XCEL ENERGY INC
Item 1 - Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Subsidiaries and Affiliates (current and former)
Cheyenne
Cheyenne Light, Fuel and Power Company, a Wyoming corporation
Eloigne
Eloigne Company, a Minnesota corporation which invests in rental housing projects that qualify for low-income housing tax credits.
NCE
New Century Energies, Inc.
NMC
Nuclear Management Company, LLC, a wholly owned subsidiary of NSP Nuclear Corporation
NRG
NRG Energy, Inc., a Delaware corporation and independent power producer
NSP-Minnesota
Northern States Power Company, a Minnesota corporation
NSP-Wisconsin
Northern States Power Company, a Wisconsin corporation
PSCo
Public Service Company of Colorado, a Colorado corporation
PSRI
P.S.R. Investments, Inc., a manager of corporate owned life insurance policies
SPS
Southwestern Public Service Co., a New Mexico corporation
UE
Utility Engineering Corporation, an engineering, construction and design company
utility subsidiaries
NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
WGI
WestGas InterState, Inc., a Colorado corporation operating an interstate natural gas pipeline
WYCO
WYCO Development L.L.C., a joint venture formed with Colorado Interstate Gas Company to develop and lease natural gas pipeline, storage, and compression facilities
Xcel Energy
Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
ASLB
Atomic Safety and Licensing Board
CAPCD
Colorado Air Pollution Control Division
CPUC
Colorado Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of PSCo's operations in Colorado. The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.
DOE
United States Department of Energy
EPA
United States Environmental Protection Agency
FERC
Federal Energy Regulatory Commission. The U. S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; hydroelectric generation licensing; and accounting requirements for utility holding companies, service companies, and public utilities.
IRS
Internal Revenue Service
MPCA
Minnesota Pollution Control Agency
MPSC
Michigan Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin's operations in Michigan.
MPUC
Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota's operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NDPSC
North Dakota Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota's operations in North Dakota.
NERC
North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the U. S. FERC and government authorities in Canada, to develop and enforce reliability standards.
NMPRC
New Mexico Public Regulation Commission. The state agency that regulates the retail rates and services and other aspects of SPS' operations in New Mexico. The NMPRC also has jurisdiction over the issuance of securities by SPS.
NRC
Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
OES
Office of Energy Security, Minnesota Department of Commerce.
PSCW
Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin's operations in Wisconsin.
PUCT
Public Utility Commission of Texas. The state agency that regulates the retail rates, services and other aspects of SPS' operations in Texas.
SDPUC
South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota's operations in South Dakota.
SEC
Securities and Exchange Commission
WDNR
Wisconsin Department of Natural Resources
Electric, Purchased Gas and Resource Adjustment Clauses
AQIR
Air quality improvement rider. Recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.
DSM
Demand side management. Energy conservation, weatherization and other programs to conserve or manage energy use by customers.
DSMCA
Demand side management cost adjustment. A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA.
ECA
Retail electric commodity adjustment. Allows PSCo to recover its actual fuel and purchased energy expense in a calendar year to a benchmark formula. Short-term sales margins and margins from the sale of SO2 allowances are shared with retail customers through the ECA.
FCA
Fuel clause adjustment. A clause included in electric rate schedules that provides for monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.
GCA
Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
OATT
Open Access Transmission Tariff
PCCA
Purchased capacity cost adjustment. Allows PSCo to recover from retail customers for all purchased capacity payments to power suppliers, effective Jan. 1, 2007. Capacity charges are not included in PSCo's electric rates or other recovery mechanisms.
PGA
Purchased gas adjustment. A clause included in NSP-Minnesota's and NSP-Wisconsin's retail natural gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas and natural gas transportation. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent period.
QSP
Quality of service plan. Provides for bill credits to retail customers if the utility does not achieve certain operational performance targets and/or specific capital investments for reliability. The current QSP for the PSCo electric utility provides for bill credits to customers based on operational performance standards through Dec. 31, 2010. The QSP for the PSCo natural gas utility also expires Dec. 31, 2010.
RES
Renewable energy standard
RESA
Renewable energy standard adjustment
SCA
Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.
SEP
State Energy Policy
TCR
Transmission cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities not included in the determination of NSP-Minnesota's electric rates in retail electric rates in Minnesota. The TCR was approved by the MPUC in 2006 to be effective in 2007, and will be revised annually as new transmission investments and costs are incurred.
Other Terms and Abbreviations
ACES
American Clean Energy and Security Act
AEP
American Electric Power
AFUDC
Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ
Administrative law judge. A judge presiding over regulatory proceedings.
ARC
Aggregator of Retail Customers
ARO
Asset retirement obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC
FASB Accounting Standards Codification
ASM
Ancillary Services Market
BACT
Best Available Control Technology
BART
Best Available Retrofit Technology
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CapX 2020
An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
CIP
Conservation improvement program
CO2
Carbon dioxide
Codification
FASB Accounting Standards Codification
COLI
Corporate owned life insurance
CON
Certificate of need
CWIP
Construction work in progress
decommissioning
The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
derivative instrument
A financial instrument or other contract with all three of the following characteristics:
• An underlying and a notional amount or payment provision or both,
• Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and
• Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution
The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
DOI
Division of Investigation
EECRF
Energy efficiency cost recovery factor
EPS
Earnings per share of common stock outstanding
ETR
Effective tax rate
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings
FTRs
Financial transmission rights. Used to hedge the costs associated with transmission congestion.
GAAP
Generally accepted accounting principles
generation
The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in MW (capacity) or MW hours (energy).
GHG
Greenhouse gas
IRP
Integrated Resource Plan
LIBOR
London Interbank Offered Rate
LLW
Low-level radioactive waste
LNG
Liquefied natural gas. Natural gas that has been converted to a liquid.
MACT
Maximum Achievable Control Technology
mark-to-market
The process whereby an asset or liability is recognized at fair value.
MERP
Metropolitan Emissions Reduction Project
MGP
Manufactured gas plant
MISO
Midwest Independent Transmission System Operator, Inc.
MOAG
Minnesota Office of Attorney General
Moody's
Moody's Investors Service
native load
The customer demand of retail and wholesale customers that a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas
A naturally occurring mixture of gases found in porous geological formations beneath the earth's surface, often in association with petroleum. The principal constituent is methane.
NOL
Net operating loss
nonutility
All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
NOx
Nitrogen oxide
O&M
Operating and maintenance
OCI
Other comprehensive income
PBRP
Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PFS
Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PIIC
Prairie Island Indian Community
PJM
Pennsylvania-New Jersey-Maryland Interconnection
PSP
Performance share plan
PURPA
Public Utility Regulatory Policies Act of 1978
rate base
The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
REC
Renewable energy credit
RECB
Regional Expansion Criteria Benefits
RFP
Request for Proposal
ROE
Return on equity
RPS
Renewable Portfolio Standard, is a regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
RTO
Regional Transmission Organization. An independent entity, which is established to have "functional control" over a utility's electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SO2
Sulfur dioxide
SPP
Southwest Power Pool, Inc.
Standard & Poor's
Standard & Poor's Ratings Services
TSR
Total shareholder return
unbilled revenues
Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying
A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission
An electric service wherein high-voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
working capital
Funds necessary to meet operating expenses.
Measurements
Bcf
Billion cubic feet
Btu
British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
GWh
Gigawatt hours. One gigawatt hour equals one billion watt hours.
KV
Kilovolts (one KV equals one thousand volts)
KW
Kilowatts (one KW equals one thousand watts)
Kwh
Kilowatt hours
Mcf
Thousand cubic feet
MMBtu
One million Btus
MW
Megawatts (one MW equals one thousand KW)
Volt
The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts.
Watt
A measure of power production or usage.
COMPANY OVERVIEW
Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business. In 2009, Xcel Energy's continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.
Xcel Energy was incorporated under the laws of Minnesota in 1909. Xcel Energy's executive offices are located at 414 Nicollet Mall, Minneapolis, Minn. 55401. Its website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. In addition, the Xcel Energy guidelines on Corporate Governance and Code of Conduct are also available on its website.
Environmental leadership is a core strategic priority for Xcel Energy. Our environmental leadership strategy is designed to meet customer and policy maker expectations while creating shareholder value. We have established a highly effective environmental compliance program and have produced an excellent compliance record. Moreover, we pursue environmental policy initiatives that promote our environmental leadership and provide growth opportunities. Among other things, Xcel Energy is a national leader in voluntary emission reduction programs, the nation's largest retail utility wind energy provider and a leader in innovative technology, energy efficiency and conservation and customer-driven renewable energy programs. Xcel Energy is implementing resource plans in Colorado and Minnesota that are designed to result in a significant reduction in GHG emissions, while meeting growing customer demand at a reasonable price. Through our environmental leadership strategy, we are well-positioned to meet the challenges of potential future climate change regulation, comply with renewable energy mandates and take advantage of clean energy incentives created by policy makers in the states in which we operate.
NSP-Minnesota
NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately 10 percent of its total sales in 2009. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 89 percent of NSP-Minnesota's retail electric operating revenues were derived from operations in Minnesota during 2009. Generally, NSP-Minnesota's earnings range from approximately 40 percent to 50 percent of Xcel Energy's consolidated net income.
The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.
NSP-Minnesota owns the following direct subsidiaries: United Power and Land Company, which holds real estate; and NSP Nuclear Corporation.
NSP-Wisconsin
NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of its total sales in 2009. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory. NSP-Wisconsin provides electric utility service to approximately 249,000 customers and natural gas utility service to approximately 105,000 customers. The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota. Approximately 98 percent of NSP-Wisconsin's retail electric operating revenues were derived from operations in Wisconsin during 2009. Generally, NSP-Wisconsin's earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.
NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.
PSCo
PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. The wholesale customers served by PSCo comprised approximately 20 percent of its total sales in 2009. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers. All of PSCo's retail electric operating revenues were derived from operations in Colorado during 2009. Generally, PSCo's earnings range from approximately 45 percent to 55 percent of Xcel Energy's consolidated net income.
PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests for PSCo; and Green and Clear Lakes Company, which owns water rights. PSCo also owns PSRI, which held certain former employees' life insurance policies. Following settlement with the IRS during 2007, such policies were terminated. PSCo also holds a controlling interest in several other relatively small ditch and water companies.
SPS
SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in portions of Texas and New Mexico. The wholesale customers served by SPS comprised approximately 36 percent of its total sales in 2009. SPS provides electric utility service to approximately 396,000 retail customers in Texas and New Mexico. Approximately 74 percent of SPS' retail electric operating revenues were derived from operations in Texas during 2009. Generally, SPS' earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.
In November 2009, SPS announced it had entered into an agreement to sell certain SPS electric distribution assets in Lubbock, Texas to Lubbock Power and Light (LP&L) for a price of $87 million. SPS' retail sales in Lubbock are 3 percent of SPS' total energy sales. SPS anticipates it will sell the same amount of power to the city under existing wholesale power arrangements with the West Texas Municipal Power Agency.
Other Subsidiaries
WGI was incorporated in 1990 under the laws of Colorado. WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to the Cheyenne system near Cheyenne, Wyo.
In 1999, WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. WYCO's High Plains gas pipeline began operations in 2008 and its Totem gas storage facilities began operations in 2009. The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.
Xcel Energy Services Inc. is the service company for the Xcel Energy holding company.
Xcel Energy's nonregulated subsidiary in continuing operations is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits.
Xcel Energy had several other subsidiaries that were sold or divested. For more information regarding Xcel Energy's discontinued operations, see Note 4 to the consolidated financial statements.
Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. Comparative segment revenues, income from continuing operations and related financial information are set forth in Note 20 to the accompanying consolidated financial statements.
Xcel Energy focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers. Xcel Energy files periodic rate cases, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. For more information regarding Xcel Energy's capital expenditures, see Note 17 to the consolidated financial statements.
ELECTRIC UTILITY OPERATIONS
Electric Utility Trends
Overview
Climate Change and Clean Energy - Like most other utilities, Xcel Energy is subject to a significant array of environmental regulations. Further, there are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. Our operating subsidiaries are subject to state RPS requirements which we believe they will be in a position to achieve by the applicable state deadlines. Although the exact form and design of any federal RPS policy is uncertain at this time, we believe that we will be well-positioned to meet a federal standard as well, although the ultimate design of any federal policy could have a varied impact on each of our operating subsidiaries depending upon the energy efficiency and other standards imposed. In addition, Xcel Energy's electric generating facilities have been and are likely to be further subject to climate change legislation introduced at either the state or federal level within the next few years. In 2009, the EPA took a number of steps toward the regulation of GHGs under the CAA. By spring 2010, the EPA expects to promulgate regulations to control GHGs from mobile sources. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.
While Xcel Energy is not currently subject to state or federal limits on its GHG emissions, Xcel Energy has undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions. These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects. Although the impact of climate change policy on Xcel Energy will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we would be granted the authority to recover the cost of these initiatives through rates.
Additional information regarding climate change and clean energy is presented in the Management's Discussion and Analysis section.
Utility Restructuring and Retail Competition - The FERC has continued with its efforts to promote more competitive wholesale markets through open access transmission and other means. As a consequence, Xcel Energy's utility subsidiaries and their wholesale customers can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries' to serve their native load. In 2008, the FERC approved a MISO proposal to begin operation of a regional ASM in January 2009.
The FERC has approved the open access transmission planning processes for the Xcel Energy operating companies and the RTOs serving the NSP-Minnesota, NSP-Wisconsin and SPS systems (MISO and SPP, respectively).
•NSP-Minnesota received MPUC approval in 2008 to construct three new 115 KV transmission lines in 2009 to deliver additional wind generation even if NSP-Minnesota does not purchase the generation. Several additional transmission expansion projects are pending final MPUC action, including the CapX 2020 expansion.
•PSCo is pursuing upgrades to its transmission system and the systems of neighboring utilities in order to facilitate renewable energy expansion, in response to statutory changes enacted in 2007.
•SPS is also pursuing strengthening its transmission system internally to alleviate north and south congestion within the Texas Panhandle and other lines to increase the transfer capability between the Texas Panhandle and other electric systems in the SPP. Transmission expansion plans include 345 KV lines from Tuco, Texas to Woodward, Okla. In addition to utility-sponsored transmission expansion, several large "overlay" transmission projects have been proposed to construct 765 KV transmission facilities through the service areas of the utility subsidiaries. It is not certain if or when specific overlay projects may be constructed and placed in service.
One state served by Xcel Energy's utility subsidiaries has implemented retail electric utility competition. In 2002, Texas implemented retail competition, but it is presently limited to utilities within the ERCOT, which does not include SPS. Under current law, SPS can file a plan to implement competition, subject to regulatory approval, in Texas. Local market conditions and political realities must be considered in proposing the transition to competition. Xcel Energy has been unable to develop a plan for the Texas Panhandle to move toward competition that would be in the best interests of its customers. As a result, Xcel Energy does not plan to propose retail competition in the Texas Panhandle. New Mexico repealed its legislation related to retail electric utility competition.
Xcel Energy's retail electric business faces competition as industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In 2009, FERC adopted rules requiring MISO and SPP to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, NSP-Wisconsin and SPS, respectively, unless the applicable state regulatory authority prohibits ARCs from serving retail customers in its state. See further discussion in Public Utility Regulation below. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While each of Xcel Energy's utility subsidiaries faces these challenges, their rates are competitive with currently available alternatives.
NSP-Minnesota
Public Utility Regulation
Summary of Regulatory Agencies and Areas of Jurisdiction - Retail rates, services and other aspects of NSP-Minnesota's operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota's financial activities, including security issuances, property transfers, mergers and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota's electric resource plans for meeting customers' future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV.
No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generating and transmission facilities, and the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.
NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce and certain natural gas transactions in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see Market Based Rate Rules discussion) and is a transmission-owner member of the MISO RTO.
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms - NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:
•CIP - The CIP invests in programs that help customers save energy. CIP includes a comprehensive list of programs that benefit all customers including Saver's Switch®, energy efficiency rebates and energy audits.
•EIR - The EIR recovers the costs of environmental improvements to the A. S. King, High Bridge and Riverside plants, which were renovated under the MERP program.
•GAP - The GAP is a surcharge billed to all non-interruptible customers to recover the costs of offering a low-income customer co-pay program designed to reduce natural gas service disconnections.
•MCR - The MCR recovers costs related to reducing Mercury emissions at two NSP-Minnesota fossil fuel power plants.
•RDF - The RDF allocates money to support development of renewable energy projects research and development of renewable energy technologies.
•RES - In 2007, the Minnesota legislature passed new requirements mandating that a certain percent of energy produced by utilities like NSP-Minnesota come from renewable resources. In order to ensure these mandates can be met, the legislature allows utilities to recover the costs of new renewable generation projects to meet the RES in a rider.
•SEP - The SEP recovers costs related to various energy policies approved by the Minnesota legislature.
•TCR - The TCR recovers costs associated with new investments in the electric transmission system necessary to deliver electric energy to customers. NSP-Minnesota's retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred cost of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms approved by the regulators in each jurisdiction.
The FCAs allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or through rate cases.
NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost-recovery level annually. While this law changed to a savings-based requirement beginning in 2010, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.
MERP Rider Regulation - The MPUC approved a rate rider to recover prudent costs to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant beginning Jan. 1, 2006. A. S. King, High Bridge and Riverside went into service in July 2007, May 2008 and March 2009, respectively. In December 2009, the MPUC authorized the recovery of approximately $116.7 million in 2010 rates. The ROE for the A. S. King plant, the High Bridge plant and the Riverside plant, is 10.55 percent, 11.22 percent and 10.55 percent, respectively. The MERP projects will be included in rate base in the next general rate case and the projects removed from the rider.
Capacity and Demand
Uninterrupted system peak demand for the NSP System's electric utility for each of the last three years and the forecast for 2010, assuming normal weather, is listed below.
The peak demand for the NSP System typically occurs in the summer. The 2009 uninterrupted system peak demand for the NSP System occurred on June 23, 2009.
Energy Sources and Related Transmission Initiatives
NSP-Minnesota expects to use existing power plants, power purchases, DSM options, new generation facilities and expansion of existing power plants to meet its system capacity requirements.
Purchased Power - NSP-Minnesota has contracts to purchase power from other utilities and independent power producers. Capacity is the measure of the rate at which a particular generating source produces electricity. Energy is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.
NSP-Minnesota also makes short-term purchases to comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements.
Purchased Transmission Services - In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.
Excelsior Energy - In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project. The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior's petition. The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.
In its August 2007 Phase 1 order, the MPUC found, among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the OES and the guidance provided by the order.
In May 2009, the MPUC affirmed its previous order to deny Excelsior Energy's Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility, which closed the docket. In August 2009, Excelsior appealed the MPUC decision to the Minnesota Court of Appeals. The Minnesota Court of Appeals heard arguments on Feb. 23, 2010, and a decision is anticipated in 2010.
GHG Emissions - The 2007 Minnesota legislature adopted the goal to reduce statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, to a level at least 30 percent below 2005 levels by 2025, and to a level at least 80 percent below 2005 levels by 2050.
The legislation also prohibits the construction within Minnesota of a new large energy facility, the import or commitment to import from outside Minnesota power from a new large energy facility, or entering into a new long-term power purchase agreement that would increase statewide power sector CO2 emissions. The statute does not impose limitations on CO2 or other GHG emissions on NSP-Minnesota and provides for certain exemptions.
In November 2008, the MPUC approved NSP-Minnesota's request to include the costs of a natural gas cast iron pipe replacement project in its SEP Rider. The proposed cost recovery was enabled by the 2007 legislation, as the pipe replacement is expected to reduce GHG emissions. NSP-Minnesota expects to recover approximately $1.4 million over the 2009-2013 period, when the project is scheduled to be complete.
2009 Minnesota Legislative Session - The 2009 Minnesota legislature considered and adopted several measures related to energy policy and regulation, including:
•Permitting enhanced recovery for costs associated with the urban central corridor development;
•Encouraging the development of solar resources; and
•Continued encouragement of DSM. The legislature considered, but did not adopt, increased taxes on utility property.
Minnesota Resource Plan - In July 2009, the MPUC approved NSP-Minnesota's 2007 resource plan. The plan would reduce CO2 emissions by 22 percent from 2005 by 2020, a 6 million ton reduction. The plan includes the following components:
•Energy efficiency savings of 1.15 percent in 2010, 1.2 percent in 2011 and 1.3 percent in 2012;
•Install sufficient renewables to meet the Minnesota RES;
•Obtain required approvals to extend the life of the Prairie Island nuclear plant and to increase the output at both Prairie Island and Monticello;
•Continue ongoing capacity expansion at Sherco Unit 3;
•Continue to investigate repowering Black Dog Units 3 and 4, and provide the MPUC with specific plans and timelines for the repowering;
•Obtain approval for the 375 MW intermediate and 350 MW diversity exchange with Manitoba Hydro beginning in 2015; and
•Continue to ensure sufficient transmission available to deliver generation to load. Additionally, the MPUC required NSP-Minnesota to consider higher levels of DSM and energy efficiency and provide recommendations in NSP-Minnesota's next resource plan, which is to be filed no later than Aug. 1, 2010.
RES - In 2007, the Minnesota legislature changed the state's renewable energy objective into a standard that requires NSP-Minnesota to generate or cause to be generated electricity from renewable resources equaling:
•At least 15 percent of its retail sales by 2010;
•18 percent of retail sales by 2012;
•25 percent of retail sales by 2016; and
•30 percent by 2020. Of the 30 percent, at least 25 percent must be generated by wind energy conversion systems and the remaining five percent by other eligible energy technology. The law allows for a modification or delay in the implementation of the standard if the implementation would cause significant rate impact, require significant measures to address reliability or raises significant technical issues. All other Minnesota utilities are required to meet a 25 percent RES by 2025. No Minnesota utility has requested a modification or delay of the standard at this time.
Minnesota Statutes also allow for recovery of eligible renewable energy investments through a cost recovery rider. NSP-Minnesota began recovering eligible investments through this mechanism in 2008.
Wind Generation - NSP-Minnesota is investing approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project. These projects are expected to be operational by the end of 2010 and 2011, respectively. In June 2009, the MPUC approved the Nobles and Merricourt Wind Projects. In August 2009, the NDPSC granted advanced determinations of prudence for the Nobles and Merricourt Wind Projects and a certificate of public convenience and necessity (CPCN) for the Merricourt Wind project.
NSP-Minnesota Transmission CONs - In April 2009, the MPUC granted a CON to construct three 345 KV electric transmission lines as part of the CapX 2020 project. The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion. The cost of the project to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million. These cost estimates will be revised after the regulatory process is completed. The MPUC also included a condition assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy. In September 2009, two intervenors appealed the MPUC's CON decisions in the Minnesota Court of Appeals.
As part of the regulatory process for the CapX 2020 345 KV projects, NSP-Minnesota and Great River Energy have filed four route permit applications with the MPUC. Route permit applications for the remaining parts of the three lines are expected to be filed in adjoining states in 2010. Three filed route permit applications are now in evidentiary hearing processes before ALJs. The fourth application is expected to be sent to an evidentiary hearing process later in 2010. NSP-Minnesota anticipates the first routing decisions in mid 2010.
As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a CON application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn. The CON application was approved in July 2009. Route hearings are scheduled to begin March 30, 2010, and an MPUC decision is anticipated by the third quarter of 2010. The Bemidji-Grand Rapids line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction to be completed by the end of 2011. The estimated cost to NSP-Minnesota is approximately $26 million.
ARCs - In 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, unless the applicable state regulatory authority prohibits ARCs from serving retail customers in their state. ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota. The MISO ARC tariff provisions are effective in June 2010. The MPUC has opened an investigation regarding possible operation of ARCs in Minnesota. NSP-Minnesota expects to file requests with the NDPSC and SDPUC by the end of the first quarter of 2010 asking the regulatory agencies to prohibit operations of ARCs in their respective states, and to take action prior to June 2010.
FCA Investigation - In 2003, the MPUC opened an investigation to consider the continuing usefulness of the FCA for electric utilities in Minnesota. Continued discussions among utilities, the OES, MOAG and business customers regarding appropriate FCA reporting detail and provision of additional information to customers is ongoing.
Mercury Reduction and Emissions Reduction Filings - The MPUC has approved mercury control plans for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants. A sorbent injection control system was put into service at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled to be completed in December 2010. Currently, the estimated project costs are approximately $6.6 million for these two units, and the MPUC authorized NSP-Minnesota to collect the 2010 revenue requirement associated with these projects, which is approximately $3.5 million from customers through a mercury rider in 2010. On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost rider.
Nuclear Power Operations and Waste Disposal - NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units. See additional discussion regarding the nuclear generating plants at Note 18 to the consolidated financial statements.
Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.
LLW Disposal - Federal law places responsibility on each state for disposal of LLW generated within its borders. LLW from NSP-Minnesota's Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah. NSP-Minnesota is also able to utilize the Clive facility through various LLW processors. NSP-Minnesota has storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site LLW disposal facilities were not available.
High-Level Radioactive Waste Disposal - The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota's spent nuclear fuel. See Item 3 - Legal Proceedings and Note 17 to the consolidated financial statements for further discussion of this matter.
NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. At the following dates, casks for storage were either authorized or casks were loaded and stored:
•In 2003, the Minnesota legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the Prairie Island nuclear plant and to store spent fuel there until its current licenses with the NRC expire in 2013 and 2014. It is estimated that operation through the end of the current license will require 29 storage casks at Prairie Island.
•In October 2006, effective June 2007, the MPUC authorized an on-site storage facility and dry cask storage of 30 casks at Monticello, which will allow the plant to operate to 2030.
•In December 2009, the MPUC authorized additional cask storage at Prairie Island to allow operation through 2033 for Unit 1 and 2034 for Unit 2. The MPUC decision is currently stayed to allow the Minnesota legislature the opportunity to review the MPUC decision during the 2010 legislative session. If no action is taken by the Minnesota legislature during the 2010 legislative session the MPUC order will go into effect on June 1, 2010.
•As of Dec. 31, 2009, there were 25 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant. PFS - NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In December 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation's spent nuclear fuel. In September 2006, the Department of the Interior issued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that it was revoking its previous conditional approval of the site lease between PFS and the Skull Valley Indian tribe. In July 2007, PFS and the Skull Valley Band filed a lawsuit challenging these two Departments of the Interior actions. The lawsuit remains pending. A judicial appeal of the NRC licensing decision has been held in abeyance pending the outcome of the lawsuit challenging the Department of the Interior decisions. The existence of PFS as a licensed out-of-state storage option remains a credible alternative if PFS and the Skull Valley Band can prevail in the pending litigation and if the federal government fails to make progress with their obligation to take title and remove spent nuclear fuel from Xcel Energy's and other nuclear reactor sites.
Nuclear Plant Power Uprates and Life Extension - NSP-Minnesota is pursuing life extensions and capacity increases of all three of its nuclear units that will total approximately 235 MW, if approved, between 2011 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on the replacement of the original steam generators, currently planned for replacement during the refueling outage in 2013. Capital investments for life cycle management and power uprate activities through 2009 have totaled over approximately $257 million. For the years 2010 through 2015, spending is estimated at over $1.0 billion. See additional discussion in Capital Requirements in Item 7 - Management's Discussion and Analysis.
In December 2008, the MPUC approved the Monticello CON for approximately 71 MW of power uprates. In 2008, NSP-Minnesota re-submitted its NRC application for the Monticello plant extended power uprate, and the NRC's sufficiency review of the license amendment re-submittal was completed. NSP-Minnesota expects to receive NRC approval and achieve the extended power uprate during 2011. The operating life of the Monticello nuclear plant has already been extended through 2030.
In December 2009, the MPUC approved both the additional dry spent fuel storage capacity to support life extension and the approximately 164 MW of power uprates at Prairie Island Units 1 and 2. If no action is taken by the Minnesota legislature during the 2010 legislative session, the MPUC decision on dry spent fuel storage capacity to support life extension will go into effect on June 1, 2010.
In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively. The PIIC filed contentions in the NRC's license renewal proceeding in August 2008, which was referred to an ASLB for review. The ASLB granted the PIIC hearing request and has admitted seven of the 11 contentions filed. To date, all seven admitted contentions have been resolved and removed from the ASLB docket. Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions. The ASLB has admitted one of the contentions and has not issued a decision on the other three. NSP-Minnesota is challenging the admitted contention, and a decision on whether the other contentions will be accepted will be made in early 2010. If the contentions are not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC's standard 22 month review schedule, resulting in a decision on the Prairie Island license renewal in late 2010.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
*Includes refuse-derived fuel and wood.
See additional discussion of fuel supply and costs under Item 7 - Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis and under
Item 1A - Risk Factors
Oversight of Risk and Related Processes
The goal of Xcel Energy's risk management process is to understand and manage material risk; management is responsible for identifying and managing the risks, while directors oversee and hold management accountable. Our risk management process has three parts: identification and analysis, management and mitigation, and communication and disclosure. Xcel Energy management identifies and analyzes risks to determine materiality and other attributes like timing, probability and controllability.
Management broadly considers our business, the utility industry, the domestic and global economy, and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process, and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing Xcel Energy's strategy. At the same time, the business planning process identifies areas where a business area may take inappropriate risk to meet goals.
The goal of the risk management process is to mitigate the risks inherent in the implementation of Xcel Energy's strategy. The process for risk management and mitigation includes our code of conduct and other compliance policies, formal structures and groups, and overall business management. At a threshold level, Xcel Energy has developed a robust compliance program and promotes a culture of compliance, which mitigates risk. In addition to the code of conduct, Xcel Energy has a robust compliance program, including policies, training and reporting options.
Building on the culture of compliance, Xcel Energy manages and mitigates risks through formal structures and groups, including management councils, risk committees, and the services of corporate areas such as internal audit, the corporate controller and legal services. While Xcel Energy has developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.
Xcel Energy confronts legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2 and risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for Xcel Energy's products and services. Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy's senior management.
Management provides information to the Board in presentations and communications over the course of the Board calendar. Senior management presents an assessment of key risks to the Board annually. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy's strategy.
The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and Xcel Energy's management and mitigation of the risk. The Board has overall responsibility for risk oversight. As described above, the Board reviews the key risk assessment process presented by senior management. This key risk assessment analyzes the most likely areas of future risk to Xcel Energy. The Board also reviews the performance and annual goals of each business area. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy.
Risks Associated with Our Business
Our profitability depends in part on the ability of our utility subsidiaries to recover their costs from their customers and there may be changes in circumstances or in the regulatory environment that impair the ability of our utility subsidiaries to recover costs from their customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies. The utility commissions in the states where we operate our utility subsidiaries regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.
The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the utility's costs incurred in a test year. Our utility subsidiaries are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all the costs of our utility subsidiaries to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that would impair the ability of our utility subsidiaries to recover costs historically collected from their customers. If all of the costs of our utility subsidiaries are not recovered through customer rates, they could incur financial operating losses, which, over the long term, could jeopardize their ability to pay us dividends and our ability to meet our financial obligations.
Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments and the payment of dividends on our common stock.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that any of our current ratings or our subsidiaries' ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor's calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor's methodology. Therefore, Xcel Energy and its subsidiaries credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs.
We are subject to interest rate risk.
If interest rates increase, we may incur increased interest expense on variable interest rate debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.
We are subject to capital market risk.
Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, such as the collapse in the U. S. sub-prime mortgage market and subsequent broad financial market stress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.
We are subject to credit risks.
Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.
Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. Additional margin requirements could impact our liquidity.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.
We do have additional indirect credit exposures to various financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party would be in technical default under the contract, which would enable us to exercise our contractual rights.
We are subject to commodity risks and other risks associated with energy markets and energy production.
We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility. Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.
If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. The impact of these cost and reliability issues vary in magnitude for each operating subsidiary depending upon unique operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2009, these sites included:
•Sites of former MGPs operated by our subsidiaries, predecessors, or other entities; and
•Third party sites, such as landfills, for which we are alleged to be a potentially responsible party that sent hazardous materials and wastes. We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.
In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to regulation of mercury, NOx, SO2, CO2, particulates and coal ash. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change.
There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.
To the extent climate change impacts a region's economic health, it may also impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.
The EPA has taken steps to regulate GHGs under the CAA. On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011. We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 17, Commitments and Contingent Liabilities, in our notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Many of the federal and state climate change legislative proposals, such as ACES, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain "allowances" or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.
For further discussion, see Management's Discussion and Analysis and Note 17 to the consolidated financial statements.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.
NSP-Minnesota's two nuclear stations, Prairie Island and Monticello, subject it to the risks of nuclear generation, which include:
•The risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for 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 licensed lives. The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures at NSP-Minnesota's nuclear plants. In addition, the Institute for Nuclear Power Operations (INPO) reviews our nuclear operations and nuclear generation facilities. Compliance with INPO recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If an incident did occur, it could have a material adverse effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota's compliance costs and impact the results of operations of its facilities.
Economic conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, and may impact customers' ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt. It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur. See credit risk section for more related information.
Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.
Our utility operations are subject to long-term planning risks.
On a periodic basis, or as needed, our utility operations file long-term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC's design basis threat requirements, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to implement the NERC critical infrastructure protection standards as they are implemented and clarified.
The insurance industry has also been affected by these events and the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because our generation, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.
We are subject to business continuity risks associated with our ability to respond to unforeseen events.
The term business continuity refers to the ability of an entity to maintain day-to-day operations in response to unforeseen events. While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations. The company's response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm's on going business operations.
Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results. It's difficult to predict the magnitude of such events and associated impacts.
We are subject to information security risks.
A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event.
Rising energy prices could negatively impact our business.
Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal businesses, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.
Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.
There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.
The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased the FERC's civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.
Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results of operations, financial position or liquidity.
We have defined benefit pension and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future.
Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
We must rely on cash from our subsidiaries to make dividend payments.
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to service our indebtedness and pay dividends depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for that purpose or for dividends on our common stock, whether by dividends or otherwise. In addition, each subsidiary's ability to pay dividends to us depends on any statutory and/or contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Also, our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.
If our utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock and preferred stock or otherwise meet our financial obligations could be adversely affected.
Item 1B - Unresolved Staff Comments
None.
Item 2 - Properties
Virtually all of the utility plant of NSP-Minnesota and NSP-Wisconsin is subject to the lien of their first mortgage bond indentures. Virtually all of the electric utility plant of PSCo is subject to the lien of its first mortgage bond indenture.
Electric Utility Generating Stations:
NSP-Minnesota
(a)Based on NSP-Minnesota's ownership of 59 percent. (b)This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.
Therefore, the on-demand net maximum capacity is zero.
NSP-Wisconsin
(a)RDF is refuse-derived fuel, made from municipal solid waste.
PSCo
(a)Construction of Comanche Unit 3, a 750 MW coal-fired unit, is expected to be completed in the first quarter of 2010.
PSCo will own 500 MW of the completed unit. (b)Based on PSCo's ownership interest of 9.7 percent. (c)Based on PSCo's ownership interest of 75.5 percent of Unit 1 and 37.4 percent of Unit 2. (d)Amount represents nameplate rating capacity.
SPS
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:
Electric utility transmission and distribution substations at Dec. 31, 2009:
Natural gas utility mains at Dec. 31, 2009:
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. After consultation with legal counsel, Xcel Energy has recorded an estimate of the probable cost of settlement or other disposition for such matters.
Additional Information
For a discussion of legal claims and environmental proceedings, see Note 17 to the consolidated financial statements. For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation and Summary of Recent Federal Regulatory Developments, Item 7 - Management's Discussion and Analysis and Note 16 to the consolidated financial statements.
Item 4 - Submission of Matters to a Vote of Security Holders
No issues were submitted for a vote during the fourth quarter of 2009.
PART II
Item 5 - Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Quarterly Stock Data
Xcel Energy's common stock is listed on the New York Stock Exchange (NYSE). The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2009 and 2008 and the dividends declared per share during those quarters.
Book value per share at Dec. 31, 2009, was $15.92. The number of common shareholders of record as of Dec. 31, 2009 was approximately 83,222. The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy's capitalization ratio (on a holding company basis only, not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy's holding company capitalization ratio at Dec. 31, 2009 and 2008 was 85 percent and 84 percent, respectively. Therefore, the restrictions do not place any effective limit on Xcel Energy's ability to pay dividends. For further discussion of Xcel Energy's dividend policy, see Item 7 - Management's Discussion and Analysis, Liquidity and Capital Resources.
The following compares our cumulative TSR on common stock with the cumulative total return of the EEI Investor-Owned Electrics Index and the Standard & Poor's 500 Composite Stock Price Index over the last five fiscal years (assuming a $100 investment in each vehicle on Dec. 31, 2004, and the reinvestment of all dividends).
The EEI Investor-Owned Electrics Index currently includes 58 companies and is a broad measure of industry performance.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Xcel Energy, The EEI Investor-Owned Electrics,
and The S&P 500
*$100 invested on Dec. 31, 2004 in stock and index - including reinvestment of dividends. Fiscal years ending Dec. 31.
See Item 12 for information concerning securities authorized for issuance under equity compensation plans.
Item 6 - Selected Financial Data
(a)Excludes undistributed equity income and includes allowance for funds during construction.
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations
Business Segments and Organizational Overview
Continuing Operations
Xcel Energy is a public utility holding company. In 2009, Xcel Energy's continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with CIG to develop and lease natural gas pipeline, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.
Xcel Energy's nonregulated subsidiary reported in continuing operations is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits.
Discontinued Operations
See Note 4 to the consolidated financial statements for discussion of discontinued operations.
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "may," "objective," "outlook," "plan," "project," "possible," "potential," "should" and similar expressions. Actual results may vary materially.
Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations, actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including "Risk Factors" in Item 1A of Xcel Energy's Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to Xcel Energy's Form 10-K for the year ended Dec. 31, 2009.
Management's Strategic Plans
Xcel Energy's strategy, called Building the Core, has three primary focuses: environmental leadership, achieving financial objectives and optimizing the management of a portfolio of our operating utilities. In summary, our objective is to provide value to our customers and execute environmental initiatives by investing in our core utility businesses and earning a reasonable return on our invested capital. Below is a detailed discussion of our three primary focuses and how they support our overall Building the Core strategy.
Xcel Energy's Environmental Leadership
Overview
Xcel Energy has adopted environmental leadership as a primary focus, forming the cornerstone of our strategic initiatives. Xcel Energy believes that our environmental leadership meets customer and policy maker expectations, while appropriately managing long-term customer costs, and, in turn, creating shareholder value.
As a portfolio of regulated utilities, Xcel Energy has an obligation to serve its customers by providing them with reasonably priced, reliable electric and gas services. However, Xcel Energy's strategy goes beyond this traditional mission. Under the environmental leadership strategy, Xcel Energy takes prudent, balanced steps to reduce the impact of our operations on the environment while promoting technological and public policy advancements that will encourage a cleaner electric system. In light of the capital-intensive nature of our business, including the long life of Xcel Energy's capital investments, Xcel Energy takes prudent steps to reduce the overall risk associated with potential new environmental mandates. Finally, Xcel Energy seeks to reduce regulatory uncertainty through favorable cost-recovery for environmental initiatives provided by public policy makers, including legislatures and public utilities commissions.
The foundation for Xcel Energy's environmental leadership strategy resides with its environmental policy. Under this policy, the Xcel Energy Board of Directors, acting through the Nuclear, Environmental and Safety Committee, establishes environmental performance goals and oversees Xcel Energy's environmental compliance program and policy initiatives. The policy is available on our website at www.xcelenergy.com. Xcel Energy has created an environmental management system that provides employees with training and documentation of Xcel Energy's compliance responsibilities, creates processes designed to minimize the risk of noncompliance and audits Xcel Energy's environmental performance. Environmental performance goals, which include the goal of carbon reduction, are incorporated into officer and employee job responsibilities and compensation.
Current Initiatives
Xcel Energy pursues environmental leadership through management of environmental policy initiatives. Xcel Energy actively evaluates public policy proposals and promotes environmental initiatives that are designed to assure compliance with state initiatives, appropriately manage long-term customer costs and, where appropriate, provide growth opportunities. These initiatives include the following:
•Xcel Energy is the nation's largest utility wind energy provider and the nation's fifth largest solar energy provider. Xcel Energy is pursuing new wind, solar and other renewable energy acquisitions and investments to meet some of the nation's most aggressive RESs in the states in which Xcel Energy operates. These standards provide for favorable cost-recovery mechanisms and investment opportunities in order to allow Xcel Energy to meet the requirements.
•Xcel Energy has implemented voluntary emission reduction programs in Minnesota and Colorado. These programs have resulted or will result in substantial emission reductions from existing facilities. They also incorporate enhanced cost-recovery mechanisms that allow for a construction work in process return and an incentive based ROE mechanism.
•Xcel Energy plans to construct one of the largest biomass generating plants in the Midwest. Xcel Energy has proposed installing technology at the Bay Front Generating Station in Ashland, Wis. to allow it to generate electricity from biomass in all three operating units. Xcel Energy currently has 67 MW of biomass generating capacity in Minnesota and Wisconsin.
•Xcel Energy has a number of environmental initiatives focused on our customers. Xcel Energy has the largest customer-driven wind program in the nation called WindSource®. In Colorado, Minnesota and New Mexico, Xcel Energy manages a growing customer-sited solar program, known as Solar*Rewards. Xcel Energy also has an increasing portfolio of customer energy efficiency and conservation programs. Xcel Energy is allowed financial performance incentives associated with our programs in Minnesota and Colorado.
•Xcel Energy is also working to apply intelligence to its electric grid, creating a smart grid, to provide customers with more choice, reliability and control over their energy use. Xcel Energy has completed the nation's first fully integrated SmartGridCity™ in Boulder, Colo.
•Xcel Energy is a leader in promoting new clean energy technologies for the future. Pursuant to state statute, NSP-Minnesota manages a renewable development fund derived from customer renewable energy charges in Minnesota that allows it to promote renewable technology advancement. Xcel Energy has also initiated a study to improve wind forecasting for the industry, allowing for better integration of wind energy, and has undertaken small-scale projects to study the technical and economic aspects of energy storage and the use of hydrogen.
•Xcel Energy is a leader in supporting the advancement of solar energy technology, and has announced plans to acquire significant solar resources in Colorado, including advanced solar technology with thermal storage. Xcel Energy was a founding member of the Solar Technology Acceleration Center in Colorado, which is focused on advancing solar technology in its final stages of development.
GHG Emissions
As one of the nation's largest electric generating companies, Xcel Energy is committed to addressing climate change through efforts to reduce its GHG emissions. Xcel Energy has adopted a methodology for calculating CO2 emissions based on the recently issued reporting protocols of The Climate Registry. Xcel Energy is a "founding reporter" under The Climate Registry. As third-party CO2 reporting protocols continue to evolve, Xcel Energy expects additional changes in reporting methodology and reported CO2 emissions. Starting in 2011, Xcel Energy will also report GHG emissions to the EPA under the agency's newly adopted GHG reporting rule.
Based on The Climate Registry's current reporting protocol, Xcel Energy has estimated that its current electric generating portfolio, which includes coal- and gas-fired plants, emitted approximately 60.1 million tons of CO2 in 2009. Xcel Energy has also estimated emissions associated with electricity purchased for resale to Xcel Energy customers from generation facilities owned by third parties. Xcel Energy estimates that these third-party facilities emitted approximately 20.7 million tons of CO2 in 2009. Estimated total CO2 emissions, associated with service to Xcel Energy electricity customers, declined by 5.9 million tons in 2009 compared to 2008, with a combined cumulative reduction of over 39.0 million tons of CO2 since 2003. Xcel Energy anticipates that its ownership share of Comanche Unit 3, a new coal-fired generation project scheduled for completion in early 2010, will result in CO2 emissions of approximately 3.4 million tons of CO2 per year. Comanche Unit 3, an efficient supercritical pulverized coal unit, will provide low-cost, base load power and help maintain a reliable, reasonably priced and environmentally sound electricity supply in Colorado. Operation of Comanche Unit 3 will help support Xcel Energy's efforts to develop renewable energy, retire older, less-efficient resources and take other steps to reduce emissions across its system consistent with state regulatory processes. Xcel Energy plans to implement clean resource development and conservation plans that will result in overall reductions in Xcel Energy's CO2 emissions, both in absolute terms and per Kwh of electricity produced.
State Resource Plans
During 2009, the acquisition component of the overall Colorado resource plan and the Minnesota resource plan were approved substantially as proposed. Both plans, proposed significant new clean energy resources. Under these plans, Xcel Energy would:
•Increase overall system wind capacity from approximately 3,000 MW at the end of 2009 to approximately 4,500 to 5,000 MW by 2015;
•Add up to 250 MW of concentrating solar thermal technology with storage;
•Increase the size of our customer energy efficiency and conservation programs, resulting in a reduction of retail demand;
•Retire and replace several existing coal-fired electric generation facilities;
•Improve the efficiency and reduction of CO2, mercury, SO2 and NOx emissions at several existing fossil plants; and
•Upgrade the capacity of existing nuclear facilities. Xcel Energy has designed these plans so that, depending on fuel, commodity and other assumptions, Xcel Energy would maintain a reasonably priced product and continue to provide reliable power to our customers. At the same time, the plans would result in a significant reduction in GHG emissions. The most recently approved Minnesota plan is expected to reduce NSP-Minnesota's CO2 emissions by 22 percent below 2005 levels by 2020. The approved Colorado plan is expected to reduce PSCo's CO2 emissions by 10 percent to 15 percent below 2005 levels by 2015 and enables PSCo to propose additional reductions to achieve the 20 percent reduction goal by 2020, currently established by Executive Order.
Our environmental leadership strategy has resulted in numerous environmental awards and recognition. For example, Xcel Energy was named Utility of the Year by the American Wind Energy Association and also received a 2009 Energy Star® partner of the year award from the EPA. Xcel Energy strives to provide the public with detailed information regarding environmental performance and risk, and was recognized on The Carbon Disclosure Project Leadership Index for its high-quality disclosure of climate change risks. Among other things, our utility companies operating in Minnesota, Colorado, and New Mexico use a carbon proxy cost mandated by the state commissions to evaluate the impact of potential future GHG regulation on its future resource acquisition plans. Xcel Energy publishes a Corporate Responsibility Report annually, which is available on our website, www.xcelenergy.com. The Corporate Responsibility Report discloses Xcel Energy's environmental, economic and social performance. Xcel Energy also provides detailed information to environmental research and disclosure organizations, such as Trucost, the Carbon Disclosure Project and The Climate Registry.
Achieving Financial Objectives
Xcel Energy's financial objectives of Building the Core also have three phases: obtaining legislative and regulatory support for large investment initiatives, investing in the utility business and earning a fair return on utility system investments.
The first phase, as noted above, is obtaining legislative and regulatory support for large investment initiatives, prior to making the investment. To avoid excessive risk, it is critical that Xcel Energy reduce regulatory uncertainty before making large capital investments. Xcel Energy has accomplished this for both the MERP in Minnesota and Comanche Unit 3 in Colorado. Transmission legislation has been passed in Minnesota, Colorado, Texas and several other jurisdictions where Xcel Energy operates. In addition, various jurisdictions have adopted legislation allowing for rider recovery of investments in renewable energy.
The second phase is investing in the utility business. In addition to Xcel Energy's normal level of capital investment, Xcel Energy expects to have significant investment opportunity, in part attributable to the environmental strategy described above. Those opportunities include the following:
•NSP-Minnesota has made, as part of our MERP program, nearly $1 billion of improvements at three Twin Cities coal-fired generating plants, A. S. King, High Bridge and Riverside, to significantly reduce air emissions from those facilities while increasing the amount of electricity they can produce by approximately 300 MW. New state-of-the-art emission control equipment was placed in service for the A. S. King plant in 2007 and the existing High Bridge facility was replaced with a 575 MW natural gas combined-cycle unit that went into service in May 2008. The final phase of the MERP, the new Riverside combined-cycle plant, was placed in service in May 2009.
•Invest approximately $1.4 billion for Comanche Unit 3, a project to build a new 750 MW supercritical coal unit in Colorado. The CPUC has approved PSCo sharing one-third ownership of this plant with other parties. Consequently, PSCo's investment in Comanche Unit 3 will be approximately $1 billion. Comanche Unit 3 is expected to achieve commercial operations by the end of the first quarter of 2010.
•Invest $156 million for the addition of two gas fired units totaling 300 MW at the PSCo Fort St. Vrain generating facility, located in Colorado. These units went into service in April 2009.
•Invest over a $1 billion through 2015 to extend the lives and increase the output of NSP-Minnesota's two nuclear facilities, Monticello and Prairie Island.
•Invest approximately $900 million over three years for the 201 MW Nobles Wind project located in southwestern Minnesota Project, and the 150 MW Merricourt Wind project located in southeastern North Dakota, expected to be operational by the end of 2010 and 2011, respectively.
•Investment by the CapX 2020 coalition of utilities of approximately $1.7 billion to expand the transmission system in the upper Midwest with major construction targeted to begin in 2010 and ending three to five years later, of which Xcel Energy's share of the investment is expected to be approximately $900 million, depending on the route and configuration approved by the MPUC. As a result of these investments, as well as continued investments in the transmission and distribution system, Xcel Energy expects that the rate base, or the amount on which Xcel Energy earns a return, will grow annually, on average, approximately 7 percent from 2009 through 2013.
The third phase is earning a fair return on utility system investments. To this end, the regulatory strategy is to receive regulatory approval for rate riders and DSM incentives, as well as general rate cases. A rate rider is a mechanism that allows recovery of certain costs and returns on investments without the costs and delays of filing a rate case. These riders allow for timely revenue recovery of the costs of large projects or other costs that vary over time. DSM incentives, which exist in Colorado and Minnesota, allow Xcel Energy to earn from helping our customers reduce energy. The incentive plans are designed to reward Xcel Energy for achieving performance at or above the approved savings goals.
Xcel Energy's regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on utility investments. Xcel Energy believes that the public utility commissions will provide reasonable recovery, and it is important to note that the financial plans include this assumption. Constructive results over the last several years are evidence of reasonable regulatory treatment and give Xcel Energy confidence that Xcel Energy is pursuing the right strategy. With any strategic plan, there are goals and objectives. Xcel Energy feels the following financial objectives continue to be both realistic and achievable:
•A long-term annual earnings per share growth rate target of 5 percent to 7 percent;
•Annual dividend increases of 2 percent to 4 percent; and
•Senior unsecured debt credit ratings in the BBB+ to A range. Successful execution of the Building the Core strategic plan should allow Xcel Energy to achieve the outlined financial objectives, which in turn, should provide investors with an attractive total return on a low-risk investment. However, our operations are affected by current local, national and worldwide economic conditions. The consequences of the current recession being prolonged may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may impact the financial objectives discussed above.
Optimizing the Management of a Portfolio of Operating Utilities
Optimizing the management of a portfolio of operating utilities is the third area of focus related to the Building the Core strategy. Even though Xcel Energy ultimately manages the business based on the revenue streams provided by electric and natural gas, Xcel Energy continues to evolve the management of the portfolio of utility investments. While Xcel Energy has four separate operating companies, there are certain similarities and differences that require us to effectively manage this portfolio. More specifically, Xcel Energy's goal is to build on the similarities among the companies, which maximizes efficiencies from centralized management and deployment of common initiatives, such as market branding and environmental policy research. From an organizational perspective, examples of similarities include corporate center services as well as certain operational functions, such as management of the generation fleet, transmission systems, environmental compliance, NERC and FERC compliance and safety program.
At the same time, Xcel Energy realizes there are unique differences in each of our service territories such as local community focus and priorities, regulatory environment, physical plant infrastructure and age, weather, as well as others that require Xcel Energy to organize and align these utility specific areas to most effectively address these utility distinct characteristics. To that end, Xcel Energy has operating presidents, each located in their respective jurisdiction. The objective of this organizational structure is to optimize Xcel Energy's operating efficiency while maximizing accountability.
Financial Review
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying consolidated financial statements and the related notes to consolidated financial statements.
Results of Operations
The following table summarizes the diluted earnings per share for Xcel Energy:
Ongoing earnings exclude the impact related to the COLI program. COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. During 2007, Xcel Energy resolved a dispute with the IRS regarding its COLI program. The 2009 impact is primarily related to legal costs associated with company claims against the insurance provider and broker of the COLI policies. The 2007 earnings were affected by the 2007 settlement with the IRS and include associated interest, penalties and tax discussed further at Note 8 - Income Taxes.
As a result of the termination of the COLI program, Xcel Energy's management believes that ongoing earnings provide a more meaningful comparison of earnings results between different periods in which the COLI program was in place and is more representative of Xcel Energy's fundamental core earnings power. Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation, and when communicating its earnings outlook to analysts and investors.
2009 Comparison with 2008
PSCo - Earnings at PSCo decreased by four cents per share for 2009. The 2009 decrease is largely due to the negative impact of weather and rising costs, partially offset by new electric rates that went into effect in July 2009.
NSP-Minnesota - Earnings at NSP-Minnesota decreased by one cent per share for 2009. The 2009 decrease is mainly due to the negative impact of weather and timing of nuclear outage expenses. The decrease was partially mitigated by a $91 million electric rate increase that went into effect in January 2009.
NSP-Wisconsin - Earnings at NSP-Wisconsin were flat for 2009. The 2009 earnings reflect increased costs, which were offset by improved fuel recovery and new rates which were effective in January 2009.
SPS - Earnings at SPS increased by eight cents per share for 2009. The 2009 increase was primarily due to electric rate increases in Texas (effective in February 2009) and New Mexico (effective in July 2009) and the 2008 resolution of certain fuel cost allocation issues, which were partially offset by higher purchased capacity costs.
Equity Earnings of Unconsolidated Subsidiaries - Equity earnings of unconsolidated subsidiaries increased by two cents per share for 2009 due to our investment in WYCO, which owns a natural gas pipeline in Colorado that began operations in late 2008 as well as a gas storage facility that commenced operations in July 2009.
PSRI - PSRI is a wholly owned subsidiary of PSCo. During 2007, Xcel Energy resolved a dispute with the IRS regarding its COLI program. The 2009 impact is primarily related to legal costs associated with company claims against the insurance provider and broker of the COLI policies.
Discontinued Operations - Loss from discontinued operations increased by one cent over 2009 primarily related to an increase in tax related expenses and legal accruals for previously divested businesses.
2008 Comparison with 2007
PSCo - Earnings at PSCo decreased by one cent per share for 2008 compared with 2007. The decrease was due to unfavorable weather offset by favorable sales growth and a gas rate increase.
NSP-Minnesota - Earnings at NSP-Minnesota increased by three cents per share for the 2008 compared with 2007. The increase was due to lower interest and non-operating expenses. This was slightly offset by unfavorable weather and purchased capacity costs.
NSP-Wisconsin - Earnings at NSP-Wisconsin increased by one cent per share 2008 compared with 2007. The increase was primarily due to an electric rate increase in Wisconsin, which was offset by unfavorable weather.
SPS - Earnings at SPS were flat for 2008 compared with 2007. SPS experienced increased sales growth, which was offset by higher purchased capacity costs.
Equity Earnings of Unconsolidated Subsidiaries - Equity earnings of unconsolidated subsidiaries increased by one cent per share for 2008 compared with 2007. The increase was primarily due to our investment in WYCO, which owns a natural gas pipeline that began operations in late 2008.
The following tables summarize significant components contributing to the changes in the diluted earnings per share compared with same prior periods, which are discussed in more detail later.
The following table provides a reconciliation of GAAP earnings and earnings per share to ongoing earnings and earnings per share for the years ended Dec. 31:
Continuing operations consist of the following:
•Regulated utility subsidiaries, operating in the electric and natural gas segments; and
•Other nonregulated subsidiaries and the holding company. The following table summarizes the earnings contributions of Xcel Energy's business segments on the basis of GAAP. See Note 4 to the consolidated financial statements for a further discussion of discontinued operations.
(a)Not a reportable segment. Included in all other segment results in Note 20 to the consolidated financial statements.
Higher 2009 ongoing earnings were primarily due to improved electric margins as a result of constructive rate case outcomes in Minnesota, Colorado, Texas, New Mexico and Wisconsin, which were partially mitigated by the negative impact of weather, lower sales and higher purchase capacity power costs. Offsetting stronger electric margins were higher operating and maintenance expenses, resulting from increased employee benefit costs as well as higher nuclear expenses, and dilution from the issuance of equity to fund the capital investment program.
Earnings from continuing operations for 2008 were higher than in 2007 primarily attributed to lower O&M expense, higher electric and gas margins, and higher AFUDC - equity. Partially offsetting these positive factors were higher depreciation and amortization, higher conservation and DSM program expenses, increased interest expense and a higher ETR.
Statement of Operations Analysis - Continuing Operations
The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Weather - Xcel Energy's earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase O&M expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce O&M expenses. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature.
Estimated Impact of Temperature Changes on Regulated Earnings - The following table summarizes the estimated impact on earnings per share of temperature variations compared with sales under normal weather conditions.
Sales Growth (Decline) - The following table summarizes Xcel Energy's regulated sales growth (decline) for actual and weather-normalized energy sales for the years ended Dec. 31, compared with the previous year. The year-end sales growth amounts for 2008 have been adjusted for leap year.
During 2009, we experienced lower than anticipated actual electric residential sales, and a decline in electric commercial and industrial sales on a weather-adjusted basis, which we believe was driven by overall economic conditions and to a lesser degree, increased conservation efforts. The declines in MwH sales to the commercial and industrial customer class, which are directly related to the economic downturn, are partially offset by demand charges, which mitigate, to a certain degree, the impact of the lower MwH sales. We anticipate that sales will grow in the future at a slower rate than historical levels in part due to increased conservation activities. Weather-normalized sales for 2010 are projected to grow approximately 1 percent for retail electric customers and to decline approximately 1 percent to 2 percent for retail firm natural gas customers.
Electric Revenues and Margin
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers in most states, the fluctuations in these costs do not materially affect electric margin. The following tables detail the change in electric revenues and margin:
The following tables summarize the components of the changes in electric revenues and electric margin for the years ended Dec. 31:
Electric Revenues
2009 Comparison with 2008 - Electric revenues decreased due to lower fuel and purchased power costs, largely due to lower customer usage and lower commodity prices, lower trading and weather. This was partially offset by retail rate increases in Colorado, Minnesota, Texas, New Mexico and Wisconsin, higher conservation and non-fuel rider recovery, mostly from the RESA rider at PSCO and the RCRF rider at SPS.
2008 Comparison with 2007 - Electric revenues increased due to higher fuel and purchased power costs, largely recovered from customers, higher conservation and non-fuel rider recovery, mostly from the RESA rider at PSCO and the RES rider at NSP-Minnesota, electric retail rate increases in Wisconsin, North Dakota, Texas and New Mexico and weather-normalized retail sales growth. Unfavorable weather partially offset the positive variances.
Electric Margin
2009 Comparison to 2008 - The increase in electric margin was due to electric rate increases in Colorado, Minnesota, Texas, New Mexico and Wisconsin, higher conservation and DSM revenue and non-fuel riders. This was partially offset by higher purchase capacity costs and a negative impact of weather.
2008 Comparison to 2007 - The increase in electric margin for the year was due to electric rate increases at Wisconsin, North Dakota, Texas and New Mexico, higher conservation and non-fuel rider revenues and weather-normalized retail sales growth. These items were partially offset by unfavorable weather and higher purchased power costs.
Natural Gas Revenues and Margin
The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin. The following table details the changes in natural gas revenues and margin.
Natural Gas Revenues
The following tables summarize the components of the changes in natural gas revenues and margin for the years ended Dec. 31:
2009 Comparison to 2008 - Natural gas revenues decreased primarily due to lower natural gas costs in 2009, and the estimated impact of weather.
2008 Comparison to 2007 - Natural gas revenues increased primarily due to higher natural gas costs in 2008 which are recovered from customers. Final gas rates were effective for Wisconsin in January 2008 and Minnesota in February 2008. Phase I rates were effective in Colorado since July 2007.
Natural Gas Margin
2009 Comparison to 2008 - Natural gas margins decreased mainly due to milder than normal temperatures.
2008 Comparison to 2007 - Natural gas margins increased due to base rate increases for Wisconsin in January 2008 and Colorado since July 2007.
Non-Fuel Operating Expenses and Other Items
Other O&M Expenses - O&M Expenses increased by approximately $130.2 million, or 7.3 percent, in 2009, compared with 2008, and decreased by 11.0 million or 0.6 percent, compared with 2007.
2009 Comparison to 2008 - The decrease in O&M expenses for 2009 was largely driven by the following:
•Higher employee benefits costs are primarily attributable to 2009 employee performance based incentive compensation expenses, higher pension expenses and increased medical expenses. In 2008, no employee performance based incentive benefits were earned.
•The increase in nuclear outage costs is due to the commissions' approval of the change in the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in 2008.
•The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new NRC requirements.
•Lower consulting costs are primarily the result of cost management initiatives achieved throughout 2009.
•Lower uncollectible receivable costs are mainly due to improved collections and a decrease in natural gas prices.
2008 Comparison to 2007 - The decrease in O&M expenses for 2008 was largely driven by the following:
•The decline in nuclear outage expense is due to the MPUC, NDPSC, and SDPUC approving the change in recovery methods for costs associated with refueling outages at Xcel Energy's nuclear plants from the direct expense method to the deferral and amortization method, effective Jan. 1, 2008. An accrual was also recorded to lower revenue, reflecting a liability for a customer refund relating to this decision.
•Lower employee benefit costs are due to eliminating our annual performance based incentive plan payout for 2008.
•The higher plant generation costs were primarily attributable to scheduled and unplanned maintenance.
•The increase in labor costs was attributable to annual wage increases, the insourcing of certain functions and additional employees to support system growth.
Conservation and DSM Expenses - Conservation and DSM program expenses increased by approximately $64.4 million for 2009, compared with 2008, and by approximately $15.9 million for 2008, compared with 2007. The higher expense for 2009 and 2008 was attributable to the expansion of programs and regulatory commitments. Conservation and DSM program expenses and financial incentives are recovered through riders or base rates.
Depreciation and Amortization - Depreciation and amortization expenses decreased by approximately $10.3 million, or 1.2 percent, for 2009, compared with 2008. In 2009, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, as a result of the MPUC decision in the Minnesota electric rate case. In addition, in 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants. These decisions reduced depreciation and decommissioning expense in 2009. These decreases were partially offset by normal system expansion.
Depreciation and amortization expenses increased by $22.6 million, or 2.8 percent for 2008 when compared with 2007. The increase was primarily due to planned system expansion partially offset by a decrease in depreciation due to the MPUC approval of two NSP-Minnesota depreciation filings in September 2008 and a NDPSC settlement agreement in December 2008.
Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased by approximately $19.9 million, or 6.9 percent, for 2009, compared with 2008, and by approximately $8.9 million, or 3.2 percent, for 2008 compared with 2007. The increase was primarily due to increased property taxes across our jurisdictions.
Other Income, Net - Other income, net, decreased by $30.6 million for 2009 compared with 2008. The net decline was mainly due to changes in our non-qualified benefit plan liabilities related to market activity, lower interest on under recovered deferred fuel balances and a decrease in interest received from WYCO for construction deposits.
Other income, net, increased by $33.0 million, for 2008 when compared with 2007. The increase was primarily the result of PSRI's termination of the COLI program in 2007, which eliminated certain expenses.
Equity Earnings of Unconsolidated Subsidiaries - Equity earnings of unconsolidated subsidiaries increased by approximately $21.1 million for 2009, compared with 2008, and by approximately 1.7 million for 2008, compared with 2007. The increase was primarily due to higher earnings from the equity investment in WYCO as a result of the High Plains natural gas pipeline, located in Colorado, which commenced operations in late 2008 as well as a gas storage facility that began operations in July 2009.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) - AFUDC increased by approximately $12.9 million, or 12.6 percent for 2009, compared with 2008, and by $30.8 million, or 42.8 percent, for 2008 when compared with 2007. The increase was due primarily to the construction of Comanche Unit 3, a power facility located in Colorado, as well as other construction projects.
Interest Charges - Interest charges increased by approximately $8.7 million, or 1.6 percent, for 2009, compared with 2008. The increase was primarily the result of increased debt levels to fund new capital investments, partially offset by lower interest rates on short-term debt.
Interest charges increased by $33 million, or 6.3 percent, for 2008 when compared with 2007. The increase was primarily the result of increased debt levels to fund Xcel Energy's rate base growth strategy.
Income Taxes - Income tax expense for continuing operations increased by $32.6 million for 2009, compared with 2008. The increase in income tax expense was primarily due to an increase in pretax income. The ETR for continuing operations was 35.1 percent for 2009, compared with 34.4 percent for 2008. The higher ETR for 2009 was primarily due to the establishment of a valuation allowance against certain state tax credit carryovers that are now expected to expire prior to full utilization. Excluding this item, the ETR for 2009 would have been 34.6 percent.
Income taxes for continuing operations increased by $44.2 million for 2008, compared with 2007. The increase in income tax expense was primarily due to an increase in pretax income in 2008. The ETR for continuing operations was 34.4 percent for 2008, compared with 33.8 percent for 2007.
The ETRs for 2009 and 2008 differ from their statutory federal income tax rates, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant related regulatory differences. The ETR for 2007 differs from its statutory federal income tax rate, primarily due to state income tax expense partially offset by tax credits recognized and tax benefits from life insurance policies and plant related regulatory differences. See Note 8 to the consolidated financial statements.
Holding Company and Other Results
The following tables summarize the net income and earnings per share contributions of the continuing operations of Xcel Energy's nonregulated businesses and Holding Company results:
Financing Costs and Preferred Dividends - Holding Company and other results include interest expense and the earnings per share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.
Eloigne - Eloigne contributed a loss of approximately $4.7 million which was primarily attributed to the sale of property in 2009.
Factors Affecting Results of Continuing Operations
Xcel Energy's utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions and affect Xcel Energy's ability to recover its costs from customers. The historical and future trends of Xcel Energy's operating results have been, and are expected to be, affected by a number of factors, including those listed below.
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy's operating results. Management cannot predict the impact of a prolonged economic recession, fluctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in future economic growth or a significant increase in interest rates.
Fuel Supply and Costs
Xcel Energy's operating utilities have varying dependence on coal, natural gas and uranium. Changes in commodity prices are generally recovered through fuel recovery mechanisms and have very little impact on earnings. However, availability of supply, the potential implementation of a carbon tax and unanticipated changes in regulatory recovery mechanisms could impact our operations. See additional discussion of fuel supply and costs under Item 1 - Electric Utility Operations.
Pension Plan Costs and Assumptions
Xcel Energy has significant net pension and postretirement benefit costs that are measured using actuarial valuations. Inherent in these valuations are key assumptions including discount rates and expected return on plan assets. Xcel Energy evaluates these key assumptions at least annually by analyzing current market conditions, which include changes in interest rates and market returns. Changes in the related net pension and postretirement benefits costs and funding requirements may occur in the future due to changes in assumptions. For further discussion and a sensitivity analysis on these assumptions, see "Employee Benefits" under Critical Accounting Policies and Estimates.
Regulation
Customer Rate Regulation - The FERC and various state regulatory commissions regulate Xcel Energy's utility subsidiaries. Decisions by these regulators can significantly impact Xcel Energy's results of operations. Xcel Energy expects to periodically file for rate changes based on changing energy market and general economic conditions.
The electric and natural gas rates charged to customers of Xcel Energy's utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive general rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy's financial results. In addition to changes in operating costs, other factors affecting rate filings are new investments, sales growth, which is affected by overall economic conditions, conservation and DSM efforts and the cost of capital. In addition, the ROE authorized is set by regulatory commissions in rate proceedings.
Wholesale Energy Market Regulation - Wholesale energy markets are operated by MISO to centrally dispatch all regional electric generation and apply a regional transmission congestion management system. MISO centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota and NSP-Wisconsin. In January 2009, MISO implemented modifications to the original market to establish a regional ASM. The ASM provides further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the original energy market. NSP-Minnesota and NSP-Wisconsin expect to recover MISO charges through either base rates or various recovery mechanisms. See Note 16 to the consolidated financial statements for further discussion.
Capital Expenditure Regulation - Xcel Energy's utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy transmission and distribution systems. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, the CPUC, MPUC, SDPUC and PUCT approved proposals to recover, through a rate rider, costs to upgrade generation plants and lower emissions, and/or increase transmission investment cost. These rate riders are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis. For wholesale electric transmission services, Xcel Energy has, consistent with FERC policy, implemented or proposed to establish formula rates for each of the utility subsidiaries that will provide annual rate increases as transmission investments increase in a manner similar to the rate riders.
Proposed Legislation
Minnesota Legislation Relating to Utility Interim Rates and Expense Disclosure - In January 2010, the Minnesota attorney general held a press conference announcing two proposed bills for the 2010 legislative session. One bill would eliminate interim rates in utility general rates cases, in most instances. The second bill would require disclosure of expense, meal and travel compensation for the top 10 officers and corporate aviation expenses of public utilities. While it is uncertain if these bills will become law, the elimination of interim rate recovery could have an adverse impact on NSP-Minnesota's ability to earn its authorized return and continue to make significant capital investment in Minnesota.
Other
Minnesota Office of Pipeline Safety (MnOPS)-Notice of Probable Violation (NPV) - On Feb. 1, 2010, a plumber working to clear a sewer line at a residence in St. Paul, Minn. struck a gas line, which ignited a fire that destroyed the house. The plumber received minor burns, was treated and released that night, and no other injuries resulted. An investigation revealed that the gas line to the house had penetrated and intersected the sewer line to the home. On Feb. 5, 2010, MnOPS delivered an NPV to NSP-Minnesota. The NPV states that NSP-Minnesota failed to take appropriate measures to prevent this accident from occurring in violation of state and federal regulations. The NPV also sets forth a four-part proposed compliance plan and a $1 million fine. The compliance order requires, among other things, that NSP-Minnesota submit an inspection and remediation plan. NSP-Minnesota subsequently investigated the sewer lines in the vicinity of the accident and determined that no additional conflicts exist. NSP-Minnesota intends to respond to the NPV on March 8, 2010.
Environmental Matters
Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, higher operating expenses and capital expenditures for environmental compliance.
In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental monitoring and disposal of hazardous materials and waste were approximately:
•$225 million in 2009;
•$213 million in 2008; and
•$173 million in 2007. Xcel Energy expects to expense an average of approximately $256 million per year from 2010 through 2014 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.
Capital expenditures for environmental improvements at regulated facilities were approximately:
•$89 million in 2009;
•$230 million in 2008; and
•$439 million in 2007. Xcel Energy expects to incur approximately $79 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2010, and approximately $530 million of related expenditures from 2011 through 2014. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado.
See Note 17 to the consolidated financial statements for further discussion of Xcel Energy's environmental contingencies.
Generating facilities throughout the Xcel Energy territory currently are subject to mercury reduction requirements only at the state level. In Minnesota mercury emissions from A. S. King and Sherco generating facilities are regulated by the Minnesota Mercury Legislation, and in Colorado, eight units are subject to a mercury emissions rule passed by the Colorado Air Quality Control Commission (AQCC).
In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans. A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled for December 2010. In November 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.
In December 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and the MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.
The EPA has required states to develop implementation plans to comply with BART, which included identification of facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities. The Colorado AQCC promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. PSCo estimates that implementation of BART alternatives will cost approximately $254 million in capital costs, which includes approximately $113 million in environmental upgrades for the existing Comanche Station Units 1 and 2 project, which are included in the capital budget. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2014. Colorado's state implementation plan has been submitted to EPA for approval. In January 2009, the CAPCD initiated a joint stakeholder process to evaluate what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado's Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals. The CAPCD has indicated that it expects to have a final plan for additional point-source NOx controls by the end of 2010.
Inflation
Inflation at its current level is not expected to materially affect Xcel Energy's prices or returns to shareholders. However, potential future inflation resulting from the economic and monetary stimulus policies of the U. S. Government and the Federal Reserve could lead to future price increases for materials and services required to deliver electric and natural gas services to customers. These potential cost increases could in turn lead to increased prices to customers.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Preparation of the consolidated financial statements and related disclosures in compliance with GAAP requires the application of accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements and disclosures, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and on the results reported even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most critical to the portrayal of Xcel Energy's financial condition and results, and that require management's most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been discussed with the Audit Committee of the Xcel Energy Board of Directors.
Regulatory Accounting
Xcel Energy is a holding company with rate-regulated subsidiaries that are subject to ASC 980 Regulated Operations, which provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates could be charged and collected. Xcel Energy's rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of current and future cash flows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. Regulatory liabilities represent incurred or accrued credits that have been deferred because they will be returned to customers in future rates. In other businesses or industries, regulatory assets would be charged to expense and regulatory liabilities would be recorded as income. As of Dec. 31, 2009 and 2008, Xcel Energy has recorded regulatory assets of approximately $2.3 billion and $2.4 billion and regulatory liabilities of approximately $1.2 billion and $1.2 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs, in any such jurisdiction, ceases to be probable, Xcel Energy would be required to charge these assets to current earnings. However, there are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. In addition, deregulation would be a change that occurs over time, due to legal processes and procedures, which could moderate the impact to Xcel Energy's consolidated financial statements.
See Note 19 for additional details on regulatory assets and liabilities.
Income Tax Accruals
Judgment, uncertainty, and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.
ETRs are also highly impacted by assumptions. ETR calculations are revised every quarter based on best available year-end tax assumptions (income levels, deductions, credits, etc.) by legal entity; adjusted in the following year after returns are filed, with the tax accrual estimates being trued-up to the actual amounts claimed on the tax returns; and further adjusted after examinations by taxing authorities have been completed.
In accordance with the interim reporting rules under ASC 740 Income Taxes, a tax expense or benefit is recorded every quarter to eliminate the difference in continuing operations tax expense computed based on the actual year-to-date ETR and the forecasted annual ETR.
ASC 740 Income Taxes also requires that only tax benefits that meet the "more likely than not" recognition threshold can be recognized or continue to be recognized. The change in the unrecognized tax benefits needs to be reasonably estimated based on evaluation of the nature of uncertainty, the nature of event that could cause the change and an estimated range of reasonably possible changes. At any period end, and as new developments occur, management will use prudent business judgment to unrecognize appropriate amounts of tax benefits. Unrecognized tax benefits can be recognized as issues are favorably resolved and loss exposures decline.
As disputes with the IRS and state tax authorities are resolved over time, we may need to adjust our unrecognized tax benefits and interest accruals to the updated estimates needed to satisfy tax and interest obligations for the related issues. These adjustments may be favorable or unfavorable, increasing or decreasing earnings.
See Note 8 for further details regarding income taxes.
Employee Benefits
Xcel Energy's pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 11 to the consolidated financial statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.
Pension costs and funding requirements are expected to increase in the next few years as a result of significantly lower-than-expected investment returns in 2008. While investment returns exceeded the assumed levels from 2004-2006, and during 2009, investment returns in 2007 and 2008 were below the assumed levels. The investment gains or losses resulting from the difference between the expected pension returns and actual returns earned are deferred in the year the difference arises and are recognized over the expected average remaining years of service for active employees. Based on current assumptions and the recognition of past investment gains and losses, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes will increase from income of $3.0 million in 2008 and an expense of $12.9 million in 2009 to expense of $36 million in 2010 and expense of $110 million in 2011. The potential increase in the 2011 expense is due to expense recognition based on cash funding and expected cash contributions of $55 million in 2011 at NSP-Minnesota compared to no contributions made during 2008 through 2010.
Xcel Energy set the discount rate used to value the Dec. 31, 2009 pension and postretirement health care obligations at 6 percent, which is a 75 basis point decrease from Dec. 31, 2008. Xcel Energy uses multiple reference points in determining the discount rate, including Citigroup Pension Liability Discount Curve, the Citigroup Above Median Curve and bond matching studies. At Dec. 31, 2009, the above reference points supported the selected rate. In addition to the reference points utilized above, Xcel Energy also reviews general survey data provided by our actuaries to assess the reasonableness of the discount rate selected.
The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Xcel Energy accelerated its planned 2010 contribution of $100 million based on available liquidity, bringing its total pension contributions to $200 million during 2009. Xcel Energy currently projects no additional funding for 2010 and cash funding of $100 million to $150 million in 2011. For future years, we anticipate contributions will be made to avoid benefit restrictions and at-risk status.
These expected contributions are summarized in Note 11 to the consolidated financial statements. These amounts are estimates and may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. However, all pension costs are expected to be recoverable in rates.
If Xcel Energy were to use alternative assumptions for Dec. 31, 2009, pension expense determinations, a one-percent change would result in the following impact on the estimates recognized:
Effective Dec. 31, 2009, Xcel Energy reduced its initial medical trend assumption from 7.4 percent to 6.8 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is three years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy's retiree medical plan.
Xcel Energy contributed $62.2 million during 2009 and $55.6 million during 2008 to the postretirement health care plans. Xcel Energy expects to contribute approximately $45.4 million during 2010.
See Note 11 to the consolidated financial statements for additional discussion of Xcel Energy's benefit plans.
Nuclear Decommissioning
NSP-Minnesota owns nuclear generation facilities and regulations require NSP-Minnesota to decommission its nuclear power plants after each facility is taken out of service. Xcel Energy records future plant removal obligations as a liability at fair value. This liability will be increased over time by applying the interest method of accretion to the liability. Due to regulation, depreciation expense is recorded to match the recovery of future cost of decommissioning, or retirement, of its nuclear generating plants. This recovery is calculated using an annuity approach designed to provide for full rate recovery of the future decommissioning costs.
Amounts recorded for nuclear AROs, in excess of decommissioning expense and investment returns, both realized and unrealized, cumulatively are deferred through the establishment of a regulatory asset for future recovery pursuant to ASC 980 Regulated Operations.
A portion of the rates charged to customers is deposited into an external trust fund, during the facilities' operating lives, in order to provide for this obligation. The fair value of external nuclear decommissioning trust fund investments are estimated based on quoted market prices for those or similar investments. Realized investment returns from these investments and recovery to date is used by regulators when determining future decommissioning recovery.
NSP-Minnesota conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The costs are initially presented in amounts prior to inflation adjustments and then inflated to future periods using decommissioning specific cost inflators. Decommissioning of NSP-Minnesota's nuclear facilities is planned for the period from cessation of operations through 2067 assuming the prompt dismantlement method. The following key assumptions have a significant effect on these estimates:
•Escalation Rate - The MPUC determines the escalation rate based on various presumptions surrounded by the fact that associated costs will escalate at a certain rate over time. The most recent decommissioning study set the escalation rate at 2.89 percent. An escalation rate for the cost of disposing of nuclear fuel waste was set at 6.0 percent. Over the short-term, these rates can differ from the set rates and accrual estimates can be significantly affected by small changes in assumed escalation rates.
•Life Extension - Currently, decommissioning recovery periods end in 2030 for Monticello and in 2023 and 2024 for Prairie Island's two facilities. Changes made to decommissioning cost estimates, the escalation rate and the earnings rate can be affected by changes to these life periods. With the recent re-licensing of Monticello and the application for the re-licensing of Prairie Island, any change in license life could have a material effect on the accrual. Current decommissioning cost calculations for Monticello have assumed full life extension, which brings the regulatory recovery period up to 2030. An application to extend the operating licenses for both reactors at Prairie Island by 20 years was submitted to the NRC in 2008. The NRC is expected to decide on the application in late 2010 or early in 2011. In the interim, the MPUC has extended the recovery period for Prairie Island Unit 1 to 2023 and Unit 2 to 2024. These changes were effective Jan. 1, 2009. As a result of the studies for Monticello and Prairie Island nuclear plants, the nuclear production decommissioning ARO and related regulatory asset decreased by $128.5 million and $139.3 million, respectively, in the fourth quarter of 2008. It was further reduced by $315.9 million in the fourth quarter of 2009 for the Prairie Island nuclear plant relating to the approved change in recovery period.
Revisions were made for asbestos, ash-containment facilities, nuclear plants, wind turbines, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.
•Cost Estimate with Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel. NSP-Minnesota has funded its portion of the DOE's permanent disposal program since 1981. The spent fuel storage assumptions have a significant influence on the decommissioning cost estimate. The manner in which spent nuclear fuel is managed and the assumptions used to develop cost estimates of decommissioning programs have a dramatic impact, which in turn can have a corresponding impact on the resulting accrual. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The total obligation for decommissioning currently is expected to be funded 100 percent by a portion of the rates charged to customers, as approved by the MPUC and other commissions. Decommissioning expense recoveries are based upon the same assumptions and methodologies as the fair value obligations are recorded. In addition to these assumptions discussed previously, assumptions related to future earnings of the nuclear decommissioning fund are utilized by the MPUC in determining the recovery of decommissioning costs. Through utilization of the annuity approach, an assumed rate of return on funding is calculated which provides the earnings rate. With a long period of decommissioning and a funding period over the operating lives of each facility, the ability of the fund to sustain the required payments after inflation while assuring the appropriate investment structure is critical in obtaining the best benefit in the accrual. Currently, an assumption that the external funds will earn a return of 6.3 percent, after tax, is utilized when setting recovery by the MPUC.
Significant uncertainties exist in estimating the future cost of decommissioning including the method to be utilized, the ultimate costs to decommission, and the planned treatment of spent fuel. Materially different results could be obtained if different assumptions were utilized. Currently, our estimates of future decommissioning costs and the obligation to retire the plants have a significant impact to our financial position. The amounts recorded for AROs and regulatory assets for unrecovered costs are $881.5 million and $207.3 million, respectively, as of Dec. 31, 2009, and $1.1 billion and $299.3 million, respectively, as of Dec. 31, 2008. If different cost estimates, shorter life assumptions or different cost escalation rates were utilized, this ARO and the unrecovered balance in regulatory assets could change materially. If future earnings on the decommissioning fund are lower than that estimated currently, future decommissioning recoveries would need to increase. The significance to our results of operations is reduced due to the fact that we record decommissioning expense based upon recovery amounts approved by our regulators. This treatment reduces the volatility of expense over time. The difference between regulatory funding (including both depreciation expense less returns from the investments fund) and amounts recorded under ASC 410 Asset Retirement and Environmental Obligations are deferred as a regulatory asset.
See Note 18 for further discussion regarding nuclear decommissioning.
Xcel Energy continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect the events and updated information that becomes available. The accompanying financial statements reflect management's best estimates and judgments of the impact of these factors as of Dec. 31, 2009.
For a discussion of significant accounting policies, see Note 1 to the consolidated financial statements.
Recent and Pending Accounting Changes
Recently Adopted
Business Combinations - In December 2007, the FASB issued new guidance on business combinations which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This new guidance is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity's fiscal year that begins on or after Dec. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Noncontrolling Interests - Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent's equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent's ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Derivatives and Hedging Disclosures - In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity's financial position, financial performance and cash flows. The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts. This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 13 to the consolidated financial statements.
Interim Fair Value Disclosures - In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Fair Value in Inactive Markets - Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly. The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants. This new guidance was effective for interim and annual periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Other-Than-Temporary Impairments - Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance was effective for interim and annual periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Accounting Standards Codification - In June 2009, the FASB issued Topic 105 - Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB ASC to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC. All other accounting literature not included in the Codification is to be considered non-authoritative. The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009. Xcel Energy implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009. The implementation did not have a material impact on Xcel Energy's consolidated financial statements.
Postretirement Benefit Plans - In December 2008, the FASB issued new guidance on employers' disclosures about postretirement benefit plan assets. The guidance amends and expands previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, and information regarding fair value measurements. This new guidance was effective for disclosures for fiscal years ending after Dec. 15, 2009. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 11 to the consolidated financial statements.
Fair Value of Liabilities - In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value (ASU No. 2009-05), which updates the Codification with clarifications for measuring the fair value of liabilities. The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model. The updates to the Codification contained in ASU No. 2009-05 were effective for interim and annual periods beginning after its August, 2009 issuance. Xcel Energy implemented the guidance on Sept. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Recently Issued
Consolidation of Variable Interest Entities - In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity's primary beneficiary. This new guidance is effective for interim and annual periods beginning after Nov. 15, 2009. Xcel Energy does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.
Fair Value Measurement Disclosures - In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. Xcel Energy does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.
Derivatives, Risk Management and Market Risk
In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Market risks associated with derivatives are discussed in further detail in Note 13 to the consolidated financial statements.
Xcel Energy is exposed to the impact of changes in price for energy and energy related products, which is partially mitigated by Xcel Energy's use of commodity derivatives. Though no material non-performance risk currently exists with the counterparties to Xcel Energy's commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the debt and equity securities in the nuclear decommissioning trust fund and master pension trust, as well as Xcel Energy's ability to earn a return on short-term investments of excess cash.
Commodity Price Risk - Xcel Energy's utility subsidiaries are exposed to commodity price risk in their electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Xcel Energy's risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.
Short-Term Wholesale and Commodity Trading Risk - Xcel Energy's utility subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy's risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31, were as follows:
At Dec. 31, 2009, the fair values by source for the commodity trading net asset balance were as follows:
1-Prices actively quoted or based on actively quoted prices. 2-Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management's estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model. Normal purchases and sales transactions, as defined by ASC 815 Derivatives and Hedging, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.
At Dec. 31, 2009, a 10 percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.9 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.9 million.
Xcel Energy's short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis, were as follows:
Interest Rate Risk - Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy's risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
At Dec. 31, 2009, a 100-basis-point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense by approximately $5.4 million annually. See Note 13 to the consolidated financial statements for a discussion of Xcel Energy and its subsidiaries' interest rate derivatives.
Xcel Energy also maintains trust funds, as required by the NRC, to fund costs of nuclear decommissioning. These trust funds are subject to interest rate risk and equity price risk. At Dec. 31, 2009, these funds were invested in a diversified portfolio of taxable and municipal fixed income securities and equity securities. These funds may be used only for activities related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore, fluctuations in equity prices or interest rates do not have an impact on earnings.
Credit Risk - Xcel Energy and its subsidiaries are also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2009, a 10 percent increase in prices would have resulted in an increase in credit exposure of $26.5 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $4.9 million.
Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase Xcel Energy's credit risk.
Fair Value Measurements
Xcel Energy adopted new accounting and disclosure guidance on fair value measurements on Jan. 1, 2008 which established a hierarchy for inputs used in measuring fair value, and generally requires that the most observable inputs available be used for fair value measurements. Note 15 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.
Commodity Derivatives - Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty's ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2009. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2009.
Commodity derivatives assets and liabilities assigned to Level 3 consist primarily of FTRs, as well as forwards and options that are either long-term in nature or related to commodities and delivery points with limited observability. Level 3 commodity derivative assets and liabilities represent approximately 3 percent and 53 percent of total assets and liabilities measured at fair value, respectively, at Dec. 31, 2009.
Determining the fair value of a FTR requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management's forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities include $23.6 million and $3.3 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2009.
Determining the fair value of certain commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. Level 3 commodity derivatives assets and liabilities include $20.3 million and $12.6 million of estimated fair values, respectively, for commodity forwards and options held at Dec. 31, 2009.
Nuclear Decommissioning Fund - Nuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities. To the extent appropriate, observable market inputs are utilized to estimate the fair value of these securities, however, less observable and subjective risk-based adjustments to estimated yield and forecasted prepayments are often significant to these valuations. Therefore, estimated fair values for all asset-backed and mortgage-backed securities totaling $93.1 million in the nuclear decommissioning fund at Dec. 31, 2009 (approximately 7 percent of total assets measured at fair value), are assigned to Level 3. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.
Liquidity and Capital Resources
Cash Flows
Cash provided by operating activities for continuing operations increased by $263 million for 2009 as compared to 2008. The increase was primarily attributable to higher net income, changes in working capital due to the timing of accounts receivable, accounts payable and inventory as a result of natural gas prices and an increase in plant-related deferred income taxes. The increase was partially offset by increased pension contributions made in 2009 and higher AFUDC due primarily to the construction of Comanche Unit 3, a power facility located in Colorado.
Cash provided by operating activities for continuing operations increased by $123 million for 2008 as compared to 2007. The increase is primarily attributable to higher net income, changes in other current liabilities due to timing for interest payable and accounts payable and an increase in recoverable gas and electric costs. This increase was partially offset by changes in working capital activity due to increased inventory, contributions for pension and non-pension postretirement benefits, and an increase in net regulatory assets and liabilities. The increased inventory reflects the higher cost of natural gas combined with an increase in storage contracts. The increase in net regulatory assets and liabilities reflects the increase in pension funding obligation, and the decrease in fair value of the investments in the decommissioning fund, partially offset by the decrease in the asset retirement obligation for the extended life of the nuclear facilities. Cash provided by operating activities for discontinued operations decreased $75 million, primarily due to decreased income taxes received during 2008.
Cash used in investing activities for continuing operations decreased by $421 million during 2009, primarily due to reduced capital expenditures; a withdrawal of funds, to refund customers, from the external decommissioning fund as approved by the MPUC; as well as reduced investment in the WYCO natural gas pipeline and storage project. No cash was provided by investing activities for discontinued operations.
Cash used in investing activities for continuing operations increased by $74 million during 2008, primarily due to increased capital expenditures, and the continued investment in the WYCO natural gas pipeline and storage project.
Cash used in financing activities related to continuing operations increased by $993 million during 2009, primarily due to lower proceeds from the issuances of long-term debt and common stock and an increase in dividends, partially offset by lower repayments of short-term borrowings.
Cash provided by financing activities related to continuing operations increased by $188 million during 2008 due to the issuance of long-term debt and approximately 17.3 million shares of common stock in 2008. This was partially offset by repayments of short-term borrowings.
See discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.
Capital Requirements
Utility Capital Expenditures - The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2010 through 2013 are shown in the tables below.
Many of the states in which Xcel Energy operates have enacted RESs, which may require significant increases in investment in renewable generation and transmission. Xcel Energy is able to meet these standards by either purchasing renewable power from an independent party or by owning the assets. Therefore, these standards may present Xcel Energy with the opportunity to increase its investment in wind generation and transmission assets. As a result, Xcel Energy's capital expenditure forecast, as detailed above, may increase due to potential increased investments for renewable generation and transmission assets.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions and approvals, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy's long-term energy needs. In addition, Xcel Energy's ongoing evaluation of restructuring requirements, compliance with future environmental requirements and RPSs to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. See additional discussion in Item 1 - Electric Utility Operations.
Contractual Obligations and Other Commitments - Xcel Energy has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2009. See additional discussion in the consolidated statements of capitalization and Notes 5, 6, and 17 to the consolidated financial statements.
(a)Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy's railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2009, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $110.3 million. In addition, at the end of the equipment lease terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value of equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value. (b)Included in operating lease payments are $151.7 million, $307.6 million, $354.1 million and $2.3 billion, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to purchase power agreements that were accounted for as operating leases. (c)Included in other long-term obligations are tax and interest related to unrecognized tax benefits recorded as required under ASC 740 Income Taxes.(d)Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. Additionally, the utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. Certain contractual purchase obligations are adjusted based on indices. The effects of price changes are mitigated through cost-of-energy adjustment mechanisms. (e)Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $2.1 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table and in the forecasted capital expenditures. (f)Xcel Energy currently projects no additional pension funding obligations for 2010. At this time, pension funding contributions for 2011, which will be dependent on several factors including realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million. (g)Xcel Energy expects to contribute approximately $45.4 million to the postretirement health care plans during 2010. Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy Board of Directors. Xcel Energy's objective is to increase the annual dividend in the range of 2 percent to 4 percent per year. Xcel Energy's dividend policy balances:
•Projected cash generation from utility operations;
•Projected capital investment in the utility businesses;
•A reasonable rate of return on shareholder investment; and
•The impact on Xcel Energy's capital structure and credit ratings. In addition, there are certain statutory limitations that could affect dividend levels. Federal law places certain limits on the ability of public utilities within a holding company system to declare dividends.
Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries dividends may be limited indirectly or directly by state regulatory commissions, bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios.
The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy's capitalization ratio (on a holding company basis only, not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy's holding company capitalization ratio at Dec. 31, 2009 and 2008 was 85 percent and 84 percent, respectively. Therefore, the restrictions do not place any effective limit on Xcel Energy's ability to pay dividends.
Regulation of Derivatives - On Dec. 11, 2009, the U. S. House of Representatives passed H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009, and there are several other bills which have been introduced regarding regulation of derivative transactions. One provision within H.R. 4173 and the other bills introduced provide the Commodity Futures Trading Commission and SEC with expanded regulatory authority of energy derivative and swap transactions. As passed by the House, H.R. 4173 could preclude or impede some types of over-the-counter energy commodity transactions and/or require clearing through regulated central counterparties, which could result in extensive margin and fee requirements. Xcel Energy will further analyze the provisions of this complex legislation to understand potential financial impacts and risk to Xcel Energy, but based on our preliminary analysis the margin requirements could be significant. The legislation passed by the U. S. House of Representatives appears to contain less onerous language on hedges used by commercial participants, however, Xcel Energy is reviewing the proposal. Additionally, the U. S. Senate is scheduled to begin debate on derivatives legislation in early 2010, but the direction of the U. S. Senate is unknown at present.
Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short - term to long-duration fixed income securities, and alternative investments, including, private equity, real estate and commodity index investments. In December 2009, Xcel Energy accelerated its planned 2010 contribution of $100 million, based on available liquidity, bringing its total 2009 pension contributions to $200 million. Xcel Energy currently projects no additional funding obligations for 2010. At this time, pension funding contributions for 2011, which will be dependent on several factors including realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million. The funded status and pension assumptions are summarized in the following tables:
(a)Excludes non-qualified plan of $46 million at Dec. 31, 2009 and 2008, respectively.
Capital Sources
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, preferred securities and hybrid securities to maintain desired capitalization ratios.
Short-Term Funding Sources - Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments - Xcel Energy, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating accounts with Wells Fargo Bank. At Dec. 31, 2009, approximately $35.5 million of cash was held in these liquid operating accounts.
Commercial Paper - Xcel Energy, NSP-Minnesota, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:
•$800 million for Xcel Energy;
•$500 million for NSP-Minnesota;
•$700 million for PSCo; and
•$250 million for SPS. Credit Facilities - As of Feb. 12, 2010 Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:
(a)Includes direct borrowings, outstanding commercial paper and letters of credit. (b)NSP-Wisconsin does not have a specific credit facility; however, it has a borrowing agreement with NSP-Minnesota. Listed below is a summary of the banks that make up the credit facilities of Xcel Energy and its subsidiaries as of Feb. 12, 2010.
Operating cash flow as a source of short-term funding is affected by such operating factors as weather, regulatory requirements, including rate recovery of costs, environmental regulation compliance, changes in the trends for energy prices, supply and operational uncertainties and other changes in working capital, all of which are difficult to predict. See further discussion of such factors under Statement of Operations Analysis.
Short-term borrowing as a source of funding is affected by regulatory actions, credit ratings and access to reasonably priced capital markets. For additional information on Xcel Energy's short-term borrowing arrangements, see Note 5 to the consolidated financial statements.
Credit Ratings - Access to reasonably priced capital markets is dependent in part on credit and ratings. The following ratings reflect the views of Moody's, Standard & Poor's, and Fitch. A security rating is not a recommendation to buy, sell or hold securities, and is subject to revision or withdrawal at any time by the rating agency.
As of Feb. 12, 2010, the following represents the credit ratings assigned to various Xcel Energy companies:
Moody's highest credit rating for debt is Aaa and lowest investment grade rating is Baa3. Both Standard & Poor's and Fitch's highest credit rating for debt are AAA and lowest investment grade rating is BBB-. Moody's prime ratings for commercial paper range from P-1 to P-3. Standard & Poor's ratings for commercial paper range from A-1 to A-3. Fitch's ratings for commercial paper range from to. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
In August 2009, Moody's upgraded the majority of the senior secured debt ratings of investment-grade regulated utilities by one notch. The senior secured ratings for NSP-Minnesota and NSP-Wisconsin were raised to A1 from A2, and the senior secured rating for PSCo was raised to A2 from A3. In June 2009, S&P revised the outlook on Xcel Energy Inc. and its regulated subsidiaries to Positive from Stable.
In the event of a downgrade of its credit ratings to below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy all or a part of its exposures under guarantees outstanding. See a list of guarantees at Note 14 to the consolidated financial statements. Xcel Energy has no explicit credit rating requirements or hard triggers in its debt agreements.
Money Pool - Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings from the utility subsidiaries and investments from the Holding Company to the utility subsidiaries at market-based interest rates. The money pool balances are eliminated during consolidation.
The utility money pool arrangement does not allow borrowings to the Holding Company. NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin does not participate in the money pool.
The borrowings or investments outstanding at Dec. 31, 2009, and the approved short-term borrowing limits from the money pool are as follows:
Registration Statements - Xcel Energy's articles of incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2009 and 2008, Xcel Energy had approximately 458 million shares and 454 million shares of common stock outstanding, respectively. In addition, Xcel Energy's articles of incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2009 and 2008, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on file with the SEC, pursuant to which they may sell, from time to time, securities:
•Xcel Energy has an effective automatic shelf registration statement that does not contain a limit on issuance capacity; however, Xcel Energy's ability to issue securities is limited by authority granted by the Board of Directors, which authority currently authorizes the issuance of up to an additional $1.5 billion of debt and common equity securities.
•NSP-Minnesota has $700 million of debt securities available under its current effective registration statement.
•PSCo has approximately $400 million of debt securities available under its currently effective registration statement.
•NSP-Wisconsin has $50 million remaining under its currently effective registration statement. Long-Term Borrowings - See the Statement of Capitalization and a discussion of the long-term borrowings in Note 6 to the consolidated financial statements.
Financing Plans - Xcel Energy issues debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. Xcel Energy plans to issue the following debt securities in 2010:
•Up to $500 million of unsecured debt at the holding company, and
•Up to $500 million of first mortgage bonds at NSP-Minnesota. Financing plans are subject to change, depending on capital expenditures, internal cash generation, interest rates, market conditions and other factors.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance
Xcel Energy's 2010 ongoing earnings guidance is $1.55 to $1.65 per share. Key assumptions are detailed below:
•Normal weather patterns are experienced for the year.
•Weather-adjusted retail electric utility sales grow approximately 1 percent.
•Weather-adjusted retail firm natural gas sales decline approximately 1 percent to 2 percent.
•Reflects increased revenue due to the full year impact of 2009 electric rate cases in Colorado, Texas and New Mexico, along with the 2010 electric rate increase in Colorado.
•Constructive outcomes in the Minnesota natural gas rate and PSCo wholesale electric rate cases.
•Increased rider revenue recovery of approximately $30 million.
•O&M expenses are projected to increase $115 million to $135 million, or 6 percent to 7 percent.
•Depreciation expense is projected to increase by $40 million to $50 million.
•Interest expense is projected to increase approximately $15 million to $25 million.
•AFUDC-equity is projected to decrease $25 million to $30 million.
•The effective tax rate for continuing operations is approximately 34 percent to 36 percent.
•Average common stock and equivalents total approximately 460 million shares.
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
See Management's Discussion and Analysis under Item 7, incorporated by reference.
Item 8 - Financial Statements and Supplementary Data
See Item 15 - 1 in Part IV for an index of financial statements included herein.
See Note 21 to the consolidated financial statements for summarized quarterly financial data.
Management Report on Internal Controls Over Financial Reporting
The management of Xcel Energy is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy's internal control system was designed to provide reasonable assurance to the company's management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy management assessed the effectiveness of the company's internal control over financial reporting as of Dec. 31, 2009. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2009, the company's internal control over financial reporting is effective based on those criteria.
Xcel Energy's independent auditors have issued an audit report on the company's internal control over financial reporting. Their report appears herein.
/s/ RICHARD C. KELLY
Richard C. Kelly
Chairman and Chief Executive Officer
February 26, 2010
/s/ DAVID M. SPARBY
David M. Sparby
Vice President and Chief Financial Officer
February 26, 2010
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Xcel Energy Inc.
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2009 and 2008, and the related consolidated statements of income, common stockholders' equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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, such consolidated financial statements present fairly, in all material respects, the financial position of Xcel Energy Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2010 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 26, 2010
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Xcel Energy Inc.
We have audited the internal control over financial reporting of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2009, based on criteria established Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible 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 Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit 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, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2009 of the Company and our report dated February 26, 2010 expressed an unqualified opinion on those financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 26, 2010
XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Income
(amounts in thousands, except per share data)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(amounts in thousands of dollars)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(amounts in thousands of dollars)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Common Stockholders' Equity
and Comprehensive Income
(amounts in thousands)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Capitalization
(amounts in thousands of dollars)
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Capitalization - (Continued)
(amounts in thousands of dollars)
(a)Resource recovery financing. (b)Pollution control financing.
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Business and System of Accounts - Xcel Energy's utility subsidiaries are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility subsidiaries' accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation - In 2009, Xcel Energy's continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. WGI, an interstate natural gas pipeline company, and Xcel Energy WYCO Inc., a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities, are also included in continuing regulated utility operations.
Xcel Energy's nonregulated subsidiary in continuing operations is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits. Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., and Xcel Energy Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.
Xcel Energy in the past had several other subsidiaries, which were sold or divested. For more information, see Note 4 to the consolidated financial statements.
In 2007, NSP-Minnesota obtained 100 percent ownership in NMC. Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota's consolidated financial statements from the transaction date. NSP-Minnesota has reintegrated its nuclear operations into its generation operations. The NRC approved the transfer of the nuclear operating licenses from NMC to NSP-Minnesota on Sept. 22, 2008.
Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects for which it does not have a controlling financial interest. Under this method, a proportionate share of pretax income is recorded as equity earnings of unconsolidated subsidiaries. In the consolidation process, all intercompany transactions and balances are eliminated. Xcel Energy has investments in several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation basis, consistent with industry practice. For more information, see Note 7 to the consolidated financial statements.
Revenue Recognition - Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Xcel Energy presents its revenue net of any excise or other fiduciary-type taxes or fees.
Xcel Energy's utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and electric fuel costs, as well as purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rate orders, fuel costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. A summary of significant rate-adjustment mechanisms follows:
•NSP-Minnesota's rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively. The electric cost-of-fuel-and-purchased-energy mechanism in North Dakota also provides a sharing among shareholders and customers of certain margins on short-term wholesale and commodity trading. NSP-Minnesota's rates include a rider for cost recovery of DSM program costs as well as recovery of a financial incentive for meeting energy savings goals.
•NSP-Minnesota operates under various service quality standards, which could require customer refunds if certain criteria are not met. NSP-Minnesota rates in Minnesota include monthly adjustments for recovery of conservation and energy-management program costs, which are reviewed annually. NSP-Minnesota is allowed to recover certain costs associated with new transmission facilities to deliver renewable energy resources and certain costs associated with production facilities through rate riders.
•NSP-Wisconsin's rates in Wisconsin include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. Requests can be made for recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, or an interim fuel-cost hearing process.
•PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the ECA for the company's retail jurisdiction. The ECA mechanism was extended in 2009 and went into effect in January 2010. The ECA allows for sharing of margins on short term energy sales.
•PSCo generally recovers all purchased capacity costs through the PCCA for the company's retail jurisdiction. The PCCA mechanism is revised annually. The PCCA was recently extended by CPUC order in PSCo's most recent rate case.
•PSCo's rates include annual adjustments for the recovery of conservation and energy-management program costs, as well as a financial incentive based on its performance in achieving established goals. PSCo is allowed to recover certain costs associated with renewable energy resources through a specific retail rate rider. In January 2008, a new recovery mechanism for transmission commenced. The TCA permits PSCo to recover costs associated with investment in transmission facilities made after March 2007 through a rate rider.
•In Texas, SPS recovers fuel and purchased energy costs through a fixed fuel and purchased energy recovery factor, which is part of SPS' retail electric rates. The Texas retail fuel factors can change up to three times per year based on the projected costs of natural gas. In January 2010, the PUCT approved recovery of certain transmission investments and other transmission costs through the TCRF rider. In New Mexico, SPS has a monthly fuel and purchased power cost-recovery factor.
•NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell firm power and energy in wholesale markets, which are regulated by the FERC. Certain of these rates include monthly wholesale fuel cost-recovery mechanisms through prices that are indexed to retail rates, including the monthly cost of fuel and purchased energy recovery mechanisms. Commodity Trading Operations - All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the consolidated statements of income.
Xcel Energy's commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated with energy produced from Xcel Energy's generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with ASC 815 Derivatives and Hedging. In addition, commodity trading results include the impact of all margin-sharing mechanisms. For more information, see Note 13 to the consolidated financial statements.
Fair Value Measurements - Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives, and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value and losses are recorded in earnings if fair value falls below recorded cost. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security.
Types of and Accounting for Derivative Instruments - Xcel Energy and its subsidiaries use derivative instruments in connection with their interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by ASC 815 Derivatives and Hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.
Gains or losses on hedging transactions for the sale of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; hedge transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.
Cash Flow and Fair Value Hedges - Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The accounting for derivatives requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. Xcel Energy and its subsidiaries formally document all hedging relationships in accordance with this guidance. The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction. In addition, at inception and on a quarterly basis, Xcel Energy and its subsidiaries formally assess whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Xcel 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. To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis. Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case associated deferred amounts are immediately recognized in current earnings.
The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge offsets the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of the derivative instrument's change in fair value is recognized in current earnings.
Normal Purchases and Normal Sales - Xcel Energy's utility subsidiaries enter into contracts for the purchase and sale of commodities for use in their business operations. ASC 815 Derivatives and Hedging requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting as normal purchases or normal sales.
Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.
For further discussion of Xcel Energy's risk management and derivative activities, see Note 13 to the consolidated financial statements.
Property, Plant and Equipment and Depreciation - Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Regulatory obligations to incur removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use.
Xcel Energy records depreciation expense related to its plant by using the straight-line method over the plant's useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 2.9, 3.2, and 3.2 percent for the years ended Dec. 31, 2009, 2008 and 2007, respectively.
AFUDC - AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy's rate base for establishing utility service rates. In addition to construction-related amounts, AFUDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.
Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases commissions have approved a more current recovery of cost associated with large capital projects, resulting in a lower recognition of AFUDC.
Decommissioning - Xcel Energy accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of external nuclear decommissioning fund investments is determined based on quoted market prices for those or similar investments. Unrealized gains or losses on the fund's assets are included with regulatory assets on the consolidated balance sheets. For more information on nuclear decommissioning, see Note 18 to the consolidated financial statements.
Nuclear Fuel Expense - Nuclear fuel expense, which is recorded as the nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC), as well as future disposal costs of spent nuclear fuel, costs associated with the end-of-life fuel segments and fees assessed by the DOE for NSP-Minnesota's portion of the cost of decommissioning the DOE's fuel-enrichment facility.
Nuclear Refueling Outage Costs - Effective Jan. 1, 2008, Xcel Energy expensed the costs associated with refueling outages as incurred at its nuclear plants. In September 2008, the MPUC authorized Xcel Energy to use a deferral and amortization method for the nuclear refueling O&M costs effective Jan. 1, 2008. This method amortizes refueling outage costs over the period between refueling outages to better match revenues and expenses.
Environmental Costs - Environmental costs are recorded when it is probable Xcel Energy is liable for the costs and the liability can reasonably be estimated. Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and as remediation proceeds. If several designated responsible parties exist, only Xcel Energy's expected share of the cost is estimated and recorded. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.
Legal Costs - Litigation accruals are recorded when it is probable Xcel Energy is liable for the costs and the liability can be reasonably estimated. External legal fees related to settlements are expensed as incurred.
Income Taxes - Xcel Energy accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.
Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 19 to the consolidated financial statements. For more information on income taxes, see Note 8 to the consolidated financial statements.
Xcel Energy follows the guidance in ASC 740 Income Taxes to measure and disclose uncertain tax positions that the Company has taken or expects to take in its income tax returns. In accordance with this guidance, Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.
Xcel Energy and its subsidiaries file consolidated federal income tax returns and combined and separate state income tax returns.
Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings. The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company.
Use of Estimates - In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.
Cash and Cash Equivalents - Xcel Energy considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Restricted Cash - At Dec. 31, 2009 and 2008, Xcel Energy had restricted cash of $1 million. The restricted cash balances primarily represent deposits held in conjunction with short-term wholesale and commodity trading activities. These balances are presented as a component of other assets on the consolidated balance sheets.
Inventory - All inventory is recorded at average cost.
Regulatory Accounting - Our regulated utility subsidiaries account for certain income and expense items in accordance with ASC 980 Regulated Operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and
•Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.
If restructuring or other changes in the regulatory environment occur, regulated utility subsidiaries may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy's results of operations in the period the write-offs are recorded. See more discussion of regulatory assets and liabilities in Note 19 to the consolidated financial statements.
Deferred Financing Costs - Other assets included deferred financing costs, net of amortization, of approximately $69 million at Dec. 31, 2009 and 2008. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt.
Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.
Accounts Receivable and Allowance for Bad Debts - Accounts receivable are stated at the actual billed amount net of write-offs and an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a reserve policy that reflects its expected exposure to the credit risk of customers.
Renewable Energy Credits - RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPSs enacted by those states that are encouraging construction and consumption of renewable energy, but can also be sold separately from the energy produced. Currently, utility subsidiaries acquire RECs from the generation or purchase of renewable power.
When RECs are acquired in the course of generation or purchase as a result of meeting load obligations, they are recorded as inventory at cost. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The cost of RECs that are retired for compliance purposes is recorded as electric fuel and purchased power expense. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues, net of any margin sharing requirements. As a result of state regulatory orders, Xcel Energy reduces recoverable fuel costs for the value of certain RECs and records the cost of RECs to satisfy future compliance requirements that are recoverable in future rates as regulatory assets.
Emission Allowances - Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. Xcel Energy follows the inventory accounting model for all allowances. The sales of allowances are reported in the operating activities section of the consolidated statements of cash flows. The net margin on sales of emission allowances is included in electric utility operating revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.
Reclassifications - Equity earnings of unconsolidated subsidiaries were reclassified from other income into a separate line item on the consolidated statements of income. Conservation and demand side management program expenses were reclassified as a separate item from depreciation and amortization within the consolidated statements of cash flows. Pension and employee benefit obligations were reclassified as a separate item from change in other noncurrent liabilities within the consolidated statements of cash flows. These reclassifications did not have an impact on net income, earnings per share, or net cash provided by operating activities.
Subsequent Events - Management has evaluated the impact of events occurring after Dec. 31, 2009 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
2. Accounting Pronouncements
Recently Adopted
Business Combinations - In December 2007, the FASB issued new guidance on business combinations which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This new guidance is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity's fiscal year that begins on or after Dec. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Noncontrolling Interests - Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent's equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent's ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Derivatives and Hedging Disclosures - In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity's financial position, financial performance and cash flows. The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts. This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 13 to the consolidated financial statements.
Interim Fair Value Disclosures - In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Fair Value in Inactive Markets - Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly. The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants. This new guidance was effective for interim and annual periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Other-Than-Temporary Impairments - Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance was effective for interim and annual periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Accounting Standards Codification - In June 2009, the FASB issued Topic 105 - Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB ASC to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC. All other accounting literature not included in the Codification is to be considered non-authoritative. The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009. Xcel Energy implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009. The implementation did not have a material impact on Xcel Energy's consolidated financial statements.
Postretirement Benefit Plans - In December 2008, the FASB issued new guidance on employers' disclosures about postretirement benefit plan assets. The guidance amends and expands previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, and information regarding fair value measurements. This new guidance was effective for disclosures for fiscal years ending after Dec. 15, 2009. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 11 to the consolidated financial statements.
Fair Value of Liabilities - In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value (ASU No. 2009-05), which updates the Codification with clarifications for measuring the fair value of liabilities. The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model. The updates to the Codification contained in ASU No. 2009-05 were effective for interim and annual periods beginning after its August, 2009 issuance. Xcel Energy implemented the guidance on Sept. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.
Recently Issued
Consolidation of Variable Interest Entities - In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity's primary beneficiary. This new guidance is effective for interim and annual periods beginning after Nov. 15, 2009. Xcel Energy does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.
Fair Value Measurement Disclosures - In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. Xcel Energy does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.
3. Selected Balance Sheet Data
4. Discontinued Operations
Results of operations for divested businesses are reported, for all periods presented, as discontinued operations. The majority of current and noncurrent assets related to discontinued operations are deferred tax assets associated with temporary differences and NOL and tax credit carryforwards that will be deductible in future years.
The major classes of assets and liabilities related to discontinued operations are as follows:
5. Short-Term Borrowings and Other Financing Instruments
Commercial Paper - At Dec. 31, 2009 and 2008, Xcel Energy and its utility subsidiaries had commercial paper outstanding of approximately $459.0 million and $330.3 million, respectively. The weighted average interest rates at Dec. 31, 2009 and 2008 were 0.36 percent and 3.53 percent, respectively. Xcel Energy and its utility subsidiaries have combined approval by the Board of Directors to issue up to $2.25 billion of commercial paper.
Credit Facility Bank Borrowings - At Dec. 31, 2008, Xcel Energy and its utility subsidiaries had credit facility bank borrowings of $125.0 million. The weighted average interest rate at Dec. 31, 2008 was 1.88 percent. Xcel Energy and its utility subsidiaries had no credit facility bank borrowings at Dec. 31, 2009.
Money Pool - Xcel Energy and its utility subsidiaries have established a utility money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The Holding Company may make investments in the utility subsidiaries at market-based interest rates. However, the money pool arrangement does not allow the utility subsidiaries to make investments in the Holding Company. At Dec. 31, 2009 and 2008, Xcel Energy and its utility subsidiaries had money pool investments outstanding of $84.0 million and $104.5 million, respectively. The money pool balances are eliminated upon consolidation. The weighted average interest rates at Dec. 31, 2009 and 2008 were 0.36 percent and 3.48 percent, respectively.
6. Long-Term Borrowings and Other Financing Instruments
Credit Facilities - At Dec. 31, 2009, Xcel Energy and its utility subsidiaries had the following committed credit facilities available:
(a)Includes direct borrowings, outstanding commercial paper and issued and outstanding letters of credit. (b)NSP-Wisconsin does not have a separate credit facility; however, it has a borrowing agreement with NSP-Minnesota.
The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Xcel Energy and its utility subsidiaries have the right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval.
•Each credit facility has one financial covenant requiring that the debt-to-total-capitalization ratio of each entity be less than or equal to 65 percent. Each entity was in compliance at Dec. 31, 2009 and 2008 as evidenced by the table below:
If Xcel Energy or any of its utility subsidiaries do not comply with the covenant, it is deemed an event of default and any outstanding amounts due under the facility can be declared due by the lender.
•Each credit facility has a cross default provision that provides the borrower will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets, defaults on any of its indebtedness greater than $50 million.
•The interest rates under these lines of credit are based on either the agent bank's prime rate or the applicable LIBOR, plus a borrowing margin based on the applicable debt rating. Based on our current credit ratings, the borrowing margin is 35 basis points for Xcel Energy, PSCo and SPS, and 25 basis points for NSP-Minnesota.
•The commitment fees, also based on applicable debt ratings, are calculated on the unused portion of the lines of credit at 8 basis points per year for Xcel Energy, PSCo and SPS, and at 6 basis points per year for NSP-Minnesota.
•At Dec. 31, 2009, the credit facilities were used to provide backup for $459.0 million of commercial paper outstanding and $21.0 million of letters of credit. At Dec. 31, 2008, Xcel Energy had short-term borrowings of $125.0 million on this line of credit. In addition, the credit facilities were used to provide backup for $330.3 million of commercial paper outstanding and $23.0 million of letters of credit.
Long-Term Borrowings
All property of NSP-Minnesota and NSP-Wisconsin and the electric property of PSCo are subject to the liens of their first mortgage indentures. In addition, certain SPS payments under its pollution-control obligations are pledged to secure obligations of the Red River Authority of Texas.
Maturities of long-term debt are:
Xcel Energy
On Jan. 16, 2008, Xcel Energy issued $400 million of 7.6 percent junior subordinated notes (Junior Notes) due 2068. Due to certain features, rating agencies consider the Junior Notes to be hybrid debt instruments with a combination of debt and equity characteristics. The Junior Notes are not redeemable by Xcel Energy prior to 2013 without payment of a make-whole premium.
Interest payments on the Junior Notes may be deferred on one or more occasions for up to 10 consecutive years. If the interest payments on the Junior Notes are deferred, Xcel Energy may not declare or pay any dividends or distributions, or redeem, purchase, acquire, or make a liquidation payment on, any shares of its capital stock. Also during the deferral period, Xcel Energy may not make any principal or interest payments on, or repay, purchase or redeem any of its debt securities that are equal in right of payment with, or subordinated to, the Junior Notes. Xcel Energy also may not make payments on any guarantees equal in right of payment with, or subordinated to, the Junior Notes.
In connection with the completion of this offering, Xcel Energy entered into a Replacement Capital Covenant (RCC). Under the terms of the RCC, Xcel Energy agrees not to redeem or repurchase all or part of the Junior Notes prior to 2038 unless qualifying securities are issued to non-affiliates in a replacement offering in the 180 days prior to the redemption or repurchase date. Qualifying securities include those that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the Junior Notes at the time of redemption or repurchase.
NSP-Minnesota
In November 2009, NSP-Minnesota issued $300 million of 5.35 percent first mortgage bonds, series due Nov. 1, 2039. NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper and borrowings under the utility money pool arrangement incurred to fund the repayment at maturity of $250 million of 6.875 percent unsecured senior notes due Aug. 1, 2009.
In March 2008, NSP-Minnesota issued $500 million of 5.25 percent first mortgage bonds, series due March 1, 2018. NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper and borrowings under the utility money pool arrangement.
NSP-Wisconsin
In March 2009, NSP-Wisconsin redeemed its 7.375 percent $65.0 million first mortgage bonds due Dec. 1, 2026.
In September 2008, NSP-Wisconsin issued $200 million of 6.375 percent first mortgage bonds, series due Sept. 1, 2038. NSP-Wisconsin added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of such net proceeds to fund the payment at maturity of $80 million of 7.64 percent senior notes due Oct. 1, 2008. The balance of the net proceeds was used for the repayment of short-term debt (including notes payable to affiliates) and for general corporate purposes.
PSCo
In June 2009, PSCo issued $400 million of 5.125 percent first mortgage bonds, series due 2019. PSCo added the proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the net proceeds to fund the payment at maturity of $200 million of 6.875 percent unsecured senior notes due July 15, 2009.
In August 2008, PSCo issued $300 million of 5.80 percent first mortgage bonds, series due Aug. 1, 2018 and $300 million of 6.50 percent first mortgage bonds, series due Aug. 1, 2038. PSCo added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of such net proceeds to fund the payment at maturity of $300 million of 4.375 percent first mortgage bonds due Oct. 1, 2008.
SPS
In February 2010, SPS redeemed its $25.0 million pollution control obligations, securing pollution control revenue bonds, due July 1, 2016.
In November 2008, SPS issued $250 million of 8.75 percent senior notes, series due 2018. The proceeds from this offering were used to repay short-term debt.
Convertible Senior Notes
During the fourth quarter of 2008, $57.5 million of remaining Xcel Energy convertible notes due Nov. 21, 2008, were converted to common stock. During the second and fourth quarter of 2007, approximately $126 million and $104 million, respectively, of Xcel Energy convertible notes due Nov. 21, 2007, were converted to common stock.
7. Generating Plant Ownership and Operation
Joint Plant Ownership - Following are the investments by Xcel Energy's subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2009:
NSP-Minnesota is part owner of Sherco Unit 3, an 860 MW, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota's share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for funding its portion of the construction costs.
PSCo's current operational assets include approximately 320 MWs of jointly owned generating capacity, excluding Comanche Unit 3. PSCo's share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs. PSCo began major construction on a new jointly owned 750 MW, coal-fired unit in Pueblo, Colo. in January 2006. Major construction on the new unit, Comanche Unit 3, was still underway in 2009 and in-service is expected by the end of the first quarter of 2010. The plant experienced certain boiler tube leaks in the start-up process that are being resolved. PSCo is the operating agent under the joint ownership agreement.
8. Income Taxes
COLI - In 2007, Xcel Energy and the U. S. government settled an ongoing dispute regarding PSCo's right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. The total exposure for the tax years in dispute through 2007 was approximately $583 million, which includes income tax, interest and potential penalties. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed. Xcel Energy anticipates these proceedings to be dismissed in 2010.
Terms of the Final Settlement
1.Xcel Energy paid the government a total of $64.4 million in full settlement of the government's claims for tax, penalty, and interest for tax years 1993-2007.
2.The recognition of this settlement resulted in total expense of $59.5 million, including federal and state tax, interest on the federal and state tax liabilities, penalties, and tax benefits on the interest expense for the nine months ended Sept. 30, 2007. The expense of $59.5 million includes $43.4 million of interest and penalties and income tax of $16.1 million (net of tax benefit on the interest expense of $14.3 million).
3.Xcel Energy surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain Federal Audit - Xcel Energy files a consolidated federal income tax return. In 2008, the IRS completed an examination of Xcel Energy's federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy's 2004 and 2005 federal income tax returns expired on Dec. 31, 2009. The IRS commenced an examination of tax years 2006 and 2007 in 2008, and this audit is expected to be completed in the first quarter of 2010. As of Dec. 31, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.
State Audits - Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. In 2008, the state of Minnesota concluded an income tax audit through tax year 2001 and the state of Texas concluded an income tax audit through tax year 2005. No material adjustments were proposed for these state audits. As of Dec. 31, 2009, Xcel Energy's earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions are as follows:
The state of Texas has notified Xcel Energy of its intent to audit tax years 2006 and 2007. As of Dec. 31, 2009, the Texas audit had not been scheduled. There currently are no other state income tax audits in progress. In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years. As of Dec. 31, 2009, the state of Minnesota had not informed Xcel Energy of its intentions.
Unrecognized Tax Benefits - The amount of unrecognized tax benefits reported in continuing operations was $23.7 million on Dec. 31, 2009 and $35.5 million on Dec. 31, 2008. The amount of unrecognized tax benefits reported in discontinued operations was $6.6 million on both Dec. 31, 2009 and Dec. 31, 2008. A reconciliation of the beginning and ending amount of unrecognized tax benefit in continuing operations is as follows:
The unrecognized tax benefit amounts reported in continuing operations were reduced by the tax benefits associated with NOL and tax credit carryovers of $8.9 million on Dec. 31, 2009 and $13.1 million on Dec. 31, 2008. The unrecognized tax benefit amounts reported in discontinued operations were reduced by the tax benefits associated with NOL and tax credit carryovers of $20.4 million on Dec. 31, 2009 and $26.5 million on Dec. 31, 2008.
The unrecognized tax benefit balance reported in continuing operations included $4.0 million and $9.2 million of tax positions on Dec. 31, 2009 and Dec. 31, 2008, respectively, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance reported in continuing operations included $19.7 million and $26.3 million of tax positions on Dec. 31, 2009 and Dec. 31, 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.
The decrease in the unrecognized tax benefit balance reported in continuing operations of $11.8 million in 2009 was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of similar uncertain tax positions related to ongoing activity. Xcel Energy's amount of unrecognized tax benefits for continuing operations could significantly change in the next 12 months as the Texas audit begins and when the IRS and other state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.
The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryovers. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits reported in continuing operations is as follows:
A reconciliation of the beginning and ending amount of the receivable for interest related to unrecognized tax benefits reported in discontinued operations is as follows:
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2009 or Dec. 31, 2008.
Other Income Tax Matters - NOL and tax credit carryforwards as of Dec. 31, 2009 and 2008 were as follows:
The federal carryforward periods expire between 2021 and 2029. The state carryforward periods expire between 2010 and 2029.
Total income tax expense from continuing operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
The components of Xcel Energy's income tax expense from continuing operations for the years ending Dec. 31 were:
The components of Xcel Energy's net deferred tax liability from continuing operations (current and noncurrent) at Dec. 31 were as follows:
9. Preferred and Common Stock
Preferred Stock - Xcel Energy has authorized 7,000,000 shares of preferred stock with a $100 par value. At Dec. 31, 2009 and 2008, Xcel Energy had six series of preferred stock outstanding, redeemable at its option at prices ranging from $102 to $103.75 per share plus accrued dividends. The holders of the $3.60 series preferred stock are entitled to three votes per each share held. The holders of the other series of preferred stock are entitled to one vote per share. In the event dividends payable on the preferred stock of any series outstanding is in arrears in an amount equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are entitled to elect the smallest number of directors necessary to constitute a majority of the Board of Directors. The holders of common stock, voting as a class, are entitled to elect the remaining directors.
The charters of some of Xcel Energy's subsidiaries also authorize the issuance of preferred stock. However, at Dec. 31, 2009 and 2008, there are no preferred shares of subsidiaries outstanding. The following table lists preferred shares by subsidiary:
Common Stock and Equivalents - In September 2008, Xcel Energy issued 17,250,000 shares of common stock to underwriters at a price of $20.10 per share. The shares were re-offered to the public at a price of $20.20 per share plus a commission of $0.05 per share from the purchasers.
Xcel Energy has common stock equivalents consisting of 401(k) equity awards and stock options. Restricted stock units and performance shares are included as common stock equivalents when all necessary conditions for issuance have been satisfied by the end of the period being reported.
In 2009, 2008 and 2007, Xcel Energy had approximately 7.6 million, 8.1 million and 8.5 million weighted-average options outstanding, respectively, that were antidilutive and, therefore, excluded from the earnings per share calculation. The dilutive impact of common stock equivalents affected earnings per share as follows for the years ending Dec. 31:
Common Stock Dividends Per Share - Historically, Xcel Energy has paid quarterly dividends to its shareholders. Dividends on common stock are paid as declared by the Board of Directors. Dividends declared per share for the quarters of 2009, 2008 and 2007 were:
Dividend and Other Capital-Related Restrictions - The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy's capitalization ratio (on a holding company basis only, not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy's holding company capitalization ratio at Dec. 31, 2009 and 2008 was 85 percent and 84 percent, respectively. Therefore, the restrictions do not place any effective limit on Xcel Energy's ability to pay dividends.
In addition, NSP-Minnesota's first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion and $1.0 billion in additional cash dividends on common stock at Dec. 31, 2009 and 2008, respectively.
The issuance of securities by Xcel Energy generally is not subject to regulatory approval. However, utility financings and certain intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC under the Federal Power Act.
•PSCo currently has authorization to issue up to $400 million of long-term debt and up to $800 million of short-term debt.
•SPS currently has authorization to issue up to $400 million in short-term debt.
•NSP-Wisconsin currently has authorization to issue up to $50 million of long-term debt and $100 million of short-term debt.
•NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 45.99 percent and 56.21 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $7.5 billion. Xcel Energy believes these authorizations are adequate and will seek additional authorization when necessary; however, there can be no assurance that additional authorization will be granted on the timeframe or in the amounts requested.
The FERC has granted a blanket authorization for certain intra-system financings involving holding companies. The utility subsidiaries participate in the money pool, in amounts ranging from $250 million for each of NSP-Minnesota and PSCo, to $100 million for SPS and $100 million for NSP-Wisconsin to borrow only from NSP-Minnesota. NSP-Wisconsin is not authorized and does not participate in the money pool.
10. Share-Based Compensation
Stock Options - Xcel Energy has incentive compensation plans under which stock options and other performance incentives are awarded to key employees. Xcel Energy has not granted stock options since December 2001. The weighted average number of common and potentially dilutive shares outstanding used to calculate Xcel Energy's diluted earnings per share include the dilutive effect of stock options and other stock awards based on the treasury stock method. The options normally have a term of 10 years and generally become exercisable from three to five years after grant date or upon specified circumstances.
Activity in stock options was as follows for the years ended Dec. 31:
The total market value of stock options exercised and the total intrinsic value of options exercised were as follows for the years ended Dec. 31:
(a)Intrinsic value is calculated as market price at exercise date less the option exercise price. Restricted Stock - Certain employees may elect to receive shares of common or restricted stock under the Xcel Energy Executive Annual Incentive Award Plan. Restricted stock vests and settles in equal annual installments over a three-year period. Xcel Energy reinvests dividends on the restricted stock it holds while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. If the restricted shares are forfeited, the employee is not entitled to the dividends on those shares. Restricted stock has a fair value equal to the market trading price of Xcel Energy's stock at the grant date.
Xcel Energy granted shares of restricted stock for the years ended Dec. 31 as follows:
A summary of the status of nonvested restricted stock as of Dec. 31, 2009, and changes for the year then ended, are as follows:
Restricted Stock Units (RSUs) - Xcel Energy's Board of Directors has granted RSUs under the Xcel Energy Omnibus Incentive Plan approved by the shareholders in 2000 and under the Xcel Energy 2005 Omnibus Incentive Plan. Both plans allow the attachment of various performance goals to the RSUs granted. The performance goals may vary by plan year. The restrictions on RSUs will not lapse, even if performance goals have been achieved, until two years after the grant date.
Payout of the RSUs and the lapsing of restrictions on the transfer of units are based on one of two separate performance criteria. A portion of the awarded units, plus associated earned dividend equivalents, will be settled and the restricted period will lapse after Xcel Energy achieves a specified EPS growth (adjusted for COLI for grant years prior to 2008). Additionally, Xcel Energy's annual dividend paid on its common stock must remain at a specified amount per share or greater. EPS growth will be measured annually at the end of each fiscal year. The remaining awarded units, plus associated earned dividend equivalents, will be settled and the restricted period will lapse after the results of environmental performance, measured as a percentage of target performance, meets or exceeds threshold performance. The environmental performance indicators will be measured annually at the end of each fiscal year. If the performance criteria have not been met within four years of the date of grant, all associated units shall be forfeited.
The 2005 environmental RSUs met their target as of Dec. 31, 2006 and were settled in shares in February 2007. In addition, the 2005 RSUs measured on EPS growth and all 2006 RSUs met their targets as of Dec. 31, 2007 and were settled in shares in February 2008. The 2007 environmental RSUs met their target as of Dec. 31, 2009 and were settled in shares in February 2010.
The RSUs granted for the years ended Dec. 31 were as follows:
A summary of the status of nonvested RSUs as of Dec. 31, 2009, and changes for the year then ended, are as follows:
The total fair value of nonvested RSUs as of Dec. 31, 2009 was $25.5 million and the weighted average remaining contractual life was 2.0 years.
There were approximately 41,000 RSUs that vested during the year ended Dec. 31, 2009. The total fair value of RSUs vested during the year ended 2009 was $0.8 million. No RSUs vested during the year ended Dec. 31, 2008. The total fair value of RSUs vested during the year ended 2007 was $14.2 million.
Stock Equivalent Unit Plan - Non-employee members of the Xcel Energy Board of Directors receive annual awards of stock equivalent units, with each unit having a value equal to one share of Xcel Energy common stock. The annual grants are vested as of the date of each member's election to the board of directors; there is no further service or other condition attached to the annual grants after the member has been elected to the board. Additionally, directors may elect to receive their fees in stock equivalent units in lieu of cash, and similarly have no further service or other conditions attached. Dividends on Xcel Energy's common stock are converted to stock equivalent units and granted based on the number of stock equivalent units held by each participant as of the dividend date. The stock equivalent units are payable as a distribution of Xcel Energy's common stock upon a director's termination of service.
The stock equivalent units granted for the years ended Dec. 31 were as follows:
A summary of the stock equivalent unit changes for the year ended Dec. 31, 2009 are as follows:
PSP Awards - Xcel Energy's Board of Directors has granted PSP awards under the Xcel Energy Omnibus Incentive Plan approved by the shareholders in 2000 and under the Xcel Energy 2005 Omnibus Incentive Plan. Both plans allow Xcel Energy to attach various performance goals to the PSP awards granted. The PSP awards have been historically dependent on a single measure of performance, Xcel Energy's TSR measured over a three-year period. Xcel Energy's TSR is compared to the TSR of other companies in the EEI Investor-Owned Electrics index. At the end of the three-year period, potential payouts of the PSP awards range from 0 percent to 200 percent, depending on Xcel Energy's TSR compared to the peer group.
The PSP awards granted for the years ended Dec. 31 were as follows:
The 2007, 2008 and 2009 awards were granted under the Xcel Energy 2005 Omnibus Incentive Plan.
The total settlement amounts of performance awards settled during the years ended Dec. 31 were as follows:
Share-Based Compensation Expense - The vesting of the RSUs is predicated on the achievement of a performance condition, which is the achievement of an earnings per share or environmental measures target. RSU awards are considered to be equity awards, since the plan settlement determination (shares or cash) resides with Xcel Energy and not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. Restricted stock as granted under the Xcel Energy Executive Annual Incentive Award Plan is also considered to be an equity award. The grant date fair value of RSUs and restricted stock is expensed as employees vest in their rights to those awards.
The PSP awards have been historically settled partially in cash, and therefore, do not qualify as an equity award, but rather are accounted for as a liability award. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance conditions, and final expense is based on the market value of the shares on the date the award is settled.
The compensation costs related to share-based awards for the years ended Dec. 31 were as follows:
(a)Compensation costs for share-based payment arrangements is included in other O&M expense in the consolidated statements of income. (b)Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $19.3 million, $18.6 million and $15.2 million for the years ended 2009, 2008 and 2007, respectively. The maximum aggregate number of shares of common stock available for issuance under the Xcel Energy Omnibus Incentive Plan, approved in 2000, is 14.5 million, and 8.3 million shares were approved for issuance under the Xcel Energy 2005 Omnibus Incentive Plan. Under the Executive Annual Incentive Plan approved in 2000, the total number of shares approved for issuance is 1.5 million, and 1.2 million shares were approved for issuance under the Executive Annual Incentive Plan in 2005.
As of Dec. 31, 2009 and 2008, there was approximately $17.9 million and $14.9 million, respectively, of total unrecognized compensation cost related to non-vested share-based compensation awards. Xcel Energy expects to recognize that cost over a weighted-average period of 1.88 years.
The amount of cash used to settle Xcel Energy's PSP awards was $2.6 million and $3.1 million in 2009 and 2008, respectively.
Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended Dec. 31 were as follows:
11. Benefit Plans and Other Postretirement Benefits
Xcel Energy offers various benefit plans to its employees. Approximately 50 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2009:
•NSP-Minnesota had 2,119 and NSP-Wisconsin had 405 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2010. NSP-Minnesota also had an additional 222 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates through September 2010.
•PSCo had 2,124 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014.
•SPS had 795 bargaining employees covered under a collective-bargaining agreement, which expires in October 2011. Effective Jan. 1, 2009, Xcel Energy adopted new guidance on employers' disclosures about pension and postretirement benefit plan assets. The new guidance expands employers' disclosure requirements for benefit plan assets, including investment policies and strategies, major categories of plan assets, and information regarding fair value measurements consistent with the disclosures for entities' recurring fair value measurements prescribed by ASC 820 Fair Value Measurements.
ASC 820 Fair Value Measurements establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels defined by the hierarchy and examples of each level are as follows:
Level 1 - Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as common stocks listed by the New York Stock Exchange.
Level 2 - Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs, such as corporate bonds with pricing based on market interest rate curves and recent trades of similarly rated securities.
Level 3 - Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as asset and mortgage backed securities, for which subjective risk-based adjustments to estimated yield and forecasted prepayments are significant inputs.
Pension Benefits
Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee's average pay and social security benefits. Xcel Energy's policy is to fully fund the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws, into an external trust over time.
Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 8.98 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 and 2007 were below the assumed level of 8.75 percent. Xcel Energy continually reviews its pension assumptions. In 2010, Xcel Energy will use an investment-return assumption of 7.79 percent.
The assets are invested in a portfolio according to Xcel Energy's return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity, however, a higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year.
The following table presents the target pension asset allocations for 2009 and 2008:
In 2009, Xcel Energy engaged J.P. Morgan's Pension Advisory Group to evaluate the allocation of the total assets in the master pension trust, taking into consideration the funded status of each individual pension plan provided by Xcel Energy. The investment strategy employed during 2009 is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan's funded status increases over time. The investment recommendations result in a greater percentage of short-to-intermediate term and long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.
Pension Plan Assets
The following table presents, for each of the fair value hierarchy levels, pension plan assets that are measured at fair value as of Dec. 31, 2009:
The following table presents the changes in Level 3 pension plan assets for the year ended Dec. 31, 2009:
Benefit Obligations - A comparison of the actuarially computed pension-benefit obligation and plan assets, on a combined basis, is presented in the following table:
At Dec. 31, 2009, Xcel Energy's pension plans, in the aggregate, had plan assets of $2.4 billion and projected benefit obligations of $2.8 billion. At Dec. 31, 2008, one of Xcel Energy's pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million and all other Xcel Energy plans in the aggregate had plan assets of $1.9 billion and projected benefit obligations of $2.4 billion.
Cash Flows - Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2007 through 2009 for Xcel Energy's pension plans and are not expected to require cash funding in 2010.
Xcel Energy accelerated its planned 2010 contribution of $100 million based on available liquidity, bringing its total pension contributions to $200 million during 2009.
•Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009, $35 million in 2008 and $35 million in 2007.
•Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $27 million in 2009. No voluntary contributions were made to the plan during 2007 or 2008.
•Pension funding contributions for 2011, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million. Plan Amendments - The decrease of the projected benefit obligation for the plan amendment is due to a change in the average earnings calculation resulting from negotiations with the PSCo Bargaining Pension Plan.
Benefit Costs - The components of net periodic pension cost (credit) are:
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2010 pension cost calculations will be 7.79 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.
Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy's operating cash flows.
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans were approximately $21.9 million in 2009, $17.9 million in 2008 and $21.8 million in 2007.
Postretirement Health Care Benefits
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees.
•The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999.
•Xcel Energy discontinued contributing toward health care benefits for former NCE nonbargaining employees retiring after June 30, 2003.
•Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits.
•Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy. In 1993, Xcel Energy adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.
Regulatory agencies for nearly all of Xcel Energy's retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs. The Colorado jurisdictional postretirement benefit costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for postretirement benefit costs, with regulatory differences fully amortized prior to 1997.
Plan Assets - Certain state agencies that regulate Xcel Energy's utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates and PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its asset portfolio. The assets are invested in a portfolio according to Xcel Energy's return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Investment-return volatility is not considered to be a material factor in postretirement health care costs.
The following table presents, for each of the fair value hierarchy levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2009:
The following table presents the changes in Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2009:
Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:
Effective Dec. 31, 2009, Xcel Energy reduced its initial medical trend assumption from 7.4 percent to 6.8 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is three years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy's retiree medical plan.
A 1-percent change in the assumed health care cost trend rate would have the following effects:
Cash Flows - The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy contributed $62.2 million during 2009 and $55.6 million during 2008 and expects to contribute approximately $45.4 million during 2010.
Plan Amendments - The decrease of the projected benefit obligation for the plan amendment is due to a change in the medical experience rate resulting from negotiations with the PSCo Bargaining Postretirement Health Care Plan.
Benefit Costs - The components of net periodic postretirement benefit costs are:
Projected Benefit Payments
The following table lists Xcel Energy's projected benefit payments for the pension and postretirement benefit plans:
12. Other Income, Net
Other income (expense), net, for the years ended Dec. 31 consisted of the following:
13. Derivative Instruments
Effective Jan. 1, 2009, Xcel Energy adopted new guidance on disclosures about derivative instruments and hedging activities contained in ASC 815 Derivatives and Hedging, which requires additional disclosures regarding why an entity uses derivative instruments, the volume of an entity's derivative activities, the fair value amounts recorded to the consolidated balance sheet for derivatives, the gains and losses on derivative instruments included in the consolidated statement of income or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.
Xcel Energy and its utility subsidiaries enter into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices, as well as variances in forecasted weather. See additional information pertaining to the valuation of derivative instruments in Note 15 to the consolidated financial statements.
Interest Rate Derivatives - Xcel Energy and its utility subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
At Dec. 31, 2009, accumulated OCI related to interest rate derivatives included $1.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.
During the fourth quarter of 2009, Xcel Energy settled a $25 million notional value interest rate swap at SPS. This interest rate swap was not designated as a hedging instrument, as such, gains and losses from changes in the fair value of the interest rate swap were recorded to earnings.
Commodity Derivatives - Xcel Energy's utility subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in their electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale and vehicle fuel.
At Dec. 31, 2009, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2012. Xcel Energy's utility subsidiaries also enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2009 and 2008.
At Dec. 31, 2009, accumulated OCI related to vehicle fuel cash flow hedges included $3.0 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
Additionally, Xcel Energy's utility subsidiaries enter into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving their electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in income, subject to applicable customer margin-sharing mechanisms.
Xcel Energy had no derivative instruments designated as fair value hedges during the period ended Dec. 31, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for the period.
The following table shows the major components of derivative instruments valuation in the consolidated balance sheets:
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, Xcel Energy began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Financial Impact of Qualifying Cash Flow Hedges - The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy's accumulated other comprehensive income, included in the consolidated statements of common stockholders' equity and comprehensive income, is detailed in the following table:
The following table details the fair value of commodity derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:
(a)ASC 815 Derivatives and Hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract. The following table details the impact of derivative activity during the year ended Dec. 31, 2009, on other comprehensive income, regulatory assets and liabilities, and income:
(a)Recorded to interest charges. (b)Recorded to electric operating revenues. Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate. (c)Recorded to electric fuel and purchased power; these derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (d)Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (e)Recorded to other O&M expenses.
At Dec. 31, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 37,932,000 megawatt hours (MwH) of electricity, 57,181,000 MMBtu of natural gas, and 3,580,000 gallons of vehicle fuel. These amounts reflect the gross notional amounts of futures, forwards and FTRs and are not reflective of net positions in the underlying commodities. Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.
Credit Related Contingent Features - Contract provisions of the derivative instruments that the utility subsidiaries enter into may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary is unable to maintain its credit rating. If the credit rating of PSCo at Dec. 31, 2009 were downgraded below investment grade, contracts underlying $0.6 million of derivative instruments in a liability position would have required Xcel Energy to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $3.4 million. At Dec. 31, 2009, there was no collateral posted on these specific contracts.
Certain of the utility subsidiaries' derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary's ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Dec. 31, 2009, Xcel Energy's utility subsidiaries had no collateral posted related to adequate assurance clauses in derivative contracts.
14. Financial Instruments
The estimated Dec. 31 fair values of Xcel Energy's recorded financial instruments are as follows:
The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair value of Xcel Energy's nuclear decommissioning fund is based on published trading data and pricing models, generally using the most observable inputs available for each class of security. The fair values of Xcel Energy's other investments are estimated based on quoted market prices for those or similar investments. The fair values of Xcel Energy's long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.
The fair value estimates presented are based on information available to management as of Dec. 31, 2009 and 2008. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.
Guarantees - Xcel Energy provides guarantees and bond indemnities supporting certain subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy's exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. On Dec. 31, 2009 and 2008, Xcel Energy had issued guarantees of up to $76.4 million and $67.5 million, respectively, with $18.0 million and $18.2 million of known exposure under these guarantees, respectively. In addition, Xcel Energy provides indemnity protection for bonds issued for itself and its subsidiaries. The total amount of bonds with this indemnity outstanding as of Dec. 31, 2009 and 2008, was approximately $29.9 million and $27.9 million, respectively. The total exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the total amount of bonds outstanding.
On Dec. 31, 2009, Xcel Energy had the following amount of guarantees and exposure under these guarantees, including those related to Seren, UE, Quixx and Xcel Energy Argentina, which are components of discontinued operations:
(a)The total exposure of this indemnification cannot be determined. Xcel Energy believes the exposure to be significantly less than the total amount of the outstanding bonds. (b)Nonperformance and/or nonpayment. (c)Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement. (d)Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that that collateral be posted. (e)The debtor becomes the subject of bankruptcy or other insolvency proceedings. (f)Xcel Energy agreed to indemnify an insurance company in connection with surety bonds they may issue or have issued for Utility Engineering up to $80 million. The Xcel Energy indemnification will be triggered only in the event that has failed to meet its obligations to the surety company. (g)See Note 17 to the consolidated financial statements for further discussion of Fru-Con Construction Corporation vs. Utility Engineering et al.
Letters of Credit
Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2009 and 2008, there were $22.2 million and $24.1 million of letters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.
15. Fair Value Measurements
Effective Jan. 1, 2008, Xcel Energy adopted new guidance for recurring fair value measurements contained in ASC 820 Fair Value Measurements and Disclosures which provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value was established by this guidance. The three levels in the hierarchy and examples of each level are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as common stocks listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.
Level 2 - Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
Level 3 - Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of FTRs.
Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty's ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy's own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.
The following tables present, for each of these hierarchy levels, Xcel Energy's assets and liabilities that are measured at fair value on a recurring basis:
The following table presents the changes in Level 3 recurring fair value measurements for the year ended Dec. 31:
Losses on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2009, include $8.2 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2009. Gains on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2008, include $3.7 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2008. Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or deferred as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.
16. Rate Matters
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings - MPUC
Base Rate
NSP-Minnesota Electric Rate Case - In November 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually. This request was later modified to $136 million.
In September 2009, the MPUC voted to approve a rate increase of approximately $91.4 million. As part of its decision, the MPUC approved a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning expenses, effective Jan. 1, 2009. This decision reduced NSP-Minnesota's overall
revenue deficiency by approximately $40 million, while at the same time reducing expense accruals by a corresponding amount. A summary of the key terms is listed below:
The written order was issued Oct. 23, 2009. As of December 2009, NSP-Minnesota recorded a customer refund of approximately $39.7 million to reflect the difference between interim rates that were implemented Jan. 2, 2009 and the amount approved by the MPUC.
NSP-Minnesota Gas Rate Case - In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota gas rates by $16.2 million for 2010, which represents a 2.8 percent overall increase in customer bills. This request is based on a ROE of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million. NSP-Minnesota also requested an additional increase of $3.45 million, for recovery of pension funding costs effective Jan. 1, 2011 to comply with federal law. In December 2009, the MPUC voted to approve an interim rate increase of $11.1 million, subject to refund. These rates went into effect on Jan. 11, 2010. The procedural schedule is listed below and a decision is expected in the fall of 2010.
•Intervenor direct testimony on May 3, 2010;
•NSP-Minnesota rebuttal testimony on June 2, 2010;
•Surrebuttal testimony on June 15, 2010;
•Evidentiary hearings on June 21-25, 2010;
•Initial briefs on July 27, 2010;
•Reply briefs and proposed findings on Aug. 19, 2010; and
•ALJ report on Oct. 1, 2010.
Electric, Purchased Gas and Resource Adjustment Clauses
TCR Rider - The MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases. The MPUC approved a rider request to recover approximately $14 million in 2009. NSP-Minnesota has a request pending seeking recovery of $12.1 million in 2010. The OES recommended disallowance of $1.7 million of plant costs because one project was over budget and also recommended that the Brookings line, which is subject to dispute at the FERC on cost allocation, not be recovered through the rider at this time. The request is pending MPUC action.
RES Rider - The MPUC has approved a rider to recover the costs for utility-owned projects implemented in compliance with the RES. In 2009, the MPUC approved the RES rider request to recover approximately $22 million in 2009. In September 2009, NSP-Minnesota submitted its proposed RES rider, seeking to recover $45.6 million in 2010. The OES expressed concerns because some of the projected costs were slightly higher than the levels included in NSP-Minnesota's certificate filings and requested additional information, which has been provided. The request is pending MPUC action.
MERP Rider - The MPUC authorized NSP-Minnesota to recover costs related to environmental improvement projects amounting to approximately $113.7 million in 2009 through the MERP rider. In December 2009, the MPUC authorized a new rate adjustment, which will recover approximately $116.7 million in 2010.
Mercury Cost Rider - The MPUC has approved mercury control plans for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants. A sorbent injection control system was put into service at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled to be completed in December 2010. Currently, the estimated project costs are approximately $6.6 million for these two units, and the MPUC authorized NSP-Minnesota to collect the 2010 revenue requirement associated with these projects, which is approximately $3.5 million from customers through a mercury rider in 2010. On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost rider. The plan proposes a flexible program of testing and monitoring as new technology emerges and federal regulations change over the next several years. The plan calls for the addition of sorbent injection by the statutory deadline of the end of 2014. The MPCA has six months to review the plan.
SEP Rider - In September 2009, the MPUC approved NSP-Minnesota proposed rider to recover approximately $2.5 million from its electric customers and $0.1 million from its natural gas customers to recover costs related to SEP mandates and a cast iron natural gas pipe replacement project to reduce GHG emissions. The revised SEP rate recovery factors were placed into effect in October 2009.
Energy Innovation Corridor (EIC) Initiative - In December 2009, NSP-Minnesota filed a request with the MPUC for approval of specific projects totaling $15 million including a $2 million deferral request. The EIC initiative will be a first-of-its-kind clean energy and transportation model in an established urban center in the upper Midwest. The 2009 legislation authorized rider cost recovery for MPUC approved projects, including NSP-Minnesota's costs to relocate its facilities along the transportation corridor. Rider cost recovery is also authorized for MPUC approved EIC projects that demonstrate the best energy efficiency management practices and the installation of innovative and sustainable energy technologies and programs for transforming a mature urban center into a national model for the future development of transportation and energy corridors. The EIC initiative will advance critical local, state, regional and federal efforts to invest in energy efficiency, transportation electrification, renewable energy and smart grid technology. MPUC action is pending.
Annual Automatic Adjustment Report for 2007/2008 - In September 2008, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2007 through June 30, 2008. During that time period, $848.5 million in fuel and purchased energy costs, including $258.8 million of MISO charges, were recovered from Minnesota electric customers through the FCA. In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the PGA. In February 2010, the MPUC voted to accept the 2008 natural gas annual automatic adjustment report.
Annual Automatic Adjustment Report for 2008/2009 - In September 2009, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2008 through June 30, 2009. During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA. In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered through the PGA. Comments are due in May 2010 on NSP-Minnesota's 2008/2009 electric and natural gas annual automatic adjustment reports. The request is pending MPUC action.
Conservation Incentive Filing - In July 2009, NSP-Minnesota filed its proposed incentive plan for achieving significantly higher DSM goals. The incentive would allow for sharing of savings of up to 15 percent of the net present value of benefits, depending on the level of savings achieved. In December 2009, the MPUC approved the proposed shared savings model. The plan would allow NSP-Minnesota to earn a higher incentive than under the previous method if it achieves the higher goals established by the OES. The amount of the incentive increases to the extent that NSP-Minnesota cost-effectively exceeds the goal. A written order was issued in January 2010.
Gas Meter Module Failures - Approximately 8,700 customers in the St. Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in the Fargo, N.D. area were under billed for a period of time during the 2007-2008 heating season due to the failure of the automated meter reading (AMR) module installed on their natural gas meters. While the modules failed to register usage, the meters continued to function.
Pursuant to the NDPSC-approved plan, which provided customers with a $50 service quality credit for each customer experiencing a module failure, NSP-Minnesota began implementing the service quality credits and the rebilling of remaining North Dakota customers in June 2009. In total, NSP-Minnesota rebilled North Dakota customers approximately $1.5 million for the estimated gas usage during the module failure period.
In July 2009, NSP-Minnesota filed with the MPUC a withdrawal of its request to rebill Minnesota customers experiencing a module failure, which the MPUC approved in October 2009. NSP-Minnesota completed the customer refunds in January 2010. In November 2009, NSP-Minnesota completed its dispute resolution with its provider of the AMR modules and meter reading services, and filed a summary of the resolution and proposed disposition of any proceeds with the MPUC. MPUC action is pending. NSP-Minnesota has determined that a number of AMR modules designed for commercial customers are defective and as a result broadened its efforts to evaluate the performance of both gas and electric AMR modules.
Annual Review of Remaining Lives - In February 2009, NSP-Minnesota filed a petition with the MPUC requesting an increase in proposed service lives, salvage rates and resulting depreciation rates for its electric and gas production facilities and a depreciation study for other gas and electric assets, effective Jan 1, 2009. In addition, the OES recommended a 10-year lengthening of depreciation life of the Prairie Island nuclear plant. In July 2009, the MPUC approved the proposed service lives, salvage rates, and resulting depreciation rates effective Jan. 1, 2009, for plant in service, with the exception of the Prairie Island nuclear plant. In the NSP-Minnesota electric rate case, the MPUC extended the depreciation life of the Prairie Island nuclear plant by 10 years beyond the current license life in light of NSP-Minnesota's application to extend the life of its nuclear plants by 20 years.
Nuclear Decommissioning Expenses - In June 2009, the MPUC issued its order in its review of NSP-Minnesota's 2009 nuclear plant decommissioning accruals. The order extended the decommissioning life for the Prairie Island nuclear plant by 10 years. The order reduced the amount of future nuclear decommissioning expenses that must be collected from customers from $32 million to zero, effective Jan. 1, 2009.
In August 2009, NSP-Minnesota filed a proposal with the MPUC to provide one-time refunds to return to customers their contributions of $22.8 million made to the external escrow decommissioning fund for the Monticello nuclear plant, which the MPUC approved in November 2009. NSP-Minnesota began refunding the excess escrow to customers in February 2010.
Pending and Recently Concluded Regulatory Proceedings - NDPSC and SDPUC
South Dakota Electric Rate Case - In June 2009, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $18.6 million annually, or 12.7 percent. This proposed increase includes approximately $2.9 million in revenues currently recovered through automatic recovery mechanisms. Thus, the requested increase, net of current automatic recovery mechanisms, is approximately $15.7 million or 10.7 percent. The request is based on a 2008 historic test year adjusted for known and measurable changes in rate base and O&M expenses, an electric rate base of $282 million, a requested ROE of 11.25 percent, and an equity ratio of 51.63 percent.
On Jan. 5, 2010, the South Dakota Commission approved a settlement agreement, which increases electric base rates by $10.9 million. The primary difference between the approved rate increase and requested amount was due to a lower ROE and the use of a 20-year life for the Prairie Island nuclear plant, which reduced the revenue deficiency and expense accruals by a corresponding amount. New rates were effective on Jan. 18, 2010.
Pending and Recently Concluded Regulatory Proceedings - FERC
Revenue Sufficiency Guarantee (RSG) Charges - The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy. A proposal in 2005 by MISO to refine the RSG charge initiated protracted proceedings. In the subsequent compliance proceeding, the FERC has issued numerous orders, attempting to refine and clarify the RSG charge. With the issuance of these orders, the FERC has directed certain refunds to market participants, but has subsequently refined or waived various refund requirements. The FERC granted rehearing in part of certain earlier orders directing refunds to correct a rate mismatch in the RSG charge.
In August 2007, numerous parties filed complaints against MISO, arguing that the allocation of the RSG charge (only to certain market participants actually withdrawing energy) was unjust, unreasonable, and unduly discriminatory. After protracted proceedings, the FERC found in November 2008 that the RSG charge was unjust and unreasonable, and directed refunds. In May 2009, FERC granted rehearing in part regarding the applicability of refunds for the RSG charges. Specifically, the FERC determined that the refund-effective date is November 2008, the date of the FERC order determining that the allocation to market participants of the RSG charges was unjust and unreasonable.
The FERC directed MISO to implement an interim RSG cost allocation to be effective starting in August 2007. The FERC further directed MISO to submit a complete and final proposal, to be implemented on a prospective basis after
the commencement of the MISO's ASMs in January 2009. In February 2009, MISO submitted a filing to implement the new RSG rate design; however, the FERC has not yet rendered a final decision to implement the new rate design. In August 2009, the FERC issued an order in which it invalidated numerous exemptions to the RSG that had previously been utilized by MISO through its business practice manuals. Several parties have sought rehearing of the order and a final FERC decision is still pending.
Xcel Energy is a party to each of the relevant RSG-related proceedings. Each of the relevant RSG-related orders has been the subject of requests for rehearing at the FERC and petitions for review filed at the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The separate RSG proceedings have proceeded in parallel at the FERC, and the most recent orders are subject to pending requests for rehearing. The D.C. Circuit proceedings are being held in abeyance pending final action in the FERC proceedings.
FERC Section 5 Rate Cases for Interstate Gas Pipelines - In November 2009, the FERC approved orders initiating rate investigations under Section 5 of the Natural Gas Act (NGA) against Northern Natural Gas Company (NNG) and Great Lakes Gas Transmission Company (GLGT). NSP-Minnesota and NSP-Wisconsin are together the largest customer on NNG, holding $41 million per year of maximum rate storage and transportation contracts.
According to the FERC orders, FERC staff concluded, based on a review of the financial information filed with the FERC by the pipelines, that each of the pipelines are substantially over-recovering their cost of service and earning excessive ROEs. The orders require the pipelines to file full cost and revenue studies, and the matters were set for hearing before an ALJ on an expedited basis. If the FERC orders the pipelines to reduce their transportation and storage rates, the rate reductions and any associated refunds would be reflected in the purchased gas and electric fuel cost adjustment mechanisms of the Xcel Energy utility subsidiaries.
Xcel Energy has filed an intervention as part of a group of similarly-situated GLGT shippers in the GLGT Section 5 case, and filed to intervene individually in the NNG Section 5 rate case. The FERC ALJ conducted a pre-hearing conference on Jan. 12, 2010 and established the procedural schedule for the proceedings. If fully litigated, the Section 5 rate cases can be expected to go to hearings before the ALJ beginning Aug. 2, 2010. An initial decision must be issued by Nov. 11, 2010.
NSP-Wisconsin
Pending and Recently Concluded Regulatory Proceedings - PSCW
Base Rate
2008 Electric Rate Case - Nuclear Decommissioning Expenses - In January 2008, the PSCW issued the final order in NSP-Wisconsin's 2008 test year rate case. The PSCW's final order included recovery of $8.7 million of annual nuclear decommissioning expenses, subject to refund, in anticipation of potential decreases in NSP-Minnesota's decommissioning expenses.
In June 2009, the MPUC issued the final order in its review of NSP-Minnesota's 2009 nuclear plant decommissioning accrual, and as a result of that order, the Wisconsin retail jurisdiction's share of annual nuclear decommissioning expenses decreased to approximately $1.4 million, effective January 2009. The PSCW reviewed NSP-Wisconsin's nuclear decommissioning expenses in the context of the company's 2010 electric rate case, and reduced the NSP-Wisconsin's 2010 revenue requirements pursuant to the refund provision in the 2008 rate case order.
The June 2009 MPUC order also directed NSP-Minnesota to return to customers their contributions made to the external escrow decommissioning fund for the Monticello nuclear plant. In NSP-Wisconsin's 2010 electric rate case the PSCW decided that NSP-Wisconsin should return the Wisconsin retail jurisdiction's share of these funds, with interest to customers in the next rate case. NSP-Wisconsin's share of these funds is approximately $5.9 million as of Dec. 31, 2009.
2010 Electric and Natural Gas Rate Case - In June 2009, NSP-Wisconsin filed an electric and gas rate case in Wisconsin seeking an increase in retail electric rates of $30.4 million, or 5.7 percent, and proposed no change in natural gas rates. The request was based on an ROE of 10.75 percent, an equity ratio of 53.12 percent, an electric rate base of $644 million, a gas rate base of $81 million and a 2010 forecasted test year. The request was comprised of a base rate increase of $45.1 million offset by projected fuel decreases of $14.7 million.
In December 2009, the PSCW approved an electric rate increase of approximately $6.4 million or 1.2 percent and no change in gas rates, based on a 10.4 percent ROE and a 52.30 percent equity ratio. The PSCW ordered
NSP-Wisconsin to apply $6.4 million of the estimated 2009 fuel refund obligation to offset the rate increase. Lastly, the PSCW approved NSP-Wisconsin's request for a limited rate case reopener in 2011 to update certain costs that are billed to NSP-Wisconsin through the interchange agreement with NSP-Minnesota.
The base non-fuel adjustments made by the PSCW include: (1) adjustments to the ROE and equity ratio as discussed above; (2) reduced interchange agreement fixed charge billings; and (3) a disallowance of certain employee compensation expenses. In addition, the PSCW adjustments include a $9.1 million reduction for Prairie Island nuclear plant decommissioning and depreciation expense as a result of the 10-year life extension approved by the MPUC earlier this year. The PSCW approved NSP-Wisconsin's request to discontinue the practice of reducing rate base and common equity to account for appropriated retained earnings associated with certain hydro licenses.
A summary of the PSCW's adjustments is listed below:
Other
2009 Electric Fuel Cost Recovery - NSP-Wisconsin's actual fuel and purchased power costs for 2009 were less than the amount authorized in rates, primarily due to lower load and lower market prices for fuel and purchased power. In April 2009, the PSCW determined fuel costs were outside the established variance ranges and set NSP-Wisconsin's electric rates subject to refund with interest, pending a full review of 2009 fuel costs.
The PSCW has not yet completed its review of NSP-Wisconsin's 2009 fuel costs. However, based on actual 2009 fuel costs, NSP-Wisconsin has established a liability of $18.5 million to reflect its expected 2009 fuel refund obligation. As noted above, the PSCW ordered NSP-Wisconsin to apply $6.4 million of the 2009 fuel refund obligation to offset the 2010 electric rate increase. NSP-Wisconsin filed an application with the PSCW in February 2010, requesting authorization to immediately refund the remainder of its 2009 fuel refund obligation to customers before the PSCW completes its review of actual 2009 fuel costs. If the PSCW review determines an additional refund is owed, the balance would be deferred and returned to customers in NSP-Wisconsin's next rate filing.
PSCo
Pending and Recently Concluded Regulatory Proceedings - CPUC
Base Rate
PSCo 2009 Electric Rate Case - In November 2008, PSCo filed a request with the CPUC to increase Colorado electric rates by $174.7 million annually, or approximately 7.4 percent. The rate filing was based on a 2009 forecast test year, an electric rate base of $4.2 billion, a requested ROE of 11.0 percent and an equity ratio of 58.08 percent. PSCo's request included a return of approximately $40 million for CWIP associated with incremental expenditures on the Comanche Unit 3 since Jan. 1, 2007. PSCo does not record AFUDC income for the months this return is actually received from customers.
In March 2009, PSCo filed rebuttal testimony and revised its rate increase request to $159.3 million to reflect updated data.
In May 2009, the CPUC approved a blackbox settlement agreement which provided for an overall $112.2 million increase in base rates. The settlement provides that incremental CWIP not included in existing rates for the Comanche Unit 3 be removed from rate base and that PSCo would be allowed to continue to record AFUDC income on this balance until the Comanche Unit 3 is placed into service. New rates went into effect on July 1, 2009.
PSCo 2010 Electric Rate Case - In May 2009, PSCo filed with the CPUC a request to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010. The request was based on a 2010 forecast test year, an 11.25 percent ROE, a rate base of $4.4 billion and an equity ratio of 58.05 percent, In October 2009, PSCo filed rebuttal testimony and revised the requested rate increase to $177.4 million.
In November 2009, PSCo reached a settlement agreement with certain intervenors. The settlement included an electric rate increase of approximately $136 million, effective Jan. 1, 2010. The settlement was based on a 10.5 percent ROE and reflects PSCo's actual capital structure. The settlement was based on an historic test year, adjusted for 2010 known and measurable changes related to plant investment as well as certain operating costs.
In December 2009, the CPUC approved a rate increase of approximately $128.3 million. The difference between the settlement rate increase and the approved amount was primarily related to adjustments related to rate base for non-major projects and an adjustment to interest on long-term debt.
In December 2009, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo's proposal to phase in the approved electric rate increase to reflect the actual cost of service. This decision is not expected to have a material impact on PSCo or Xcel Energy's financial results. Under the plan the following increases will be implemented:
•A rate increase of $67 million was implemented on Jan. 1, 2010. The adjustments to the rate increase, as a result of the delay of the in-service date of Comanche Unit 3, include reduced O&M, property taxes, the impact of a delay in changes to jurisdictional allocators and depreciation expenses.
•Base rates will increase to $121 million, once Comanche Unit 3 goes into service (currently expected by the end of the first quarter of 2010).
•Finally, base rates will increase to $128.3 million on Jan. 1, 2011 to reflect 2011 property taxes. Several parties, including the Office of Consumer Counsel, have filed motions for reconsideration. The CPUC has denied those requests that would change the initial order approving the rate increase, with the exception of PSCo's request to not include long-term debt interest in the working capital calculation. The CPUC will reconsider PSCo's request after parties have filed additional comments. A written order is pending.
Unreasonable Rates for Natural Gas Formal Complaint - In July 2009, the trial advocacy staff of the CPUC proposed a formal draft complaint against PSCo for unjust and unreasonable rates for natural gas service associated with earnings in excess of PSCo's authorized return that occurred in 2008. In January 2010, the CPUC opened a proceeding and assigned this matter to an ALJ.
The procedural schedule in the case has been set as follows:
•Direct testimony of CPUC staff on May 10, 2009;
•PSCo answer testimony on June 28, 2010;
•Staff rebuttal testimony on July 19, 2010;
•Surrebuttal testimony on Aug. 9, 2010; and
•Hearings on Aug. 23 - 27, 2010. TCA Rider - PSCo filed its annual update to the TCA rider in November 2008, and new rates went into effect on Jan. 1, 2009, to recover approximately $18.0 million on an annual basis until the rates in the 2009 rate case take effect. Coincident with the implementation of new electric rates on July 1, 2009, approximately $16.0 million from the TCA rider were included in base rates with a corresponding reduction in the TCA rider.
Renewable Energy Credit (REC) Sharing Settlement - In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California. PSCo's request sought 45 percent of the margins on these specific transactions for both the customers and PSCo with the remaining ten percent being used to fund a program to develop carbon offset projects and expertise. On Jan. 20, 2010, PSCo, the Office of Consumer Council, the CPUC staff, the Colorado governor's energy office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that 10 percent of margins will go to carbon offsets, 40 percent of the first $10 million in margins, 35 percent of the next $20 million and 30 percent of all remaining margins will go to PSCo with all remaining margins going to Colorado retail customers as a credit toward renewable energy projects. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone renewable energy credits without energy would be credited 100 percent to customers. It is expected that PSCo will file an application by Aug. 31, 2010 for future treatment of margins from transactions for RECs bundled with energy after the end of the pilot program. On Feb. 18, 2010, the CPUC approved the settlement.
Pending and Recently Concluded Regulatory Proceedings - FERC
Pacific Northwest FERC Refund Proceeding - In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC's orders in this proceeding with the U. S. Court of Appeals for the Ninth Circuit.
In an order issued in August 2007, the Court of Appeals remanded the proceeding back to the FERC. The Court of Appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued. The FERC has yet to act on this order on remand; currently, certain motions concerning procedures on remand are pending before the FERC.
Wholesale Rate Case - In 2009, PSCo proposed to increase Colorado wholesale rates by $30 million based on a 12.5 percent ROE, a 58 percent equity ratio and an electric production rate base of $315 million. PSCo has requested that FERC suspend action on the filing to allow time for settlement negotiations. Settlement discussions with PSCo's wholesale customers are continuing. PSCo expects rates subject to refund to go into effect in the second quarter of 2010.
SPS
Pending and Recently Concluded Regulatory Proceedings - PUCT
Base Rate
Texas Retail Base Rate Case - In June 2008, SPS filed a rate case with the PUCT seeking an annual rate increase of approximately $61.3 million, or approximately 5.9 percent. Base revenues are proposed to increase by $94.4 million, while fuel and purchased power revenue would decline by $33.1 million, primarily due to fuel savings from the Lea Power Partners (LPP) purchase power agreement. The rate filing was based on a 2007 test year adjusted for known and measurable changes, a requested ROE of 11.25 percent, an electric rate base of $989.4 million and an equity ratio of 51.0 percent. Interim rates of $18 million for costs associated with the LPP power purchase agreement went into effect in September 2008.
In January 2009, a settlement agreement was reached with various intervenors, which provided for a base rate increase of $57.4 million, a reduced depreciation expense of $5.6 million, allowed SPS to implement the transmission rider in 2009 and precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010. In January 2009, an ALJ approved interim rates effective February 2009. On June 2, 2009, the PUCT issued its order approving the settlement.
John Deere Wind Complaint - In June 2007, several John Deere Wind Energy subsidiaries (JD Wind) filed a complaint against SPS disputing SPS' payments for energy produced from the JD Wind projects. SPS responded that the payments to JD Wind are appropriate and in accordance with SPS' filed tariffs. In March 2009, the ALJ recommended that SPS payment methodology to JD Wind is proper and that JD Wind's complaint be denied.
In May 2009 the PUCT issued a final order denying JD Wind's request for relief against SPS. In June 2009, JD Wind filed a petition for review of the final order in Texas District Court. In July 2009, the PUCT filed an answer to JD Wind's petition in Texas District Court in which the PUCT denied all allegations contained in the JD Wind petition. The case is pending in Texas District Court.
In November 2009, the FERC declined to rule on a request to overturn the PUCT decision by JD Wind but did issue a declaratory order stating that the PUCT's order denying JD Wind's complaint is not consistent with the FERC's regulations. In December 2009, SPS requested that the FERC reconsider its November 2009 declaratory order. In December 2009, JD Wind filed a complaint against the PUCT in U. S. District Court seeking federal law enforcement, including declaratory and injunctive relief to enforce and give proper effect to the PURPA. JD Wind
requests a declaration that the PUCT's order does not implement PURPA and FERC PURPA rules and is preempted by federal law. The complaint also requests that the PUCT be required to revise its order and be enjoined from enforcing its current order. SPS intends to intervene in this case and defend the PUCT's order. On Jan. 28, 2010, JD Wind filed a damage suit against SPS in Texas state district court to toll the statute of limitations while the above cases are being decided.
Texas Jurisdictional Fuel Allocation Methodology - In May 2009, SPS filed an application to revise the calculation of Texas retail jurisdictional fuel and purchased power expense, effective in January 2008. SPS has determined that its current method results in a material amount of unrecovered fuel and purchased power expense. The application seeks approval for a revised methodology, which matches the fuel and purchased power expenses in a month with the fuel factor revenue received from each kilowatt hour used that month.
In November 2009, the PUCT issued a final order approving a unanimous settlement that would allow for the change in the calculation of deferred fuel consistent with the approach proposed by SPS. The estimated impact is expected to result in an approximate $6.5 million increase to fuel and purchased power expenses for the Texas retail jurisdiction for Jan. 1, 2008 to Dec. 31, 2009. SPS has agreed to reduce the new allocated portion by $3 million subsequent to adopting the new methodology going forward.
Texas Transmission Cost Recovery Factor (TCRF) - In 2007, the PUCT implemented rules allowing utilities to request a TCRF in between rate cases for recovery of new transmission investment costs. In June 2009, SPS filed a request to implement a TCRF with proposed revenues of $7.4 million annually. This is SPS' first filing under that rule.
In November 2009, the parties filed a unanimous stipulation, which allows SPS to recover $4.5 million annually, and the ALJ issued an order approving interim TCRF rates beginning Jan. 1, 2010. In January 2010, the PUCT approved the unanimous stipulation.
Pending and Recently Concluded Regulatory Proceedings - NMPRC
Base Rate
2008 New Mexico Retail Electric Rate Case - In December 2008, SPS filed with the NMPRC a request to increase electric rates in New Mexico by approximately $24.6 million, or 6.2 percent. The request was based on a historic test year (split year based on the year ending June 30, 2008), an electric rate base of $321 million, and an equity ratio of 50.0 percent and a requested ROE of 12.0 percent. SPS also requested interim rates of $7.6 million per year to recover capacity costs of the Lea Power facility, which became operational in September 2008.
In March 2009, the NMPRC approved a partial stipulated settlement between the parties that allows SPS to recover approximately $5.7 million of interim rates, effective May 1, 2009, through an LPP cost rider until the final rates from the remainder of the case are effective.
In July 2009, the NMPRC issued an order approving the stipulation settlement agreement. Under the stipulation, SPS receives a base rate increase of $14.2 million, effective July 1, 2009. SPS has agreed that Dec. 1, 2010 is the earliest date it will file its next base rate case, subject to a force majeure provision triggered by additional environmental compliance costs. SPS implemented the new rates on July 15, 2009.
Pending and Recently Concluded Regulatory Proceedings - FERC
Wholesale Rate Complaints - In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer's Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS' rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the Complaint). Among other things, the complainants asserted that SPS had inappropriately allocated average fuel and purchased power costs to other wholesale customers, effectively raising the fuel cost charges to the complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS' largest retail customer, intervened in the proceeding.
Golden Spread Complaint Settlement - In December 2007, SPS reached a settlement with Golden Spread (which now includes Lyntegar Electric) and Occidental regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding. In April 2008, the FERC approved the settlement, which resolved all issues pertaining to Golden Spread that were the subject of the Complaint; implemented a formula rate and extended the
term of its partial requirements sale to Golden Spread beginning 2012 at 500 MW and ramping down to 200 MW for the two years prior to the end of the term in 2019. The settlement made the extended purchase contingent on certain state approvals. Golden Spread agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed sale and SPS agreed to contingent payments ranging from $3 million to a maximum of $12 million, payable in 2012, in the event that there is an adverse cost assignment decision or a failure to obtain state approvals. Request for approvals are currently pending before the NMPRC and the PUCT, and SPS anticipates actions by the state commissions during the first quarter of 2010.
New Mexico Cooperatives' Complaint Settlement - In January 2010, SPS reached a settlement with Farmers' Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, all wholesale customers of SPS located in New Mexico, and Occidental regarding the same base rate and fuel issues raised in the complaint described above. The settlement with these wholesale customers is now pending approval by the FERC. The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended term of its requirements sale to the four wholesale customers. The four wholesale customers must reduce their system average cost power purchases by 90 to 100 MW in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates on May 31, 2026. The settlement made the replacement contract contingent on certain state approvals. In the event all regulatory approvals are not received, the Settlement includes a one time total contingent payment of $12 million by SPS to these wholesale customers. These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale.
Order on Wholesale Rate Complaints - In April 2008, the FERC issued its Order on the Complaint applied to the remaining non-settling parties. The Order addresses base rate issues for the period from Jan. 1, 2005 through June 30, 2006, for SPS' full requirements customers who pay traditional cost-based rates and requires certain refunds.
Several parties, including SPS, filed requests for rehearing on the order. These requests are pending before the FERC. In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million. Several wholesale customers have protested the calculations. Once the final refund amounts are approved by the FERC, interest will be added to the refund due to the remaining non-settled customers. As of Dec. 31, 2009, SPS has accrued an amount sufficient to cover the estimated refund obligation.
SPS 2008 Wholesale Rate Case - In March 2008, SPS filed a wholesale rate case seeking an annual revenue increase of $14.9 million or an overall 5.14 percent increase, based on 12.20 percent requested ROE. In April 2009, the parties reached a settlement in which SPS will receive an annual revenue increase of approximately $9.6 million or an increase of 3.3 percent. The FERC issued an order approving the uncontested settlement in September 2009.
SPS 2008 Transmission Formula Rate Case - In December 2007, Xcel Energy submitted an application to implement a transmission formula rate for the SPS zone of the Xcel Energy OATT. The changed rates affect all wholesale transmission service customers using the SPS transmission network under either the Xcel Energy OATT or the SPP Regional OATT.
In September 2009, Xcel Energy filed an uncontested offer of settlement with the FERC which resolves all issues in the proceeding with the exception of the ratemaking and rate design treatment for certain radial lines under the SPP OATT. The parties are still formulating the methodology for designating direct assignment of radial transmission lines to wholesale and retail customers pursuant to the SPP OATT.
The settlement provides for a formula rate using a fully forecasted test year effective Jan. 1, 2009, with a stated ROE of 11.27 percent (including the 50 basis point adder for SPP RTO participation). The settlement will result in approximately $0.8 million in additional revenues for 2008 and 2009 in aggregate and will allow SPS to update its transmission rates annually for predicted costs and loads, subject to an annual true-up. In October 2009, SPS announced the 2010 costs and charges pursuant to the formula rate and are expected to provide $2.7 million in additional revenue, subject to true-up. The settlement was approved by the FERC in December 2009, and SPS and SPP are now effectuating the settlement.
17. Commitments and Contingent Liabilities
Commitments
Capital Commitments - As of Dec. 31, 2009, the estimated cost of capital requirements of Xcel Energy and its subsidiaries and the capital expenditure programs is approximately $2.2 billion in 2010, $2.3 billion in 2011 and $2.1 billion in 2012. Xcel Energy's capital forecast includes the following major projects:
Nuclear Capacity Increases and Life Extension - NSP-Minnesota is seeking a 20-year license renewal for the Monticello and Prairie Island nuclear plants. A renewed operating license was approved and issued for Monticello by the NRC in November 2006 licensing the plant to operate until 2030, and the MPUC order approving the spent fuel storage capacity needed to support plant operations until 2030 went into effect in June 2007. The application to renew Prairie Island's operating licenses was submitted to the NRC in April 2008 and the application for a CON for additional spent fuel storage capacity to support 20 additional years of plant operation was approved by the MPUC in December 2009. Final state and federal approvals are expected in 2010.
NSP-Minnesota is pursuing capacity increases of Monticello and Prairie Island that will total approximately 235 MW, to be implemented, if approved, between 2010 and 2015. The life extension and capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2's original steam generators, currently planned during the refueling outage in 2013. Total capital investment for these activities is estimated to be over $1 billion between 2010 and 2015. NSP-Minnesota submitted the CON and site permit applications for Monticello's power uprate in the first quarter of 2008 and the CON and site permit applications for Prairie Island's power uprate in the second quarter of 2008. The MPUC approved the Monticello power uprate CON and site permit in December 2008 and the Prairie Island power uprate CON and site permit in December 2009.
Wind Generation - NSP-Minnesota is investing approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project. These projects are expected to be operational by the end of 2010 and 2011, respectively. NSP-Minnesota has received regulatory approval for the projects, and has requested recovery of eligible costs beginning in 2010.
CapX 2020 - In 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified several groups of transmission projects that proposed to be complete by 2020. Group 1 project investments are expected to total approximately $1.7 billion, with major construction targeted to begin in 2010 and ending three to five years later. Xcel Energy's investment is expected to be approximately $900 million depending on the route and configuration approved by the MPUC and the PSCW. Approximately 75 percent of the 2010 capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota TCR tariff rider mechanism authorized by Minnesota legislation, as well as a similar TCR mechanism passed in South Dakota. Cost-recovery by NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy's long-term energy needs. In addition, Xcel Energy's ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.
Fuel Contracts - Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2010 and 2040. In total, Xcel Energy is committed to the minimum purchase of approximately $2.3 billion of coal, $598.3 million of nuclear fuel and $4.4 billion of natural gas, including $3.3 billion of natural gas storage and transportation, or to make payments in lieu thereof, under these contracts. In addition, Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy's risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.
Purchased Power Agreements - The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota,
PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indices. However, the effects of price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.
At Dec. 31, 2009, the estimated future payments for capacity, accounted for as executory contracts, that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows:
Variable Interest Entities - Xcel Energy has certain long-term purchased power agreements with independent power producing entities that contain tolling arrangements under which Xcel Energy procures the fuel required to produce the energy purchased. Xcel Energy enters into these agreements to meet electric system capacity and energy needs. Xcel Energy is not subject to risk of loss from the operations of these entities. Xcel Energy has evaluated such entities for possible consolidation and has concluded that these entities are not required to be consolidated in Xcel Energy's consolidated financial statements. The significant qualitative factors considered evaluating purchase power agreements under ASC 810 Consolidation include length and terms of the contract and operational, fuel price and financing risk. When necessary, a quantitative analysis demonstrated that Xcel Energy would absorb less than 50 percent of the expected gains or losses. Significant assumptions used in the quantitative analysis by Xcel Energy, to determine the primary beneficiary, include an inflation rate equal to the Bureau of Labor Statistics 10 year average, estimated future fuel and electricity prices, future operating cash flows, an incremental borrowing rate, the expected life of the plant and a debt to equity financing ratio.
Leases - Xcel Energy and its subsidiaries lease a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities acquired under capital leases are recorded at the lower of fair market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators.
In 1999, WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. In 2009, WYCO's Totem gas storage facilities were placed in service. WYCO leases the facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under a service arrangement that commenced on July 1, 2009.
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease in accordance with the authoritative guidance on lease accounting. As a result, PSCo has a $141.1 million capital lease obligation recorded for the arrangement as of Dec. 31, 2009, 50% of which is eliminated in Xcel Energy's consolidated balance sheet along with an equal amount of Xcel Energy's equity investment in WYCO. WYCO is expected to incur approximately $14 million of additional construction costs, 50 percent of which will be paid by Xcel Energy, to finalize construction and make Totem operational at full storage capacity.
Following is a summary of property held under capital leases:
The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total rental expense under operating lease obligations for
Xcel Energy and its subsidiaries was approximately $209.5, $176.9, and $105.2 million for 2009, 2008, and 2007, respectively. Included in total rental expense were purchase power agreement payments of $171.3 million, $130.3 million, and $55.7 million in 2009, 2008 and 2007, respectively.
Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with ASC 840 Leases. Future commitments under operating and capital leases for continuing operations are:
(a)Amounts do not include purchase power agreements accounted for as executory contracts. (b)Purchase power agreement operating leases contractually expire through 2033. Technology Agreements - Xcel Energy has a contract that extends through 2015 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at Xcel Energy's option, although there are financial penalties for early termination. In 2009, Xcel Energy paid IBM $96.6 million under the contract and $1.2 million for other project business. The contract also has a committed minimum payment each year from 2010 through September 2015.
In August 2008, Xcel Energy entered into a contract with Accenture for information technology services, which began on Feb. 1, 2009 and extends through 2014. The contract is cancelable at Xcel Energy's option, although there are financial penalties for early termination. In 2009, Xcel Energy paid Accenture $11.3 million under the contract and $1.6 million for other project business. The contract also has a committed minimum payment each year from 2010 through 2014.
Payments under these obligations are as follows:
Environmental Contingencies
Xcel Energy and its subsidiaries have been, or are currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other PRPs and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense.
Site Remediation - Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of its subsidiaries or other parties have caused environmental contamination. Environmental contingencies could arise from
various situations, including sites of former MGPs operated by Xcel Energy subsidiaries, predecessors, or other entities; and third-party sites, such as landfills, for which Xcel Energy is alleged to be a PRP that sent hazardous materials and wastes. At Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $102.1 million, of which $6.3 million was considered to be a current liability.
MGP Sites
Ashland MGP Site - NSP-Wisconsin has been named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (Ashland site) includes property owned by NSP-Wisconsin, which was previously an MGP facility and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior's Chequamegon Bay adjoining the park.
In September 2002, the Ashland site was placed on the National Priorities List. A final determination of the scope and cost of the remediation of the Ashland site is not currently expected until 2010. In October 2004, the state of Wisconsin filed a lawsuit in Wisconsin state court for reimbursement of past oversight costs incurred at the Ashland site between 1994 and March 2003 in the approximate amount of $1.4 million. The state also alleged a claim for forfeitures and interest. This litigation was resolved in the first quarter of 2009, and all costs paid to the state are expected to be recoverable in rates.
In 2009, the EPA issued its proposed remedial action plan (PRAP). The estimated remediation costs for the cleanup proposed by the EPA in the PRAP range between $94.4 million and $112.8 million. NSP-Wisconsin submitted comments to EPA in response to the PRAP, and indicated that it had serious concerns about the cleanup approach proposed by the EPA. It is expected that the EPA will select a final remedial action plan sometime in early 2010.
NSP-Wisconsin's potential liability, the actual cost of remediating the Ashland site and the time frame over which the amounts may be paid out are not determinable until the EPA selects a remediation strategy for the entire site and determines NSP-Wisconsin's level of responsibility. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site. NSP-Wisconsin has recorded a liability of $97.5 million based upon the minimum of the range of remediation costs established by the PRAP, together with estimated outside legal, consultant and remedial design costs. NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.
In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers.
In addition to potential liability for remediation, NSP-Wisconsin may also have potential liability for natural resource damages at the Ashland site. NSP-Wisconsin has recorded an estimate of its potential liability based upon its best estimate of potential exposure.
Asbestos Removal - Some of Xcel Energy's facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Xcel Energy has recorded an estimate for final removal of the asbestos as an ARO. See additional discussion of AROs below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
Other Environmental Requirements
EPA GHG Endangerment Finding - On Dec. 7, 2009, in response to the U. S. Supreme Court's decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its "endangerment" finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty vehicles. The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.
CAIR - In March 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy's service territory. In response to the decisions by the D.C. Circuit Court of Appeals vacating but reinstating CAIR while EPA develops revised regulations, the EPA has indicated that a CAIR replacement rule will be proposed in early 2010 with finalization planned for early 2011.
As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap and trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA's proposed model program, or they can propose another method, which the EPA would need to approve.
Under CAIR's cap and trade structure, SPS can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. The remaining capital investments for NOx controls in the SPS region are estimated at $4.5 million. For 2009, the NOx allowance compliance costs were $1.7 million. The estimated NOx allowance cost for 2010 is $1.2 million. Annual purchases of SO2 allowances are estimated in the range of $1.7 million to $7.7 million each year, beginning in 2013, for phase I.
On Nov. 3, 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective Dec. 3, 2009. Cost estimates are therefore not included at this time for NSP-Minnesota. For 2009, the NOx allowance costs for NSP-Wisconsin were $0.5 million. The estimated NOx allowance cost for 2010 is $0.4 million. Allowance cost estimates for SPS and NSP-Wisconsin are based on fuel quality and current market data. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.
CAMR - In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize MACT emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR. Xcel Energy anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.
Colorado Mercury Regulation - In Colorado, the AQCC passed a mercury rule, which requires mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for absorbent expense. PSCo is evaluating the emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.
Minnesota Mercury Legislation - In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants. For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities. Xcel Energy installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.
In September 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs recoverable under the Act. In January 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million. In November 2008, NSP-Minnesota filed a request with the MPUC to reflect its requested recovery of these emission reduction compliance costs incurred through 2009 in the NSP-Minnesota electric rate case. In June 2009, NSP-Minnesota received an order from the MPUC closing the docket to correspond with the inclusion of costs in the electric rate case. The recovery of the costs was allowed as part of the rate case.
In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans. A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled for December 2010. In an order dated Nov. 4, 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.
On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and the MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.
Regional Haze Rules - In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will be subject to BART requirements.
States are required to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities. In May 2006, the Colorado AQCC promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. PSCo estimates that the remaining cost for implementation of BART emission control projects is approximately $141 million in capital costs, which are included in the capital budget.
PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2015. Colorado's BART state implementation plan has been submitted to the EPA for approval. In January 2009, the CAPCD initiated a joint stakeholder process to evaluate what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado's Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals. The CAPCD has indicated that it expects to have a final plan for additional point-source NOx controls by the end of 2010.
NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006. The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART. On Nov. 13, 2008, NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCA to account for increased construction and equipment costs. The underlying conclusions and proposed emission control equipment, however, remain unchanged from the original 2006 BART analysis. The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft state implementation plan (SIP) that are equivalent to the reductions made under CAIR.
On Oct. 21, 2009, the United States Department of Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to pollution emissions from Xcel Energy's Sherco Plant Units 1 and 2. The EPA currently administers the 1980 Visibility Protection Rules for the State of Minnesota through a Federal Implementation Plan. As such, EPA Region 5 is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and if so, to determine the appropriate BART levels of control.
The MPCA determined that this certification does not alter the proposed SIP. The SIP proposes BART controls for Sherco that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2. The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs. On Dec. 15, 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval.
Federal Clean Water Act - The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit (Court of Appeals) challenging the phase II rulemaking. In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration. In June 2007, the EPA suspended the deadlines and referred any implementation to each state's best professional judgment until the EPA is able to fully respond to the remand. In April 2008, the U. S. Supreme Court granted limited review of the Court of Appeals' opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA. On April 1, 2009, the U. S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals' earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds to the Court of Appeals' decision, the rule's compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.
The MPCA exercised its authority under best professional judgment to require the Black Dog Generating Station in its recently renewed wastewater discharge permit to create a plan by April 2010 to reduce the plant intake's impact on aquatic wildlife. NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.
PSCo Notice of Violation (NOV) - In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.
Cunningham Draft Compliance Order - On Feb. 18, 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station. In the draft order, NMED alleges that Cunningham exceeded its permit limits for NOx on 7,336 occasions and failed to report these exceedances as required by its permit. The draft order includes a proposed penalty of $16.1 million. SPS denies these allegations and will have an opportunity to discuss the alleged violations and proposed penalty with NMED prior to the issuance of a final order. SPS will vigorously defend its position in negotiations with NMED.
Asset Retirement Obligations
Xcel Energy records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with ASC 410 Asset Retirement and Environmental Obligations. This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.
Recorded ARO - AROs have been recorded for plant related to nuclear production, steam production, electric transmission and distribution, natural gas transmission and distribution and office buildings. The steam production obligation includes asbestos, ash-containment facilities, radiation sources and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. Generally, this asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for NSP-Minnesota, PSCo and SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities. Additional AROs have been recorded for NSP-Minnesota and PSCo steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.
Xcel Energy recognized an ARO for the retirement costs of natural gas mains at NSP-Minnesota, NSP-Wisconsin and PSCo. In addition, an ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. The electric transmission and distribution ARO consists of many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.
For the nuclear assets, the ARO associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originates with the in-service date of the facility. Monticello began operation in 1971. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively. See Note 18 to the consolidated financial statements for further discussion of nuclear obligations.
A reconciliation of the beginning and ending aggregate carrying amounts of Xcel Energy's AROs is shown in the table below for the 12 months ended Dec. 31, 2009 and Dec. 31, 2008, respectively:
The fair value of NSP-Minnesota assets legally restricted, for purposes of settling the nuclear ARO is $1.2 billion as of Dec. 31, 2009, including external nuclear decommissioning investment funds and internally funded amounts.
Revisions were made for asbestos, ash-containment facilities, nuclear plants, wind turbines, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.
The revised end of life date for the Prairie Island nuclear plant approved by the MPUC in 2008 and effective Jan. 1, 2009 resulted in the nuclear production decommissioning ARO and related regulatory asset decreasing by $315.9 million in the fourth quarter of 2009.
A new decommissioning study filed with the MPUC in 2008 proposed extension of the final removal date of the Monticello and Prairie Island nuclear plants by 14 and 26 years, respectively, effective Jan. 1, 2009. As a result of the studies for the Monticello and Prairie Island nuclear plants, the nuclear production decommissioning ARO and related regulatory asset decreased by $128.5 million and $139.3 million, respectively, in the fourth quarter of 2008.
Indeterminate AROs - PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined; therefore, an ARO has not been recorded.
Removal Costs - Xcel Energy accrues an obligation for plant removal costs for other generation, transmission and distribution facilities of its utility subsidiaries. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the utility subsidiaries have estimated the
amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.
Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs by entity are as follows at Dec. 31:
Nuclear Insurance
NSP-Minnesota's public liability for claims resulting from any nuclear incident is limited to $12.5 billion under the Price-Anderson amendment to the Atomic Energy Act of 1954, as amended. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $117.5 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $17.5 million per reactor during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC's last adjustment was effective Oct. 29, 2008. The next adjustment is due on or before Oct. 29, 2013.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota's two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $15.2 million for business interruption insurance and $30.9 million for property damage insurance if losses exceed accumulated reserve funds.
Legal Contingencies
Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy's financial position and results of operations.
Gas Trading Litigation
e prime is a wholly owned subsidiary of Xcel Energy. Among other things, e prime was in the business of natural gas trading and marketing. e prime has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits have been commenced against e prime and Xcel Energy (and NSP-Wisconsin, in one instance); alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Xcel Energy, e prime, and NSP-Wisconsin deny these allegations and will vigorously defend against these lawsuits, including seeking dismissal and summary judgment.
The initial gas-trading lawsuit, a purported class action brought by wholesale natural gas purchasers, was filed in November 2003 in the United States District Court in the Eastern District of California. e prime is one of several defendants named in the complaint. This case is captioned Texas-Ohio Energy vs. CenterPoint Energy et al. The other twelve cases arising out of the same or similar set of facts are captioned Fairhaven Power Company vs. EnCana Corporation et al.; Ableman Art Glass vs. EnCana Corporation et al.; Utility Savings and Refund Services LLP vs. Reliant
Energy Services Inc. et al.; Sinclair Oil Corporation vs. e prime and Xcel Energy Inc.; Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al.; Learjet, Inc. vs. e prime and Xcel Energy Inc et al.; J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al.; Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al.; Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. et al.; Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al.; NewPage Wisconsin System Inc vs. e prime, Xcel Energy, NSP-Wisconsin et al. and Heartland Regional Medical Center vs. e prime, Xcel Energy et al. Many of these cases involve multiple defendants and have been transferred to Judge Phillip Pro of the United States District Court in Nevada, who is the judge assigned to the Western Area Wholesale Natural Gas Antitrust Litigation.
e prime and some other defendants were dismissed from the Breckenridge Brewery lawsuit in February 2008, but Xcel Energy remains a defendant in that lawsuit and e prime Energy Marketing was added as a defendant in February 2008.
No trial dates have been set for any of these lawsuits. In January 2009, the parties reached a settlement agreement in principle in the Abelman Art Glass, Ever Bloom, Fairhaven Power Company, Texas-Ohio Energy, and Utility Savings and Refund Services cases. The terms of the settlement in principle will not have a material financial effect upon Xcel Energy. Discovery in most of the remaining cases was completed by Dec. 5, 2009. In October 2009, the Court granted defendants' motion to renew their summary judgment motions and such motions were filed in November 2009. If summary judgment is not granted, trial for all cases venued in Nevada will likely be set for 2010.
In November 2007, the Missouri Public Service Commission case was remanded to Missouri state court. On Jan. 13, 2009, the Missouri state court granted defendants' motion to dismiss plaintiff's complaint for lack of standing. Plaintiffs filed an appeal and on Dec. 8, 2009, the Missouri Court of Appeals affirmed the dismissal.
In late March 2009, Newpage Wisconsin System Inc. commenced a lawsuit in state court in Wood County, Wis. The allegations are substantially similar to Arandell and name several defendants, including Xcel Energy, e prime and NSP-Wisconsin. In September 2009, Plaintiffs moved to consolidate the Newpage and Arandell matters. Defendants have filed motions to dismiss and, as with Arandell, Xcel Energy, e prime and NSP-Wisconsin believe the allegations asserted against them are without merit and they intend to vigorously defend against the asserted claims.
Environmental Litigation
Carbon Dioxide Emissions Lawsuit - In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U. S. Court of Appeals for the Second Circuit. On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision. On Nov. 5, 2009 the defendants, including Xcel Energy, filed a petition for rehearing and en banc review. It is uncertain when the Court of Appeals will respond to the petition.
Comer vs. Xcel Energy Inc. et al. - In 2006, Xcel Energy received notice of a purported class action lawsuit filed in U. S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants' CO2 emissions "were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina." Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Fifth Circuit. On Oct. 16, 2009, the U. S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. On Nov. 27, 2009, defendants, including Xcel Energy, filed a petition for en banc review. It is uncertain when the Court of Appeals will respond to the petition.
Native Village of Kivalina vs. Xcel Energy Inc. et al. - In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U. S. District Court for the Northern District of California against Xcel Energy and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants' emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. On Oct. 15, 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds. On Nov. 5, 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.
Comanche Unit 3 CAA Lawsuit - On July 2, 2009, WildEarth Guardians (WEG) filed a lawsuit against PSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3 without a final MACT determination from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD). The state has proposed a more stringent case-by-case MACT determination for Comanche Unit 3 that, if final, could increase the operating costs of Comanche Unit 3. PSCo disputes these claims and has filed a motion to dismiss the suit. Comanche Unit 3 was constructed with state-of-the-art emission controls and pursuant to a valid air permit issued by the APCD. On Oct. 28, 2009, WEG filed a motion for a preliminary injunction, seeking to enjoin PSCo from constructing, modifying, or operating Comanche Unit 3 prior to receiving a final MACT determination. PSCo strongly opposes the injunction. Among other issues, PSCo believes that WEG has failed to establish a substantial likelihood of prevailing on the merits of the suit and that therefore there is no valid legal basis upon which an injunction should be issued. The court has yet to rule on WEG's motion and the group sought a temporary restraining order to stop Comanche Unit 3 from coming on-line. The court denied WEG's request for a temporary restraining order on Jan. 26, 2010. On Feb. 23, 2010, the court held a hearing on PSCo's motion to dismiss. It is uncertain when the court will render a decision.
Employment, Tort and Commercial Litigation
Siewert vs. Xcel Energy - In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota's distribution system. Plaintiffs claim losses of approximately $7 million. NSP-Minnesota denies all allegations. In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs' claims for injunctive relief, but otherwise rejecting NSP-Minnesota's contentions and ordering the matter remanded for trial. The Minnesota Supreme Court subsequently granted NSP-Minnesota's petition for further review and heard oral arguments on Dec. 2, 2009. It is uncertain when the Minnesota Supreme Court will render a decision.
Qwest vs. Xcel Energy Inc. - In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million. In April 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo. Qwest filed a petition for rehearing with the Colorado Supreme Court in June 2009. On Feb. 22, 2010 issued a ruling where it will review the Court of Appeals' decision as to the punitive damages issue and will not review the Court of Appeals' decision as it relates to PSCo.
MGP Insurance Coverage Litigation - In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire and La Crosse, Wis. In lieu of participating in discussions, in October 2003, two of NSP-Wisconsin's insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. In November 2003, NSP-Wisconsin commenced suit in Wisconsin state court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation. The Wisconsin action remains in abeyance.
NSP-Wisconsin has reached settlements with 22 insurers, and these insurers have been dismissed from both the Minnesota and Wisconsin actions. NSP-Wisconsin has also reached settlements in principle with Ranger Insurance Company (Ranger), TIG Insurance Company (TIG), Royal Indemnity Company and Globe Indemnity Company.
In July 2007, the Minnesota state court issued a decision on allocation, reaffirming its prior rulings that Minnesota law on allocation should apply and ordering the dismissal, without prejudice, of 11 insurers whose coverage would not be triggered under such an allocation method. In September 2007, NSP-Wisconsin commenced an appeal in the Minnesota Court of Appeals challenging the dismissal of these carriers.
On Aug. 25, 2009, the Minnesota Court of Appeals affirmed the district court decision. NSP-Wisconsin subsequently filed a petition for review of this decision with the Minnesota Supreme Court. On Nov. 17, 2009 the Minnesota Supreme Court issued an order denying the petition. Defendants subsequently filed in the Wisconsin state court action a motion to dismiss, which NSP-Wisconsin intends to oppose. Oral arguments are set for March 5, 2010. It is unknown when the court will rule on this motion.
The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers. None of the aforementioned lawsuit settlements are expected to have a material effect on Xcel Energy's consolidated financial statements.
Nuclear Waste Disposal Litigation - In 1998, NSP-Minnesota filed a complaint in the U. S. Court of Federal Claims against the United States requesting breach of contract damages for the DOE failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota. At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004. On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages. In December 2007, the court denied the DOE's motion for reconsideration. In February 2008, the DOE filed an appeal to the U. S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue. In April 2008, the DOE asked the Court of Appeals to stay briefing until the appeals in several other nuclear waste cases have been decided, and the Court of Appeals granted the request. In December 2008, NSP-Minnesota made a motion in the Court of Appeals to lift the stay, which was denied by the Court of Appeals in February 2009. Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved. Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.
In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U. S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE's continuing failure to abide by the terms of the contract. This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel. Per the court's scheduling order, NSP-Minnesota's expert report on damages was submitted on April 15, 2009, and asserts damages in excess of $250 million. In November 2009, the Court ordered the DOE to submit its expert report by May 17, 2010. Trial is expected to take place in mid to late 2010.
Mallon vs. Xcel Energy Inc. - In August 2007, Xcel Energy, PSCo and PSRI (hereafter "Plaintiffs") commenced a lawsuit in Colorado state court against Theodore Mallon and TransFinancial Corporation seeking damages for, among other things, breach of contract and breach of fiduciary duties associated with the sale of COLI policies. In May 2008, Plaintiffs filed an amended complaint that, among other things, adds Provident Life & Accident Insurance Company (Provident) as a defendant and asserts claims for breach of contract, unjust enrichment and fraudulent concealment against the insurance company. On June 23, 2008, Provident filed a motion to dismiss the complaint. On Oct. 22, 2008, the court granted Provident's motion in part, but denied the motion with respect to a majority of the core causes of action asserted by Plaintiffs. In September 2009, Plaintiffs reached a settlement with Mallon and TransFinancial Corporation. Pursuant to the terms of the agreement, Mallon agreed to pay Plaintiffs a specified amount and the parties agreed to mutually release each other from all claims. Plaintiffs continue to prosecute their claims against Provident. In November 2009, Plaintiffs and Provident filed motions for partial summary judgment, which the court subsequently granted in part in favor of Plaintiffs with respect to an interpretation of the policies. On Feb. 11, 2010, the court denied Provident's motion for partial summary judgment. Trial for this lawsuit was continued to Aug. 16, 2010.
Cabin Creek Hydro Generating Station Accident - In October 2007, employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxy coating to the inside of a penstock at PSCo's Cabin Creek Hydro Generating Station near Georgetown, Colo. A fire occurred inside a pipe used to deliver water from a reservoir to the hydro facility. Five RPI employees were unable to exit the pipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and the U. S. Chemical Safety Board and the Colorado Bureau of Investigations.
In March 2008, OSHA proposed penalties totaling $189,900 for twenty-two serious violations and three willful violations arising out of the accident. In April 2008, Xcel Energy notified OSHA of its decision to contest all of the proposed citations. On May 28, 2008, the Secretary of Labor filed its complaint, and Xcel Energy subsequently filed its answer on June 17, 2008. The Court ordered this proceeding stayed until March 3, 2009 and subsequently extended the stay to October 2009. The Court is currently considering whether to extend the stay.
A lawsuit was filed in Colorado state court in Denver on behalf of four of the deceased workers and four of the injured workers (Foster, et. al. v. PSCo, et. al.). PSCo and Xcel Energy were named as defendants in that case, along with RPI Coatings and related companies and the two other contractors who also performed work in connection with the relining project at Cabin Creek. A second lawsuit (Ledbetter et. al vs. PSCo et. al) was also filed in Colorado state court in Denver on behalf of three employees allegedly injured in the accident. A third lawsuit was filed on behalf of one of the deceased RPI workers in the California state court (Aguirre v. RPI, et. al.), naming PSCo, RPI, and the two other contractors as defendants. The court subsequently dismissed the Aguirre lawsuit. Settlements were subsequently reached in all three lawsuits. These confidential settlements are not expected to have a material effect on the financial statements of Xcel Energy or its subsidiaries.
On Aug. 28, 2009, the U. S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted. On Sept. 22, 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges. In December 2009, Xcel Energy and PSCo filed two separate motions to dismiss. It is uncertain when the court will rule on these motions.
Stone & Webster, Inc. vs. PSCo - On July 14, 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal fired plant in Pueblo, Colo. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo was responsible for and mismanaged the construction of Comanche Unit 3. Shaw further claims that this alleged mismanagement caused delays and damages in excess of $55 million. The complaint also alleges that Xcel Energy and related entities, including PSCo, guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement. PSCo denies these allegations and believes the claims are without merit. PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled, among other things, to liquidated damages and excess costs incurred. It is not anticipated that this lawsuit will affect Comanche Unit 3's scheduled in-service date.
Fru-Con Construction Corporation vs. UE et al. - In March 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U. S. District Court in the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined-cycle power plant in Sacramento County. Fru-Con's complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD. In August 2005, the court granted UE's motion to dismiss. Because SMUD remains a defendant in this action, the court has not entered a final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit. Because this lawsuit was commenced prior to the April 2005, closing of the sale of UE to Zachry, Xcel Energy is obligated to indemnify Zachry for damages related to this case up to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million.
Connie DeWeese vs. PSCo - In November 2008, there was an explosion in Pueblo, Colo. which destroyed a tavern and a neighboring store. The explosion killed one person and injured seven people. The Pueblo Fire Department and the Federal Bureau of Alcohol, Tobacco and Firearms (ATF) have determined a natural gas leak from a pipeline under the street led to the explosion, stating that natural gas passed through the soil and built up in the tavern's basement. On Feb. 8, 2010, a wrongful death lawsuit was filed in Colorado District Court in Pueblo, Colorado against PSCo and the City of Pueblo by several parties that were allegedly injured, as a result of this explosion. The plaintiffs are also alleging economic and noneconomic damages. Among other things, the lawsuit alleges that the accident occurred as a result of PSCo's negligence. PSCo denies liability for this accident and intends to file an answer to the complaint on or before March 1, 2010.
Other Contingencies
See Note 16 to the consolidated financial statements.
18. Nuclear Obligations
Fuel Disposal - NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota's nuclear plants as well as from other U. S. nuclear plants. NSP-Minnesota has funded its portion of the DOE's permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per Kwh sold to customers from nuclear generation. Fuel expense includes the DOE fuel disposal assessments of approximately $12 million in 2009, $13 million in 2008 and $13 million 2007, respectively. In total, NSP-Minnesota had paid approximately $398 million to the DOE through Dec. 31, 2009. The Nuclear Waste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE's failure to meet its statutory and contractual obligations.
NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities at both sites. The amount of spent fuel storage capacity currently authorized by the NRC and the MPUC will allow NSP-Minnesota to continue operation of its Prairie Island nuclear plant until the end of its current license terms in 2013 and 2014 and its Monticello nuclear plant until the end of its renewed operating license in 2030. Other alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.
Regulatory Plant Decommissioning Recovery - Decommissioning of NSP-Minnesota's nuclear facilities is planned for the period from cessation of operations through 2067, assuming the prompt dismantlement method. NSP-Minnesota is currently recording the regulatory costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in a regulatory liability account. The total decommissioning cost obligation is recorded as an ARO in accordance with ASC 410 Asset Retirement and Environmental Obligations.
Monticello began operation in 1971 and with its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation can operate until 2030. The Monticello 20-year depreciation life extension until September 2030 was granted by the MPUC in 2007. Construction of the Monticello dry-cask storage facility is complete and 10 of the 30 canisters authorized have been filled and placed in the facility.
Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are currently licensed to operate until 2013 and 2014, respectively. In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years until 2033 and 2034, respectively. The PIIC filed contentions in the NRC's license renewal proceeding in August 2008. The PIIC request was referred to an ASLB for review. The ASLB has granted the PIIC hearing request and has admitted seven of the 11 contentions filed. To date, all seven admitted contentions have been resolved and removed from the ASLB docket. Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions. The ASLB has admitted one of the contentions and has not issued a decision on the other three. NSP-Minnesota is challenging the admitted contention, and a decision on whether the other contentions will be accepted will be made in early 2010. If the contentions are not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC's standard 22 month review schedule, resulting in a decision on the Prairie Island license renewal in late 2010.
The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC, when decommissioning commences. The MPUC last approved NSP-Minnesota's nuclear decommissioning study request in October 2009, using 2008 cost data. The next study update will be submitted in October 2011 for the 2012 accrual. The MPUC approval, eliminated 2009 decommissioning funding for Minnesota retail customers, due to a full extension of the accrual period for the Monticello unit from 2020 to 2030, along with an extension of the accrual period for Prairie Island (from 2013 for Unit 1 and 2014 for Unit 2 to 2023 and 2024 respectively). Further, in November 2009, the MPUC also approved a proposal to refund the Minnesota portion of the Monticello escrow fund in a supplemental filing.
The assets held in trusts, primarily consist of investments in fixed income securities, such as tax-exempt municipal bonds and U. S. government securities that mature in one to 20 years and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.
Consistent with cost-recovery in utility customer rates, NSP-Minnesota previously recorded annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. The most recent study, which resulted in an authorization of no funding, presumes that costs will escalate in the future at a rate of 2.89 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 6.30 percent, net of tax, for external funding. The net unrealized loss on nuclear decommissioning investments is deferred as a regulatory liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.
The external funds are held in trust and in escrow. The portion in escrow is subject to refund if approved by the various rate commissions. The MPUC authorized the return of $23.5 million of funds associated with the Monticello plant for the Minnesota retail jurisdictions. This amount was withdrawn in December 2009 and was refunded on customer's bills in February 2010.
At Dec. 31, 2009, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning expense of $1.3 billion. The following table summarizes the funded status of NSP-Minnesota's decommissioning obligation based on approved regulatory recovery parameters. Xcel Energy believes future decommissioning cost expense, if necessary, will continue to be recovered in customer rates. These amounts are not those recorded in the financial statements for the ARO.
Decommissioning expenses recognized include the following components:
Reductions to expense for internally-funded portions in 2009, 2008 and 2007 are a direct result of the 2008 or 2005 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the remaining operating life of the unit. The 2008 nuclear decommissioning filing approved in 2009 has been used for the regulatory presentation. The change in estimated decommissioning obligations was calculated using a cost estimate for Monticello assuming a 60-year operating life.
19. Regulatory Assets and Liabilities
Xcel Energy's regulated businesses prepare their consolidated financial statements in accordance with the provisions of ASC 980 Regulated Operations, as discussed in Note 1 to the consolidated financial statements. Under this guidance, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy's business that is not regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of Xcel Energy no longer allow for the application of regulatory accounting guidance under GAAP, Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in its consolidated statement of income.
The components of unamortized regulatory assets and liabilities of continuing operations shown on the consolidated balance sheets at Dec. 31 are:
(a)Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates. (b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (c)Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements. (d)Included in other current liabilities of $350,318 and $331,419 at Dec. 31, 2009 and 2008, respectively, in the consolidated balance sheets. (e)Includes $415.5 million for the regulatory recognition of the NSP-Minnesota pension expense and the PSCo unamortized prior service costs, offset by $18.1 million of regulatory assets related to the non-qualified pension plan.
20. Segments and Related Information
The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy's chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Given the similarity of the regulated electric utility operations of its utility subsidiaries, and the similarity of the regulated natural gas utility operations of its utility subsidiaries, Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.
•Xcel Energy's regulated electric utility segment generates, transmits, and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations.
•Xcel Energy's regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
To report income from continuing operations for regulated electric and regulated natural gas utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are:
•Directly assigned wherever applicable;
•Allocated based on cost causation allocators wherever applicable; and
•Allocated based on a general allocator for all other costs not assigned by the above two methods. The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements.
21. Summarized Quarterly Financial Data (Unaudited)
Due to the seasonality of Xcel Energy's electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results. Summarized quarterly unaudited financial data is as follows:
22. Lubbock Electric Distribution Assets
In November 2009, SPS entered into an asset purchase agreement with the city of Lubbock, Texas (City of Lubbock). This agreement sets forth that SPS will sell its electric distribution system assets within the city limits to LP&L for approximately $87 million. The sale and related transactions will eliminate the inefficiencies of maintaining duplicate distribution systems, one by SPS and the other by the city-owned LP&L. SPS currently serves about 24,000 customers within Lubbock, representing about 25 percent of the total customers in the dually certified service area. As part of this transaction, SPS will continue to provide the wholesale power to meet the electric load for these customers, initially by amending the current wholesale full-requirements contract with West Texas Municipal Power Agency (WTMPA), which provides service to LP&L through 2019 and then for an additional 25 years under a new contract directly with LP&L when the WTMPA contract terminates. Both of these wholesale power agreements provide for formula rates that change annually based on the actual cost of service. The formula rate with WTMPA reflects an initial 10.5 percent ROE. All or portions of this transaction are subject to review and approval by the PUCT, the NMPRC and FERC. This transaction is expected to close late in 2010. It is anticipated that any resulting gain on the sale of assets will be shared with retail customers in Texas.
Additionally, SPS and the City of Lubbock entered into an amended long-term treated sewage effluent water agreement under which SPS will continue to purchase waste water from the city for cooling SPS's Jones Station southeast of Lubbock. This new waste water agreement will provide a long-term and low cost source for cooling water for SPS. This agreement is not subject to regulatory approval.
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 2008 and 2009, and through the date of this report, there were no disagreements with the independent public accountants on accounting principles or practices, financial statement disclosures, or auditing scope or procedures.
Item 9A - Controls and Procedures
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2009, based on an evaluation carried out under the supervision and with the participation of Xcel Energy's management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy's disclosure controls and procedures were effective.
Internal Controls Over Financial Reporting
No change in Xcel Energy's internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Xcel Energy's internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2009 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.
Item 9B - Other Information
None.
PART III
Item 10 - Directors, Executive Officers and Corporate Governance
Information required under this Item with respect to directors is set forth in Xcel Energy's Proxy Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.
Item 11 - Executive Compensation
Information required under this Item is set forth in Xcel Energy's Proxy Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by reference.
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information concerning the security ownership of the directors and officers of Xcel Energy and securities authorized for issuance under equity compensation plans is contained in Xcel Energy's Proxy Statement for its 2010 Annual Meeting of Shareholders which is incorporated by reference.
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Information concerning relationships and related transactions of the directors and officers of Xcel Energy is contained in Xcel Energy's Proxy Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by reference.
Item 14 - Principal Accountant Fees and Services
Information concerning fees paid to the principal accountant for each of the last two years is contained in Xcel Energy's Proxy Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
Item 15 - Exhibits and Financial Statement Schedules
1.
Consolidated Financial Statements:
Management Report on Internal Controls - For the year ended Dec. 31, 2009.
Reports of Independent Registered Public Accounting Firm - For the years ended Dec. 31, 2009, 2008 and 2007.
Consolidated Statements of Income - For the three years ended Dec. 31, 2009, 2008 and 2007.
Consolidated Statements of Cash Flows - For the three years ended Dec. 31, 2009, 2008 and 2007.
Consolidated Balance Sheets - As of Dec. 31, 2009 and 2008.
2.
Schedule I - Condensed Financial Information of Registrant.
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2009, 2008 and 2007.
3.
Exhibits
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Xcel Energy
3.01*
Restated Articles of Incorporation of Xcel Energy, as amended on May 21, 2008. (Exhibit 3.01 to Form 10-Q for the quarter ended June 30, 2008 (file no. 001-03034)).
3.02*
Restated By-Laws of Xcel Energy (Exhibit 3.01 to Form 8-K dated Aug. 12, 2008 (file no. 001-03034)).
Xcel Energy
4.01*
Trust Indenture dated Dec. 1, 2000, between Xcel Energy and Wells Fargo Bank, Minnesota, National Association (NA), as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 18, 2000).
4.02*
Indenture dated Nov. 21, 2002 between Xcel Energy and Wells Fargo Bank, Minnesota, NA, 7.5 percent convertible senior notes due 2007 (Exhibit 4.137 to Form 10-K (file no. 001-03034) dated March 31, 2003).
4.03*
Supplemental Trust Indenture No. 2 dated June 15, 2003 between Xcel Energy and Wells Fargo Bank, Minnesota, NA, supplementing trust indenture dated Dec. 1, 2000 (Exhibit 4.01 to Form 10-Q (file no. 001-03034) dated Aug. 15, 2003).
4.04+*
Form of Stock Option Agreement Dated Aug. 5, 2005 (Exhibit 4.04 to Form S-8 (file no. 333-127217) dated Aug. 5, 2005).
4.05+*
Form of Restricted Stock Agreement Dated Aug. 5, 2005 (Exhibit 4.08 to Form S-8 (file no. 333-127217) dated Aug. 5, 2005).
4.06*
Supplemental Trust Indenture dated June 1, 2006 between Xcel Energy and Wells Fargo Bank, Minnesota, NA, as Trustee, creating $300,000,000 principal amount of 6.5 percent Senior Notes, Series due 2036 (Exhibit 4.01 to Current Report on Form 8-K (file no. 001-03034) dated June 6, 2006).
4.07*
Registration Rights Agreement dated March 30, 2007 between Xcel Energy and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Greenwich Capital Markets, Inc. and Lazard Capital Markets LLC. (Exhibit 10.1 to Form 8-K (file no. 001-03034) dated March 30, 2007).
4.08*
Supplemental Indenture dated March 30, 2007 between Xcel Energy and Wells Fargo Bank, Minnesota, NA, as Trustee, creating $253,979,000 aggregate principal amount of 5.613 percent Senior Notes, Series due 2017 (Exhibit 4.1 to Form 8-K (file no. 001-03034) dated March 30, 2007).
4.09*
Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy and Wells Fargo Bank, Minnesota, NA, as trustee (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
4.10*
Supplemental Indenture No. 1, dated Jan. 16, 2008, by and between Xcel Energy and Wells Fargo Bank, Minnesota, NA, as trustee (Exhibit 4.02 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
4.11*
Replacement Capital Covenant, dated Jan. 16, 2008 (Exhibit 4.03 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
NSP-Minnesota
4.12*
Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee.(Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034). Supplemental Indentures between NSP-Minnesota and said Trustee, dated as follows:
Supplemental Indenture dated Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 13, 1992, Rider A).
Supplemental Indenture dated April 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 1993, Rider A).
Supplemental Indenture dated Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 7, 1993, Rider A).
Supplemental Indenture dated June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995, Rider A).
Supplemental Indenture dated March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998, Rider A).
Supplemental Indenture dated May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000, Rider A).
Supplemental Indenture dated June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000, Rider A).
4.13*
Supplemental Indenture Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.14*
Trust Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.15*
Supplemental Trust Indenture, dated July 15, 1999, between NSP-Minnesota and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.16*
Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.17*
Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31387) dated Sept. 30, 2002).
4.18*
Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31387) dated Sept. 30, 2002).
4.19*
Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between NSP-Minnesota and Wells Fargo Bank, Minnesota, NA, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31387) dated July 8, 2002).
4.20*
Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.21*
Supplemental Trust Indenture dated Aug. 1, 2003 between NSP-Minnesota and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.22*
Supplemental Trust Indenture dated May 1, 2003 between NSP-Minnesota and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988. (Exhibit 4.73 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2003)
4.23*
Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated July 14, 2005).
4.24*
Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated May 18, 2006).
4.25*
Supplemental Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
4.26*
Supplemental Indenture dated March 1, 2008 between NSP-Minnesota and BNY Midwest Trust Company, as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008.
4.27*
Supplemental Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300,000,000 principal amount of 5.35% First Mortgage Bonds, Series due Sept. 1, 2039 (Exhibit 4.01 of Form 8-K of NSP-Minnesota dated Nov. 16, 2009 (file no. 001-31387)).
NSP-Wisconsin
4.28*
Supplemental and Restated Trust Indenture, dated March 1, 1991. (Exhibit 4.01 to Registration Statement 33-39831).
4.29*
Supplemental Trust Indenture, dated April 1, 1991. (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
4.30*
Supplemental Trust Indenture, dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
4.31*
Trust Indenture dated Sept. 1, 2000, between NSP-Wisconsin and Firstar Bank, NA as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
4.32*
Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and US Bank NA, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.33*
Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U. S. Bank NA, as successor Trustee, creating $200,000,000 principal amount of 6.375% First Mortgage Bonds, Series due Sept. 1, 2038 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Sept. 3, 2008 (file no. 001-03140)).
PSCo
4.34*
Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 - Exhibit 4(a)).
4.35*
Indentures supplemental to Indenture dated as of Oct. 1, 1993:
Dated as of
Previous Filing: Form; Date or file no.
Exhibit
No.
Dated as of
Previous Filing: Form; Date or file no.
Exhibit
No.
Nov. 1, 1993
S-3, (33-51167)
4(b)(2)
Aug. 15, 2002
10-Q, Sept. 30, 2002 (001-03280)
4.03
Jan. 1, 1994
10-K, 1993
4(b)(3)
Sept. 1, 2002
8-K, Sept. 18, 2002 (001-03280)
4.01
Sept. 2, 1994
8-K, September 1994
4(b)
Sept. 15, 2002
10-Q, Sept. 30, 2002 (001-03280)
4.04
May 1, 1996
10-Q, June 30, 1996
4(b)
March 1, 2003
S-3, April 14, 2003 (333-104504)
4(b)(3)
Nov. 1, 1996
10-K, 1996 (001-03280)
4(b)(3)
April 1, 2003
10-Q May 15, 2003 (001-03280)
4.02
Feb. 1, 1997
10-Q, March 31, 1997 (001-03280)
4(a)
May 1, 2003
S-4, June 11, 2003 (333-106011)
4.9
April 1, 1998
10-Q, March 31,1998 (001-03280)
4(b)
Sept. 1, 2003
8-K, Sept. 2, 2003 (001-03280)
4.02
Sept. 15, 2003
Xcel 10-K, March 15, 2004 (001-03034)
4.100
Aug. 1, 2005
PSCo 8-K, Aug. 18, 2005 (001-03280)
4.02
Aug. 1, 2007
PSCo 8-K, Aug. 14, 2007 (001-03280)
4.01
4.36*
Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
4.37*
Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.38*
Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U. S. Bank Trust NA, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no 001-03280) dated Aug. 14, 2007).
4.39*
Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U. S. Bank Trust NA, as successor Trustee, creating $300,000,000 principal amount of 5.80% First Mortgage Bonds, Series No. 18 due 2018 and $300,000,000 principal amount of 6.50% First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)).
4.40*
Supplemental Indenture dated as of May 1, 2009 between PSCo and U. S. Bank Trust NA, as successor Trustee, creating $400,000,000 principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
SPS
4.41*
Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.42*
First Supplemental Indenture dated March 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.43*
Second Supplemental Indenture dated Oct. 1, 2001 between SPS and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).
4.44*
Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.45*
Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.46*
Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 - Exhibit 4(b)).
4.47*
Supplemental Trust Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250,000,000 principal amount of Series G Senior Notes, 8.75% due 2018 (Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001- 03789)).
Xcel Energy
10.01*+
Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+
Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+
Amended and Restated Executive Long-Term Incentive Award Stock Plan (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+
NCE Omnibus Incentive Plan, (Exhibit A to NCE, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998.
10.05*+
Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.07*+
Xcel Energy Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+
Xcel Energy Non-employee Directors' Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*
Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+
Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+
Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+
Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+
Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.14*+
Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005)
10.15*+
Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*+
First Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of Jan. 1, 2009. (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.17*+
First Amendment to Xcel Energy Inc. Omnibus Incentive Plan effective as of Jan. 1, 2009. (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.18*
Amendment dated as of April 13, 2009 to the Xcel Energy Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.19*
Credit Agreement dated Dec. 14, 2006 between Xcel Energy and various lenders (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.20*+
Second Amendment to the Xcel Energy 2005 Omnibus Incentive Plan (renaming it the Xcel Energy 2005 Long-Term Incentive Plan) (Exhibit 10.05 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.21*+
Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy. Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.22*+
Second Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan (Effective May 25, 2005) (Exhibit 10.07 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.23*+
Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.24+
Xcel Energy 2010 Executive Annual Discretionary Award Plan.
NSP-Minnesota
10.25*
Facilities Agreement, dated July 21, 1976, between NSP-Minnesota and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (KV) line. (Exhibit 5.06I to file no. 2-54310).
10.26*
Transactions Agreement, dated July 21, 1976, between NSP-Minnesota and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06J to file no. 2-54310).
10.27*
Coordinating Agreement, dated July 21, 1976, between NSP-Minnesota and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06K to file no. 2-54310).
10.28*
Ownership and Operating Agreement, dated March 11, 1982, between NSP-Minnesota, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.29*
Power Agreement, dated June 14, 1984, between NSP-Minnesota and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.30*
Power Agreement, dated August 1988, between NSP-Minnesota and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
10.31*
Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG (formerly known as Norenco Corp.) and NSP-Minnesota and Norenco Corp. (Exhibit 10.33 to NRG's Registration on Form S-1, file no. 333-35096).
10.32*
Operations and maintenance agreement dated Nov. 1, 1996 between NRG and NSP-Minnesota (Exhibit 10.34 to NRG's Registration on Form S-1, file no. 333-35096).
10.33*
Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between NSP-Minnesota and Norenco Corp. (Exhibit 10.36 to NRG's Registration on Form S-1, file no. 333-35096).
10.34*
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.35*
500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between NSP-Minnesota and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).
10.36*
Amendment dated as of April 13, 2009 to the NSP-Minnesota Credit Agreement dated as of Dec. 14, 2006. (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.37*
Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
NSP-Wisconsin
10.38*
Restated Interchange Agreement dated Jan. 16, 2001 between NSP- Wisconsin and NSP-Minnesota (Exhibit 10.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
PSCo
10.39*
Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 - Exhibit 10I(1)).
10.40*
First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 - Exhibit 10I(2)).
10.41*
Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.42*
Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.43*
Amendment dated as of April 13, 2009 to the PSCo Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2009).
10.44*
Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
SPS
10.45*
Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 - Exhibit 3).
10.46*
Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 - Exhibit 5(A)).
10.47*
Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 - Exhibit 5(B)).
10.48*
Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 - Exhibit 10(b)).
10.49*
Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 - Exhibit 10I).
10.50*
Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
10.51*
Amendment dated as of April 13, 2009 to the SPS Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.04 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2009).
10.52*
Credit Agreement dated Dec. 14, 2006 between SPS and various lenders. (Exhibit 10.04 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
Xcel Energy
12.01
Statement of Computation of Ratio of Earnings to Fixed Charges.
21.01
Subsidiaries of Xcel Energy Inc.
23.01
Consent of Independent Registered Public Accounting Firm.
24.01
Written Consent Resolution of the Board of Directors of Xcel Energy Inc., adopting Power of Attorney
31.01
Principal Executive Officer's certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02
Principal Financial Officer's certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01
Statement pursuant to Private Securities Litigation Reform Act of 1995.
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
SCHEDULE I
XCEL ENERGY INC.
Condensed Statements of Income
(amounts in thousands of dollars)
XCEL ENERGY INC.
Condensed Statements of Cash Flows
(amounts in thousands of dollars)
XCEL ENERGY INC.
Condensed Balance Sheets
(amounts in thousands of dollars)
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are Xcel Energy Inc. and Subsidiaries consolidated statements of common stockholders' equity and OCI in Part II, Item 8.
Basis of Presentation - The condensed financial information of the Holding Company of Xcel Energy is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy's investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.
Cash dividends paid to Xcel Energy by subsidiaries were $647 million, $630 million, and $694 million in the three years ended Dec. 31, 2009, respectively.
See Xcel Energy Inc. notes to the consolidated financial statements in Part II, Item 8 for other disclosures.
SCHEDULE II
XCEL ENERGY INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
Years Ended Dec. 31, 2009, 2008 and 2007
(amounts in thousands of dollars)
(a)Recovery of amounts previously written off. (b)Principally bad debts written off or transferred.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
XCEL ENERGY INC.
Feb. 26, 2010
By:
/s/ DAVID M. SPARBY
David M. Sparby
Vice President and Chief Financial Officer
(Principal Financial 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 on Feb. 26, 2010.
/s/ RICHARD C. KELLY
RICHARD C. KELLY
Chairman and Chief Executive Officer
(Principal Executive Officer)
/s/ TERESA S. MADDEN
TERESA S. MADDEN
Vice President and Controller
(Principal Accounting Officer)
/s/ DAVID M. SPARBY
DAVID M. SPARBY
Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ BENJAMIN G.S. FOWKE III
BENJAMIN G.S. FOWKE III
President and Director
*
C. CONEY BURGESS
Director
*
FREDRIC W. CORRIGAN
Director
*
RICHARD K. DAVIS
Director
*
ALBERT F. MORENO
Director
*
CHRISTOPHER J. POLICINSKI
Director
*
MARGARET R. PRESKA
Director
*
A. PATRICIA SAMPSON
Director
*
RICHARD H. TRULY
Director
*
DAVID A. WESTERLUND
Director
*
TIMOTHY V. WOLF
Director
*
/s/ TERESA S. MADDEN
TERESA S. MADDEN
Attorney-in-Fact