awards under the 1998 Plan incurred a change in status from Duke Energy employees to non-employees. As a result, all outstanding stock-based awards were required to be remeasured as of July 2005 under EITF Issue No. 96-18, or EITF 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using the fair value method prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123. Compensation expense is recognized prospectively beginning at the date of the change in status over the remaining vesting period based on the fair value of each award at each reporting date. The fair value of stock options is determined using the Black-Scholes option pricing model and the fair value of all other awards is determined based on the closing equity price at each measurement date.
Effective January 1, 2006, we adopted the provisions of SFAS No. 123(R) (Revised 2004) “Share-Based Payment,” or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Liability classified stock-based compensation cost is remeasured at each reporting date, and is recognized over the requisite service period.
We elected to adopt the modified prospective application method as provided by SFAS 123R and, accordingly, financial statement amounts for the prior periods presented in these consolidated financial statements have not been restated. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.
We recorded stock-based compensation expense for the years ended December 31, 2006 and 2005 as follows, the components of which are further described in Note 13:
FF-12
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
The following table shows what net income would have been if the fair value recognition provisions of SFAS 123 had been applied to all stock-based compensation awards for the year ended December 31, 2005.
Accounting for Sales of Units by a Subsidiary-In December 2005, we formed DCP Partners through the contribution of certain assets and investments in unconsolidated affiliates in exchange for common units, subordinated units and a 2% general partner interest. Concurrent with the formation, we sold approximately 58% of DCP Partners to the public, through an initial public offering, for proceeds of approximately $206 million, net of offering costs. We account for sales of units by a subsidiary under Staff Accounting Bulletin No. 51, or SAB 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. Under SAB 51, a gain on the sale of subsidiary equity cannot be recognized until multiple classes of outstanding securities convert to common equity. As a result, we have deferred approximately $150 million of gain on sale of common units in DCP Partners as other long-term liabilities in the consolidated balance sheets. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.
Income Taxes-We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes.
We follow the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities.
New Accounting Standards-SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FAS 115,” or SFAS 159. In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.
SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.
SFAS No. 154 “Accounting Changes and Error Corrections,” or SFAS 154. In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated results of operations, cash flows or financial position.
FF-13
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
FIN No. 48 “Accounting for Uncertainty in Income Taxes-An Interpretation of FASB Statement 109,” or FIN 48. In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for us on January 1, 2007. The adoption of FIN 48 is not expected to have a material impact on our combined results of operations, cash flows or financial position.
EITF Issue No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” or EITF 04-13. In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29 when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. EITF 04-13 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.
Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108-In September 2006, the SEC issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated results of operations, cash flows or financial position.
2. Acquisitions and Dispositions
Acquisitions
Acquisition of Various Gathering, Transmission and Processing Assets-In the fourth quarter of 2005, we entered into an agreement to purchase certain Federal Energy Regulatory Commission, or FERC, regulated pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate these assets as intrastate pipeline. This acquisition is expected to close in the second half of 2007.
Acquisition of Additional Equity Interests-In December 2006, we acquired an additional 33.33 % interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own 66.67% of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering pipeline system in the Gulf of Mexico.
In November 2006, we purchased the remaining 16% minority interest in Dauphin Island Gathering Partners, or DIGP, for $7 million. DIGP was owned 84% by us prior to this transaction, and subsequent to this transaction, is owned 100% by us. DIGP owns gathering and transmission assets in the Gulf Coast.
In December 2005, we purchased an additional 6.67% interest in Discovery Producer Services, LLC, or Discovery, from Williams Energy, LLC for a purchase price of $13 million. Discovery is an unconsolidated affiliate, which, prior to this transaction, was 33.33% owned by us, and subsequent to this transaction is 40% owned by us. Discovery owns and operates an interstate pipeline, a condensate handling facility, a cryogenic gas processing plant and other gathering assets in deepwater offshore Louisiana.
Dispositions
Disposition of Various Gathering, Transmission and Processing Assets-In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified certain of these assets as held for sale, recorded in other non-current assets, consisting primarily of property, plant and equipment totaling $58 million at December 31, 2005. Assets at one location, totaling $48 million as of December 31, 2005, were sold in the first quarter of 2006 for $76 million and we recognized a gain of $28 million. Assets at another location, totaling $9 million as of December 31, 2005, were sold in the first quarter of 2006 for $9 million and we recognized no gain or loss.
FF-14
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
In August 2005, we sold certain gas gathering facilities in Kansas and Oklahoma for a sales price of approximately $11 million. No gain or loss was recognized.
In February 2005, we exchanged certain processing plant assets in Wyoming for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.
In February 2005, we sold certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming for approximately $28 million.
Disposition of Equity Interests-In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid its outstanding borrowings in full in March 2005. Duke Capital, LLC repaid its outstanding borrowings in full in July 2005.
Distribution of Canadian Business to Duke Energy-In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. The following is a summary of the net assets distributed to Duke Energy on the closing date of July 1, 2005 (millions):
We routinely sell assets that comprise a component of the Company, and are recorded as discontinued operations, but are not individually significant. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented.
There were no assets accounted for as discontinued operations for the year ended December 31, 2006. The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005:
FF-15
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
3. Agreements and Transactions with Affiliates
The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging instruments with affiliates as of December 31:
The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the years ended December 31:
(a)
Includes ConocoPhillips’ 50% owned equity method investment, CP Chem
Spectra Energy and Duke Energy
Services Agreement-Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.
In connection with the Spectra spin, we will need to transfer responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transition these services either to Spectra or to third party service providers.
Included on the consolidated balance sheets in other non-current assets-affiliates as of December 31, 2006, are insurance recovery receivables of $47 million, and included in accounts receivable-affiliates as of December 31, 2006 and 2005, are other receivables of $8 million and $39 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. During the years ended December 31, 2006 and 2005, we recorded hurricane related business interruption insurance recoveries of $1 million and $3 million, respectively, included in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.
In the fourth quarter of 2006, an insurance provider that is a subsidiary of Duke Energy agreed to settle an insurance claim, related to a damaged underground storage facility, for approximately $21 million. We had recorded a receivable in 2005 related to this claim for approximately $4 million. Upon receipt of the cash in December 2006, we relieved the receivable and recorded business interruption insurance recoveries of approximately $16 million, included in the consolidated statements of operations and comprehensive income as transportation, storage and processing.
FF-16
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Commodity Transactions-We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Duke Energy and Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Spectra Energy in the ordinary course of business.
ConocoPhillips
Long-term NGLs Purchases Contract and Transactions-We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem, a 50% equity investment of ConocoPhillips (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement, or the CP Chem NGL Agreement, between us and CP Chem, CP Chem has the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The CP Chem NGL Agreement also grants CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.
Transactions with other unconsolidated affiliates
In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid their outstanding borrowings in full in March 2005. Duke Capital LLC repaid their outstanding borrowings in full in July 2005.
We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell these commodities and provide these services to unconsolidated affiliates in the ordinary course of business.
Estimates related to affiliates
Revenue for goods and services provided but not invoiced to affiliates is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated revenues and purchases recorded at December 31, 2006 and 2005.
4. Marketable Securities
Short-term and restricted investments-At December 31, 2006 and 2005, we had $437 million and $627 million, respectively, of short-term investments. These instruments are classified as available-for-sale securities under SFAS 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as the interest rates re-set on a daily, weekly or monthly basis.
In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash was invested in financial instruments as described above. Under the terms of the amended and restated LLC Agreement, however, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. As this cash was to be used to acquire non-current assets, we had $0 and $264 million, respectively, classified as a long-term asset, as restricted investments, on the consolidated balance sheets at December 31, 2006 and 2005. At December 31, 2006 and 2005, we had restricted investments of $102 million and $100 million, respectively, consisting of collateral for DCP Partners’ term loan.
FF-17
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
5. Inventories
Inventories by category were as follows as of December 31:
6. Property, Plant and Equipment
Property, plant and equipment by classification was as follows as of December 31:
Depreciation expense for 2006 and 2005 was $275 million and $278 million, respectively. Interest capitalized on construction projects in 2006 and 2005, was approximately $3 million and $2 million, respectively. At December 31, 2006, we had non-cancelable purchase obligations of approximately $27 million for capital projects expected to be completed in 2007. In addition, property, plant and equipment includes $10 million and $13 million of non-cash additions for the years ended December 31, 2006 and 2005, respectively.
7. Goodwill and Other Intangibles
The changes in the carrying amount of goodwill are as follows for the years ended December 31:
We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.
We completed our annual goodwill impairment test as of August 31, 2006. We also tested goodwill for impairment in July 2005 upon the distribution of substantially all of our Canadian business to Duke Energy, in conjunction with the 50-50 Transaction. These goodwill impairment tests were performed by comparing our reporting units’ estimated fair values to their carrying, or book, values. These valuations indicated our reporting units’ fair values were in excess of their carrying, or book, values; therefore, we have determined that there is no indication of impairment. There were no impairments of goodwill for the years ended December 31, 2006 and 2005.
FF-18
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
During 2005, we recorded an adjustment to properly account for deferred taxes established as a result of purchase business combinations that occurred during 2001. As a result of this adjustment, goodwill and deferred income tax liabilities decreased by approximately $11 million and $3 million, respectively, and property, plant and equipment, net, increased by $8 million.
In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. Included in the distribution was $18 million of goodwill, which was determined based on the relative fair value of the Canadian business to the fair value of the Natural Gas Services reporting unit.
The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows for the years ended December 31:
During the years ended December 31, 2006 and 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these intangibles range from less than one year to 20 years with a weighted average remaining period of approximately 7 years.
Estimated amortization for these contracts for the next five years and thereafter is as follows:
8. Investments in Unconsolidated Affiliates
We have investments in the following unconsolidated affiliates accounted for using the equity method:
Discovery Producer Services LLC-Discovery Producer Services LLC, or Discovery, owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. In December 2005, we acquired an additional 6.67% interest in Discovery from Williams Energy, LLC for a purchase price of $13 million, bringing our total ownership to 40%. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $49 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.
FF-19
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Main Pass Oil Gathering Company-In December 2006, we acquired an additional 33.33% interest in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method. The excess of the carrying amount of the investment over the underlying equity of Main Pass of $12 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.
Sycamore Gas System General Partnership-Sycamore Gas System General Partnership, or Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $9 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.
Mont Belvieu I-Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I of $11 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.
Tri-States NGL Pipeline, LLC-Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence, therefore, this investment is accounted for under the equity method of accounting in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
Black Lake Pipe Line Company-Black Lake Pipe Line Company, or Black Lake, owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $7 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.
Fox Plant, LLC-In May 2006, we purchased the remaining 50% interest in Fox Plant, LLC, a limited liability company formed for the purpose of constructing, owning, and operating a gathering facility and gas processing plant in Carter County, Oklahoma. Subsequent to May 2006, Fox Plant, LLC was accounted for as a consolidated subsidiary. Fox Plant, LLC is included in other unconsolidated affiliates in the above table as of December 31, 2005.
TEPPCO Partners, L.P.-In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million.
Equity in earnings of unconsolidated affiliates amounted to the following for the years ended December 31:
FF-20
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
The following summarizes combined financial information of unconsolidated affiliates for the years ended and as of December 31:
9. Estimated Fair Value of Financial Instruments
We have determined the following fair value amounts using available market information and appropriate valuation methodologies. Considerable judgment is required, however, in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.
The fair value of short-term investments, restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.
The estimated fair values of current debt, including current maturities of long-term debt, and long-term debt, with the exception of DCP Partners’ long-term debt, are determined by prices obtained from market quotes. The carrying value of DCP Partners’ long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.
10. Asset Retirement Obligations
Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.
We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally
FF-21
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.
The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes changes in the asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets, for the years ended December 31:
11. Financing
Long-term debt was as follows at December 31:
(a) See Note 12 for further discussion.
Debt Securities-In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007. The proceeds from this offering were used to repay our 5.75% Senior Notes that matured on November 15, 2006.
In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015, or 5.375% Notes, for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We pay interest semiannually on April 15 and October 15 of each year, commencing April 15, 2006. The proceeds from this offering were used to repay the August 2005 term loan facility discussed below.
In August 2005, we repaid the $600 million 7.5% Notes that were due on August 16, 2005. We repaid a portion of this debt with available cash and proceeds from the issuance of commercial paper, and refinanced a portion of this debt with the August 2005 term loan facility discussed below.
The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.
FF-22
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Credit Facilities with Financial Institutions-On April 29, 2005, we entered into a credit facility, or the Facility, to replace a $250 million 364-day facility that was terminated on April 29, 2005. The Facility is used to support our commercial paper program, and for working capital and other general corporate purposes. In December 2005, we amended the Facility to amend the definition of consolidated capitalization to include minority interest, which is referred to in these financial statements as non-controlling interest. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility is a $450 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.35% per year for the initial 50% usage or LIBOR plus 0.45% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.1% based on our credit rating on the drawn and undrawn portions. As of December 31, 2006, there were no borrowings or commercial paper outstanding, and there was approximately $5 million in letters of credit drawn against the Facility. As of December 31, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.
In August 2005, we entered into a credit agreement, or the Term Loan Facility, where we made a one-time request to borrow $200 million in the form of a term loan. We used this Term Loan Facility to repay a portion of our $600 million 7.5% Notes that matured on August 16, 2005. The Term Loan Facility was repaid in October 2005 with proceeds from the 5.375% Notes.
On December 7, 2005, DCP Partners entered into a 5-year credit agreement, or the DCP Partners’ Credit Agreement, with a $250 million revolving credit facility and a $100 million term loan facility. The DCP Partners’ Credit Agreement matures on December 7, 2010. At December 31, 2006 and 2005, there was $168 million and $110 million, respectively, outstanding on the revolving credit facility and $100 million outstanding on the term loan facility. The term loan facility is fully collateralized by investments in high-grade securities, which are classified as restricted investments on the accompanying consolidated balance sheet. Outstanding letters of credit on the DCP Partners’ Credit Agreement were less than $1 million as of December 31, 2006, and there were no letters of credit outstanding at December 31, 2005. The DCP Partners’ Credit Agreement requires DCP Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the DCP Partners’ Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. Indebtedness under the revolving credit facility bears interest, at our option, at either (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50% or (2) LIBOR plus an applicable margin, which ranges from 0.27% to 1.025% dependent upon the leverage level or credit rating. As of December 31, 2006, the $100 million term loan facility bears interest at LIBOR plus a rate per annum of 0.15%. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.
Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2006:
12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments
Commodity price risk-Our principal operations of gathering, processing, compression, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, gathering, treating, processing, storage and trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs,
FF-23
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.
Energy trading (market) risk-Certain of our subsidiaries are engaged in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.
Interest rate risk-We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.
Credit risk-Our principal customers range from large, natural gas marketing services to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.
As of December 31, 2006, we held cash or letters of credit of $83 million to secure future performance of financial or physical contracts, and had deposited with counterparties $7 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclose credit ratings, which may impact the amounts of collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
Commodity hedging strategies-Historically, we have used commodity cash flow hedges, as specifically defined in SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and our ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions. Our current strategy is to use cash flow hedges only for commodity price risk related to DCP Partners’ operations. Some of the assets operated by DCP Partners generate cash flows that are subject to volatility from fluctuating commodity prices. As a publicly traded master limited partnership, an important component of the strategy of DCP Partners is to generate consistent cash flow from its operations in order to pay distributions to its unitholders. For operations other than those of DCP Partners, we do not currently anticipate using cash flow hedges in the near future, because management believes cash flows will be sufficient to fund our business.
Commodity cash flow hedges-We have executed a series of derivative financial instruments, which have been designated as cash flow hedges of the price risk associated with forecasted sales of natural gas, NGLs and condensate through 2010, and the price risk associated with forecasted sales of condensate during 2011, related to assets of DCP Partners. Because of the strong correlation between NGL prices and crude oil prices, and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk.
For the year ended December 31, 2006, amounts recognized as comprehensive income in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were gains of $4 million, and amounts recognized for the effects of any ineffectiveness were insignificant for the year ended December 31, 2006. For the year ended December 31,
FF-24
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
2005, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. During the year ended December 31, 2006, we reclassified $1 million in net gains (net of minority interest of $2 million) to the consolidated statements of operations and comprehensive income as a result of settlements. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of a change in the probability of forecasted transactions occurring, which would cause us to discontinue hedge treatment. The deferred balance in AOCI was a gain of $3 million at December 31, 2006, and was insignificant at December 31, 2005. As of December 31, 2006, $1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.
Commodity fair value hedges-We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).
For the years ended December 31, 2006 and 2005, the gains or losses representing the ineffective portion of our fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items and, therefore, did not recognize an associated gain or loss.
Interest rate cash flow hedges-During 2006, DCP Partners entered into interest rate swap agreements to convert $125 million of the indebtedness on their revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps expire on December 7, 2010 and re-price prospectively approximately every 90 days. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the accompanying consolidated balance sheets. For the year ended December 31, 2006, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were not significant, and there was no ineffectiveness recorded for the year ended December 31, 2006. At December 31, 2006, the gains deferred in AOCI related to these swaps were insignificant. At December 31, 2006, the amount of deferred net gains on derivative instruments in AOCI that are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur are insignificant; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.
Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred into AOCI and amortized against interest expense over the life of the respective debt. The amount amortized to interest expense during the years ended December 31, 2006 and 2005, was $1 million for both periods. The deferred balance was a loss of $7 million and $8 million at December 31, 2006 and 2005, respectively. Approximately $1 million of deferred net losses related to these instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the underlying hedged interest expense transaction occurs.
Interest rate fair value hedges-In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities, which were issued in August 2000, to floating rate debt. The interest rate fair value hedge was at a floating rate based on a six-month LIBOR, which was re-priced semiannually through the date of maturity, August 2005.
In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions, which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2006 and 2005, the fair value of the interest rate swaps was a $4 million and $8 million asset, respectively, which is included in the consolidated balance sheets as unrealized gains or losses on mark-to-market and hedging instruments with offsets to the underlying debt included in current maturities of long-term debt and long-term debt.
Commodity derivatives-trading and marketing-Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales
FF-25
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.
13. Stock-Based Compensation
DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan-Relative Performance Units-RPU’s generally cliff vest at the end of eight years, consisting of a three year performance period and a five year deferral period. The number of RPU’s that will ultimately vest range from 0% to 200% of the outstanding RPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. At the end of the performance period, based on the market value of the RPU’s, we will create an account for each grantee in our deferred compensation plan. Payment of the grantee’s deferred compensation account will occur after a five year deferral period, the value of which is based on the value of the participant’s investment elections during the deferral period. Each RPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the RPUs for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the RPU’s, which was calculated using an estimated forfeiture rate of 64%, and is expected to be recognized over a weighted-average period of 7.0 years. The following tables presents information related to RPUs:
Strategic Performance Units-SPU’s generally cliff vest at the end of three years. The number of SPU’s that will ultimately vest range from 0% to 150% of the outstanding SPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. Each SPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the SPUs for the year ended December 31, 2006, was approximately $1 million. At December 31, 2006 there was approximately $3 million of unrecognized compensation expense related to the SPU’s, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to SPUs:
FF-26
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
The estimate of RPU’s and SPU’s that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.
Phantom Units-Phantom Units generally cliff vest at the end of five years. Each Phantom Unit includes a dividend or distribution equivalent right, which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the Phantom Units, which was calculated using an estimated forfeiture rate of 19%, and is expected to be recognized over a weighted-average period of 4.0 years. The following table presents information related to Phantom Units:
DCP Partners’ Phantom Units-The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of a common unit of DCP Partners, which generally cliff vest at December 31, 2008. Each DCP Partners’ Phantom Unit includes a distribution equivalent right, which is paid quarterly in arrears. Expense related to the DCP Partners’ Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the DCP Partners’ Phantom Units, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the DCP Partners’ Phantom Units:
During the year ended December 31, 2006, no awards under the 2006 Plan were forfeited, vested or settled.
FF-27
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan-Performance Units-Performance Units generally cliff vest at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance percentage payout is determined by the compensation committee of DCP Partners’ board of directors. Each Performance Unit includes a distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the Performance Units for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the Performance Units, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to the Performance Units:
The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.
Phantom Units-Of the Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date and 8,000 units vest ratably over three years. Each Phantom Unit includes a distribution equivalent right which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006, estimated unrecognized compensation expense related to the Phantom Units was not significant. The following tables presents information related to the Phantom Units:
The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.
All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of the relevant underlying securities at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.
Duke Energy 1998 Plan-Under its 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, our employees incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased accounting for these awards under APB 25 and FIN 44, and began accounting for these awards in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.
FF-28
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Stock Options-Under the 1998 Plan, the exercise price of each option granted could not be less than the market price of Duke Energy’s common stock on the date of grant. Vesting periods range from immediate to four years with a maximum option term of 10 years. Effective July 1, 2005, these options were accounted for in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. As a result, compensation expense subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock options at each reporting date until vesting.
The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.
The total intrinsic value of options exercised during the year ended December 31, 2006 and 2005, was approximately $3 million and $2 million, respectively. As of December 31, 2006, all compensation expense related to these awards has been recognized.
There were no options granted during the years ended December 31, 2006 or 2005.
Stock-Based Performance Awards-Stock-based performance awards outstanding under the 1998 Plan vest over three years if certain performance targets are achieved. Duke Energy awarded 160,910 shares during the year ended December 31, 2005. There were no stock-based performance awards granted during the year ended December 31, 2006.
The following table summarizes information about stock-based performance awards activity during the year ended December 31, 2006:
As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted, vested or canceled during the year ended December 31, 2006.
Phantom Stock Awards-Phantom stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 128,850 shares during the year ended December 31, 2005. There were no phantom stock awards granted during the year ended December 31, 2006.
The following table summarizes information about phantom stock awards activity during the year ended December 31, 2006:
FF-29
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
The total fair value of the phantom stock awards that vested during the year ended December 31, 2006 and 2005 was approximately $2 million and less than $1 million, respectively. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of 2.7 years. No awards were granted or canceled during the year ended December 31, 2006.
Other Stock Awards-Other stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy granted 3,000 other stock awards during the year ended December 31, 2005. There were no other stock awards granted during the year ended December 31, 2006.
The following table summarizes information about other stock awards activity during the year ended December 31, 2006:
The total fair value of the other stock awards that vested during the years ended December 31, 2006 and 2005 was not significant. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was not significant, and is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted or canceled during the year ended December 31, 2006.
14. Benefits
All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contributed 4% of each eligible employee’s qualified earnings, through December 31, 2006. Effective January 1, 2007, we began contributing a range of 4% to 7% of each eligible employee’s qualified earnings, based on years of service. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings. During 2006 and 2005, we expensed plan contributions of $15 million.
We offer certain eligible executives the opportunity to participate in the DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of our general assets and liabilities, respectively.
15. Income Taxes
We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise, and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes. Taxes associated with these subsidiaries have been reclassified to discontinued operations for year ended December 31, 2005.
In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax.
As a result of the change in Texas franchise law, our tax status in the state of Texas has changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year.
FF-30
DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. We have computed taxable margin as total revenue less cost of goods sold. Based on information currently available, we recorded a deferred tax liability of $18 million in 2006. The deferred tax liability is recorded as non-current in the consolidated balance sheets as of December 31, 2006, and as a non-cash offset to income tax expense in the consolidated statements of operations and comprehensive income for the year ended December 31, 2006.
Income tax expense consists of the following for the years ended December 31:
Temporary differences for our gross deferred tax assets of $4 million primarily relate to basis differences between property, plant and equipment, and investments in unconsolidated affiliates. Temporary differences for our gross deferred tax liabilities of $17 million primarily relate to basis differences between property, plant and equipment.
Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.
16. Commitments and Contingent Liabilities
Litigation-The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.
In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Midstream Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
In November 2006, we received a demand associated with the alleged migration of acid gas from a storage formation into a third party producing formation. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.
Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.
General Insurance-In 2005, we carried all of our insurance coverage with an affiliate of Duke Energy. Beginning in 2006, we elected to carry only property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips, however, effective August 2006, we no longer carry insurance coverage with an affiliate of Duke Energy. Our remaining insurance coverage is with an affiliate of ConocoPhillips and a third party insurer. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. Property insurance deductibles are currently $1 million for onshore or non-hurricane related incidents or up to $5 million per occurrence for hurricane related incidents. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Casualty insurance deductibles are currently $1 million per occurrence. The cost of our general insurance coverages increased over the past year reflecting the adverse conditions of the insurance markets.
During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. The resulting losses are expected to be covered by insurance, subject to applicable deductibles for property and business interruption. Insurance recovery receivables related to hurricane Ivan included on the consolidated balance sheets in other non-current assets-affiliates as of December 31, 2006, are $25 million, and included in accounts receivable-affiliates as of December 31, 2006 and 2005, are $3 million and $28 million, respectively, from an insurance provider that is a subsidiary of Duke Energy.
During the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico, however, substantially all of our facilities have resumed pre-hurricane levels of capacity utilization. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages are covered by our insurance, subject to applicable deductibles. The financial impact of recent hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Insurance recovery receivables related to hurricane Katrina included on the consolidated balance sheets in other non-current assets-affiliates as of December 31, 2006 are $21 million, and included in accounts receivable-affiliates as of December 31, 2006 and 2005, are $2 million and $5 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. Included in other non-current assets-affiliates as of December 31, 2006, are insurance recovery receivables related to hurricane Rita of $1 million at December 31, 2006. The balance at December 31, 2005, was not significant. Based on recent negotiations, we have reclassified a portion of these hurricane insurance receivables as non-current at December 31, 2006.
During the years ended December 31, 2006 and 2005, we recorded business interruption insurance recoveries related to these hurricanes of $1 million and $3 million, respectively, in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.
Environmental-The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at three of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions from January 2001 to date and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. The Compliance Orders seek a civil penalty but did not request a specific amount. We intend to contest these allegations. Management does not believe this will result in a material impact on our consolidated results of operations, cash flows or financial position.
Other Commitments and Contingencies-We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $37 million and $36 million in 2006 and 2005, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.
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(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006:
17. Guarantees and Indemnifications
In September 2005, we signed a corporate guaranty, which was amended in December 2005 upon our purchase of an additional interest in the related unconsolidated affiliate, pursuant to which we are the guarantor of a maximum of $10 million of construction obligations. The original guaranty was $22 million as of December 31, 2005, and was reduced by construction payments of $12 million during the year ended December 31, 2006. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated results of operations, financial position or cash flows.
We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At both December 31, 2006 and 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.
18. Subsequent Events
During the year ended December 31, 2007, we distributed $1,364 million to Spectra Energy and ConocoPhillips, and DCP Partners distributed $44 million to its unitholders. On January 24, 2008, DCP Partners announced the declaration of a cash distribution of $0.57 per unit, payable on February 14, 2008, to unitholders of record on February 7, 2008.
In September 2007, we issued $450 million principal amount of 6.75% Senior Notes due 2037, or the 6.75% Notes, for proceeds of approximately $444 million (net of related offering costs). The 6.75% Notes mature and become due and payable on September 15, 2037. We will pay interest semiannually on March 15 and September 15 of each year, commencing March 15, 2008. The proceeds of this offering were used to fund the Momentum Energy Group, Inc. or MEG, acquisition.
On August 29, 2007, we acquired the stock of MEG for approximately $635 million plus closing adjustments of approximately $8 million. MEG owns assets in the Fort Worth, Piceance and Powder River producing basins. Concurrent with this transaction, DCP Partners acquired certain subsidiaries of MEG from us for $165 million plus closing adjustments of approximately $10 million, subject to final closing adjustments. These subsidiaries of MEG own assets in the Piceance Basin, including a 70% operated interest in the 31-mile Collbran Valley Gas Gathering joint venture in western Colorado, assets in the Powder River Basin, including the 1,324-mile Douglas gas gathering system, and other facilities in Wyoming. We ultimately funded our portion of this acquisition with the 6.75% Notes, as well as cash on hand. DCP Partners financed this transaction with $120 million of revolver and term loan borrowings under DCP Partners’ Amended Credit Agreement, the issuance of approximately $100 million of common units through a private placement (described in the next sentence) with certain institutional inventors and cash on hand. In August 2007, DCP Partners sold 2,380,952 common limited partner units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate.
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
Notes To Consolidated Financial Statements-(Continued)
Years Ended December 31, 2006 and 2005
In July 2007, we contributed to DCP Partners a 25% limited liability company interest in DCP East Texas Holdings, LLC, our 40% limited liability company interest in Discovery Producer Services LLC, and a derivative instrument, for aggregate consideration of $244 million in cash, including $1 million for net working capital and other adjustments, $27 million in common units and $1 million in general partner equivalent units. We own the remaining 75% limited liability company interest in East Texas Holdings, LLC, while third parties still own the other 60% limited liability interest in Discovery Producer Services LLC. DCP Partners financed the cash portion of this transaction with borrowings under DCP Partners’ existing credit agreement. We will continue to operate these assets and these assets will continue to be included in our financial statements, along with DCP Partners.
In June 2007, DCP Partners entered into a private placement agreement with a group of institutional investors for $130 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $129 million, net of offering costs. DCP Partners used a portion of the net proceeds of this private placement to pay down a portion of the debt associated with the acquisition from Anadarko Petroleum Corporation of assets in southern Oklahoma, and used the remaining portion of the net proceeds to fund future capital expenditures, including the MEG acquisition.
In June 2007, DCP Partners entered into an Amended and Restated Credit Agreement, or DCP Partners’ Amended Credit Agreement, which amended DCP Partners’ Credit Agreement. This new 5-year DCP Partners’ Amended Credit Agreement consists of a $600 million revolving credit facility and a $250 million term loan facility, and matures on June 21, 2012. The amendment also improved pricing and certain other terms and conditions of DCP Partners’ Credit Agreement.
In May 2007, DCP Partners acquired certain gathering and compression assets located in southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181 million.
On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. We do not expect this transaction to have a material effect on our operations.
On January 1, 2007, we changed our name from Duke Energy Field Services, LLC to DCP Midstream, LLC, to coincide with the Spectra spin.
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DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
SCHEDULE II-CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Years Ended December 31, 2006 and 2005
(a)
Principally consists of other contingency reserves, which are included in other current liabilities.
(b)
Consists of other contingency and litigation reserves reclassified between accounts.
(c)
Principally consists cash payments, collections, reserve reversals and liabilities settled.
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PART IV
EXHIBIT INDEX
Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**). Portions of the exhibit designated by a triple asterisk (***) have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934.
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The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.
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