ITEM 1. BUSINESS
OUR BUSINESS
OVERVIEW
We are a public utility holding company whose indirect wholly owned subsidiaries include:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which provides electric transmission and distribution services to retail electric providers serving approximately 1.9 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 4.8 million people and includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns gas distribution systems serving approximately 3.1 million customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Through wholly owned subsidiaries, CERC also owns two interstate natural gas pipelines and gas gathering systems, provides various ancillary services, and offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.
Our reportable business segments are Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Pipelines and Field Services (formerly Pipelines and Gathering), and Other Operations. The operations of Texas Genco Holdings, Inc. (Texas Genco), formerly our majority owned generating subsidiary, the sale of which was completed in April 2005, are presented as discontinued operations.
We were a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). The 1935 Act and related rules and regulations imposed a number of restrictions on our activities and those of our subsidiaries. The Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since that date we and our subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005), which grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require us to notify the FERC of our status as a holding company and to maintain certain books and records and make these available to the FERC. The FERC continues to consider motions for rehearing or clarification of these rules.
Our principal executive offices are located at 1111 Louisiana, Houston, Texas 77002 (telephone number: 713-207-1111).
We make available free of charge on our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and 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 we electronically file such reports with, or furnish them to, the Securities and Exchange Commission (SEC). Additionally, we make available free of charge on our Internet website:
- our Code of Ethics for our Chief Executive Officer and Senior Financial Officers;
- our Ethics and Compliance Code;
- our Corporate Governance Guidelines; and
- the charters of our audit, compensation, finance and governance committees.
Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our Internet website
within five business days and maintained for at least 12 months or reported on Item 5.05 of our Forms 8-K. Our website address is www.centerpointenergy.com. Except to the extent explicitly stated herein, documents and information on our website are not incorporated by reference herein.
ELECTRIC TRANSMISSION & DISTRIBUTION
Electric Transmission
On behalf of retail electric providers, CenterPoint Houston delivers electricity from power plants to substations and from one substation to another and to retail electric customers taking power above 69 kilovolts (kV) in locations throughout the control area managed by the Electric Reliability Council of Texas, Inc. (ERCOT). CenterPoint Houston provides transmission services under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).
Electric Distribution
In ERCOT, end users purchase their electricity directly from certificated "retail electric providers." CenterPoint Houston delivers electricity for retail electric providers in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. Its distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. CenterPoint Houston's operations include construction and maintenance of electric transmission and distribution facilities, metering services, outage response services and call center operations. CenterPoint Houston provides distribution services under tariffs approved by the Texas Utility Commission. Texas Utility Commission rules and market protocols govern the commercial operations of distribution companies and other market participants.
ERCOT Market Framework
CenterPoint Houston is a member of ERCOT. ERCOT serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally owned electric utilities, rural electric cooperatives, independent generators, power marketers and retail electric providers. The ERCOT market includes much of the State of Texas, other than a portion of the panhandle, a portion of the eastern part of the state bordering Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation's largest power markets. The ERCOT market includes an aggregate net generating capacity of approximately 77,000 megawatts. There are only limited direct current interconnections between the ERCOT market and other power markets in the United States.
The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council. The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state's main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.
CenterPoint Houston's electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. We participate with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines
necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.
True-Up and Securitization
The Texas Electric Choice Plan (Texas electric restructuring law), which became effective in September 1999, substantially amended the regulatory structure governing electric utilities in order to allow retail competition for electric customers beginning in January 2002. The Texas electric restructuring law requires the Texas Utility Commission to conduct a "true-up" proceeding to determine CenterPoint Houston's stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission's rulings. The judgment would have the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of an inaccurate stranded cost estimate made by the Texas Utility Commission in 2000. Additional credits of approximately $30 million were paid after August 2004. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. CenterPoint Houston and other parties appealed the district court decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but oral argument has not yet been scheduled.
Among the issues raised in our appeal of the True-Up Order is the Texas Utility Commission's reduction of our stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with our former Texas Genco assets. Such reduction was considered in our recording of an after-tax extraordinary loss of $977 million in the last half of 2004. We believe that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 related to those tax benefits. Those proposed regulations would have allowed utilities which were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. If the December 2005 proposed regulations become effective and if the Texas Utility Commission's order on this issue is not reversed on appeal or the amount of the tax benefits is not otherwise restored by the Texas Utility Commission, the IRS is likely to consider that a "normalization violation" has occurred. If so, the IRS could require us to pay an amount equal to CenterPoint Houston's unamortized ADITC balance as of the date that the normalization violation was deemed to have occurred. In addition, if a normalization violation is deemed to have occurred, the IRS could also deny CenterPoint Houston the ability to elect accelerated depreciation benefits. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation.
There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging
from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.
In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC which will collect approximately $596 million over 14 years plus interest at an annual rate of 11.075 percent (CTC Order). The CTC Order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. The CTC Order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. Certain parties appealed the CTC Order to the Travis County Court in September 2005.
Under the True-Up Order, CenterPoint Houston is allowed to recover carrying charges at 11.075 percent until the true-up balance is recovered. In January 2006, the Texas Utility Commission staff (Staff) proposed that the Texas Utility Commission adopt new rules governing the carrying charges on unrecovered true-up balances. If the Texas Utility Commission adopts the rule as the Staff proposed it and the rule is deemed to apply to CenterPoint Houston, the rule would reduce carrying costs on the unrecovered CTC balance prospectively from 11.075 percent to the utility's cost of debt.
CenterPoint Houston Rate Case
The Texas Utility Commission requires each electric utility to file an annual Earnings Report providing certain information to enable the Texas Utility Commission to monitor the electric utilities' earnings and financial condition within the state. In May 2005, CenterPoint Houston filed its Earnings Report for the calendar year ended December 31, 2004. CenterPoint Houston's Earnings Report shows that it earned less than its authorized rate of return on equity in 2004.
In October 2005, the Staff filed a memorandum summarizing its review of the Earnings Reports filed by electric utilities. Based on its review, the Staff concluded that continuation of CenterPoint Houston's rates could result in excess retail transmission and distribution revenues of as much as $105 million and excess wholesale transmission revenues of as much as $31 million annually and recommended that the Texas Utility Commission initiate a review of the reasonableness of existing rates. The Staff's analysis was based on a 9.60 percent cost of equity, which is 165 basis points lower than the approved return on equity from CenterPoint Houston's last rate proceeding, the elimination of interest on debt that matured in November 2005 and certain other adjustments to CenterPoint Houston's reported information. Additionally, a hypothetical capital structure of 60 percent debt and 40 percent equity was used which varies materially from the actual capital structure of CenterPoint Houston as of December 31, 2005 of approximately 50 percent debt and 50 percent equity.
In December 2005, the Texas Utility Commission considered the Staff report and agreed to initiate a rate proceeding concerning the reasonableness of CenterPoint Houston's existing rates for transmission and distribution service and to require CenterPoint Houston to make a filing by April 15, 2006 to justify or change those rates.
These and other significant matters currently affecting our financial condition are further discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Executive Summary -- Significant Events in 2005" in Item 7 of this report.
Customers
CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. CenterPoint Houston's customers consist of 66 retail electric providers, which sell electricity in its certificated service area, and municipalities, electric cooperatives and other distribution companies located outside CenterPoint Houston's certificated service area. Each retail electric provider is licensed by, and must meet creditworthiness
criteria established by, the Texas Utility Commission. Two of the retail electric providers in our service area are subsidiaries of Reliant Energy, Inc (RRI). Sales to subsidiaries of RRI represented approximately 78%, 71% and 62% of CenterPoint Houston's transmission and distribution revenues in 2003, 2004 and 2005, respectively. CenterPoint Houston's billed receivables balance from retail electric providers as of December 31, 2005 was $127 million. Approximately 56% of this amount was owed by subsidiaries of RRI. CenterPoint Houston does not have long-term contracts with any of its customers. It operates on a continuous billing cycle, with meter readings being conducted and invoices being distributed to retail electric providers each business day.
Distribution Automation
CenterPoint Houston, with assistance from IBM, has developed an Electric Distribution Grid Automation Strategy that involves the implementation of an "Intelligent Grid". An Intelligent Grid has the potential to provide us with on demand data and information that should enable a significant improvement in grid planning, operations and maintenance. This, in turn, should contribute to fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of the workforce. A limited system deployment, with an expected capital cost of $11 million in 2006, has been initiated and allows for a disciplined approach to proving the technology and validating potential benefits prior to a full-scale implementation. The outcome of this limited deployment will be a major factor in any decision to expand the deployment in 2007 and beyond.
Competition
There are no other electric transmission and distribution utilities in CenterPoint Houston's service area. In order for another provider of transmission and distribution services to provide such services in CenterPoint Houston's territory, it would be required to obtain a certificate of convenience and necessity from the Texas Utility Commission and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We know of no other party intending to enter this business in CenterPoint Houston's service area at this time.
Seasonality
A significant portion of CenterPoint Houston's revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of such retail electric provider. Thus, CenterPoint Houston's revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.
Properties
All of CenterPoint Houston's properties are located in Texas. CenterPoint Houston's transmission system carries electricity from power plants to substations and from one substation to another. These substations serve to connect power plants, the high voltage transmission lines and the lower voltage distribution lines. Unlike the transmission system, which carries high voltage electricity over long distances, distribution lines carry lower voltage power from the substation to the retail electric customers. The distribution system consists primarily of distribution lines, transformers, secondary distribution lines and service wires and meters. Most of CenterPoint Houston's transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets as permitted by law.
All real and tangible properties of CenterPoint Houston, subject to certain exclusions, are currently subject to:
- the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and
- the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.
As of December 31, 2005, CenterPoint Houston had outstanding $2.0 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.0 billion of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2005. However, CenterPoint Houston is contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds.
Electric Lines -- Overhead. As of December 31, 2005, CenterPoint Houston owned 27,026 pole miles of overhead distribution lines and 3,621 circuit miles of overhead transmission lines, including 451 circuit miles operated at 69,000 volts, 2,093 circuit miles operated at 138,000 volts and 1,077 circuit miles operated at 345,000 volts.
Electric Lines -- Underground. As of December 31, 2005, CenterPoint Houston owned 16,662 circuit miles of underground distribution lines and 18.8 circuit miles of underground transmission lines, including 4.5 circuit miles operated at 69,000 volts and 14.3 circuit miles operated at 138,000 volts.
Substations. As of December 31, 2005, CenterPoint Houston owned 225 major substation sites having total installed rated transformer capacity of 47,864 megavolt amperes.
Service Centers. CenterPoint Houston operates 16 regional service centers located on a total of 311 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.
Franchises
CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 5 to 50 years.
In June 2005, CenterPoint Houston accepted an ordinance granting it a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two-year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the Additional Amount will be adjusted annually based on the increase, if any, in kWh delivered by CenterPoint Houston within the City of Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case.
NATURAL GAS DISTRIBUTION
CERC's natural gas distribution business engages in regulated intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas through two unincorporated divisions: Minnesota Gas and Southern Gas Operations.
Minnesota Gas provides natural gas distribution services to approximately 780,000 customers in over 240 communities. The largest metropolitan area served by Minnesota Gas is Minneapolis. In 2005, approximately 44% of Minnesota Gas' total throughput was attributable to residential customers and approximately 56% was attributable to commercial and industrial customers. Minnesota Gas also provides unregulated services consisting of heating, ventilating and air conditioning (HVAC) equipment and appliance repair, sales of HVAC, water heating and hearth equipment and home security monitoring.
Southern Gas Operations provides natural gas distribution services to approximately 2.3 million customers in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. The largest metropolitan areas served by Southern Gas Operations are Houston, Texas; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. In 2005, approximately 42% of Southern Gas Operations' total throughput was attributable to residential customers and approximately 58% was attributable to commercial and industrial customers.
The demand for intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers is seasonal. In 2005, approximately 70% of the total throughput of CERC's local distribution companies' business occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during those periods.
Supply and Transportation. In 2005, Minnesota Gas purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Minnesota Gas' major suppliers in 2005 included BP Canada Energy Marketing Corp. (54% of supply volumes), Tenaska Marketing Ventures (11%), ONEOK Energy Services Company, LP (7%) and ConocoPhillips Company (5%). Numerous other suppliers provided the remaining 23% of Minnesota Gas' natural gas supply requirements. Minnesota Gas transports its natural gas supplies through various interstate pipelines under contracts with remaining terms, including extensions, varying from one to sixteen years. We anticipate that these gas supply and transportation contracts will be renewed prior to their expiration.
In 2005, Southern Gas Operations purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to five years. Southern Gas Operations' major suppliers in 2005 included Energy Transfer Company (24% of supply volumes), Kinder Morgan Texas Pipeline Corporation (18%), BP Energy Company (12%), Merrill Lynch Commodities (9%), ONEOK Energy Services Company, LP (7%), and Coral Energy LLC (5%). Numerous other suppliers provided the remaining 25% of Southern Gas Operations' natural gas supply requirements. Southern Gas Operations transports its natural gas supplies through various intrastate and interstate pipelines including CenterPoint Energy's pipeline subsidiaries.
Generally, the regulations of the states in which CERC's natural gas distribution business operates allow it to pass through changes in the costs of natural gas to its customers under purchased gas adjustment provisions in its tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually, using estimated gas costs. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.
Minnesota Gas and Southern Gas Operations use various leased or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. Minnesota Gas also supplements contracted supplies and storage from time to time with stored liquefied natural gas and propane-air plant production.
Minnesota Gas owns and operates an underground storage facility with a capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.1 Bcf available for use during a normal heating season and a maximum
daily withdrawal rate of 50 million cubic feet (MMcf). It also owns nine propane-air plants with a total capacity of 204 MMcf per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf gas equivalent). Minnesota Gas owns liquefied natural gas plant facilities with a 12 million-gallon liquefied natural gas storage tank (1.0 Bcf gas equivalent) and a send-out capability of 72 MMcf per day.
On an ongoing basis, CERC enters into contracts to provide sufficient supplies and pipeline capacity to meet its customer requirements. However, it is possible for limited service disruptions of interruptible customers' load to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.
Assets
As of December 31, 2005, CERC owned approximately 66,000 linear miles of gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by CERC, we own the underground gas mains and service lines, metering and regulating equipment located on customers' premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which CERC receives gas are owned, operated and maintained by others, and its distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on the land owned by suppliers.
Competition
CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end-users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC's facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.
COMPETITIVE NATURAL GAS SALES AND SERVICES
CERC offers variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities through a number of subsidiaries, primarily CenterPoint Energy Services, Inc. (CES). We have reorganized the oversight of our Natural Gas Distribution business segment and, as a result, beginning in the fourth quarter of 2005, we have established a new reportable business segment, Competitive Natural Gas Sales and Services. These operations were previously reported as part of the Natural Gas Distribution business segment.
In 2005, CES marketed approximately 538 Bcf (including 27 Bcf to affiliates) of natural gas, transportation and related energy services to nearly 7,000 customers which vary in size from small commercial to large utility companies in the central and eastern regions of the United States. The business has three operational functions: wholesale, retail and intrastate pipelines further described below.
Wholesale Operations. CES offers a portfolio of physical delivery services and financial products designed to meet wholesale customers' supply and price risk management needs. These customers are served directly through interconnects with various inter- and intra-state pipeline companies, and include gas utilities, large industrial and electric generation customers.
Retail Operations. CES also offers a variety of natural gas management services to smaller commercial and industrial customers, whose facilities are located downstream of natural gas distribution utility city gate stations, including load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES manages transportation contracts and energy supply for retail customers in ten states.
Intrastate Pipeline Operations. Another wholly owned subsidiary of CERC owns and operates approximately 210 miles of intrastate pipeline in Louisiana and Texas. This subsidiary provides bundled and unbundled merchant and transportation services to shippers and end-users.
CES currently transports natural gas on over 30 pipelines throughout the central and eastern United States. CES maintains a portfolio of natural gas supply contracts and firm transportation agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas markets in an effort to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.
As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers' purchase commitments to forecast and arrange its own supply purchases and transportation services to serve customers' natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers' purchase commitments. These supply imbalances arise each month as customers' natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES' processes and risk control environment are designed to measure and value all supply imbalances on a real-time basis to ensure that CES' exposure to commodity price and volume risk is kept to a minimum. The value assigned to these volumetric imbalances is calculated daily and is known as the aggregate Value at Risk (VaR). In 2005, CES' VaR averaged $0.5 million with a high of $3 million.
The CenterPoint Energy Risk Control policy, governed by the Risk Oversight Committee, defines authorized and prohibited trading instruments and volumetric trading limits. CES is a physical marketer of natural gas and uses a variety of tools, including pipeline and storage capacity, financial instruments and physical commodity purchase contracts to support its sales. The CES business optimizes its use of these various tools to minimize its supply costs and does not engage in proprietary or speculative commodity trading. The VaR limits within which CES operates are consistent with its operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply.
Competition
CES competes with regional and national wholesale and retail gas marketers including the marketing divisions of natural gas producers and utilities. In addition, CES competes with intrastate pipelines for customers and services in its market areas.
PIPELINES AND FIELD SERVICES
CERC's pipelines and field services business operates two interstate natural gas pipelines, as well as gas gathering and processing facilities and also provides operating and technical services and remote data monitoring and communication services. The rates charged by interstate pipelines for interstate transportation and storage services are regulated by the FERC.
CERC owns and operates gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's pipeline operations are primarily conducted by two wholly owned interstate pipeline subsidiaries which provide gas transportation and storage services primarily to industrial customers and local distribution companies:
- CenterPoint Energy Gas Transmission Company (CEGT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas; and
- CenterPoint Energy-Mississippi River Transmission Corporation (MRT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas and Missouri.
CERC's pipeline project management and facility operation services are provided to affiliates and third parties through a wholly owned pipeline services subsidiary, CenterPoint Energy Pipeline Services, Inc.
CERC's field services operations are conducted by a wholly owned subsidiary, CenterPoint Energy Field Services, Inc. (CEFS). CEFS provides natural gas gathering and processing services for certain natural gas fields in the Midcontinent basin of the United States that interconnect with CEGT's and MRT's pipelines, as well as other interstate and intrastate pipelines. CEFS operates gathering pipelines, which collect natural gas from approximately 200 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas. CEFS, either directly, or through its 50% interest in the Waskom Joint Venture, processes in excess of 240 MMcf per day of natural gas along its gathering system. CEFS, through its ServiceStar operating division, provides remote data monitoring and communications services to affiliates and third parties. The ServiceStar operating division currently provides monitoring activities at 9,100 locations across Alabama, Arkansas, Colorado, Illinois, Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma, Texas and Wyoming.
In 2005, approximately 20% of our total operating revenue from pipelines and field services was attributable to services provided to Southern Gas Operations and approximately 7% was attributable to services provided to Laclede Gas Company (Laclede), an unaffiliated distribution company that provides natural gas utility service to the greater St. Louis metropolitan area in Illinois and Missouri. Services to Southern Gas Operations and Laclede are provided under several long-term firm storage and transportation agreements. The agreement to provide services to Laclede expires in 2007. We expect that this agreement will be renewed prior to its expiration. Agreements for firm transportation, "no notice" transportation service and storage service in Southern Gas Operations' major service areas (Arkansas, Louisiana and Oklahoma) expire in 2012.
In October 2005, CEGT signed a firm transportation agreement with XTO Energy to transport 600 MMcf per day of natural gas from Carthage, Texas to CEGT's Perryville hub in Northeast Louisiana. To accommodate this transaction, CEGT is in the process of filing applications for certificates with the FERC to build a 172 mile, 42-inch diameter pipeline, and related compression facilities at an estimated cost of $400 million. The final capacity of the pipeline will be between 960 MMcf per day and 1.24 Bcf per day. CEGT expects to have firm contracts for the full capacity of the pipeline prior to its expected in service date in early 2007. During the four year period subsequent to the in service date of the pipeline, XTO can request, and subject to mutual negotiations that meet specific financial parameters, CEGT would construct a 67 mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern Gas Transmission at Union Church, Mississippi.
Our pipelines and field services business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Midcontinent and Gulf Coast natural gas supply regions and general economic conditions.
Assets
We own and operate approximately 8,200 miles of gas transmission lines primarily located in Missouri, Illinois, Arkansas, Louisiana, Oklahoma and Texas. We also own and operate six natural gas storage fields with a combined daily deliverability of approximately 1.2 Bcf per day and a combined working gas capacity of approximately 59.0 Bcf. We also own a 10% interest in Gulf South Pipeline Company, LP's Bistineau storage facility. This facility has a total working gas capacity of 85.7 Bcf and approximately 1.1 Bcf per day of deliverability. Storage capacity in the Bistineau facility is 8 Bcf of working gas with 100 MMcf per day of deliverability. Most storage operations are in north Louisiana and Oklahoma. We also own and operate approximately 4,000 miles of gathering pipelines that collect, treat and process natural gas from approximately 200 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
Competition
Our pipelines and field services business competes with other interstate and intrastate pipelines and gathering companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our pipelines and field services business competes indirectly with other forms of energy available to our customers, including
electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services. In addition, competition for our gathering operations is impacted by commodity pricing levels because of their influence on the level of drilling activity. Both pipeline services and ServiceStar compete with other similar service companies based on market pricing. The principal elements of competition are rates, terms of service and reliability of services.
OTHER OPERATIONS
Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.
DISCONTINUED OPERATIONS
In July 2004, we announced our agreement to sell our majority owned subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed on April 13, 2005.
We recorded an after-tax gain (loss) of $91 million, $(133) million and $(3) million for the years ended December 31, 2003, 2004 and 2005, respectively, related to the operations of Texas Genco. The consolidated financial statements report these operations for all periods presented as discontinued operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
FINANCIAL INFORMATION ABOUT SEGMENTS
For financial information about our segments, see Note 14 to our consolidated financial statements, which note is incorporated herein by reference.
REGULATION
We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below.
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
As a registered public utility holding company under the 1935 Act, we and our subsidiaries were subject to a comprehensive regulatory scheme imposed by the SEC. Although the SEC did not regulate rates and charges under the 1935 Act, it did regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies.
The Energy Act repealed the 1935 Act effective February 8, 2006, and since that date, we and our subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes PUHCA 2005, which grants to the FERC authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require us to notify the FERC of our status as a holding company and to maintain certain books and records and make these available to the FERC. The FERC continues to consider motions for rehearing or clarification of these rules.
FEDERAL ENERGY REGULATORY COMMISSION
The FERC has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in intrastate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. The Energy Act expanded the FERC's authority to prohibit market manipulation in connection with FERC-regulated transactions and gave the FERC additional authority to impose civil penalties for statutory violations and violations of the FERC's rules or orders and also expanded criminal penalties for such violations.
Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates.
CenterPoint Houston is not a "public utility" under the Federal Power Act and therefore is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. The Energy Act provides the FERC the authority to establish mandatory and enforceable service reliability standards for the electric industry. CenterPoint Energy is subject to these standards.
STATE AND LOCAL REGULATION
Electric Transmission & Distribution. CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. In addition, CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 5 to 50 years. As discussed above under "Our Business -- Electric Transmission & Distribution -- Franchises," a new franchise ordinance for the City of Houston franchise was granted in June 2005 with a term of 30 years. There are a total of 37 cities whose franchises will expire in 2007 and 2008. CenterPoint Houston expects to be able to renew these expiring franchises.
All retail electric providers in CenterPoint Houston's service area pay the same rates and other charges for the same transmission and distribution services.
CenterPoint Houston's distribution rates charged to retail electric providers for residential customers are based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are based on peak demand. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under "postage stamp" rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services. The transmission and distribution rates for CenterPoint Houston have been in effect since electric competition began. This regulated delivery charge includes the transmission and distribution rate (which includes municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility (South Texas Project), transition charges associated with securitization of regulatory assets and securitization of stranded costs, a competition transition charge for collection of the true-up balance not securitized and a rate case expense charge.
As discussed above under "Electric Transmission & Distribution -- CenterPoint Houston Rate Case," in December 2005, the Texas Utility Commission agreed to initiate a rate proceeding concerning the reasonable-
ness of CenterPoint Houston's existing rates for transmission and distribution service and to require CenterPoint Houston to make a filing by April 15, 2006 to justify or change those rates.
Natural Gas Distribution. In almost all communities in which CERC provides natural gas distribution services, it operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, though franchises in Arkansas are perpetual. None of CERC's material franchises expire in the near term. CERC expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.
Substantially all of CERC's retail natural gas sales by its local distribution divisions are subject to traditional cost-of-service regulation at rates regulated by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and certain municipalities CERC serves.
SOUTHERN GAS OPERATIONS
In November 2004, Southern Gas Operations filed an application for a $34 million base rate increase, which was subsequently adjusted downward to $28 million, with the Arkansas Public Service Commission (APSC). In September 2005, an $11 million rate reduction (which included a $10 million reduction relating to depreciation rates) ordered by the APSC went into effect. The reduced depreciation rates were implemented effective October 2005. This base rate reduction and corresponding reduction in depreciation expense represent an annualized operating income reduction of $1 million.
In April 2005, the Railroad Commission established new gas tariffs that increased Southern Gas Operations' base rate and service revenues by a combined $2 million in the unincorporated environs of its Beaumont/East Texas and South Texas Divisions. In June and August 2005, Southern Gas Operations filed requests to implement these same rates within 169 incorporated cities located in the two divisions. The proposed rates were approved or became effective by operation of law in 164 of these cities. Five municipalities denied the rate change requests within their respective jurisdictions. Southern Gas Operations has appealed the actions of these five cities to the Railroad Commission. In February 2006, Southern Gas Operations notified the Railroad Commission that it had reached a settlement with four of the five cities. If approved, the settlement will affect rates in a total of 60 cities in the South Texas Division. In addition, 19 cities where rates have already gone into effect have challenged the jurisdictional and statutory basis for implementation of the new rates within their respective jurisdictions. Southern Gas Operations has petitioned the Railroad Commission for an order declaring that the new rates have been properly established within these 19 cities. If the settlement is approved and assuming all other rate change proposals become effective, revenues from Southern Gas Operations' base rates and miscellaneous service charges would increase by an additional $17 million annually. Currently, approximately $15 million of this expected annual increase is in effect in the incorporated areas of Southern Gas Operations' Beaumont/East Texas and South Texas Divisions.
In October 2005, Southern Gas Operations filed requests with the Louisiana Public Service Commission (LPSC) for approximately $2 million in base rate increases for its South Louisiana service territory and approximately $2 million in base rate reductions for its North Louisiana service territory in accordance with the Rate Stabilization Plans in its tariffs. These base rate changes became effective on January 2, 2006 in accordance with the tariffs and are subject to review and possible adjustment by the staff of the LPSC. Southern Gas Operations is unable to predict when the LPSC staff may conclude its review or what adjustments, if any, the staff may recommend.
In December 2005, Southern Gas Operations filed a request with the Mississippi Public Service Commission (MPSC) for approximately $1 million in miscellaneous service charges (e.g., charges to connect service, charges for returned checks, etc.) in its Mississippi service territory. This request was approved in the first quarter of 2006.
In addition, in January and February 2006, Southern Gas Operations filed requests with the MPSC for approximately $3 million in base rate increases in its Mississippi service territory in accordance with the Automatic Rate Adjustment Mechanism provisions in its tariffs and an additional $2 million in surcharges to recover system restoration expenses incurred following hurricane Katrina. Both requests are being reviewed by the MPSC staff with a decision expected in the first quarter of 2006.
MINNESOTA GAS
In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a settlement which increased Minnesota Gas' base rates by approximately $9 million annually. An interim rate increase of approximately $17 million had been implemented in October 2004. Substantially all of the excess amounts collected in interim rates over those approved in the final settlement were refunded to customers in the third quarter of 2005.
In November 2005, Minnesota Gas filed a request with the MPUC to increase annual rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. Any excess of amounts collected under the interim rates over the amounts approved in final rates is subject to refund to customers. A decision by the MPUC is expected in the third quarter of 2006.
In December 2004, the MPUC opened an investigation to determine whether Minnesota Gas' practices regarding restoring natural gas service during the period between October 15 and April 15 (Cold Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs disconnection and reconnection of customers during the Cold Weather Period. The Minnesota Office of the Attorney General (OAG) issued its report alleging Minnesota Gas has violated the CWR and recommended a $5 million penalty. Minnesota Gas and the OAG have reached an agreement on procedures to be followed for the current Cold Weather Period which began on October 15, 2005. In addition, in June 2005, CERC was named in a suit filed in the United States District Court, District of Minnesota on behalf of a purported class of customers who allege that Minnesota Gas' conduct under the CWR was in violation of the law. Minnesota Gas is in settlement discussions regarding both the OAG's action and the action on behalf of the purported class.
DEPARTMENT OF TRANSPORTATION
In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (the Act). This legislation applies to our interstate pipelines as well as our intrastate pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires pipeline and distribution companies to assess the integrity of their pipeline transmission facilities in areas of high population concentration or High Consequence Areas (HCA). The legislation further requires companies to perform remediation activities, in accordance with the requirements of the legislation, over a 10-year period.
Final regulations implementing the Act became effective on February 14, 2004 and provided guidance on, among other things, the areas that should be classified as HCA.
Our interstate and intrastate pipelines and our natural gas distribution companies anticipate that compliance with these regulations will require increases in both capital and operating cost. The level of expenditures required to comply with these regulations will be dependent on several factors, including the age of the facility, the pressures at which the facility operates and the number of facilities deemed to be located in areas designated as HCA. Based on our interpretation of the rules and preliminary technical reviews, we believe compliance will require average annual expenditures of approximately $15 to $20 million during the initial 10-year period.
ENVIRONMENTAL MATTERS
Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines, gas gathering and processing systems, and
electric transmission and distribution systems we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
- restricting the way we can handle or dispose of our wastes;
- limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
- requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and
- enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.
In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:
- construct or acquire new equipment;
- acquire permits for facility operations;
- modify or replace existing and proposed equipment; and
- clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
Based on current regulatory requirements and interpretations, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental remediation activities in which we are presently engaged will not materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.
AIR EMISSIONS
Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
WATER DISCHARGES
Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.
HAZARDOUS WASTE
Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.
LIABILITY FOR REMEDIATION
The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), also known as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is excluded from CERCLA's definition of a "hazardous substance," in the course of our ordinary operations we generate wastes that may fall within the definition of a "hazardous substance." CERCLA authorizes the United States Environmental Protection Agency (EPA) and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.
LIABILITY FOR PREEXISTING CONDITIONS
Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical
contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.
Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. In the pending litigation, the plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. We do not expect the ultimate cost associated with resolving this matter to have a material impact on our financial condition, results of operations or cash flows or that of CERC.
Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.
At December 31, 2005, CERC had accrued $14 million for remediation of these Minnesota sites. At December 31, 2005, the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of December 31, 2005, CERC has collected $13 million from insurance companies and ratepayers to be used for future environmental remediation.
In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned or operated by one of its former affiliates. CERC has been named as a defendant in two lawsuits under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of one of the lawsuits. In March 2005, the court considering the other suit for contribution granted CERC's motion to dismiss on the grounds that CERC was not an "operator" of the site as had been alleged. The plaintiff in that case has filed an appeal of the court's dismissal of CERC. We are investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of those sites under CERCLA and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP.
Mercury Contamination. Our pipeline and natural gas distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. We have found this type of contamination at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows.
Other Environmental. From time to time, we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Although their ultimate outcome cannot be predicted at this time, we do not
believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
Asbestos. Some of our facilities contain or have contained asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations we own, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by Texas Genco LLC. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between us and Texas Genco, ultimate financial responsibility for uninsured losses from these claims relating to facilities transferred to Texas Genco has been assumed by Texas Genco, but under the terms of our agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to defend such claims to the extent they are covered by insurance we maintain, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.
REGULATORY MATTERS RELATING TO DISCONTINUED OPERATIONS
Texas Genco and the other owners of the South Texas Project are required by NRC regulations to estimate from time to time the amounts required to decommission that nuclear generating facility and are required to maintain funds to satisfy that obligation when the plant ultimately is decommissioned. Although CenterPoint Houston no longer owns an interest in the South Texas Project, CenterPoint Houston currently collects through a separate nuclear decommissioning charge amounts calculated to provide sufficient funds at the time of decommissioning to discharge these obligations. Funds collected are deposited into nuclear decommissioning trusts. The beneficial ownership of the nuclear decommissioning trusts is held by a subsidiary of Texas Genco LLC as a licensee of the facility. While current funding levels exceed NRC minimum requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and waste burial. In the event that funds from the trust are inadequate to decommission the facilities, CenterPoint Houston will be required by the transaction agreement with Texas Genco LLC to collect through rates or other authorized charges all additional amounts required to fund Texas Genco LLC's obligations relating to the decommissioning of the South Texas Project.
EMPLOYEES
As of December 31, 2005, we had 9,001 full-time employees. The following table sets forth the number of our employees by business segment:
As of December 31, 2005, approximately 30% of the Company's employees are subject to collective bargaining agreements. Two of these agreements, covering approximately 19% of the Company's employees will expire in 2006. Minnesota Gas has 466 bargaining unit employees who are covered by a collective bargaining unit agreement with the United Association of Journeymen and Apprentices of Plumbing and Pipe Fitting Industry of the United States and Canada Local 340 that expires in April 2006. CenterPoint Houston has 1,225 bargaining unit employees who are covered by a collective bargaining unit agreement with the International Brotherhood of Electrical Workers Local 66, that expires in May 2006. We have a good relationship with these bargaining units and expect to renegotiate new agreements in 2006.
EXECUTIVE OFFICERS (AS OF FEBRUARY 28, 2006)
DAVID M. MCCLANAHAN has been President and Chief Executive Officer and a director of CenterPoint Energy since September 2002. He served as Vice Chairman of Reliant Energy, Incorporated (Reliant Energy) from October 2000 to September 2002 and as President and Chief Operating Office of Reliant Energy's Delivery Group from April 1999 to September 2002. He has served in various executive capacities with CenterPoint Energy since 1986. He previously served as Chairman of the Board of Directors of ERCOT and Chairman of the Board of the University of St. Thomas in Houston. He currently serves on the boards of the Edison Electric Institute and the American Gas Association.
SCOTT E. ROZZELL has served as Executive Vice President, General Counsel and Corporate Secretary of CenterPoint Energy since September 2002. He served as Executive Vice President and General Counsel of the Delivery Group of Reliant Energy from March 2001 to September 2002. Before joining CenterPoint Energy in 2001, Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P. He currently serves as Chair of the Association of Electric Companies of Texas.
GARY L. WHITLOCK has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since September 2002. He served as Executive Vice President and Chief Financial Officer of the Delivery Group of Reliant Energy from July 2001 to September 2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company, from 1998 to 2001.
JAMES S. BRIAN has served as Senior Vice President and Chief Accounting Officer of CenterPoint Energy since August 2002. He served as Senior Vice President, Finance and Administration of the Delivery Group of Reliant Energy from 1999 to August 2002. Mr. Brian has served in various executive capacities with CenterPoint Energy since 1983.
BYRON R. KELLEY has served as Senior Vice President and Group President -- CenterPoint Energy Pipelines and Field Services since June 2004, having previously served as President and Chief Operating Officer of CenterPoint Energy Pipelines and Field Services from May 2003 to June 2004. Prior to joining CenterPoint Energy he served as President of El Paso International, a subsidiary of El Paso Corporation, from January 2001 to August 2002. He currently serves on the Board of Directors of the Interstate Natural Gas Association of America.
THOMAS R. STANDISH has served as Senior Vice President and Group President-Regulated Operations of CenterPoint Energy since August 2005, having previously served as Senior Vice President and Group President and Chief Operating Officer of CenterPoint Houston from June 2004 to August 2005 and as President and Chief Operating Officer of CenterPoint Houston from August 2002 to June 2004. He served as President and Chief Operating Officer for both electricity and natural gas for Reliant Energy's Houston area from 1999 to August 2002. Mr. Standish has served in various executive capacities with CenterPoint Energy since 1993. He currently serves on the Board of Directors of ERCOT.
ITEM 1A.
ITEM 1A. RISK FACTORS
We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries:
RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS
CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN ULTIMATELY RECOVERING THE FULL VALUE OF ITS TRUE-UP COMPONENTS, WHICH COULD RESULT IN THE ELIMINATION OF CERTAIN TAX BENEFITS AND COULD HAVE AN ADVERSE IMPACT ON CENTERPOINT HOUSTON'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission's rulings. The judgment would have the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of an inaccurate stranded cost estimate made by the Texas Utility Commission in 2000. Additional credits of approximately $30 million were paid after August 2004. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. CenterPoint Houston and other parties appealed the district court decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but oral argument has not yet been scheduled. No prediction can be made as to the ultimate outcome or timing of such appeals. Additionally, if the amount of the true-up balance is reduced on appeal to below the amount recovered through the issuance of transition bonds and under the CTC, while the amount of transition bonds outstanding would not be reduced, CenterPoint Houston would be required to refund the over recovery to its customers.
Among the issues raised in our appeal of the True-Up Order is the Texas Utility Commission's reduction of our stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with our former Texas Genco assets. Such reduction was considered in our recording of an after-tax extraordinary loss of $977 million in the last half of 2004. We believe that the Texas Utility Commission based its order on proposed regulations issued by the IRS in March 2003 related to those tax benefits. Those proposed regulations would have allowed utilities which were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of ADITC and EDFIT back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. If the December 2005 proposed regulations become effective and if the Texas Utility Commission's order on this issue is not reversed on appeal or the amount of the tax benefits is not otherwise restored by the Texas Utility Commission, the IRS is likely to consider that a "normalization violation" has occurred. If so, the IRS could require us to pay an amount equal to CenterPoint Houston's unamortized ADITC balance as of the date that the normalization violation was deemed to have occurred. In addition, if a normalization violation is deemed to have occurred, the IRS could also deny CenterPoint Houston the ability to elect accelerated depreciation benefits. If a normalization violation should ultimately be found to exist, it could have an adverse impact on our results of operations, financial condition and cash flows. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation.
CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL ELECTRIC PROVIDERS, AND ANY DELAY OR DEFAULT IN PAYMENT COULD ADVERSELY AFFECT CENTERPOINT HOUSTON'S CASH FLOWS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
CenterPoint Houston's receivables from the distribution of electricity are collected from retail electric providers that supply the electricity CenterPoint Houston distributes to their customers. Currently, CenterPoint Houston does business with 66 retail electric providers. Adverse economic conditions, structural problems in the market served by the Electric Reliability Council of Texas, Inc. (ERCOT) or financial difficulties of one or more retail electric providers could impair the ability of these retail providers to pay for CenterPoint Houston's services or could cause them to delay such payments. CenterPoint Houston depends on these retail electric providers to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a retail electric provider cannot make timely payments. RRI, through its subsidiaries, is CenterPoint Houston's largest customer. Approximately 56% of CenterPoint Houston's $127 million in billed receivables from retail electric providers at December 31, 2005 was owed by subsidiaries of RRI. Any delay or default in payment could adversely affect CenterPoint Houston's cash flows, financial condition and results of operations.
RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY CENTERPOINT HOUSTON'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER ITS COSTS.
CenterPoint Houston's rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston's costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.
DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION SERVICES.
CenterPoint Houston transmits and distributes to customers of retail electric providers electric power that the retail electric providers obtain from power generation facilities owned by third parties. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston's sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows may be adversely affected.
CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A significant portion of CenterPoint Houston's revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of such retail electric provider. Thus, CenterPoint Houston's revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.
RISK FACTORS AFFECTING OUR NATURAL GAS DISTRIBUTION, COMPETITIVE NATURAL GAS SALES AND SERVICES AND PIPELINES AND FIELD SERVICES BUSINESSES
RATE REGULATION OF CERC'S BUSINESS MAY DELAY OR DENY CERC'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER ITS COSTS.
CERC's rates for its local distribution companies are regulated by certain municipalities and state commissions, and for its interstate pipelines by the FERC, based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC's costs and enable CERC to earn a reasonable return on its invested capital.
CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD LEAD TO LESS NATURAL GAS BEING MARKETED, AND ITS PIPELINES AND FIELD SERVICES BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION, STORAGE, GATHERING, TREATING AND PROCESSING OF NATURAL GAS, WHICH COULD LEAD TO LOWER PRICES, EITHER OF WHICH COULD HAVE AN ADVERSE IMPACT ON CERC'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC's results of operations, financial condition and cash flows.
CERC's two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of CERC's competitors could lead to lower prices, which may have an adverse impact on CERC's results of operations, financial condition and cash flows.
CERC'S NATURAL GAS DISTRIBUTION AND COMPETITIVE NATURAL GAS SALES AND SERVICES BUSINESSES ARE SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS, WHICH COULD AFFECT THE ABILITY OF CERC'S SUPPLIERS AND CUSTOMERS TO MEET THEIR OBLIGATIONS OR OTHERWISE ADVERSELY AFFECT CERC'S LIQUIDITY.
CERC is subject to risk associated with increases in the price of natural gas, which has been the trend in recent years. Increases in natural gas prices might affect CERC's ability to collect balances due from its customers and, on the regulated side, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC's tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which CERC operates and increase the risk that CERC's suppliers or customers fail or are unable to meet their obligations. Additionally, increasing gas prices could create the need for CERC to provide collateral in order to purchase gas.
IF CERC WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF ITS SIGNIFICANT PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS OPERATIONS.
CERC's contract with Laclede Gas Company, one of its pipeline's customers, is currently scheduled to expire in 2007. To the extent the pipeline is unable to extend this contract or the contract is renegotiated at rates substantially less than the rates provided in the current contract, there could be an adverse effect on CERC's results of operations, financial condition and cash flows.
A DECLINE IN CERC'S CREDIT RATING COULD RESULT IN CERC'S HAVING TO PROVIDE COLLATERAL IN ORDER TO PURCHASE GAS.
If CERC's credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC might be unable to obtain the necessary natural gas to meet its obligations to customers, and its results of operations, financial condition and cash flows would be adversely affected.
CERC'S PIPELINES' AND FIELD SERVICES' BUSINESS REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS.
CERC's pipelines and field services business largely relies on gas sourced in the various supply basins located in the Midcontinent region of the United States. To the extent the availability of this supply is
substantially reduced, it could have an adverse effect on CERC's results of operations, financial condition and cash flows.
CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A substantial portion of CERC's revenues is derived from natural gas sales and transportation. Thus, CERC's revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.
RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION
IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY TO REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED.
As of December 31, 2005, we had $8.9 billion of outstanding indebtedness on a consolidated basis, which includes $2.5 billion of non-recourse transition bonds. As of December 31, 2005, approximately $665 million principal amount of this debt must be paid through 2008. This amount excludes principal repayments of approximately $379 million on transition bonds, for which a dedicated revenue stream exists. In addition, we have $830 million of outstanding convertible notes on which holders could exercise their "put" rights during this period. Our future financing activities may depend, at least in part, on:
- the timing and amount of our recovery of the true-up components, including, in particular, the results of appeals to the courts of determinations on rulings obtained to date;
- general economic and capital market conditions;
- credit availability from financial institutions and other lenders;
- investor confidence in us and the market in which we operate;
- maintenance of acceptable credit ratings;
- market expectations regarding our future earnings and probable cash flows;
- market perceptions of our ability to access capital markets on reasonable terms;
- our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; and
- provisions of relevant tax and securities laws.
As of December 31, 2005, CenterPoint Houston had outstanding $2.0 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.0 billion of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2005. However, CenterPoint Houston is contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds.
Our current credit ratings are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 7 of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction
or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.
AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MEET OUR PAYMENT OBLIGATIONS, AND PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD LIMIT THE AMOUNT OF THOSE DISTRIBUTIONS.
We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit their ability to make payments or other distributions to us, and they could agree to contractual restrictions on their ability to make distributions.
Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.
THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES.
We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
RISKS COMMON TO OUR BUSINESSES AND OTHER RISKS
WE ARE SUBJECT TO OPERATIONAL AND FINANCIAL RISKS AND LIABILITIES ARISING FROM ENVIRONMENTAL LAWS AND REGULATIONS.
Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
- restricting the way we can handle or dispose of our wastes;
- limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
- requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and
- enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.
In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:
- construct or acquire new equipment;
- acquire permits for facility operations;
- modify or replace existing and proposed equipment; and
- clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.
In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. If CenterPoint Houston were to sustain any loss of, or damage to, its transmission and distribution properties, it may not be able to recover such loss or damage through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.
WE, CENTERPOINT HOUSTON AND CERC COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS.
Under some circumstances, we and CenterPoint Houston could incur liabilities associated with assets and businesses we and CenterPoint Houston no longer own. These assets and businesses were previously owned by Reliant Energy, a predecessor of CenterPoint Houston, directly or through subsidiaries and include:
- those transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and
- those transferred to Texas Genco in connection with its organization and capitalization.
In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. The indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy has not been released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.
Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI's trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guarantee obligations prior to separation, but when separation occurred in September 2002, RRI had been unable to extinguish all
obligations. To secure CenterPoint Energy and CERC against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of CERC and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guarantees. Our current exposure under the remaining guarantees relates to CERC's guarantee of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. As a result of changes in market conditions, CenterPoint Energy's potential exposure under that guarantee currently exceeds the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC's obligations under the guarantee, and CenterPoint Energy and RRI are pursuing alternatives. RRI continues to meet its obligations under the transportation contracts.
RRI's unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI's creditors might be made against us as its former owner.
Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of power sales in California and other West Coast markets and financial reporting matters. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include the effect of RRI's financial results on Reliant Energy's historical financial statements and liability of Reliant Energy as a controlling shareholder of RRI. We or CenterPoint Houston could incur liability if claims in one or more of these lawsuits were successfully asserted against us or CenterPoint Houston and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.
In connection with the organization and capitalization of Texas Genco, Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were obligations of CenterPoint Houston and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco, regardless of the time those liabilities arose. In connection with the sale of Texas Genco's fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC, the separation agreement we entered into with Texas Genco in connection with the organization and capitalization of Texas Genco was amended to provide that all of Texas Genco's rights and obligations under the separation agreement relating to its fossil generation assets, including Texas Genco's obligation to indemnify us with respect to liabilities associated with the fossil generation assets and related business, were assigned to and assumed by Texas Genco LLC. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and CenterPoint Energy has assumed and agreed to indemnify Texas Genco LLC against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies or other similar agreements held by CenterPoint Energy. If Texas Genco or Texas Genco LLC were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.
We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations we own, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by Texas Genco LLC. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between us and Texas Genco, ultimate financial responsibility for uninsured losses from claims relating to facilities transferred
to Texas Genco has been assumed by Texas Genco, but under the terms of our agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to defend such claims to the extent they are covered by insurance we maintain, subject to reimbursement of the costs of such defense from Texas Genco LLC.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES
CHARACTER OF OWNERSHIP
We own or lease our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.
ELECTRIC TRANSMISSION & DISTRIBUTION
For information regarding the properties of our Electric Transmission & Distribution business segment, please read "Our Business -- Electric Transmission & Distribution -- Properties" in Item 1 of this report, which information is incorporated herein by reference.
NATURAL GAS DISTRIBUTION
For information regarding the properties of our Natural Gas Distribution business segment, please read "Our Business -- Natural Gas Distribution -- Assets" in Item 1 of this report, which information is incorporated herein by reference.
PIPELINES AND FIELD SERVICES
For information regarding the properties of our Pipelines and Field Services business segment, please read "Our Business -- Pipelines and Field Services -- Assets" in Item 1 of this report, which information is incorporated herein by reference.
OTHER OPERATIONS
For information regarding the properties of our Other Operations business segment, please read "Our Business -- Other Operations" in Item 1 of this report, which information is incorporated herein by reference.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
For a discussion of material legal and regulatory proceedings affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 4 and 10(d) to our consolidated financial statements, which information is incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to the vote of our security holders during the fourth quarter of 2005.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of February 28, 2006, our common stock was held of record by approximately 54,679 shareholders. Our common stock is listed on the New York and Chicago Stock Exchanges and is traded under the symbol "CNP."
The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the New York Stock Exchange composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods. Cash dividends paid aggregated $0.40 per share in both 2004 and 2005.
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(1) During 2005, we paid irregular quarterly dividends based on earnings in each specific quarter in order to comply with requirements under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The 1935 Act, with its requirements associated with dividends, has been repealed effective as of February 8, 2006.
The closing market price of our common stock on December 31, 2005 was $12.85 per share.
The amount of future cash dividends will be subject to determination based upon our results of operations and financial condition, our future business prospects, any applicable contractual restrictions and other factors that our board of directors considers relevant and will be declared at the discretion of the board of directors.
On January 26, 2006, we announced a regular quarterly cash dividend of $0.15 per share, payable on March 10, 2006 to shareholders of record on February 16, 2006.
Repurchases of Equity Securities
During the quarter ended December 31, 2005, none of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our "affiliated purchasers," as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report.
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(1) 2001 net income includes the cumulative effect of an accounting change resulting from the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ($58 million after-tax gain, or $0.20 earnings per basic and diluted share).
(2) 2003 net income includes the cumulative effect of an accounting change resulting from the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" ($80 million after-tax gain, or $0.26 and $0.24 earnings per basic and diluted share, respectively), which is included in discontinued operations related to Texas Genco.
(3) 2004 net income includes an after-tax extraordinary loss of $977 million ($3.18 and $2.72 loss per basic and diluted share, respectively) based on our analysis of the Texas Utility Commission's order in the 2004 True-Up Proceeding. Additionally, we recorded a net after-tax loss of approximately $133 million ($0.43 and $0.37 loss per basic and diluted share, respectively) in 2004 related to our interest in Texas Genco.
(4) 2005 net income includes an after-tax extraordinary gain of $30 million ($0.10 and $0.09 per basic and diluted share, respectively) recorded in the first quarter reflecting an adjustment to the extraordinary loss recorded in the last half of 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.
(5) The subsidiary trusts that issued trust preferred securities have been deconsolidated as a result of the adoption of FIN 46 "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46) and the subordinated debentures issued to those trusts were reported as long-term debt effective December 31, 2003.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in combination with our consolidated financial statements included in Item 8 herein.
OVERVIEW
BACKGROUND
We are a public utility holding company whose indirect wholly owned subsidiaries include:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which provides electric transmission and distribution services to retail electric providers serving approximately 1.9 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 4.8 million people and includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns gas distribution systems serving approximately 3.1 million customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Through wholly owned subsidiaries, CERC also owns two interstate natural gas pipelines and gas gathering systems, provides various ancillary services, and offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.
We were a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). The 1935 Act and related rules and regulations imposed a number of restrictions on our activities and those of our subsidiaries. The Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since that date we and our subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005), which grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require us to notify the FERC of our status as a holding company and to maintain certain books and records and make these available to the FERC. The FERC continues to consider motions for rehearing or clarification of these rules.
BUSINESS SEGMENTS
In this section, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and critical accounting policies. CenterPoint Energy is first and foremost an energy delivery company and it is our intention to remain focused on this segment of the energy business. The results of our business operations are significantly impacted by weather, customer growth, cost management, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to which we are subject. Our transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. Our natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution business segment. Our reportable business segments include:
Electric Transmission & Distribution
Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers serving approximately 1.9 million metered customers in a 5,000-square-mile area of the Texas Gulf coast that has a population of approximately 4.8 million people and includes Houston.
On behalf of retail electric providers, CenterPoint Houston delivers electricity from power plants to substations and from one substation to another and to retail electric customers in locations throughout the control area managed by the Electric Reliability Council of Texas, Inc. (ERCOT). ERCOT serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally owned electric utilities, rural electric cooperatives, independent generators, power marketers and retail electric providers. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation's largest power markets. Transmission services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).
Operations include construction and maintenance of electric transmission and distribution facilities, metering services, outage response services and other call center operations. Distribution services are provided under tariffs approved by the Texas Utility Commission.
Natural Gas Distribution
CERC owns and operates our regulated natural gas distribution business, which engages in intrastate natural gas sales to, and natural gas transportation for, approximately 3.1 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.
Competitive Natural Gas Sales and Services
CERC's operations also include non-rate regulated natural gas sales and services provided primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. We have reorganized the oversight of our Natural Gas Distribution business segment and, as a result, beginning in the fourth quarter of 2005, we have established a new reportable business segment, Competitive Natural Gas Sales and Services. These operations were previously reported as part of the Natural Gas Distribution business segment. We have reclassified all prior period segment information to conform to this new presentation.
Pipelines and Field Services
CERC's pipelines and field services business owns and operates approximately 8,200 miles of gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's pipelines and field services business also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.2 Bcf per day and a combined working gas capacity of approximately 59.0 Bcf. Most storage operations are in north Louisiana and Oklahoma. CERC's pipelines and field services business also owns and operates approximately 4,000 miles of gathering pipelines that collect, treat and process natural gas from approximately 200 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
Other Operations
Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.
EXECUTIVE SUMMARY
SIGNIFICANT EVENTS IN 2005
RECOVERY OF TRUE-UP BALANCE/SECURITIZATION FINANCING
The Texas Electric Choice Plan (Texas electric restructuring law), which became effective in September 1999, substantially amended the regulatory structure governing electric utilities in order to allow retail competition for electric customers beginning in January 2002. The Texas electric restructuring law requires the Texas Utility Commission to conduct a "true-up" proceeding to determine CenterPoint Houston's stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission's rulings. The judgment would have the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of an inaccurate stranded cost estimate made by the Texas Utility Commission in 2000. Additional credits of approximately $30 million were paid after August 2004. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. CenterPoint Houston and other parties appealed the district court decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but oral argument has not yet been scheduled.
There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.
In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC which will collect approximately $596 million over 14 years plus interest at an annual rate of 11.075 percent (CTC Order). The CTC Order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. The CTC Order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. During the period from September 13, 2005, the date of implementation of the CTC Order, through December 31, 2005, CenterPoint Houston recognized approximately $21 million in CTC operating income. Certain parties appealed the CTC Order to the Travis County Court in September 2005.
Under the True-Up Order, CenterPoint Houston is allowed to recover carrying charges at 11.075 percent until the true-up balance is recovered. In January 2006, the Texas Utility Commission staff (Staff) proposed that the Texas Utility Commission adopt new rules governing the carrying charges on unrecovered true-up
balances. If the Texas Utility Commission adopts the rule as the Staff proposed it and the rule is deemed to apply to CenterPoint Houston, the rule would reduce carrying costs on the unrecovered CTC balance prospectively from 11.075 percent to the utility's cost of debt.
CENTERPOINT HOUSTON RATE CASE
The Texas Utility Commission requires each electric utility to file an annual Earnings Report providing certain information to enable the Texas Utility Commission to monitor the electric utilities' earnings and financial condition within the state. In May 2005, CenterPoint Houston filed its Earnings Report for the calendar year ended December 31, 2004. CenterPoint Houston's Earnings Report shows that it earned less than its authorized rate of return on equity in 2004.
In October 2005, the Staff filed a memorandum summarizing its review of the Earnings Reports filed by electric utilities. Based on its review, the Staff concluded that continuation of CenterPoint Houston's rates could result in excess retail transmission and distribution revenues of as much as $105 million and excess wholesale transmission revenues of as much as $31 million annually and recommended that the Texas Utility Commission initiate a review of the reasonableness of existing rates. The Staff's analysis was based on a 9.60 percent cost of equity, which is 165 basis points lower than the approved return on equity from CenterPoint Houston's last rate proceeding, the elimination of interest on debt that matured in November 2005 and certain other adjustments to CenterPoint Houston's reported information. Additionally, a hypothetical capital structure of 60 percent debt and 40 percent equity was used which varies materially from the actual capital structure of CenterPoint Houston as of December 31, 2005 of approximately 50 percent debt and 50 percent equity.
In December 2005, the Texas Utility Commission considered the Staff report and agreed to initiate a rate proceeding concerning the reasonableness of CenterPoint Houston's existing rates for transmission and distribution service and to require CenterPoint Houston to make a filing by April 15, 2006 to justify or change those rates.
CITY OF HOUSTON FRANCHISE
In June 2005, CenterPoint Houston accepted an ordinance granting it a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two-year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the Additional Amount will be adjusted annually based on the increase, if any, in kWh delivered by CenterPoint Houston within the City of Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case.
DEBT FINANCING TRANSACTIONS
During the fourth quarter of 2005, CenterPoint Houston retired at maturity its $1.31 billion term loan, which bore interest at the London inter-bank offer rate (LIBOR) plus 975 basis points, subject to a minimum LIBOR rate of 3 percent. CenterPoint Houston used its $1.31 billion credit facility bearing interest at LIBOR plus 75 basis points to retire the term loan. Borrowings under the credit facility were subsequently repaid with a portion of the proceeds of the $1.85 billion transition bonds referred to above.
In August 2005, we accepted for exchange approximately $572 million aggregate principal amount of our 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of our new 3.75% convertible senior notes due 2023 (New Notes). Old Notes of approximately $3 million remain outstanding. We commenced the exchange offer in response to the guidance set forth in Emerging Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the principal portion of the New Notes will be made in cash rather than stock, the exchange of New Notes for Old Notes will allow us to exclude the portion of the conversion value of the New Notes attributable to their principal amount from our computation of diluted earnings per share from continuing operations.
SALE OF TEXAS GENCO
In July 2004, we announced our agreement to sell our majority-owned generating subsidiary, Texas Genco Holdings, Inc. (Texas Genco), to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed on April 13, 2005. The operations of Texas Genco, formerly presented as our Electric Generation business segment, are presented as discontinued operations.
2005 HIGHLIGHTS
Our operating performance for 2005 compared to 2004 was affected by:
- increased operating income of $55 million in our Pipelines and Field Services business segment primarily from increased demand for transportation resulting from basis differentials across the system and higher demand for ancillary services and increased throughput and demand for services related to our core gas gathering operations;
- increased operating income of $16 million in our Competitive Natural Gas Sales and Services business segment primarily from higher sales to utilities and favorable basis differentials over the pipeline capacity that we control;
- a decreased operating loss of $14 million in our Other Operations business segment primarily from increased overhead allocated in 2005;
- continued customer growth, with the addition of 105,000 metered electric and gas customers;
- a decrease in interest expense of $67 million; and
- a decrease in the return on the true-up balance of $105 million in 2005, partially offset by an increase in operating income of $21 million related to the return on the true-up balance being recovered through the CTC. This decrease is primarily due to the recording of the return on the true-up balance for 2002 through 2004 in the fourth quarter of 2004.
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including:
- the timing and amount of our recovery of the true-up components, including, in particular, the results of appeals to the courts of determinations on rulings obtained to date;
- state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, changes in or application of laws or regulations applicable to other aspects of our business and actions with respect to:
- allowed rates of return;
- rate structures;
- recovery of investments; and
- operation and construction of facilities;
- timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
- industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;
- the timing and extent of changes in commodity prices, particularly natural gas;
- changes in interest rates or rates of inflation;
- weather variations and other natural phenomena;
- the timing and extent of changes in the supply of natural gas;
- commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;
- actions by rating agencies;
- effectiveness of our risk management activities;
- inability of various counterparties to meet their obligations to us;
- non-payment for our services due to financial distress of our customers, including Reliant Energy, Inc. (RRI);
- the ability of RRI to satisfy its obligations to us, including indemnity obligations;
- our ability to control costs;
- the investment performance of our employee benefit plans;
- our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will provide the anticipated benefits to us; and
- other factors we discuss under "Risk Factors" in Item 1A of this report.
CONSOLIDATED RESULTS OF OPERATIONS
All dollar amounts in the tables that follow are in millions, except for per share amounts.
2005 COMPARED TO 2004
Income from Continuing Operations. We reported income from continuing operations before extraordinary item of $225 million ($0.67 per diluted share) for 2005 as compared to $205 million ($0.61 per diluted share) for 2004. The increase in income from continuing operations of $20 million was primarily due to increased operating income of $55 million in our Pipelines and Field Services business segment resulting from increased demand for transportation resulting from basis differentials across the system and higher demand for ancillary services as well as increased throughput and demand for services related to our core gas gathering operations, increased operating income of $16 million in our Competitive Natural Gas Sales and Services business segment primarily due to higher sales to utilities and favorable basis differentials over the pipeline capacity that we control, a decrease in the operating loss of $14 million in our Other Operations business segment resulting from increased overhead allocated in 2005 and a $67 million decrease in interest expense due to lower borrowing levels and lower borrowing costs reflecting the replacement of certain of our credit facilities. The above increases were partially offset by a decrease of $105 million in the return on the true-up
balance of our Electric Transmission & Distribution business segment as a result of the True-Up Order, partially offset by an increase in operating income of $21 million related to the return on the true-up balance being recovered through the CTC, and decreased operating income of $29 million in our Electric Transmission & Distribution business segment, excluding the CTC operating income discussed above, primarily from increased franchise fees paid to the City of Houston, increased depreciation expense and higher operation and maintenance expenses, including higher transmission costs, the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in the second quarter of 2004 and the absence of an $11 million gain from a land sale recorded in 2004, partially offset by increased usage mainly due to weather, continued customer growth and higher transmission cost recovery. Additionally, income tax expense increased $14 million in 2005 as compared to 2004.
Net income for 2005 included an after-tax extraordinary gain of $30 million ($0.09 per diluted share) recorded in the second quarter reflecting an adjustment to the after-tax extraordinary loss of $977 million recorded in the last half of 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.
Income Tax Expense. In 2005, our effective tax rate was 40.6%. The most significant items affecting our effective tax rate in 2005 were an addition to the tax reserve of approximately $42 million relating to the contention of the Internal Revenue Service (IRS) that the current deductions for original issue discount (OID) on our 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) be capitalized, potentially converting what would be ordinary deductions into capital losses at the time the ZENS are settled, partially offset by favorable tax audit adjustments of $10 million. Future changes to the reserve will depend upon a number of variables, including the market price of TW Common, the amount of ZENS OID, which increases quarterly, our assessment of available capital gains and the ultimate outcome of the dispute with the IRS.
2004 COMPARED TO 2003
Income from Continuing Operations. We reported income from continuing operations before extraordinary loss of $205 million ($0.61 per diluted share) for 2004 as compared to $409 million ($1.24 per diluted share) for 2003. The decrease in income from continuing operations of $204 million was primarily due to the termination of revenues in our Electric Transmission & Distribution business segment related to ECOM as of January 1, 2004, which had contributed $430 million of income in 2003, higher net transmission costs of $6 million related to our Electric Transmission & Distribution business segment and increased interest expense of $36 million related to continuing operations as discussed below. These items were partially offset by the absence of an $87 million reserve recorded in 2003 by our Electric Transmission & Distribution business segment related to the final fuel reconciliation, a $15 million reversal of this reserve in 2004 and $226 million of the return on the true-up balance of our Electric Transmission & Distribution business segment. These items were a result of the Texas Utility Commission's final orders in the final fuel reconciliation and the 2004 True-Up Proceeding. Additionally, income from continuing operations was favorably impacted by increased operating income of $31 million related to customer growth in our Electric Transmission & Distribution business segment, increased operating income of $21 million in our Natural Gas Distribution business segment primarily due to rate increases, increased operating income of $22 million in our Pipelines and Field Services business segment primarily from increased throughput, favorable commodity prices and increased ancillary services, and a gain of $11 million on the sale of land by our Electric Transmission & Distribution business segment.
Net loss for 2004 included an after-tax extraordinary loss of $977 million ($2.72 per diluted share) from a write-down of regulatory assets based on our analysis of the Texas Utility Commission's final order in the 2004 True-Up Proceeding. Additionally, net loss for 2004 included a net after-tax loss from discontinued operations of Texas Genco of $133 million ($0.37 per diluted share).
Net income for 2003 included the cumulative effect of an accounting change resulting from the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" ($80 million after-tax gain, or $0.24 earnings per diluted share), which is included in discontinued operations related to Texas Genco.
INTEREST EXPENSE AND OTHER FINANCE CHARGES
In 2003, our $3.85 billion credit facility consisted of a revolver and a term loan. This facility was amended in October 2003 to a $2.35 billion credit facility, consisting of a revolver and a term loan. According to the terms of the $3.85 billion credit facility, any net cash proceeds received from the sale of Texas Genco were required to be applied to repay borrowings under the credit facility. According to the terms of the $2.35 billion credit facility, until such time as the facility had been reduced to $750 million, 100% of any net cash proceeds received from the sale of Texas Genco were required to be applied to repay borrowings under the credit facility and reduce the amount available under the credit facility. In the fourth quarter of 2004, we reduced borrowings under our credit facility by $1.574 billion and retired $375 million of trust preferred securities. We expensed $15 million of unamortized loan costs in the fourth quarter of 2004 that were associated with the credit facility. In accordance with EITF Issue No. 87-24 "Allocation of Interest to Discontinued Operations", we have reclassified interest to discontinued operations of Texas Genco based on net proceeds received from the sale of Texas Genco of $2.5 billion, and have applied the proceeds to the amount of debt assumed to be paid down in each respective period according to the terms of the respective credit facilities in effect for those periods. In periods where only the term loan was assumed to be repaid, the actual interest paid on the term loan was reclassified. In periods where a portion of the revolver was assumed to be repaid, the percentage of that portion of the revolver to the total outstanding balance was calculated, and that percentage was applied to the actual interest paid in those periods to compute the amount of interest reclassified.
Total interest expense incurred was $942 million, $849 million and $711 million in 2003, 2004 and 2005, respectively. We have reclassified $201 million, $72 million and $1 million of interest expense in 2003, 2004 and 2005, respectively, based upon actual interest expense incurred within our discontinued operations and interest expense associated with debt that would have been required to be repaid as a result of our disposition of Texas Genco.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
Revenues by segment include intersegment sales, which are eliminated in consolidation.
The following table presents operating income (in millions) for each of our business segments for 2003, 2004 and 2005. Some amounts from the previous years have been reclassified to conform to the 2005 presentation of the financial statements. These reclassifications do not affect consolidated operating income.
OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
ELECTRIC TRANSMISSION & DISTRIBUTION
The following tables provide summary data of our Electric Transmission & Distribution business segment, CenterPoint Houston, for 2003, 2004 and 2005 (in millions, except throughput and customer data):
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(1) In 2003, revenues include $661 million of non-cash ECOM revenues in accordance with the Texas electric restructuring law. In 2004 and 2005, there were no ECOM revenues.
(2) Represents the amount necessary to pay interest on the transition bonds.
2005 Compared to 2004. Our Electric Transmission & Distribution business segment reported operating income of $487 million for 2005, consisting of $448 million for the regulated electric transmission and distribution utility and $39 million for the transition bond company subsidiaries of CenterPoint Houston that issued $749 million and $1.851 billion principal amount of transition bonds in 2001 and 2005, respectively. For 2004, operating income totaled $494 million, consisting of $456 million for the regulated electric transmission and distribution utility and $38 million for the transition bond company. Operating revenues increased primarily due to increased usage resulting from warmer weather ($13 million), continued customer growth ($33 million) with the addition of 61,000 metered customers since December 2004, recovery of our 2004 true-up balance not covered by the transition bond financing order ($21 million) and higher transmission cost recovery ($13 million). The increase in operating revenues was more than offset by higher transmission costs ($24 million), the absence of a gain from a land sale recorded in 2004 ($11 million), the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in 2004, increased employee-related expenses ($20 million) and higher tree trimming expense ($6 million), partially offset by a decrease in pension expense ($14 million). Depreciation and amortization expense increased ($10 million) primarily as a result of higher plant balances. Taxes other than income taxes increased ($11 million) primarily due to higher franchise fees paid to the City of Houston.
In September 2005, CenterPoint Houston's service area in Texas was adversely affected by Hurricane Rita. Although damage to CenterPoint Houston's electric facilities was limited, over 700,000 customers lost
power at the height of the storm. Power was restored to over a half million customers within 36 hours and all power was restored in less than five days. The Electric Transmission & Distribution business segment's revenues lost as a result of the storm were more than offset by warmer than normal weather during the third quarter. CenterPoint Houston has deferred $28 million of restoration costs for recovery in a future rate case and has capitalized an additional $8 million of costs as property, plant and equipment.
2004 Compared to 2003. Our Electric Transmission & Distribution business segment reported operating income of $494 million for 2004, consisting of $456 million for the regulated electric transmission and distribution utility and $38 million for the transition bond company. For 2003, operating income totaled $1.0 billion, consisting of $321 million for the regulated electric transmission and distribution utility, $38 million for the transition bond company and $661 million of non-cash income associated with ECOM. Operating income increased $31 million from continued customer growth and a $11 million gain on a land sale, partially offset by milder weather and decreased usage of $18 million and higher net transmission costs of $6 million. Additionally, operating income in 2004 was favorably impacted by the absence of $87 million reserve recorded in 2003 related to the final fuel reconciliation and a $15 million partial reversal of this fuel reserve in 2004 as a result of the Texas Utility Commission's final orders in the final fuel reconciliation.
NATURAL GAS DISTRIBUTION
The following table provides summary data of our Natural Gas Distribution business segment for 2003, 2004 and 2005 (in millions, except throughput and customer data):
2005 Compared to 2004. Our Natural Gas Distribution business segment reported operating income of $175 million for 2005 as compared to $178 million for 2004. Increases in operating margins (revenues less natural gas costs) from rate increases ($19 million) and margin from gas exchanges ($7 million) were partially offset by the impact of milder weather and decreased throughput net of continued customer growth with the addition of approximately 44,000 customers since December 2004 ($13 million). Operation and maintenance expense increased $7 million. Excluding an $8 million charge recorded in 2004 for severance costs associated with staff reductions, operation and maintenance expenses increased by $15 million primarily due to increased litigation reserves ($11 million) and increased bad debt expense ($9 million), partially offset by the capitalization of previously incurred restructuring expenses as allowed by a regulatory order from the
Railroad Commission of Texas ($5 million). Additionally, operating income was unfavorably impacted by increased depreciation expense primarily due to higher plant balances ($11 million).
During the third quarter of 2005, our east Texas, Louisiana and Mississippi natural gas service areas were affected by Hurricanes Katrina and Rita. Damage to our facilities was limited, but approximately 10,000 homes and businesses were damaged to such an extent that they will not be taking service for the foreseeable future. The impact on the Natural Gas Distribution business segment's operating income was not material.
2004 Compared to 2003. Our Natural Gas Distribution business segment reported operating income of $178 million for 2004 as compared to $157 million for 2003. Increases in operating income of $4 million from continued customer growth with the addition of 45,000 customers since December 31, 2003, $15 million from rate increases, $11 million from the impact of the 2003 change in estimate of margins earned on unbilled revenues implemented in 2003 and $9 million related to certain regulatory adjustments made to the amount of recoverable gas costs in 2003 were partially offset by the $8 million impact of milder weather. Operations and maintenance expense increased $4 million for 2004 as compared to 2003. Excluding an $8 million charge recorded in the first quarter of 2004 for severance costs associated with staff reductions, which has reduced costs in later periods, operation and maintenance expenses decreased by $4 million.
COMPETITIVE NATURAL GAS SALES AND SERVICES
The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for 2003, 2004 and 2005 (in millions, except throughput and customer data):
2005 Compared to 2004. Our Competitive Natural Gas Sales and Services business segment reported operating income of $60 million for 2005 as compared to $44 million for 2004. The increase in operating income of $16 million was primarily due to increased operating margins (revenues less natural gas costs) related to higher sales to utilities and favorable basis differentials over the pipeline capacity that we control
($32 million) less the impact of certain derivative transactions ($6 million), partially offset by higher payroll and benefit related expenses ($4 million) and increased bad debt expense ($3 million).
2004 Compared to 2003. Our Competitive Natural Gas Sales and Services business segment reported operating income of $44 million for 2004 as compared to $45 million for 2003. The decrease in operating income was primarily due to increased payroll and benefit-related expenses ($3 million), increased factoring expenses ($1 million) and increased franchise taxes ($1 million), partially offset by increased operating margins related to increased volatility and growth ($2 million) and a decrease in bad debt expense ($2 million).
PIPELINES AND FIELD SERVICES
The following table provides summary data of our Pipelines and Field Services business segment for 2003, 2004 and 2005 (in millions, except throughput data):
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(1) Elimination of volumes both transported and sold.
2005 Compared to 2004. Our Pipelines and Field Services business segment reported operating income of $235 million for 2005 compared to $180 million for 2004. Operating income for the pipeline business for 2005 was $165 million compared to $129 million in 2004. The field services business recorded operating income of $70 million for 2005 compared to $51 million in 2004. Operating margins (revenues less natural gas costs) increased by $58 million primarily due to increased demand for transportation resulting from basis differentials across the system and higher demand for ancillary services ($43 million), increased throughput and demand for services related to our core gas gathering operations ($29 million), partially offset by reductions in project-related revenues ($11 million). Additionally, operation and maintenance expenses remained flat primarily due to a reduction in project-related expenses ($9 million), offset by increases in materials and supplies and contracts and services ($8 million).
2004 Compared to 2003. Our Pipelines and Field Services business segment's operating income increased by $22 million in 2004 compared to 2003. Operating margins (revenues less fuel costs) increased by $59 million primarily due to favorable commodity pricing ($3 million), increased demand for certain transportation services driven by commodity price volatility ($36 million) and increased throughput and enhanced services related to our core gas gathering operations ($11 million). The increase in operating margin was partially offset by higher operation and maintenance expenses of $35 million primarily due to compliance
with pipeline integrity regulations ($4 million) and costs relating to environmental matters ($9 million). Project work expenses included in operation and maintenance expense increased ($11 million) resulting in a corresponding increase in revenues billed for these services ($15 million).
Additionally, included in other income in 2003, 2004 and 2005 is equity income of $-0-, $2 million and $6 million, respectively, related to a joint venture owned by our field services business.
OTHER OPERATIONS
The following table provides summary data for our Other Operations business segment for 2003, 2004 and 2005 (in millions):
2005 Compared to 2004. Our Other Operations business segment's operating loss in 2005 compared to 2004 decreased $14 million primarily due to increased overhead allocated in 2005.
2004 Compared to 2003. Our Other Operations business segment's operating loss in 2004 compared to 2003 increased $7 million primarily due to a reduction in rental income from Reliant Energy, Inc. (RRI) in 2004 as compared to 2003, partially offset by changes in unallocated corporate costs in 2004 as compared to 2003.
DISCONTINUED OPERATIONS
In February 2003, we sold our interest in Argener, a cogeneration facility in Argentina, for $23 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. We recorded an after-tax gain of $7 million from the sale of Argener in the first quarter of 2003. In April 2003, we sold our final remaining investment in Argentina, a 90 percent interest in Empresa Distribuidora de Electricidad de Santiago del Estero S.A. We recorded an after-tax loss of $3 million in the second quarter of 2003 related to our Latin America operations. We have completed our strategy of exiting all of our international investments.
In November 2003, we sold CenterPoint Energy Management Services, Inc. (CEMS), a business that provides district cooling services in the Houston central business district and related complementary energy services to district cooling customers and others. We recorded an after-tax loss of $1 million from the sale of CEMS in the fourth quarter of 2003. We recorded an after-tax loss in discontinued operations of $16 million ($25 million pre-tax) during the second quarter of 2003 to record the impairment of the CEMS long-lived assets based on the impending sale and to record one-time employee termination benefits.
In July 2004, we announced our agreement to sell our majority owned subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed on April 13, 2005. We recorded an after-tax gain (loss) of $91 million, $(133) million and $(3) million for the years ended December 31, 2003, 2004 and 2005, respectively, related to the operations of Texas Genco.
The consolidated financial statements report the businesses described above as discontinued operations for all periods presented in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
For further information regarding discontinued operations, please read Note 3 to our consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
HISTORICAL CASH FLOW
The net cash provided by/used in operating, investing and financing activities for 2003, 2004 and 2005 is as follows (in millions):
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities in 2005 decreased $673 million compared to 2004 primarily due to increased tax payments of $475 million, the majority of which related to the tax payment in the second quarter of 2005 associated with the sale of Texas Genco, decreased cash provided by Texas Genco of $393 million, increased net accounts receivable/payable ($151 million), increased gas storage inventory ($105 million) and increased fuel under-recovery ($154 million), primarily due to higher gas prices in 2005 as compared to 2004. These decreases were partially offset by decreases in net regulatory assets/liabilities ($328 million), primarily due to the termination of excess mitigation credits effective April 29, 2005, and decreased pension contributions of $401 million in 2005 as compared to 2004.
Net cash provided by operating activities in 2004 decreased $158 million compared to 2003 primarily due to increased pension contributions of $453 million and decreased income tax refunds of $74 million, partially offset by the receipt of a $177 million retail clawback payment from RRI in the fourth quarter of 2004, decreased accounts receivable attributable to a higher level of accounts receivable being sold under CERC Corp.'s receivables facility ($81 million) and increased cash provided by Texas Genco's operations ($110 million). Additionally, other changes in working capital items, primarily increased net accounts receivable and accounts payable due to higher natural gas prices in December 2004 as compared to December 2003 ($99 million), contributed to the overall decrease in cash provided by operating activities.
CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
Net cash provided by investing activities decreased $1.4 billion in 2005 as compared to 2004 primarily due to proceeds of $700 million received from the sale of our remaining interest in Texas Genco in April 2005 compared to proceeds of $2.947 billion received in 2004 from the sale of Texas Genco's fossil generation assets and increased capital expenditures of $89 million, partially offset by the purchase of the minority interest in Texas Genco in 2004 of $716 million and cash collateralization of letters of credit by Texas Genco in 2004 related to its anticipated purchase of an additional interest in the South Texas Project in the first half of 2005 of $191 million.
Net cash provided by investing activities increased $2.1 billion in 2004 as compared to 2003 primarily due to proceeds of $2.947 billion received from the sale of Texas Genco's fossil generation assets in December 2004, offset by the purchase of the minority interest in Texas Genco in December 2004 ($716 million) and cash collateralization of letters of credit by Texas Genco related to its anticipated purchase of an additional interest in the South Texas Project in the first half of 2005 ($191 million).
CASH USED IN FINANCING ACTIVITIES
In 2005, debt payments exceeded net loan proceeds by $66 million. Proceeds from the December 2005 issuance of $1.85 billion in transition bonds were used to repay borrowings under our credit facility and CenterPoint Houston's $1.3 billion term loan.
In 2004, debt payments exceeded net loan proceeds by $2.0 billion. Proceeds received from the sale of Texas Genco's fossil generation assets in December 2004 and the retail clawback payment from RRI as discussed above were used to retire a $915 million term loan, pay down $944 million in borrowings under our revolving credit facility and retire $375 million of trust preferred securities. As of December 31, 2004, we had borrowings of $239 million under our revolving credit facility which were used to fund a portion of the $420 million pension contribution made in December 2004.
FUTURE SOURCES AND USES OF CASH
Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for 2006 include the following:
- approximately $1 billion of capital expenditures, including the construction of a new pipeline by our Pipelines and Field Services business segment ($343 million) and transmission project by our Electric Transmission & Distribution business segment ($60 million);
- dividend payments on CenterPoint Energy common stock and debt service payments; and
- long-term debt payments of $224 million, including $73 million of transition bonds.
We expect that borrowings under our credit facilities and anticipated cash flows from operations will be sufficient to meet our cash needs for the next twelve months. Cash needs may also be met by issuing securities in the capital markets.
The following table sets forth our capital expenditures for 2005 excluding capital expenditures of $9 million related to discontinued operations, and estimates of our capital requirements for 2006 through 2010 (in millions):
The following table sets forth estimates of our contractual obligations, including payments due by period (in millions):
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(1) Transition charges are adjusted at least annually to cover debt service on transition bonds.
(2) We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2005; we typically expect to settle such interest payments with cash flows from operations and short-term borrowings.
(3) For a discussion of operating leases, please read Note 10(b) to our consolidated financial statements.
(4) Contributions to the pension plan are not required in 2006; however, we expect to contribute approximately $26 million to our postretirement benefits plan in 2006 to fund a portion of our obligations in accordance with rate orders or to fund pay-as-you-go costs associated with the plan.
(5) Represents capital commitments for material in connection with the construction of a new pipeline by our Pipelines and Field Services business segment. This project has been included in the table of capital expenditures presented above.
(6) For a discussion of other commodity commitments, please read Note 10(a) to our consolidated financial statements.
Off-Balance Sheet Arrangements. Other than operating leases, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. CERC Corp. has a bankruptcy remote subsidiary, which we consolidate, which was formed for the sole purpose of buying receivables created by CERC and selling those receivables to an unrelated third-party. This transaction is accounted for as a sale of receivables under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," and, as a result, the related receivables are excluded from the Consolidated Balance Sheet. In January 2006, the $250 million facility, which temporarily increased to $375 million for the period from January 2006 to June 2006, was extended to January 2007. As of December 31, 2005, CERC had $141 million of advances under its receivables facility.
Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI's trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guarantee obligations prior to separation, but when separation occurred in September 2002, RRI had been unable to extinguish all obligations. To secure CenterPoint Energy and CERC against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of CERC and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guarantees. Our current exposure under the remaining guarantees relates to CERC's guarantee of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. As a result of changes in market conditions, CenterPoint Energy's potential exposure under that guarantee currently exceeds the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC's obligations under the guarantee, and CenterPoint Energy and RRI are pursuing alternatives. RRI continues to meet its obligations under the transportation contracts.
Credit Facilities. In June 2005, CERC Corp. replaced its $250 million three-year revolving credit facility with a $400 million five-year revolving credit facility. Borrowings under this facility may be made at LIBOR plus 55 basis points, including the facility fee, based on current credit ratings. An additional utilization fee of 10 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. CERC Corp.'s $400 million credit facility contains covenants, including a total debt to capitalization covenant of 65% and an earnings before interest, taxes, depreciation and amortization (EBITDA) to interest covenant. Borrowings under CERC Corp.'s $400 million credit facility are available notwithstanding that a material adverse change has occurred or litigation that could be expected to have a material adverse effect has occurred, so long as other customary terms and conditions are satisfied.
In March 2005, we replaced our $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 87.5 basis points based on current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. The facility contains covenants, including a debt to EBITDA covenant and an EBITDA to interest covenant.
Borrowings under our credit facility are available upon customary terms and conditions for facilities of this type, including a requirement that we represent, except as described below, that no "material adverse change" has occurred at the time of a new borrowing under this facility. A "material adverse change" is defined as the occurrence of a material adverse change in our ability to perform our obligations under the facility but excludes any litigation related to the True-Up Order. The base line for any determination of a relative material adverse change is our most recently audited financial statements. At any time after the first time our credit ratings reach at least BBB by Standard & Poor's Ratings Services, a division of The McGraw Hill Companies (S&P), and Baa2 by Moody's Investors Service, Inc. (Moody's), BBB+ by S&P and Baa3 by Moody's, or BBB- by S&P and Baa1 by Moody's, or if the drawing is to retire maturing commercial paper, we are not required to represent as a condition to such drawing that no material adverse change has occurred or that no litigation expected to have a material adverse effect has occurred.
Also in March 2005, CenterPoint Houston established a $200 million five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 75 basis points based on CenterPoint Houston's current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. CenterPoint Houston's $200 million credit facility contains covenants, including a debt (excluding transition bonds) to total capitalization covenant of 68% and an EBITDA to interest covenant. Borrowings under CenterPoint Houston's $200 million credit facility are available notwithstanding that a material adverse change has occurred or litigation that could be expected to have a material adverse effect has occurred, so long as other customary terms and conditions are satisfied.
We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective credit facilities.
As of February 28, 2006, we had the following credit facilities (in millions):
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(1) Includes $28 million of outstanding letters of credit and $68 million of commercial paper backstopped by the credit facility.
(2) Represents $4 million of outstanding letters of credit.
The $1 billion CenterPoint Energy credit facility backstops a $1 billion commercial paper program under which CenterPoint Energy began issuing commercial paper in June 2005. As of December 31, 2005, $3 million of commercial paper was outstanding. The commercial paper is rated "Not Prime" by Moody's, "A-3" by S&P and "F3" by Fitch, Inc. (Fitch) and, as a result, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in "-- Impact on Liquidity of a Downgrade in Credit Ratings," will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit
ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.
During the fourth quarter of 2005, CenterPoint Houston retired at maturity its $1.31 billion term loan, which bore interest at LIBOR plus 975 basis points, subject to a minimum LIBOR rate of 3 percent. It used its $1.31 billion credit facility bearing interest at LIBOR plus 75 basis points to retire the term loan. All amounts borrowed under the credit facility were repaid with a portion of the proceeds of the $1.85 billion transition bonds referred to above.
Securities Registered with the SEC. At December 31, 2005, CenterPoint Energy had a shelf registration statement covering senior debt securities, preferred stock and common stock aggregating $1 billion and CERC Corp. had a shelf registration statement covering $500 million principal amount of debt securities.
Temporary Investments. On December 31, 2005, we had no temporary investments.
Money Pool. We have a "money pool" through which our participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy's revolving credit facility or the sale of commercial paper.
Impact on Liquidity of a Downgrade in Credit Ratings. As of February 28, 2006, Moody's, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:
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(1) A "stable" outlook from Moody's indicates that Moody's does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed.
(2) An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.
(3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to the likely ratings direction.
A decline in credit ratings could increase borrowing costs under our $1 billion credit facility, CenterPoint Houston's $200 million credit facility and CERC's $400 million revolving credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce margins of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.
As described above under "-- Credit Facilities," our revolving credit facility contains a "material adverse change" clause that could impact our ability to make new borrowings under this facility. CenterPoint Houston's $200 million credit facility and CERC Corp.'s $400 million credit facility do not contain material adverse change clauses with respect to borrowings.
In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. Each ZENS note is exchangeable at the holder's option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or
from other sources. We own shares of TW Common equal to 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes and TW Common shares become current tax obligations when ZENS notes are exchanged and TW Common shares are sold.
CES, a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to hedge its exposure to natural gas prices, CES uses financial derivatives with provisions standard for the industry that establish credit thresholds and require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. We estimate that as of December 31, 2005, unsecured credit limits extended to CES by counterparties aggregate $128 million; however, utilized credit capacity is significantly lower. In addition, CERC and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on CERC's S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.
Cross Defaults. Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. Pursuant to the indenture governing our senior notes, a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million will cause a default. As of February 28, 2006, we had issued six series of senior notes aggregating $1.4 billion in principal amount under this indenture. A default by CenterPoint Energy would not trigger a default under our subsidiaries' debt instruments or bank credit facilities.
Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by:
- cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;
- acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of suppliers;
- increased costs related to the acquisition of gas;
- increases in interest expense in connection with debt refinancings and borrowings under credit facilities;
- various regulatory actions;
- the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and in respect of RRI's indemnity obligations to us and our subsidiaries;
- slower customer payments and increased write-offs of receivables due to higher gas prices;
- cash payments in connection with the exercise of contingent conversion rights of holders of convertible debt;
- contributions to benefit plans;
- restoration costs and revenue losses resulting from natural disasters such as hurricanes; and
- various other risks identified in "Risk Factors" in Item 1A of this report.
Certain Contractual Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock. CenterPoint Houston's credit facility limits CenterPoint Houston's debt, excluding transi-
tion bonds, as a percentage of its total capitalization to 68 percent. CenterPoint Houston's $200 million credit facility also contains an EBITDA to interest covenant. CERC Corp.'s bank facility and its receivables facility limit CERC's debt as a percentage of its total capitalization to 65 percent and contain an EBITDA to interest covenant. Our $1 billion credit facility contains a debt to EBITDA covenant and an EBITDA to interest covenant. Additionally, in connection with the issuance of a certain series of general mortgage bonds, CenterPoint Houston agreed not to issue, subject to certain exceptions, additional first mortgage bonds.
We were a registered public utility holding company under the 1935 Act. The 1935 Act and related rules and regulations imposed a number of restrictions on our activities and those of our subsidiaries. The Energy Act repealed the 1935 Act effective February 8, 2006, and since that date we and our subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes PUHCA 2005 which grants to the FERC authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require us to notify the FERC of our status as a holding company and to maintain certain books and records and make these available to the FERC. The FERC continues to consider motions for rehearing or clarification of these rules.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors.
ACCOUNTING FOR RATE REGULATION
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), 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 can be charged and collected. Application of SFAS No. 71 to the electric generation portion of our business was discontinued as of June 30, 1999. Our Electric Transmission & Distribution business continues to apply SFAS No. 71 which results in our accounting for the regulatory effects of recovery of stranded costs and other regulatory assets resulting from the unbundling of the transmission and distribution business from our electric generation operations in our consolidated financial statements. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Significant accounting estimates embedded within the application of SFAS No. 71 with respect to our Electric Transmission & Distribution business segment relate to $332 million of recoverable electric generation-related
regulatory assets as of December 31, 2005. These costs are recoverable under the provisions of the Texas electric restructuring law. Based on our analysis of the True-Up Order, we recorded an after-tax charge to earnings in 2004 of approximately $977 million to write-down our electric generation-related regulatory assets to their realizable value, which was reflected as an extraordinary loss. Based on subsequent orders received from the Texas Utility Commission, we recorded an extraordinary gain of $30 million after-tax in the second quarter of 2005 related to the regulatory asset. Additionally, a district court in Travis County, Texas issued a judgment that would have the effect of restoring approximately $650 million, plus interest, of disallowed costs. Appeals of the district court's judgment are still pending. No amounts related to the court's judgment have been recorded in our consolidated financial statements.
IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES
We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge.
Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.
We perform our goodwill impairment test at least annually and evaluate goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon adoption of SFAS No. 142, we initially selected January 1 as our annual goodwill impairment testing date. Since the time we selected the January 1 date, our year-end closing and reporting process has been truncated in order to meet the accelerated periodic reporting requirements of the SEC, resulting in significant constraints on our human resources at year-end and during our first fiscal quarter. Accordingly, in order to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in the third quarter of 2005, we changed the date on which we perform our annual goodwill impairment test from January 1 to July 1. We believe the July 1 alternative date will alleviate the resource constraints that exist during the first quarter and allow us to utilize additional resources in conducting the annual impairment evaluation of goodwill. We performed the test at July 1, 2005, and determined that no impairment charge for goodwill was required. The change is not intended to delay, accelerate or avoid an impairment charge. We believe that this accounting change is an alternative accounting principle that is preferable under the circumstances.
ASSET RETIREMENT OBLIGATIONS
We account for our long-lived assets under SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), and Financial Accounting Standards Board Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations -- An Interpretation of SFAS No. 143" (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process.
We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components:
- Inflation adjustment -- The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs;
- Discount rate -- The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and
- Third party markup adjustments -- Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset.
Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 3.0%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately the same percentage. At December 31, 2005, our estimated cost of retiring these assets is approximately $76 million.
UNBILLED ENERGY REVENUES
Revenues related to the sale and/or delivery of electricity or natural gas (energy) are generally recorded when energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which is performed 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. Unbilled electricity delivery revenue is estimated each month based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
PENSION AND OTHER RETIREMENT PLANS
We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors which attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. Please read "-- Other Significant Matters -- Pension Plan" for further discussion.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 2(n) to the consolidated financial statements for a discussion of new accounting pronouncements that affect us.
OTHER SIGNIFICANT MATTERS
Pension Plan. As discussed in Note 2(o) to our consolidated financial statements, we maintain a non-contributory pension plan covering substantially all employees. Employer contributions are based on actuarial computations that establish the minimum contribution required under the Employee Retirement Income Security Act of 1974 (ERISA) and the maximum deductible contribution for income tax purposes. At December 31, 2005, the projected benefit obligation exceeded the market value of plan assets by $20 million;
however, the market value of the plan assets exceeded the accumulated benefit obligation by $41 million. Changes in interest rates and the market values of the securities held by the plan during 2006 could materially, positively or negatively, change our funded status and affect the level of pension expense and required contributions in 2007 and beyond.
Although we have not been required to make contributions to our pension plan in 2004 or 2005, we have made voluntary contributions of $476 million and $75 million in 2004 and 2005, respectively.
Under the terms of our pension plan, we reserve the right to change, modify or terminate the plan. Our funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA and the Internal Revenue Code.
In accordance with SFAS No. 87, "Employers' Accounting for Pensions," changes in pension obligations and assets may not be immediately recognized as pension costs in the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of benefit payments provided to plan participants.
Pension costs were $90 million, $80 million and $30 million for 2003, 2004 and 2005, respectively. In addition, included in the costs for 2003, 2004 and 2005 are $17 million, $11 million and less than $1 million, respectively, of expense related to Texas Genco participants. Pension expense for Texas Genco participants is reflected in the Statement of Consolidated Operations as discontinued operations.
Additionally, we maintain a non-qualified benefit restoration plan which allows participants to retain the benefits to which they would have been entitled under our non-contributory pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with this non-qualified plan was $8 million, $6 million and $6 million in 2003, 2004 and 2005, respectively.
The calculation of pension expense and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.
As of December 31, 2005, the expected long-term rate of return on plan assets was 8.5%, which is unchanged from the rate assumed as of December 31, 2004. We believe that our actual asset allocation, on average, will approximate the targeted allocation and the estimated return on net assets. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate.
As of December 31, 2005, the projected benefit obligation was calculated assuming a discount rate of 5.70%, which is a 0.05% decline from the 5.75% discount rate assumed in 2004. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of our plan.
Pension expense for 2006, including the benefit restoration plan, is estimated to be $38 million based on an expected return on plan assets of 8.5% and a discount rate of 5.70% as of December 31, 2005. If the expected return assumption were lowered by 0.5% (from 8.5% to 8.0%), 2006 pension expense would increase by approximately $8 million.
Currently, pension plan assets (excluding the unfunded benefit restoration plan) exceed the accumulated benefit obligation by $41 million. However, if the discount rate were lowered by 0.5% (from 5.70% to 5.20%), the assumption change would increase our projected benefit obligation, accumulated benefit obligation and 2006 pension expense by approximately $131 million, $120 million and $11 million, respectively. In addition, the assumption change would have significant impacts on our Consolidated Balance Sheet by changing the pension asset recorded as of December 31, 2005 of $655 million to a pension liability of $79 million and would result in a charge to comprehensive income in 2005 of $477 million, net of tax.
For the benefit restoration plan, if the discount rate were lowered by 0.5% (from 5.70% to 5.20%), the assumption change would increase our projected benefit obligation, accumulated benefit obligation and 2006 pension expense by approximately $4 million, $4 million, and less than $1 million, respectively. In addition, the assumption change would result in a charge to comprehensive income of approximately $3 million.
Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plan will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IMPACT OF CHANGES IN INTEREST RATES AND ENERGY COMMODITY PRICES
We are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in our consolidated financial statements. Most of the revenues and income from our business activities are impacted by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below:
- Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas and other energy commodities risk.
- Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.
- Equity price risk results from exposures to changes in prices of individual equity securities.
Management has established comprehensive risk management policies to monitor and manage these market risks. We manage these risk exposures through the implementation of our risk management policies and framework. We manage our exposures through the use of derivative financial instruments and derivative commodity instrument contracts. During the normal course of business, we review our hedging strategies and determine the hedging approach we deem appropriate based upon the circumstances of each situation.
Derivative instruments such as futures, forward contracts, swaps and options derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments that are listed and traded on an exchange.
Derivative transactions are entered into in our non-trading operations to manage and hedge certain exposures, such as exposure to changes in natural gas prices. We believe that the associated market risk of these instruments can best be understood relative to the underlying assets or risk being hedged.
INTEREST RATE RISK
We have outstanding long-term debt, bank loans, mandatory redeemable preferred securities of a subsidiary trust holding solely our junior subordinated debentures (trust preferred securities), some lease obligations and our obligations under our 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) that subject us to the risk of loss associated with movements in market interest rates. In 2003, we had interest rate swaps in place in order to hedge portions of our floating-rate debt.
Our floating-rate obligations aggregated $1.5 billion and $3 million at December 31, 2004 and 2005, respectively. If the floating interest rates were to increase by 10% from December 31, 2005 rates, our combined interest expense would not materially change.
At December 31, 2004 and 2005, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $7.4 billion and $8.8 billion, respectively, in principal amount and having a fair value of $8.1 billion and $9.3 billion, respectively. These instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates (please read Note 8 to our consolidated financial statements). However, the fair value of these instruments would increase
by approximately $400 million if interest rates were to decline by 10% from their levels at December 31, 2005. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.
As discussed in Note 6 to our consolidated financial statements, upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $109 million at December 31, 2005 is a fixed-rate obligation and, therefore, does not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $17 million if interest rates were to decline by 10% from levels at December 31, 2005. Changes in the fair value of the derivative component, a $292 million recorded liability at December 31, 2005, are recorded in our Statements of Consolidated Operations and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from December 31, 2005 levels, the fair value of the derivative component liability would increase by approximately $5 million, which would be recorded as an unrealized loss in our Statements of Consolidated Operations.
EQUITY MARKET VALUE RISK
We are exposed to equity market value risk through our ownership of 21.6 million shares of TW Common, which we hold to facilitate our ability to meet our obligations under the ZENS. Please read Note 6 to our consolidated financial statements for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. A decrease of 10% from the December 31, 2005 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as an unrealized loss in our Statements of Consolidated Operations.
COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES
To reduce our commodity price risk from market fluctuations in the revenues derived from the sale of natural gas and related transportation, we enter into forward contracts, swaps and options (Non-Trading Energy Derivatives) in order to hedge some expected purchases of natural gas and sales of natural gas (a portion of which are firm commitments at the inception of the hedge). Non-Trading Energy Derivatives are also utilized to fix the price of future operational gas requirements.
We use derivative instruments as economic hedges to offset the commodity exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our Non-Trading Energy Derivatives using a sensitivity analysis. The sensitivity analysis performed on our Non-Trading Energy Derivatives measures the potential loss in earnings based on a hypothetical 10% movement in energy prices. A decrease of 10% in the market prices of energy commodities from their December 31, 2004 levels would have decreased the fair value of our Non-Trading Energy Derivatives by $46 million. At December 31, 2005, the recorded fair value of our Non-Trading Energy Derivatives was a net asset of $157 million. A decrease of 10% in the market prices of energy commodities from their December 31, 2005 levels would have decreased the fair value of our Non-Trading Energy Derivatives by $85 million.
The above analysis of the Non-Trading Energy Derivatives utilized for hedging purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. Furthermore, the Non-Trading Energy Derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of Non-Trading Energy Derivatives held for hedging purposes
associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming:
- the Non-Trading Energy Derivatives are not closed out in advance of their expected term;
- the Non-Trading Energy Derivatives continue to function effectively as hedges of the underlying risk; and
- as applicable, anticipated underlying transactions settle as expected.
If any of the above-mentioned assumptions ceases to be true, a loss on the derivative instruments may occur, or the options might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first. Non-Trading Energy Derivatives designated and effective as hedges, may still have some percentage which is not effective. The change in value of the Non-Trading Energy Derivatives that represents the ineffective component of the hedges is recorded in our results of operations.
We have established a Risk Oversight Committee composed of corporate and business segment officers, that oversees our commodity price and credit risk activities, including our trading, marketing, risk management services and hedging activities. The committee's duties are to establish commodity risk policies, allocate risk capital within limits established by our board of directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with our risk management policies and procedures and trading limits established by our board of directors.
Our policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of CenterPoint Energy, Inc. Houston, Texas
We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2005, and the related consolidated statements of operations, comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy, Inc. and subsidiaries at December 31, 2004 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations," effective December 31, 2005.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, 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 March 15, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
Houston, Texas March 15, 2006
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
See Notes to the Company's Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
See Notes to the Company's Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See Notes to the Company's Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
See Notes to the Company's Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY
See Notes to the Company's Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
(a) BACKGROUND
CenterPoint Energy, Inc. is a public utility holding company, created on August 31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) that implemented certain requirements of the Texas Electric Choice Plan (Texas electric restructuring law).
CenterPoint Energy was a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). The 1935 Act and related rules and regulations imposed a number of restrictions on the activities of the Company and its subsidiaries. The Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since that date the Company and its subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005), which grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require the Company to notify the FERC of its status as a holding company and to maintain certain books and records and make these available to the FERC. The FERC continues to consider motions for rehearing or clarification of these rules.
The Company's operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of December 31, 2005, the Company's indirect wholly owned subsidiaries included:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns gas distribution systems. The operations of its local distribution companies are conducted through two unincorporated divisions: Minnesota Gas and Southern Gas Operations. Through wholly owned subsidiaries, CERC owns two interstate natural gas pipelines and gas gathering systems, provides various ancillary services, and offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.
(b) BASIS OF PRESENTATION
In 2003, the Company sold all of its remaining Latin America operations.
In November 2003, the Company sold its district cooling services business in the Houston central business district and related complementary energy services to district cooling customers and others.
The Company sold the fossil generation assets of Texas Genco Holdings, Inc. (Texas Genco) in December 2004 and completed the sale of Texas Genco, which had continued to own an interest in a nuclear generating facility, in April 2005.
The consolidated financial statements report the businesses described above as discontinued operations for all periods presented in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
For a description of the Company's reportable business segments, see Note 14.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) RECLASSIFICATIONS AND USE OF ESTIMATES
In addition to the items discussed in Note 3, some amounts from the previous years have been reclassified to conform to the 2005 presentation of financial statements. These reclassifications relate to a new reportable business segment discussed in Note 14 and do not affect net income.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(b) PRINCIPLES OF CONSOLIDATION
The accounts of CenterPoint Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All significant intercompany transactions and balances are eliminated in consolidation. The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. Such investments were $13 million and $15 million as of December 31, 2004 and 2005, respectively. Other investments, excluding marketable securities, are carried at cost.
(c) REVENUES
The Company records revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. The Pipelines and Field Services business segment records revenues as transportation services are provided.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(d) LONG-LIVED ASSETS AND INTANGIBLES
The Company records property, plant and equipment at historical cost. The Company expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:
The components of the Company's other intangible assets consist of the following:
The Company recognizes specifically identifiable intangibles, including land use rights and permits, when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives recorded as of December 31, 2005 other than goodwill discussed below. The Company amortizes other acquired intangibles on a straight-line basis over the lesser of their contractual or estimated useful lives that range from 27 to 75 years for land rights and 10 to 56 years for other intangibles.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Amortization expense for other intangibles for 2003, 2004 and 2005 was $2 million in each year. Estimated amortization expense for the five succeeding fiscal years is as follows (in millions):
Goodwill by reportable business segment is as follows (in millions):
- ---------------
(1) In December 2005, the Company determined that $35 million of deferred tax liabilities originally established in connection with an acquisition were no longer required. In accordance with Emerging Issues Task Force (EITF) Issue No. 93-7, "Uncertainties Related to Income Taxes in a Purchase Business Combination," the adjustment was applied to decrease the remaining goodwill attributable to that acquisition.
The Company performs its goodwill impairment test at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit's goodwill is determined by allocating the reporting unit's fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.
Upon adoption of SFAS No. 142, "Goodwill and Other Intangible Assets," the Company initially selected January 1 as its annual goodwill impairment testing date. Since the time the Company selected the January 1 date, the Company's year-end closing and reporting process has been truncated in order to meet the accelerated reporting requirements of the Securities and Exchange Commission (SEC), resulting in significant constraints on the Company's human resources at year-end and during its first fiscal quarter. Accordingly, in order to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in the third quarter of 2005, the Company changed the date on which it performs its annual goodwill impairment test from January 1 to July 1. The Company believes the July 1 alternative date will alleviate the resource constraints that exist during the first quarter and allow it to utilize additional resources in conducting the annual impairment evaluation of goodwill. The Company performed the
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
test at July 1, 2005, and determined that no impairment charge for goodwill was required. The change is not intended to delay, accelerate or avoid an impairment charge. The Company believes that this accounting change is an alternative accounting principle that is preferable under the circumstances.
The Company periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets.
(e) REGULATORY ASSETS AND LIABILITIES
The Company applies the accounting policies established in SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), to the accounts of the Electric Transmission & Distribution business segment and the Natural Gas Distribution business segment and to some of the accounts of the Pipelines and Field Services business segment.
The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 2004 and 2005:
- ---------------
(1) Excludes $147 million and $248 million of allowed equity return on the true-up balance as of December 31, 2004 and 2005, respectively. See Note 4(a).
Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.
If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write-off or write-down these regulatory assets and liabilities. During 2004, the Company wrote-off net regulatory assets of $1.5 billion ($977 million after-tax) as an extraordinary loss in response to the Texas Utility Commission's order on CenterPoint Houston's final true-up application. Based on subsequent orders received from the Texas Utility Commission, the Company recorded an extraordinary gain of $47 million ($30 million after-tax) in the second quarter of 2005 related to these regulatory assets. For further discussion of regulatory assets, see Note 4.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2004 and 2005, these removal costs of $677 million and $662 million, respectively, are classified as regulatory liabilities in the Consolidated Balance Sheets. A portion of the amount of removal costs that relate to asset retirement obligations have been reclassified from a regulatory liability to an asset retirement liability, which is included in other liabilities in the Consolidated Balance Sheets, in connection with the Company's adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47) as further discussed in Note 2(n).
(f) DEPRECIATION AND AMORTIZATION EXPENSE
Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization expense includes amortization of regulatory assets and other intangibles. See Notes 2(e) and 4(a) for additional discussion of these items.
The following table presents depreciation and amortization expense for 2003, 2004 and 2005 (in millions):
(g) CAPITALIZATION OF INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash through depreciation provisions included in rates for subsidiaries that apply SFAS No. 71. Interest and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component of projects under construction and will be amortized over the assets' estimated useful lives. During 2003, 2004 and 2005, the Company capitalized interest and AFUDC of $4 million each year.
(h) INCOME TAXES
The Company files a consolidated federal income tax return and follows a policy of comprehensive interperiod income tax allocation. The Company uses the liability method of accounting for deferred income taxes and measures deferred income taxes for all significant income tax temporary differences in accordance with SFAS No. 109, "Accounting for Income Taxes." Investment tax credits were deferred and are being amortized over the estimated lives of the related property. Management evaluates uncertain tax positions and accrues for those which management believes are probable of an unfavorable outcome. For additional information regarding income taxes, see Note 9.
(i) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS
Accounts receivable are net of an allowance for doubtful accounts of $30 million and $43 million at December 31, 2004 and 2005, respectively. The provision for doubtful accounts in the Company's Statements of Consolidated Operations for 2003, 2004 and 2005 was $24 million, $27 million and $40 million, respectively.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 2004 and 2005, CERC had $181 million and $141 million of advances, respectively, under its receivables facility. CERC Corp. formed a bankruptcy remote subsidiary for the sole purpose of buying receivables created by CERC and selling those receivables to an unrelated third-party. These transactions were accounted for as a sale of receivables under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," (SFAS No. 140) and, as a result, the related receivables are excluded from the Consolidated Balance Sheets. The bankruptcy remote subsidiary purchases receivables with cash and subordinated notes. The subordinated notes owned by CERC are pledged to a gas supplier to secure obligations incurred in connection with the purchase of gas by CERC and totaled approximately $433 million as of December 31, 2005.
In January 2006, CERC's $250 million receivables facility, which was temporarily increased to $375 million for the period from January 2006 to June 2006 to provide additional liquidity to CERC during the peak heating season of 2006, was extended to January 2007.
Advances under the receivables facility averaged $100 million, $190 million and $166 million in 2003, 2004 and 2005, respectively. Sales of receivables were approximately $1.2 billion, $2.4 billion and $2.0 billion in 2003, 2004 and 2005, respectively.
(j) INVENTORY
Inventory consists principally of materials and supplies and natural gas. Materials and supplies are valued at the lower of average cost or market. Inventories used in the retail natural gas distribution operations are also primarily valued at the lower of average cost or market.
(k) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES
In accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" (SFAS No. 115), the Company reports "available-for-sale" securities at estimated fair value within other long-term assets in the Company's Consolidated Balance Sheets and any unrealized gain or loss, net of tax, as a separate component of shareholders' equity and accumulated other comprehensive income. In accordance with SFAS No. 115, the Company reports "trading" securities at estimated fair value in the Company's Consolidated Balance Sheets, and any unrealized holding gains and losses are recorded as other income (expense) in the Company's Statements of Consolidated Operations.
As of December 31, 2004, Texas Genco held debt and equity securities in its nuclear decommissioning trust, which was reported at its fair value of $216 million in the Company's Consolidated Balance Sheets in non-current assets of discontinued operations. Any unrealized losses or gains were accounted for as a non-current asset/liability of discontinued operations as Texas Genco will not benefit from any gains, and losses will be recovered through the rate-making process.
As of December 31, 2004 and 2005, the Company held an investment in Time Warner Inc. common stock, which was classified as a "trading" security. For information regarding this investment, see Note 6.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(l) ENVIRONMENTAL COSTS
The Company expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations, and that do not have future economic benefit. The Company records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
(m) STATEMENTS OF CONSOLIDATED CASH FLOWS
For purposes of reporting cash flows, the Company considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. In connection with the issuance of transition bonds in October 2001 and December 2005, the Company was required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds. Cash and Cash Equivalents does not include restricted cash. For additional information regarding the December 2005 securitization financing, see Notes 4(a) and 8(a).
(n) NEW ACCOUNTING PRONOUNCEMENTS
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3" (SFAS No. 154). SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The correction of an error in previously issued financial statements is not an accounting change and must be reported as a prior-period adjustment by restating previously issued financial statements. SFAS No. 154 was effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
In March 2005, the FASB issued FIN 47. FIN 47 clarifies that an entity must record a liability for a "conditional" asset retirement obligation if the fair value of the obligation can be reasonably estimated. The Company has identified conditional asset retirement obligations in the natural gas distribution segment that exist due to requirements of the U.S. Department of Transportation to cap and purge certain mains upon retirement. Also, the Company identified conditional asset retirement obligations for treated utility poles and for transformers contaminated by polychlorinated biphenyls. The fair value of these obligations is recorded as a liability on a discounted basis with a corresponding increase to the related asset. Over time, the liabilities are accreted for the change in the present value and the initial capitalized costs are depreciated over the useful lives of the related assets. The adoption of FIN 47, effective December 31, 2005, resulted in the recognition of an asset retirement obligation liability of $76 million, an increase in net property, plant and equipment of $37 million and a $39 million increase in net regulatory assets. The Company's rate-regulated businesses have previously recognized removal costs as a component of depreciation expense in accordance with regulatory treatment, and these costs have been classified as a regulatory liability. Upon adoption of FIN 47, the portion of the removal costs that relates to this asset retirement obligation has been reclassified from a regulatory liability to an asset retirement liability, which is included in other liabilities in the Consolidated Balance Sheets.
The pro forma effect of applying this guidance in the prior periods would have resulted in an asset retirement obligation of approximately $67 million and $72 million as of January 1, 2004 and December 31, 2004, respectively.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments" (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS No. 140. SFAS No. 155 includes provisions that permit fair value remeasurement for any hybrid financial instrument that contains an embedded derivative and that otherwise would require bifurcation. It also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are free-standing or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of the Company's first fiscal year that begins after September 15, 2006. The fair value election in SFAS No. 155 may also be applied upon adoption for hybrid instruments that have been bifurcated under SFAS No. 133 prior to the adoption of this statement. The Company is evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows and does not expect the standard to have a material impact.
(o) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS
STOCK-BASED INCENTIVE COMPENSATION PLANS
The Company has long-term incentive compensation plans (LICPs) that provide for the issuance of stock-based incentives, including performance-based shares, performance-based units, restricted shares and stock options to directors, officers and key employees. A maximum of approximately 36 million shares of CenterPoint Energy common stock is authorized to be issued under these plans.
Performance-based shares, performance-based units and restricted shares are granted to employees without cost to the participants. The performance shares and units are distributed based upon the performance of the Company over a three-year cycle. The restricted shares vest at various times ranging from one year to the end of a three-year period. Upon vesting, the shares are issued to the participants along with the value of common dividends declared during the vesting period. The restricted shares granted in 2005 are subject to the performance condition that common dividends declared during the vesting period must be at least $1.20 per share.
Option awards are generally granted with an exercise price equal to the average of the high and low sales price of the Company's stock at the date of grant. These option awards generally become exercisable in one-third increments on each of the first through third anniversaries of the grant date and have 10-year contractual terms. No options were granted during 2005.
Effective January 1, 2005, the Company adopted SFAS No. 123 (Revised 2004), "Share-Based Payment" (SFAS 123(R)), using the modified prospective transition method. Under this method, the Company records compensation expense at fair value for all awards it grants after the date it adopted the standard. In addition, the Company records compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption awards of time-based restricted stock and performance-based restricted stock will continue to be expensed using the guidance contained in Accounting Principles Board Opinion No. 25. The adoption of SFAS 123(R) did not have a material impact on the Company's results of operations, financial condition or cash flows.
The Company recorded LICP compensation expense of $9 million, $8 million and $13 million in 2003, 2004 and 2005, respectively.
The total income tax benefit recognized related to such arrangements was $4 million, $3 million and $5 million in 2003, 2004 and 2005, respectively. No compensation cost related to such arrangements was capitalized as a part of inventory or fixed assets in 2003, 2004 or 2005.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma information for 2003 and 2004 is provided to show the effect of amortizing stock-based compensation to expense on a straight-line basis over the vesting period. Had compensation costs been determined as prescribed by SFAS No. 123, the Company's net income and earnings per share would have been as follows (in millions, except per share amounts):
The following tables summarize the methods used to measure compensation cost for the various types of awards granted under the LICPs:
FOR AWARDS GRANTED BEFORE JANUARY 1, 2005
In 2003 and 2004, the fair values of stock options were estimated using the Black-Scholes option valuation model with the following assumptions:
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR AWARDS GRANTED AS OF AND AFTER JANUARY 1, 2005
For awards granted before January 1, 2005, forfeitures of awards were measured upon their occurrence. For awards granted as of and after January 1, 2005, forfeitures are estimated on the date of grant and are adjusted as required through the remaining vesting period.
The following tables summarize the Company's LICP activity for 2005:
STOCK OPTIONS
PERFORMANCE SHARES
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The non-vested and outstanding shares displayed in the above tables assume that shares are issued at the maximum performance level (150%). The aggregate intrinsic value reflects the impacts of current expectations of achievement and stock price.
PERFORMANCE-BASED UNITS
The aggregate intrinsic value reflects the value of the performance units given current expectations of performance through the end of the cycle.
TIME-BASED RESTRICTED STOCK
The weighted-average grant-date fair values of awards granted were as follows for 2003, 2004 and 2005:
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The total intrinsic value of awards received by participants were as follows for 2003, 2004 and 2005:
As of December 31, 2005, there was $13 million of total unrecognized compensation cost related to non-vested LICP arrangements. That cost is expected to be recognized over a weighted-average period of 1.7 years.
Cash received from LICPs was $1 million, $4 million and $9 million for 2003, 2004 and 2005, respectively.
The actual tax benefit realized for tax deductions related to LICPs totaled $2 million, $4 million and $5 million, for 2003, 2004 and 2005, respectively.
The Company has a policy of issuing new shares in order to satisfy share-based payments related to LICPs.
PENSION AND POSTRETIREMENT BENEFITS
The Company maintains a non-contributory qualified defined benefit plan covering substantially all employees, with benefits determined using a cash balance formula. Under the cash balance formula, participants accumulate a retirement benefit based upon 4% of eligible earnings and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. Certain employees participating in the plan as of December 31, 1998 automatically receive the greater of the accrued benefit calculated under the prior plan formula through 2008 or the cash balance formula. Participants are 100% vested in their benefit after completing five years of service.
The Company provides certain healthcare and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Under plan amendments, effective in early 1999, healthcare benefits for future retirees were changed to limit employer contributions for medical coverage.
Such benefit costs are accrued over the active service period of employees. The net unrecognized transition obligation, resulting from the implementation of accrual accounting, is being amortized over approximately 20 years.
In January 2005, the Department of Health and Human Services' Centers for Medicare and Medicaid Services released final regulations governing the Medicare prescription drug benefit and other key elements of the Medicare Modernization Act. Under the final regulations, a greater portion of benefits offered under the Company's plans meets the definition of actuarial equivalence and therefore qualifies for federal subsidies equal to 28% of allowable drug costs. As a result, the Company has remeasured its obligations and costs to take into account the new regulations. The Medicare subsidy reduced 2005's net periodic postretirement benefit costs by approximately $8 million, including $3 million of amortization of the actuarial loss, $2 million of reduced service cost and $3 million of reduced interest cost on the accumulated postretirement benefit obligation.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's net periodic cost includes the following components relating to pension and postretirement benefits:
The Company used the following assumptions to determine net periodic cost relating to pension and postretirement benefits:
In determining net periodic benefits cost, the Company uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table displays the change in the benefit obligation, the fair value of plan assets and the amounts included in the Company's Consolidated Balance Sheets as of December 31, 2004 and 2005 for the Company's pension and postretirement benefit plans:
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Assumed healthcare cost trend rates have a significant effect on the reported amounts for the Company's postretirement benefit plans. A 1% change in the assumed healthcare cost trend rate would have the following effects:
The following table displays the weighted-average asset allocations as of December 31, 2004 and 2005 for the Company's pension and postretirement benefit plans:
In managing the investments associated with the benefit plans, the Company's objective is to preserve and enhance the value of plan assets while maintaining an acceptable level of volatility. These objectives are expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As part of the investment strategy discussed above, the Company has adopted and maintains the following weighted average allocation targets for its benefit plans:
The expected rate of return assumption was developed by reviewing the targeted asset allocations and historical index performance of the applicable asset classes over a 15-year period, adjusted for investment fees and diversification effects.
The pension plan did not include any holdings of CenterPoint Energy common stock as of December 31, 2004 or 2005.
Although funding for the Company's pension and postretirement plans was not required during 2005, the Company contributed $75 million and $24 million to its pension plan and postretirement benefits plan in 2005, respectively.
Contributions to the pension plan are not required in 2006; however, the Company expects to make a contribution. The Company expects to contribute approximately $26 million to its postretirement benefits plan in 2006.
The following benefit payments are expected to be paid by the pension and postretirement benefit plans (in millions):
In addition to the non-contributory pension plans discussed above, the Company maintains a non-qualified benefit restoration plan which allows participants to retain the benefits to which they would have been entitled under the Company's non-contributory pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with this non-qualified plan was $8 million, $6 million and $6 million in 2003, 2004 and 2005, respectively. The accrued benefit liability for the non-qualified pension plan was $69 million and $79 million at December 31, 2004 and 2005, respectively. In addition, these accrued benefit liabilities include the recognition of minimum liability adjustments of $10 million as of December 31, 2004 and $14 million as of December 31, 2005, which are reported as a component of other comprehensive income, net of income tax effects.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table displays the Company's plans that have or have had accumulated benefit obligations in excess of plan assets:
On January 5, 2006, the Company offered a Voluntary Early Retirement Program (VERP) to approximately 200 employees who were age 55 or older with at least five years of service as of February 28, 2006. The election period was from January 5, 2006 through February 28, 2006. For those electing to accept the VERP, three years of age and service will be added to their qualified pension plan benefit and three years of service will be added to their postretirement benefit. The one-time additional pension and postretirement expense of approximately $9 million will be reflected in the first quarter of 2006.
SAVINGS PLAN
The Company has a qualified employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended (the Code), and an employee stock ownership plan (ESOP) under Section 4975(e)(7) of the Code. Under the plan, participating employees may contribute a portion of their compensation, on a pre-tax or after-tax basis, generally up to a maximum of 16% of compensation. The Company matches 75% of the first 6% of each employee's compensation contributed. The Company may contribute an additional discretionary match of up to 50% of the first 6% of each employee's compensation contributed. These matching contributions are fully vested at all times.
Participating employees may elect to invest all or a portion of their contributions to the plan in CenterPoint Energy common stock, to have dividends reinvested in additional shares or to receive dividend payments in cash on any investment in CenterPoint Energy common stock, and to transfer all or part of their investment in CenterPoint Energy common stock to other investment options offered by the plan.
The savings plan has significant holdings of CenterPoint Energy common stock. As of December 31, 2005, an aggregate of 27,720,006 shares of CenterPoint Energy's common stock were held by the savings plan, which represented 28% of its investments. Given the concentration of the investments in CenterPoint Energy's common stock, the savings plan and its participants have market risk related to this investment.
The Company's savings plan benefit expense was $38 million, $40 million and $35 million in 2003, 2004 and 2005, respectively. Included in these amounts is $7 million, $6 million and less than $1 million of savings plan benefit expense for 2003, 2004 and 2005, respectively, related to Texas Genco participants. Amounts for Texas Genco's participants are reflected as discontinued operations in the Statements of Consolidated Operations.
POSTEMPLOYMENT BENEFITS
Net postemployment benefit costs for former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan) were $10 million, $8 million and $8 million in 2003, 2004 and 2005, respectively.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Included in "Benefit Obligations" in the accompanying consolidated Balance Sheets at December 31, 2004 and 2005 was $38 million and $42 million, respectively, relating to postemployment obligations.
OTHER NON-QUALIFIED PLANS
The Company has non-qualified deferred compensation plans that provide benefits payable to directors, officers and certain key employees or their designated beneficiaries at specified future dates, upon termination, retirement or death. Benefit payments are made from the general assets of the Company. During 2003, 2004 and 2005, the Company recorded benefit expense relating to these programs of $13 million, $9 million and $8 million, respectively. Included in "Benefit Obligations" in the accompanying Consolidated Balance Sheets at December 31, 2004 and 2005 was $121 million and $113 million, respectively, relating to deferred compensation plans. Included in "Non-Current Liabilities of Discontinued Operations" in the accompanying Consolidated Balance Sheets at December 31, 2004 was $3 million relating to deferred compensation plans for Texas Genco participants.
CHANGE OF CONTROL AGREEMENTS AND OTHER EMPLOYEE MATTERS
In December 2003, the Company entered into agreements with certain of its executive officers that generally provide, to the extent applicable, in the case of a change of control of the Company and termination of employment, for severance benefits of up to three times annual base salary plus bonus and other benefits. By their terms, these agreements will expire December 31, 2006.
As of December 31, 2005, approximately 30% of the Company's employees are subject to collective bargaining agreements. Two of these agreements, covering approximately 19% of the Company's employees, have expired or will expire in 2006. Minnesota Gas, a division of our natural gas distribution business, has 466 bargaining unit employees that are covered by a collective bargaining unit agreement with the United Association of Journeymen and Apprentices of Plumbing and Pipe Fitting Industry of US and Canada Local 340 that expires in April 2006. CenterPoint Houston has 1225 bargaining unit employees that are covered by a collective bargaining unit agreement with the International Brotherhood of Electrical Workers Local 66, which expires in May 2006. The Company has a good relationship with these bargaining units and expects to renegotiate new agreements in 2006.
(3) DISCONTINUED OPERATIONS
Latin America. In February 2003, the Company sold its interest in Argener, a cogeneration facility in Argentina, for $23 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. The Company recorded an after-tax gain of $7 million from the sale of Argener in the first quarter of 2003. In April 2003, the Company sold its final remaining investment in Argentina, a 90 percent interest in Empresa Distribuidora de Electricidad de Santiago del Estero S.A. The Company recorded an after-tax loss of $3 million in the second quarter of 2003 related to its Latin America operations.
Revenues related to the Company's Latin America operations included in discontinued operations for the year ended December 31, 2003 were $2 million. Income from these discontinued operations for the year ended December 31, 2003 is reported net of income tax expense of $2 million.
CenterPoint Energy Management Services, Inc. In November 2003, the Company completed the sale of a component of its Other Operations business segment, CenterPoint Energy Management Services, Inc. (CEMS), that provides district cooling services in the Houston central business district and related complementary energy services to district cooling customers and others. The Company recorded an after-tax loss of $1 million from the sale of CEMS in the fourth quarter of 2003. The Company recorded an after-tax loss in discontinued operations of $16 million ($25 million pre-tax) during the second quarter of 2003 to
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
record the impairment of the CEMS long-lived assets based on the impending sale and to record one-time employee termination benefits.
Revenues related to CEMS included in discontinued operations for the year ended December 31, 2003 were $10 million. Loss from these discontinued operations for the year ended December 31, 2003 is reported net of income tax benefit of $2 million.
Texas Genco. In July 2004, the Company announced its agreement to sell Texas Genco to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco's principal remaining asset was its ownership interest in the South Texas Project Electric Generating Station, a nuclear generating facility (South Texas Project). The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to the Company of $700 million, was completed on April 13, 2005.
The following table summarizes the components of the income (loss) from discontinued operations of Texas Genco for each of the years ended December 31, 2003, 2004 and 2005:
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(1) In 2004, Texas Genco recorded an after-tax loss of $426 million related to the sale of its coal, lignite and gas-fired generation plants which occurred in the first step of the transaction pursuant to which Texas Genco was sold. This loss was reversed by CenterPoint Energy to reflect its estimated loss on the sale of Texas Genco.
(2) General corporate overhead previously allocated to Texas Genco from CenterPoint Energy, which will not be eliminated by the sale of Texas Genco, was excluded from income from discontinued operations and is reflected as general corporate overhead of CenterPoint Energy in income from continuing operations in accordance with SFAS No. 144.
(3) Interest expense was reclassified to discontinued operations of Texas Genco related to the applicable amounts of CenterPoint Energy's term loan and revolving credit facility debt that would have been assumed to be paid off with any proceeds from the sale of Texas Genco during those respective periods in accordance with SFAS No. 144.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenues related to Texas Genco included in discontinued operations for the years ended December 31, 2003, 2004 and 2005 were $2.0 billion, $2.1 billion and $62 million, respectively. Income from these discontinued operations for the years ended December 31, 2003, 2004 and 2005 is reported net of income tax expense of $71 million, $166 million and $4 million, respectively.
Summarized balance sheet information as of December 31, 2004 related to discontinued operations of Texas Genco is as follows:
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(1) Taxes payable resulting from the sale were paid by the Company, and were included in current liabilities as of December 31, 2004.
On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Texas Genco used approximately $716 million of the cash proceeds from the sale to repay an overnight bridge loan that Texas Genco had entered into in order to finance the repurchase of Texas Genco's common stock held by minority shareholders prior to the first step of the Texas Genco sale. Texas Genco distributed the balance of the cash proceeds from the sale ($2.097 billion) and cash on hand ($134 million), for a total of $2.231 billion, to the Company. Included in current assets of discontinued operations as of December 31, 2004 was $390 million of restricted cash designated to buy back the remaining shares of Texas Genco's common stock which had not yet been tendered by Texas Genco's former minority shareholders.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 2004, Texas Genco owned a 30.8% interest in the South Texas Project, which consists of two 1,250 megawatt nuclear generating units and bore a corresponding 30.8% share of capital and operating costs associated with the project. As of December 31, 2004, the South Texas Project was owned as a tenancy in common among Texas Genco and three other co-owners, with each owner retaining its undivided ownership interest in the two generating units and the electrical output from those units. Texas Genco was severally liable, but not jointly liable, for the expenses and liabilities of the South Texas Project. Texas Genco and the three other co-owners organized the STP Nuclear Operating Company (STPNOC) to operate and maintain the South Texas Project. STPNOC was managed by a board of directors comprised of one director appointed by each of the four co-owners, along with the chief executive officer of STPNOC. Texas Genco's share of direct expenses of the South Texas Project was included in discontinued operations in the Statements of Consolidated Operations. As of December 31, 2004, Texas Genco's total utility plant for the South Texas Project was $436 million (net of $2.3 billion accumulated depreciation, which includes an impairment loss recorded in 1999 of $745 million). As of December 31, 2004, Texas Genco's investment in nuclear fuel was $34 million (net of $334 million amortization). These assets were included in non-current assets of discontinued operations in the Consolidated Balance Sheets.
(4) REGULATORY MATTERS
(a) RECOVERY OF TRUE-UP BALANCE
The Texas Electric Choice Plan (Texas electric restructuring law), which became effective in September 1999, substantially amended the regulatory structure governing electric utilities in order to allow retail competition for electric customers beginning in January 2002. The Texas electric restructuring law requires the Texas Utility Commission to conduct a "true-up" proceeding to determine CenterPoint Houston's stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission's rulings. The judgment would have the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of an inaccurate stranded cost estimate made by the Texas Utility Commission in 2000. Additional credits of approximately $30 million were paid after August 2004. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. CenterPoint Houston and other parties appealed the district court decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but oral argument has not yet been scheduled. No amounts related to the court's judgment have been recorded in the consolidated financial statements.
Among the issues raised in CenterPoint Houston's appeal of the True-Up Order is the Texas Utility Commission's reduction of CenterPoint Houston's stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with its former Texas Genco assets. Such reduction was considered in the Company's recording of an after-tax extraordinary loss of $977 million in the last half of 2004. The Company believes that the Texas Utility Commission based its order on proposed
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
regulations issued by the Internal Revenue Service (IRS) in March 2003 related to those tax benefits. Those proposed regulations would have allowed utilities which were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. If the December 2005 proposed regulations become effective and if the Texas Utility Commission's order on this issue is not reversed on appeal or the amount of the tax benefits is not otherwise restored by the Texas Utility Commission, the IRS is likely to consider that a "normalization violation" has occurred. If so, the IRS could require the Company to pay an amount equal to CenterPoint Houston's unamortized ADITC balance as of the date that the normalization violation was deemed to have occurred. In addition, if a normalization violation is deemed to have occurred, the IRS could also deny CenterPoint Houston the ability to elect accelerated depreciation benefits. If a normalization violation should ultimately be found to exist, it could have an adverse impact on the Company's results of operations, financial condition and cash flows. However, the Company and CenterPoint Houston are vigorously pursuing the appeal of this issue and will seek other relief from the Texas Utility Commission to avoid a normalization violation. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation.
There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.
In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC which will collect approximately $596 million over 14 years plus interest at an annual rate of 11.075 percent (CTC Order). The CTC Order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. The CTC Order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. During the period from September 13, 2005, the date of implementation of the CTC Order, through December 31, 2005, CenterPoint Houston recognized approximately $21 million in CTC operating income. Certain parties appealed the CTC Order to the Travis County Court in September 2005.
Under the True-Up Order, CenterPoint Houston is allowed to recover carrying charges at 11.075 percent until the true-up balance is recovered. The rate of return is based on CenterPoint Houston's cost of capital, established in the Texas Utility Commission's final order issued in October 2001, which is derived from CenterPoint Houston's cost to finance assets (debt return) and an allowance for earnings on shareholders' investment (equity return). Consequently, in accordance with SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans," the rate of return has been bifurcated into a debt return component and an equity return component. CenterPoint Houston was allowed a return on the true-up balance of $222 million in 2005. Effective September 13, 2005, the date of implementation of the CTC Order, the return on the CTC portion of the true-up balance is included in CenterPoint Houston's tariff-based revenues. The debt return of $121 million recorded in 2005 was accrued and included in other income in the Company's Statements of Consolidated Operations. The equity return of $101 million recorded in 2005 will be recognized in income as it is recovered in the future. As of December 31, 2005, the Company has recorded a regulatory asset of
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$347 million related to the debt return on its true-up balance and has not recorded an allowed equity return of $248 million on its true-up balance because such return will be recognized as it is recovered in the future.
In January 2006, the Texas Utility Commission staff (Staff) proposed that the Texas Utility Commission adopt new rules governing the carrying charges on unrecovered true-up balances. If the Texas Utility Commission adopts the rule as the Staff proposed it and the rule is deemed to apply to CenterPoint Houston, the rule would reduce carrying costs on the unrecovered CTC balance prospectively from 11.075 percent to the utility's cost of debt.
Net income for 2005 included an after-tax extraordinary gain of $30 million ($0.09 per diluted share) recorded in the second quarter reflecting an adjustment to the after-tax extraordinary loss of $977 million ($2.72 per diluted share) recorded in the last half of 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.
(b) FINAL FUEL RECONCILIATION
The results of the Texas Utility Commission's final decision related to CenterPoint Houston's final fuel reconciliation are a component of the True-Up Order. CenterPoint Houston has appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation in 2003 plus interest of $10 million. A judgment was entered by a Travis County court in May 2005 affirming the Texas Utility Commission's decision. CenterPoint Houston filed an appeal to the court of appeals in June 2005. The parties have filed briefs on the issues with the court and are awaiting a decision from the court of appeals.
(c) REMAND OF 2001 UNBUNDLED COST OF SERVICE ORDER
The 3rd Court of Appeals in Austin has remanded to the Texas Utility Commission an issue that was decided by the Texas Utility Commission in CenterPoint Houston's 2001 unbundled cost of service proceeding. In its remand order, the court ruled that the Texas Utility Commission had failed to adequately explain its basis for its determination of certain projected costs associated with interconnection of a new merchant generating plant. The 3rd Court of Appeals in Austin ordered the Texas Utility Commission to reconsider that determination on the basis of the record that existed at the time of the Commission's original order. The Company and CenterPoint Houston believe that record is sufficient to support a determination by the Texas Utility Commission that is consistent with its original determination. However, no prediction can be made at this time as to the ultimate outcome of this matter on remand.
(d) RATE CASES
NATURAL GAS DISTRIBUTION
SOUTHERN GAS OPERATIONS
In November 2004, Southern Gas Operations filed an application for a $34 million base rate increase, which was subsequently adjusted downward to $28 million, with the Arkansas Public Service Commission (APSC). In September 2005, an $11 million rate reduction (which included a $10 million reduction relating to depreciation rates) ordered by the APSC went into effect. The reduced depreciation rates were implemented effective October 2005. This base rate reduction and corresponding reduction in depreciation expense represent an annualized operating income reduction of $1 million.
In April 2005, the Railroad Commission established new gas tariffs that increased Southern Gas Operations' base rate and service revenues by a combined $2 million in the unincorporated environs of its
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Beaumont/East Texas and South Texas Divisions. In June and August 2005, Southern Gas Operations filed requests to implement these same rates within 169 incorporated cities located in the two divisions. The proposed rates were approved or became effective by operation of law in 164 of these cities. Five municipalities denied the rate change requests within their respective jurisdictions. Southern Gas Operations has appealed the actions of these five cities to the Railroad Commission. In February 2006, Southern Gas Operations notified the Railroad Commission that it had reached a settlement with four of the five cities. If approved, the settlement will affect rates in a total of 60 cities in the South Texas Division. In addition, 19 cities where rates have already gone into effect have challenged the jurisdictional and statutory basis for implementation of the new rates within their respective jurisdictions. Southern Gas Operations has petitioned the Railroad Commission for an order declaring that the new rates have been properly established within these 19 cities. If the settlement is approved and assuming all other rate change proposals become effective, revenues from Southern Gas Operations' base rates and miscellaneous service charges would increase by an additional $17 million annually. Currently, approximately $15 million of this expected annual increase is in effect in the incorporated areas of Southern Gas Operations' Beaumont/East Texas and South Texas Divisions.
In October 2005, Southern Gas Operations filed requests with the Louisiana Public Service Commission (LPSC) for approximately $2 million in base rate increases for its South Louisiana service territory and approximately $2 million in base rate reductions for its North Louisiana service territory in accordance with the Rate Stabilization Plans in its tariffs. These base rate changes became effective on January 2, 2006 in accordance with the tariffs and are subject to review and possible adjustment by the staff of the LPSC. Southern Gas Operations is unable to predict when the LPSC staff may conclude its review or what adjustments, if any, the staff may recommend.
In December 2005, Southern Gas Operations filed a request with the Mississippi Public Service Commission (MPSC) for approximately $1 million in miscellaneous service charges (e.g., charges to connect service, charges for returned checks, etc.) in its Mississippi service territory. This request was approved in the first quarter of 2006.
In addition, in January and February 2006, Southern Gas Operations filed requests with the MPSC for approximately $3 million in base rate increases in its Mississippi service territory in accordance with the Automatic Rate Adjustment Mechanism provisions in its tariffs and an additional $2 million in surcharges to recover system restoration expenses incurred following hurricane Katrina. Both requests are being reviewed by the MPSC staff with a decision expected in the first quarter of 2006.
MINNESOTA GAS
In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a settlement which increased Minnesota Gas' base rates by approximately $9 million annually. An interim rate increase of approximately $17 million had been implemented in October 2004. Substantially all of the excess amounts collected in interim rates over those approved in the final settlement were refunded to customers in the third quarter of 2005.
In November 2005, Minnesota Gas filed a request with the MPUC to increase annual rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. Any excess of amounts collected under the interim rates over the amounts approved in final rates is subject to refund to customers. A decision by the MPUC is expected in the third quarter of 2006.
In December 2004, the MPUC opened an investigation to determine whether Minnesota Gas' practices regarding restoring natural gas service during the period between October 15 and April 15 (Cold Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs disconnection and
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
reconnection of customers during the Cold Weather Period. The Minnesota Office of the Attorney General (OAG) issued its report alleging Minnesota Gas has violated the CWR and recommended a $5 million penalty. Minnesota Gas and the OAG have reached an agreement on procedures to be followed for the current Cold Weather Period which began on October 15, 2005. In addition, in June 2005, CERC was named in a suit filed in the United States District Court, District of Minnesota on behalf of a purported class of customers who allege that Minnesota Gas' conduct under the CWR was in violation of the law. Minnesota Gas is in settlement discussions regarding both the OAG's action and the action on behalf of the purported class.
ELECTRIC TRANSMISSION & DISTRIBUTION
The Texas Utility Commission requires each electric utility to file an annual Earnings Report providing certain information to enable the Texas Utility Commission to monitor the electric utilities' earnings and financial condition within the state. In May 2005, CenterPoint Houston filed its Earnings Report for the calendar year ended December 31, 2004. CenterPoint Houston's Earnings Report shows that it earned less than its authorized rate of return on equity in 2004.
In October 2005, the Staff filed a memorandum summarizing its review of the Earnings Reports filed by electric utilities. Based on its review, the Staff concluded that continuation of CenterPoint Houston's rates could result in excess retail transmission and distribution revenues of as much as $105 million and excess wholesale transmission revenues of as much as $31 million annually and recommended that the Texas Utility Commission initiate a review of the reasonableness of existing rates. The Staff's analysis was based on a 9.60 percent cost of equity, which is 165 basis points lower than the approved return on equity from CenterPoint Houston's last rate proceeding, the elimination of interest on debt that matured in November 2005 and certain other adjustments to CenterPoint Houston's reported information. Additionally, a hypothetical capital structure of 60 percent debt and 40 percent equity was used which varies materially from the actual capital structure of CenterPoint Houston as of December 31, 2005 of approximately 50 percent debt and 50 percent equity.
In December 2005, the Texas Utility Commission considered the Staff report and agreed to initiate a rate proceeding concerning the reasonableness of CenterPoint Houston's existing rates for transmission and distribution service and to require CenterPoint Houston to make a filing by April 15, 2006 to justify or change those rates.
(e) CITY OF TYLER, TEXAS DISPUTE
In July 2002, the City of Tyler, Texas, asserted that Southern Gas Operations had overcharged residential and small commercial customers in that city for gas costs under supply agreements in effect since 1992. That dispute was referred to the Railroad Commission by agreement of the parties for a determination of whether Southern Gas Operations has properly charged and collected for gas service to its residential and commercial customers in its Tyler distribution system in accordance with lawful filed tariffs during the period beginning November 1, 1992, and ending October 31, 2002. In December 2004, the Railroad Commission conducted a hearing on the matter. In May 2005, the Railroad Commission issued a final order finding that the Company had complied with its tariffs, acted prudently in entering into its gas supply contracts, and prudently managed those contracts. In August 2005, the City of Tyler appealed this order to the Court of Appeals.
(f) CITY OF HOUSTON FRANCHISE
CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that
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the franchises permit. The terms of the franchises, with various expiration dates, typically range from 5 to 50 years.
In June 2005, CenterPoint Houston accepted an ordinance granting it a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two-year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the Additional Amount will be adjusted annually based on the increase, if any, in kWh delivered by CenterPoint Houston within the City of Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case.
(g) SETTLEMENT OF FERC AUDIT
In June 2005, CenterPoint Energy Gas Transmission Company (CEGT), a subsidiary of CERC Corp., received an Order from the FERC accepting the terms of a settlement agreed upon by CEGT with the Staff of the FERC's Office of Market Oversight and Investigations (OMOI). The settlement brought to a conclusion an investigation of CEGT initiated by OMOI in August 2003. Among other things, the investigation involved a comprehensive review of CEGT's relationship with its marketing affiliates and compliance with various FERC record-keeping and reporting requirements covering the period from January 1, 2001 through September 22, 2004.
OMOI Staff took the position that some of CEGT's actions resulted in a limited number of violations of the FERC's affiliate regulations or were in violation of certain record-keeping and administrative requirements. OMOI did not find any systematic violations of its rules governing communications or other relationships among affiliates.
The settlement included two remedies: a payment of a $270,000 civil penalty and the execution of a compliance plan, applicable to both CEGT and CenterPoint Energy-Mississippi River Transmission Corporation (MRT). The compliance plan consists of a detailed set of Implementation Procedures that will facilitate compliance with the FERC's Order No. 2004, the Standards of Conduct, which regulate behavior between regulated entities and their affiliates. The Company does not believe the compliance plan will have any material effect on CEGT's or MRT's ability to conduct their business.
(5) DERIVATIVE INSTRUMENTS
The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments such as physical forward contracts, swaps and options (Energy Derivatives) to mitigate the impact of changes in its natural gas businesses on its operating results and cash flows.
(a) NON-TRADING ACTIVITIES
Cash Flow Hedges. During 2005, hedge ineffectiveness was a loss of $2 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments' gain or loss
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was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Company's Statements of Consolidated Operations under the caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2005, the Company expects $10 million in accumulated other comprehensive income to be reclassified as a decrease in Natural Gas expense during the next twelve months.
The maximum length of time the Company is hedging its exposure to the variability in future cash flows on existing financial instruments is primarily two years with a limited amount of exposure up to ten years. The Company's policy is not to exceed ten years in hedging its exposure.
Other Derivative Financial Instruments. The Company also has natural gas contracts that are derivatives which are not hedged and are accounted for on a mark-to-market basis with changes in fair value reported through earnings. Load following services that the Company offers its natural gas customers create an inherent tendency for the Company to be either long or short natural gas supplies relative to customer purchase commitments. The Company measures and values all of its volumetric imbalances on a real-time basis to minimize its exposure to commodity price and volume risk. The Company does not engage in proprietary or speculative commodity trading. Unhedged positions are accounted for by adjusting the carrying amount of the contracts to market and recognizing any gain or loss in operating income, net. During 2005, the Company recognized net gains related to unhedged positions amounting to $8 million. As of December 31, 2004 and 2005, the Company had recorded short-term risk management assets of $4 million and $28 million, respectively, and short-term risk management liabilities of $5 million and $25 million, respectively, included in other current assets and other current liabilities, respectively.
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include entering into transactions for the physical purchase, transportation and sale of natural gas at different locations (physical contracts). CES attempts to mitigate basis risk associated with these activities by entering into financial derivative contracts (financial contracts or financial basis swaps) to address market price volatility between the purchase and sale delivery points that can occur over the term of the physical contracts. The underlying physical contracts are accounted for on an accrual basis with all associated earnings not recognized until the time of actual physical delivery. The timing of the earnings impacts for the financial contracts differs from the physical contracts because the financial contracts meet the definition of a derivative under SFAS No. 133 and are recorded at fair value as of each reporting balance sheet date with changes in value reported through earnings. Changes in prices between the delivery points (basis spreads) can and do vary daily resulting in changes to the fair value of the financial contracts. However, the economic intent of the financial contracts is to fix the actual net difference in the natural gas pricing at the different locations for the associated physical purchase and sale contracts throughout the life of the physical contracts and thus, when combined with the physical contracts' terms, provide an expected fixed gross margin on the physical contracts that will ultimately be recognized in earnings at the time of actual delivery of the natural gas. As of December 31, 2005, the mark-to-market value of the financial contracts described above reflected an unrealized loss of $1 million; however, the underlying expected fixed gross margin associated with delivery under the physical contracts combined with the price risk management provided through the financial contracts is expected to offset the unrealized loss. As described above, over the term of these financial contracts, the quarterly reported mark-to-market changes in value may vary significantly and the associated unrealized gains and losses will be reflected in CES' earnings.
CES also sells physical gas and basis to its end-use customers who desire to lock in a future spread between a specific location and Henry Hub (NYMEX). As a result, CES incurs exposure to commodity basis risk related to these transactions, which it attempts to mitigate by buying offsetting financial basis swaps.
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Under SFAS No. 133, CES records at fair value and marks-to-market the financial basis swaps as of each reporting balance sheet date with changes in value reported through earnings. However, the associated physical sales contracts are accounted for using the accrual basis, whereby earnings impacts are not recognized until the time of actual physical delivery. Although the timing of earnings recognition for the financial basis swaps differs from the physical contracts, the economic intent of the financial basis swaps is to fix the basis spread over the life of the physical contracts to an amount substantially the same as the portion of the basis spread pricing included in the physical contracts. In so doing, over the period that the financial basis swaps and related physical contracts are outstanding, actual cumulative earnings impacts for changes in the basis spread should be minimal, even though from a timing perspective there could be fluctuations in unrealized gains or losses associated with the changes in fair value recorded for the financial basis swaps. The cumulative earnings impact from the financial basis swaps recognized each reporting period is expected to be offset by the value realized when the related physical sales occur. As of December 31, 2005, the mark-to-market value of the financial basis swaps reflected an unrealized loss of $3 million.
Interest Rate Swaps. During 2002, the Company settled forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million, which was recorded in other comprehensive loss and is being amortized into interest expense over the five-year life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive loss for 2003, 2004 and 2005, was $12 million, $25 million and $31 million, respectively.
Embedded Derivative. The Company's 3.75% and 2.875% convertible senior notes contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the balance sheet. The value of the contingent interest components was not material at issuance or at December 31, 2005.
(b) CREDIT RISKS
In addition to the risk associated with price movements, credit risk is also inherent in the Company's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of the Company as of December 31, 2004 and 2005 (in millions):
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(1) "Investment grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompass cash and standby letters of credit.
(2) For unrated counterparties, the Company performs financial statement analysis, considering contractual rights and restrictions and collateral, to create a synthetic credit rating.
(c) GENERAL POLICY
The Company has established a Risk Oversight Committee composed of corporate and business segment officers that oversees all commodity price and credit risk activities, including the Company's trading,
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marketing, risk management services and hedging activities. The committee's duties are to establish the Company's commodity risk policies, allocate risk capital within limits established by the Company's board of directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with the Company's risk management policies and procedures and trading limits established by the Company's board of directors.
The Company's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.
(6) INDEXED DEBT SECURITIES (ZENS) AND TIME WARNER SECURITIES
(a) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES
In 1995, the Company sold a cable television subsidiary to Time Warner Inc. (TW) and received TW convertible preferred stock (TW Preferred) as partial consideration. On July 6, 1999, the Company converted its 11 million shares of TW Preferred into 45.8 million shares of TW common stock (TW Common). The Company currently owns 21.6 million shares of TW Common. Unrealized gains and losses resulting from changes in the market value of the TW Common are recorded in the Company's Statements of Consolidated Operations.
(b) ZENS
In September 1999, the Company issued its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. ZENS are exchangeable for cash equal to the market value of a specified number of shares of TW common. The Company pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the shares of TW Common attributable to the ZENS. The principal amount of ZENS is subject to being increased or decreased to the extent that the annual yield from interest and cash dividends on the reference shares of TW Common is less than or more than 2.309%. At December 31, 2005, ZENS having an original principal amount of $840 million and a contingent principal amount of $851 million were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of 21.6 million shares of TW Common deemed to be attributable to the ZENS. At December 31, 2005, the market value of such shares was approximately $377 million, which would provide an exchange amount of $427 for each $1,000 original principal amount of ZENS. At maturity, the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of TW Common, or other securities distributed with respect to TW Common.
In 2002, holders of approximately 16% of the 17.2 million ZENS originally issued exercised their right to exchange their ZENS for cash, resulting in aggregate cash payments by CenterPoint Energy of approximately $45 million. Exchanges of ZENS subsequent to 2002 aggregate less than one percent of ZENS originally issued.
A subsidiary of the Company owns shares of TW Common and elected to liquidate a portion of such holdings to facilitate the Company's making the cash payments for the ZENS exchanged in 2002 through 2004. In connection with the exchanges, the Company received net proceeds of approximately $43 million from the liquidation of approximately 4.1 million shares of TW Common at an average price of $10.56 per share. The Company now holds 21.6 million shares of TW Common which are classified as trading securities under SFAS No. 115 and are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS.
Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component (the holder's option to receive the appreciated value of
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TW Common at maturity). The derivative component was valued at fair value and determined the initial carrying value assigned to the debt component ($121 million) as the difference between the original principal amount of the ZENS ($1 billion) and the fair value of the derivative component at issuance ($879 million). Effective January 1, 2001 the debt component was recorded at its accreted amount of $122 million and the derivative component was recorded at its fair value of $788 million, as a current liability. Subsequently, the debt component accretes through interest charges at 17.5% annually up to the minimum amount payable upon maturity of the ZENS in 2029 (approximately $913 million assuming no dividends are paid on the TW Common subsequent to 2005) which reflects exchanges and adjustments to maintain a 2.309% annual yield, as discussed above. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Operations. During 2003, 2004 and 2005, the Company recorded a gain (loss) of $106 million, $31 million and $(44) million, respectively, on the Company's investment in TW Common. During 2003, 2004 and 2005, the Company recorded a gain (loss) of $(96) million, $(20) million and $49 million, respectively, associated with the fair value of the derivative component of the ZENS obligation. Changes in the fair value of the TW Common held by the Company are expected to substantially offset changes in the fair value of the derivative component of the ZENS.
The following table sets forth summarized financial information regarding the Company's investment in TW common and the Company's ZENS obligation (in millions):
(7) EQUITY
(a) CAPITAL STOCK
CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock.
(b) SHAREHOLDER RIGHTS PLAN
The Company has a Shareholder Rights Plan that states that each share of its common stock includes one associated preference stock purchase right (Right) which entitles the registered holder to purchase from the Company a unit consisting of one-thousandth of a share of Series A Preference Stock. The Rights, which
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expire on December 11, 2011, are exercisable upon some events involving the acquisition of 20% or more of the Company's outstanding common stock. Upon the occurrence of such an event, each Right entitles the holder to receive common stock with a current market price equal to two times the exercise price of the Right. At anytime prior to becoming exercisable, the Company may repurchase the Rights at a price of $0.005 per Right. There are 700,000 shares of Series A Preference Stock reserved for issuance upon exercise of the Rights.
(8) LONG-TERM DEBT AND RECEIVABLES FACILITY
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(1) Includes amounts due, exchangeable or scheduled to be paid within one year of the date noted.
(2) Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's ZENS obligation was bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 6(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.
(3) These series of debt are secured by first mortgage bonds of CenterPoint Houston.
(4) $527 million of these series of debt is secured by general mortgage bonds of CenterPoint Houston.
(5) Classified as long-term debt because the termination dates of the facilities under which the funds were borrowed are more than one year from the date noted.
(6) The junior subordinated debentures were issued to subsidiary trusts in connection with the issuance by those trusts of preferred securities. The trust preferred securities were deconsolidated effective December 31, 2003 pursuant to the adoption of FIN 46. This resulted in the junior subordinated debentures held by the trusts being reported as long-term debt.
(7) London inter-bank offered rate (LIBOR) had a minimum rate of 3% under the terms of this debt. This term loan was secured by general mortgage bonds of CenterPoint Houston.
(8) These series of debt are secured by general mortgage bonds of CenterPoint Houston.
(9) Debt acquired in business acquisitions is adjusted to fair market value as of the acquisition date. Included in long-term debt is additional unamortized premium related to fair value adjustments of long-term debt of $5 million at both December 31, 2004 and 2005, which is being amortized over the respective remaining term of the related long-term debt.
(a) LONG-TERM DEBT
Revolving Credit Facilities. In March 2005, the Company replaced its $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 87.5 basis points based on current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of December 31, 2005, borrowings of $3 million in commercial paper were backstopped by the revolving credit facility and $27 million in letters of credit were outstanding under the revolving credit facility.
Also, in March 2005, CenterPoint Houston established a $200 million five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 75 basis points based on CenterPoint Houston's current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of December 31, 2005, there were $4 million in letters of credit outstanding under the revolving credit facility.
In June 2005, CERC Corp. replaced its $250 million three-year revolving credit facility with a $400 million five-year revolving credit facility. Borrowings under this facility may be made at LIBOR plus 55 basis points, including the facility fee, based on current credit ratings. An additional utilization fee of 10 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of December 31, 2005, such credit facility was not utilized.
The bank facilities contain various business and financial covenants with which the borrowers were in compliance as of December 31, 2005. CenterPoint Houston's credit facility limits CenterPoint Houston's debt, excluding transition bonds, as a percentage of its total capitalization to 68 percent. CERC Corp.'s bank facility and its receivables facility limit CERC's debt as a percentage of its total capitalization to 65 percent.
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Transition Bonds. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Scheduled payment dates range from August 2006 to August 2019. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued. The proceeds received from the issuance of the transition bonds were used to repay CenterPoint Houston's $1.3 billion credit facility, which was utilized in November 2005 to repay CenterPoint Houston's $1.3 billion term loan upon its maturity.
Convertible Debt. On May 19, 2003, the Company issued $575 million aggregate principal amount of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. Holders may convert each of their notes into shares of CenterPoint Energy common stock, initially at a conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes at any time prior to maturity, under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Ratings Services (S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company's assets, debt securities or certain rights to purchase the Company's securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. Holders have the right to require the Company to purchase all or any portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of notes commencing on or after May 15, 2008, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.
In August 2005, the Company accepted for exchange approximately $572 million aggregate principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes due 2023 (New Notes). Old Notes of approximately $3 million remain outstanding. The Company commenced the exchange offer in response to the guidance set forth in EITF Issue No. 04-8, "Accounting Issues Related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the principal portion of the New Notes will be made in cash rather than stock, the exchange of New Notes for Old Notes will allow the Company to exclude the portion of the conversion value of the New Notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. See Note 12 for the impact on diluted earnings per share related to these securities. The Company determined that the New Notes did not have substantially different terms than the Old Notes, and thus, in accordance with EITF Issue No. 96-19 "Debtor's Accounting for a Modification or Exchange of Debt Instruments", the exchange
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transaction was accounted for as a modification of the original instrument and not as an extinguishment of debt. Accordingly, a new effective interest rate was determined based on the carrying amount of the original debt instrument and the revised cash flows, and the recorded discount will be amortized as an adjustment to interest expense in future periods.
On December 17, 2003, the Company issued $255 million aggregate principal amount of convertible senior notes due January 15, 2024 with an interest rate of 2.875%. Holders may convert each of their notes into shares of CenterPoint Energy common stock, initially at a conversion rate of 78.064 shares of common stock per $1,000 principal amount of notes at any time prior to maturity, under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody's and S&P are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company's assets, debt securities or certain rights to purchase the Company's securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. Under the original terms of these convertible senior notes, CenterPoint Energy could elect to satisfy part or all of its conversion obligation by delivering cash in lieu of shares of CenterPoint Energy. On December 13, 2004, the Company entered into a supplemental indenture with respect to these convertible senior notes in order to eliminate its right to settle the conversion of the notes solely in shares of its common stock. Holders have the right to require the Company to purchase all or any portion of the notes for cash on January 15, 2007, January 15, 2012 and January 15, 2017 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of notes commencing on or after January 15, 2007, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.
Junior Subordinated Debentures (Trust Preferred Securities). In February 1997, a Delaware statutory business trust created by CenterPoint Energy (HL&P Capital Trust II) issued to the public $100 million aggregate amount of capital securities. The trust used the proceeds of the offering to purchase junior subordinated debentures issued by CenterPoint Energy having an interest rate and maturity date that correspond to the distribution rate and the mandatory redemption date of the capital securities. The amount of outstanding junior subordinated debentures discussed above was included in long-term debt as of December 31, 2004 and 2005.
The junior subordinated debentures are the trust's sole assets and their entire operations. CenterPoint Energy considers its obligations under the Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where applicable, Agreement as to Expenses and Liabilities, relating to the capital securities, taken together, to constitute a full and unconditional guarantee by CenterPoint Energy of the trust's obligations with respect to the capital securities.
The capital securities are mandatorily redeemable upon the repayment of the related series of junior subordinated debentures at their stated maturity or earlier redemption. Subject to some limitations, CenterPoint Energy has the option of deferring payments of interest on the junior subordinated debentures.
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During any deferral or event of default, CenterPoint Energy may not pay dividends on its capital stock. As of December 31, 2005, no interest payments on the junior subordinated debentures had been deferred.
The outstanding aggregate liquidation amount, distribution rate and mandatory redemption date of the capital securities of the trust described above and the identity and similar terms of the related series of junior subordinated debentures are as follows:
In June 1996, a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued $173 million aggregate amount of convertible preferred securities to the public. CERC Trust used the proceeds of the offering to purchase convertible junior subordinated debentures issued by CERC Corp. having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the convertible preferred securities. The convertible junior subordinated debentures represented CERC Trust's sole asset and its entire operations. The $6 million of outstanding junior subordinated debentures was included in long-term debt as of December 31, 2004. The convertible preferred securities and the related convertible junior subordinated debentures were redeemed on August 1, 2005.
Maturities. The Company's maturities of long-term debt (including scheduled payments on transition bonds), capital leases and sinking fund requirements, excluding the ZENS obligation, are $230 million in 2006, $153 million in 2007, $666 million in 2008, $181 million in 2009 and $400 million in 2010.
Liens. As of December 31, 2005, CenterPoint Houston's assets were subject to liens securing approximately $253 million of first mortgage bonds. Sinking or improvement fund and replacement fund requirements on the first mortgage bonds may be satisfied by certification of property additions. Sinking fund and replacement fund requirements for 2003, 2004 and 2005 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2006 is approximately $151 million, and the sinking fund requirement to be satisfied in 2006 is approximately $3 million. The Company expects CenterPoint Houston to meet these 2006 obligations by certification of property additions. As of December 31, 2005, CenterPoint Houston's assets were also subject to liens securing approximately $2.0 billion of general mortgage bonds which are junior to the liens of the first mortgage bonds.
(b) RECEIVABLES FACILITY
In January 2006, CERC's $250 million receivables facility, which was temporarily increased to $375 million for the period from January 2006 to June 2006 to provide additional liquidity to CERC during the peak heating season of 2006, was extended to January 2007. As of December 31, 2005, CERC had $141 million of advances under its receivables facility.
Advances under the receivables facility averaged $100 million, $190 million and $166 million in 2003, 2004 and 2005, respectively. Sales of receivables were approximately $1.2 billion, $2.4 billion and $2.0 billion in 2003, 2004 and 2005, respectively.
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(9) INCOME TAXES
The Company's current and deferred components of income tax expense (benefit) were as follows:
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
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Following are the Company's tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases:
Tax Attribute Carryforwards. Based on returns filed the Company has $239 million of state net operating loss carryforwards. The losses are available to offset future state taxable income through the year 2024. Substantially all of the state loss carryforwards will expire between 2012 and 2020. A valuation allowance has been established against approximately 58% of the state net operating loss carryforwards.
The valuation allowance reflects a net decrease of $53 million in 2004 and an increase of $1 million in 2005. The net changes resulted from a reassessment of the Company's ability to use federal capital loss and state net operating loss carryforwards in 2004 and state net operating loss carryforwards, in 2005.
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Tax Refunds. In 2004, the Company received a refund from the IRS of $163 million, related to the carryback of the federal tax net operating loss generated in 2003.
Tax Contingencies. CenterPoint Energy's consolidated federal income tax returns have been audited and settled through the 1996 tax year.
In the audits of the 1997 through 2003 tax years, the IRS disallowed all deductions for original issue discount (OID) and interest paid relating to the Company's 2.0% ZENS, due 2029, and the 7% Automatic Common Exchange Securities (ACES), redeemed in 1999. It is the contention of the IRS that (1) those instruments, in combination with the Company's long position in TW Common, constitute a straddle under Section 1092 and 246 of the Internal Revenue Code of 1986, as amended and (2) the indebtedness underlying those instruments was incurred to carry the TW Common. If the IRS prevails on both of those positions, none of the OID and interest paid on the ZENS and ACES would be currently deductible but would instead be added to the Company's basis in the TW Common it holds. The capitalization of OID and interest to the TW Common basis would have the effect of recharacterizing ordinary interest deductions to capital losses or reduced capital gains.
The Company's ability to realize the tax benefit of future capital losses, if any, from the sale of the 21.6 million shares of TW Common currently held will depend on the timing of those sales, the value of TW Common stock when sold, and the extent of any other capital gains and losses.
Although the Company is protesting the disallowance of the ZENS and ACES OID and interest paid, reserves have been established for the tax and interest on this issue totaling $79 million and $121 million as of December 31, 2004 and 2005, respectively. The Company has also established reserves for other significant tax items including issues relating to prior acquisitions and dispositions of business operations and certain positions taken with respect to state tax filings. The total amount reserved for the other tax items is approximately $74 million and $60 million as of December 31, 2004 and 2005, respectively.
(10) COMMITMENTS AND CONTINGENCIES
(a) FUEL COMMITMENTS
Fuel commitments include natural gas contracts related to the Company's natural gas distribution and competitive natural gas sales and services operations, which have various quantity requirements and durations that are not classified as non-trading derivatives assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2005 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Minimum payment obligations for natural gas supply contracts are approximately $858 million in 2006, $375 million in 2007, $53 million in 2008, $4 million in 2009, $3 million in 2010 and $23 million in 2011 and thereafter.
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(b) LEASE COMMITMENTS
The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases at December 31, 2005, which primarily consist of rental agreements for building space, data processing equipment and vehicles (in millions):
Total lease expense for all operating leases was $35 million, $32 million and $37 million during 2003, 2004 and 2005, respectively.
(c) CAPITAL COMMITMENTS
In October 2005, CEGT signed a firm transportation agreement with XTO Energy to transport 600 million cubic feet (MMcf) per day of natural gas from Carthage, Texas to CEGT's Perryville hub in Northeast Louisiana. To accommodate this transaction, CEGT is in the process of filing applications for certificates with the FERC to build a 172 mile, 42-inch diameter pipeline, and related compression facilities at an estimated cost of $400 million. The final capacity of the pipeline will be between 960 MMcf per day and 1.24 billion cubic feet per day. CEGT expects to have firm contracts for the full capacity of the pipeline prior to its expected in service date in early 2007. During the four year period subsequent to the in service date of the pipeline, XTO can request, and subject to mutual negotiations that meet specific financial parameters, CEGT would construct a 67 mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern Gas Transmission at Union Church, Mississippi.
(d) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS
LEGAL MATTERS
RRI Indemnified Litigation
The Company, CenterPoint Houston or their predecessor, Reliant Energy, and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between the Company and RRI, the Company and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys' fees and other costs, arising out of the lawsuits described below under Electricity and Gas Market Manipulation Cases and Other Class Action Lawsuits. Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. The ultimate outcome of these matters cannot be predicted at this time.
Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in federal court in California, Nevada and Kansas and in California state court in connection with the operation of the electricity and natural gas markets in California and certain other western states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and
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breaches of contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit, attorneys' fees and divestiture of assets. The Company's former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally.
The Company or its predecessor, Reliant Energy, has been named in approximately 30 of these lawsuits, which were instituted between 2001 and 2005 and are pending in California state court in San Diego County and in federal district courts in San Francisco, San Diego, Los Angeles, Fresno, Sacramento, San Jose, Kansas and Nevada and before the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court, and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases.
To date, several of the electricity complaints have been dismissed, and several of the dismissals have been affirmed by appellate courts. Others have been resolved by the settlement described in the following paragraph. Four of the gas complaints have also been dismissed based on defendants' claims of federal preemption and the filed rate doctrine, and these dismissals have been appealed. In June 2005, a San Diego state court refused to dismiss other gas complaints on the same basis. The other gas cases remain in the early procedural stages.
On August 12, 2005, RRI reached a settlement with the states of California, Washington and Oregon, California's three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement also resolves the claims of the states and the investor-owned utilities related to the 2000-2001 natural gas markets. The settlement has been approved by the FERC and by the California Public Utilities Commission, and now must be approved by the courts in which the class action cases are pending. This approval is expected in the second quarter of 2006. The Company is not a party to the settlement, but may rely on the settlement as a defense to any claims brought against it related to the time when the Company was an affiliate of RRI. The terms of the settlement do not require payment by the Company.
Other Class Action Lawsuits. A number of class action lawsuits filed in 2002 on behalf of purchasers of securities of RRI and/or Reliant Energy were consolidated in federal district court in Houston. The consolidated complaint named RRI, certain of its current and former executive officers, Reliant Energy, the underwriters of the initial public offering of RRI's common stock in May 2001 (RRI Offering), and RRI's and Reliant Energy's independent auditors as defendants. The complaint sought monetary relief on behalf of purchasers of common stock of Reliant Energy or RRI during certain time periods ranging from February 2000 to May 2002, and purchasers of common stock that could be traced to the RRI Offering. The plaintiffs alleged, among other things, that the defendants misrepresented revenues and trading volumes by engaging in round-trip trades and improperly accounted for certain structured transactions as cash-flow hedges, which resulted in earnings from these transactions being accounted for as future earnings rather than being accounted for as earnings in fiscal year 2001. In July 2005, the parties announced that they had reached agreement on a settlement of this matter, and in January 2006, following a hearing, the trial judge approved that settlement and dismissed this matter. The terms of the settlement do not require payment by the Company.
In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by the Company. Two of the lawsuits were dismissed
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without prejudice. In the remaining lawsuit, the Company and certain current and former members of its benefits committee are defendants. That lawsuit alleged that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of 1974 by permitting the plans to purchase or hold securities issued by the Company when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint sought monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. In January 2006, the federal district judge granted a motion for summary judgment filed by the Company and the individual defendants. The plaintiffs have filed an appeal of the ruling to the Fifth Circuit Court of Appeals. The Company believes that this lawsuit is without merit and will continue to vigorously defend the case. However, the ultimate outcome of this matter cannot be predicted at this time.
Other Legal Matters
Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI, Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of other participants in the Electric Reliability Council of Texas (ERCOT) power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. In June 2004, the federal court dismissed the plaintiff's claims and the plaintiff appealed to the U.S. Fifth Circuit Court of Appeals, which affirmed the dismissal. The plaintiff then sought review by the U.S. Supreme Court in a petition for certiorari which was denied. Thus, this matter has now been finally resolved in favor of the defendants.
In February 2005, Utility Choice Electric filed in federal court in Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP and a number of other participants in the ERCOT power market. The plaintiff, a retail electricity provider in the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws, intentionally interfered with prospective business relationships and contracts, and committed fraud and negligent misrepresentation. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. In December 2005, the district court judge granted the defendants' motion to dismiss the complaint. Subsequently, a settlement was reached under which the CenterPoint Energy entities have been fully released from all claims without the payment of any settlement amount by the Company.
Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit in state district court in Harris County, Texas for themselves and a proposed class of all similarly situated cities in Reliant Energy's electric service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of the Company's predecessor, Reliant Energy) alleging underpayment of municipal franchise fees. After a jury trial involving the Three Cities' claims (but not the class of cities), and a subsequent appeal, a state court of appeals in Houston rendered an opinion that the Three Cities should take nothing by their claims. The Texas Supreme Court declined further review. Thus, the Three Cities' claims have been finally resolved in the Company's favor. Individual claims of the remaining 45 cities were filed in the state district court and remain pending before that same court. Other than the City of Houston nonsuiting its claim in February 2006, there has been no activity on these claims since the Texas Supreme Court declined further review of the Three Cities' claims. The Company does not expect the
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outcome of the remaining claims to have a material impact on its financial condition, results of operations or cash flows.
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a suit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming.
In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC and its subsidiaries believe that there has been no systematic mismeasurement of gas and that the suits are without merit. CERC does not expect the ultimate outcome to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company, and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. Subsequently, the plaintiffs added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company, United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation Group, Inc., all of which are subsidiaries of the Company. The plaintiffs alleged that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed in state court in Caddo Parish, Louisiana against CERC with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas services allegedly provided by Southern Gas Operations to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CERC, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River Transmission Corp. and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged
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rate overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the resolution of the respective proceedings by the LPSC. The plaintiffs in the Miller County case seek class certification, but the proposed class has not been certified. In February 2005, the Wharton County case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified. The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney's fees. In these cases, the Company, CERC and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. The allegations in these cases are similar to those asserted in the City of Tyler proceeding described in Note 4(e). The Company and CERC do not expect the outcome of these matters to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
Pipeline Safety Compliance. Pursuant to an order from the Minnesota Office of Pipeline Safety, CERC substantially completed removal of certain non-code-compliant components from a portion of its distribution system by December 2, 2005. The components were installed by a predecessor company, which was not affiliated with CERC during the period in which the components were installed. In November 2005, Minnesota Gas filed a request with the MPUC to recover the capitalized expenditures (approximately $39 million) and related expenses, together with a return on and of the capitalized portion through rates.
Minnesota Cold Weather Rule. In December 2004, the MPUC opened an investigation to determine whether Minnesota Gas' practices regarding restoring natural gas service during the period between October 15 and April 15 (Cold Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs disconnection and reconnection of customers during the Cold Weather Period. The Minnesota Office of the Attorney General (OAG) issued its report alleging Minnesota Gas has violated the CWR and recommended a $5 million penalty. Minnesota Gas and the OAG have reached an agreement on procedures to be followed for the current Cold Weather Period which began on October 15, 2005. In addition, in June 2005, CERC was named in a suit filed in the United States District Court, District of Minnesota on behalf of a purported class of customers who allege that Minnesota Gas' conduct under the CWR was in violation of the law. Minnesota Gas is in settlement discussions regarding both the OAG's action and the action on behalf of the purported class. The Company and CERC do not expect the outcome of this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
ENVIRONMENTAL MATTERS
Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.
Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or
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diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The Company does not expect the ultimate cost associated with resolving this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.
At December 31, 2005, CERC had accrued $14 million for remediation of these Minnesota sites. At December 31, 2005, the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of December 31, 2005, CERC has collected $13 million from insurance companies and rate payers to be used for future environmental remediation.
In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in two lawsuits filed in United States District Court, District of Maine and Middle District of Florida, Jacksonville Division under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of one of the lawsuits. In March 2005, the court considering the other suit for contribution granted CERC's motion to dismiss on the grounds that CERC was not an "operator" of the site as had been alleged. The plaintiff in that case has filed an appeal of the court's dismissal of CERC. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of those sites under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP.
Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on the Company's experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows.
Asbestos. Facilities owned by the Company contain or have contained asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company's subsidiaries but currently owned by Texas Genco LLC. The Company anticipates that additional claims like those received may be asserted in
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the future. Under the terms of the separation agreement between the Company and Texas Genco, ultimate financial responsibility for uninsured losses from claims relating to facilities transferred to Texas Genco has been assumed by Texas Genco, but under the terms of its agreement to sell Texas Genco to Texas Genco LLC, the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company's financial condition, results of operations or cash flows.
Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company's financial condition, results of operations or cash flows.
OTHER PROCEEDINGS
The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management does not expect the disposition of these matters to have a material adverse effect on the Company's financial condition, results of operations or cash flows.
GUARANTEES
Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI's trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guarantee obligations prior to separation, but when separation occurred in September 2002, RRI had been unable to extinguish all obligations. To secure CenterPoint Energy and CERC against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of CERC and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guarantees. The Company's current exposure under the remaining guarantees relates to CERC's guarantee of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. As a result of changes in market conditions, CenterPoint Energy's potential exposure under that guarantee currently exceeds the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC's obligations under the guarantee, and CenterPoint Energy and RRI are pursuing alternatives. RRI continues to meet its obligations under the transportation contracts.
TEXAS GENCO MATTERS
CenterPoint Houston, as collection agent for the nuclear decommissioning charge assessed on its transmission and distribution customers, transferred $2.9 million in 2003 and 2004 and $3.2 million in 2005 to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project. There are various investment restrictions imposed upon Texas Genco by the Texas Utility Commission and
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the Nuclear Regulatory Commission relating to Texas Genco's nuclear decommissioning trusts. Pursuant to the provisions of both a separation agreement and the Texas Utility Commission's final order, CenterPoint Houston and Texas Genco are presently jointly administering the decommissioning funds through the Nuclear Decommissioning Trust Investment Committee. Texas Genco and CenterPoint Houston have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the investment policy of the trusts and oversees the investment of the trusts' assets. As administrators of the decommissioning funds, CenterPoint Houston and Texas Genco are jointly responsible for assuring that the funds are prudently invested in a manner consistent with the rules of the Texas Utility Commission. On February 2, 2006, CenterPoint Houston and Texas Genco filed a request with the Texas Utility Commission to name Texas Genco as the sole fund administrator. Pursuant to the Texas electric restructuring law, costs associated with nuclear decommissioning that were not recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be charged to transmission and distribution customers of CenterPoint Houston or its successor.
(11) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair values of cash and cash equivalents, investments in debt and equity securities classified as "available-for-sale" and "trading" in accordance with SFAS No. 115, and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities are equivalent to their carrying amounts in the Consolidated Balance Sheets at December 31, 2004 and 2005 and have been determined using quoted market prices for the same or similar instruments when available or other estimation techniques (see Note 5). Therefore, these financial instruments are stated at fair value and are excluded from the table below.
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(12) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's basic and diluted earnings (loss) per share calculations:
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(1) Options to purchase 10,106,673, 11,892,508 and 8,677,660 shares were outstanding for the years ended December 31, 2003, 2004 and 2005, respectively, but were not included in the computation of diluted earnings (loss) per share because the options' exercise price was greater than the average market price of the common shares for the respective years.
In accordance with EITF 04-8, because all of the 2.875% contingently convertible senior notes and approximately $572 million of the 3.75% contingently convertible senior notes (subsequent to the August 2005 exchange discussed in Note 8) provide for settlement of the principal portion in cash rather than stock, the Company excludes the portion of the conversion value of these notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. The Company includes the conversion spread in the calculation of diluted earnings per share when the average market price of the Company's common stock in the respective reporting period exceeds the conversion price. The conversion prices for the 2.875% and the 3.75% contingently convertible senior notes are $12.81 and $11.58, respectively.
(13) UNAUDITED QUARTERLY INFORMATION
The consolidated financial statements for 2004 and 2005 have been prepared to reflect the sale of Texas Genco as described in Note 3. Accordingly, the consolidated financial statements present the Texas Genco business as discontinued operations, in accordance with SFAS No. 144.
Summarized quarterly financial data is as follows:
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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(1) Quarterly earnings per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings per common share. The Company's 3.75% contingently convertible notes are not included in the calculation of diluted earnings per share during the first three quarters of 2004 as they were anti-dilutive due to lower income from continuing operations in these periods. However, the 3.75% contingently convertible notes are included in the calculation of diluted earnings per share for the fourth quarter of 2004, and the first and second quarters of 2005, as they are dilutive. In the third quarter of 2005, the Company modified approximately $572 million of the 3.75% contingently convertible senior notes to provide for settlement of the principal portion in cash rather than stock. Accordingly, the Company excludes the portion of the conversion value of these notes and the 2.875% contingently convertible notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. The Company includes the conversion spread in the calculation of diluted earnings per share when the average market price of the Company's common stock in the respective reporting period exceeds the conversion price.
(14) REPORTABLE BUSINESS SEGMENTS
The Company's determination of reportable business segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments.
The Company's reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Pipelines and Field Services
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(formerly Pipelines and Gathering) and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. The Company reorganized the oversight of its Natural Gas Distribution business segment and, as a result, beginning in the fourth quarter of 2005, the Company established a new reportable business segment, Competitive Natural Gas Sales and Services. Competitive Natural Gas Sales and Services represents the Company's non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. Pipelines and Field Services includes the interstate natural gas pipeline operations and the natural gas gathering and pipeline services businesses. Other Operations consists primarily of other corporate operations which support all of the Company's business operations. The Company's Latin America operations and its energy management services business, which were previously reported in the Other Operations business segment, are presented as discontinued operations within these consolidated financial statements. Additionally, the Company's generation operations, which were previously reported in the Electric Generation business segment, are presented as discontinued operations within these consolidated financial statements. All prior period segment information has been reclassified to conform to the 2005 presentation.
Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.
Financial data for business segments and products and services are as follows (in millions):
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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(1) Revenues from external customers for the Electric Transmission & Distribution business segment include ECOM revenues of $661 million for 2003.
(2) Sales to subsidiaries of RRI in 2003, 2004 and 2005 represented approximately $948 million, $882 million and $812 million, respectively, of CenterPoint Houston's transmission and distribution revenues.
(3) Sales to Texas Genco in 2003 and 2004 represented approximately $28 million and $20 million, respectively, of the Competitive Natural Gas Sales and Services business segment's revenues from external customers. Texas Genco has been presented as discontinued operations in these consolidated financial statements.
(4) Sales to Texas Genco in 2003 and 2004 represented approximately $3 million and $2 million, respectively, of the Pipelines and Field Services business segment's revenues from external customers. Texas Genco has been presented as discontinued operations in these consolidated financial statements.
(5) Included in total assets of Other Operations as of December 31, 2004 and 2005 is a pension asset of $610 million and $654 million, respectively. See Note 2(o) for further discussion.
(15) SUBSEQUENT EVENT
On January 26, 2006, the Company's board of directors declared a regular quarterly cash dividend of $0.15 per share of common stock payable on March 10, 2006, to shareholders of record as of the close of business on February 16, 2006.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2005 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.
"Management's Annual Report on Internal Control over Financial Reporting" appears on page 118 of this annual report on Form 10-K. In December 2005, the Company determined that, during 2004 and 2005, certain transactions involving purchases and sales of natural gas among divisions within its Natural Gas Distribution and Competitive Natural Gas Sales and Services segments were not properly eliminated in the consolidated financial statements. Consequently, revenues and natural gas expenses during the year ended December 31, 2004 were each overstated by approximately $511 million and during the nine months ended September 30, 2005 were each overstated by approximately $402 million. Management concluded that a restatement of the 2004 consolidated financial statements and the 2005 interim consolidated financial statements was necessary to correct this error. In connection with the discovery of the error described above and the conclusion that the Company had a material weakness in its internal control over financial reporting related to ineffective controls over the process of eliminating certain interdivision purchases and sales of natural gas within its Natural Gas Distribution and Competitive Natural Gas Sales and Services segments in the consolidation process, the Company improved procedures related to the recording and reporting of purchases and sales of natural gas during the three months ended December 31, 2005, including increased review and approval controls by senior financial personnel over the personnel that prepare the accruals and enhanced analysis of the recorded activity, including ensuring that intercompany activity is properly eliminated in consolidation. Management believes these changes remediated the material weakness in internal control over financial reporting referenced above as of December 31, 2005.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive and principal financial officers 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 and includes those policies and procedures that:
- Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
- 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
- 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.
Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management's assessment included review and testing of both the design effectiveness and operating effectiveness of controls over all relevant assertions related to all significant accounts and disclosures in the 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. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control -- Integrated Framework, our management has concluded that our internal control over financial reporting was effective as of December 31, 2005.
Deloitte & Touche LLP, the Company's independent registered public accounting firm, has issued an attestation report on our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 which is included herein on page 119.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of CenterPoint Energy, Inc. Houston, Texas
We have audited management's assessment, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting, that CenterPoint Energy, Inc. and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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 as of and for the year ended December 31, 2005 of the Company and our report dated March 15, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company's adoption of a new accounting standard related to conditional asset retirement obligations.
DELOITTE & TOUCHE LLP
Houston, Texas March 15, 2006
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
The information called for by Item 10, to the extent not set forth in "Executive Officers" in Item 1, is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 10 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by Item 11 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 11 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information called for by Item 12 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 12 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by Item 13 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 13 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information called for by Item 14 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 14 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements.
(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2005.
The following schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements:
III, IV and V.
(a)(3) Exhibits.
See Index of Exhibits beginning on page 133, which index also includes the management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of CenterPoint Energy, Inc. Houston, Texas
We have audited the consolidated financial statements of CenterPoint Energy, Inc. and subsidiaries (the "Company") as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated March 15, 2006 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's adoption of a new accounting standard for conditional asset retirement obligations). We have also audited management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005 and the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and have issued our report thereon dated March 15, 2006; such reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules the Company listed in the index at Item 15 (a)(2). These consolidated financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated 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.
DELOITTE & TOUCHE LLP
Houston, Texas March 15, 2006
CENTERPOINT ENERGY, INC.
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF CENTERPOINT ENERGY, INC. (PARENT COMPANY)
STATEMENTS OF OPERATIONS
See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8
CENTERPOINT ENERGY, INC.
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF CENTERPOINT ENERGY, INC. (PARENT COMPANY)
BALANCE SHEETS
See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8
CENTERPOINT ENERGY, INC.
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF CENTERPOINT ENERGY, INC. (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8
CENTERPOINT ENERGY, INC.
SCHEDULE I -- NOTES TO CONDENSED FINANCIAL INFORMATION (PARENT COMPANY)
(1) The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of CenterPoint Energy, Inc. (CenterPoint Energy or the Company) appearing in the Annual Report on Form 10-K. Bank facilities at CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp., indirect wholly owned subsidiaries of the Company, limit debt, excluding transition bonds, as a percentage of their total capitalization to 68 percent and 65 percent, respectively. These covenants could restrict the ability of these subsidiaries to distribute dividends to the Company.
(2) CenterPoint Energy was a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). The 1935 Act and related rules and regulations imposed a number of restrictions on the activities of the Company and its subsidiaries. The Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since that date the Company and its subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005), which grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require the Company to notify the FERC of its status as a holding company and to maintain certain books and records and make these available to the FERC. The FERC continues to consider motions for rehearing or clarification of these rules.
(3) Effective January 1, 2004, CenterPoint Energy established a service company in order to comply with the 1935 Act. As a result, certain assets and liabilities of the parent company were transferred to the service company, primarily property, plant and equipment and related deferred taxes. These transfers have been excluded from the Statement of Cash Flows for the year ended December 31, 2004 as they represent non-cash transactions.
(4) In July 2004, the Company announced its agreement to sell its majority owned subsidiary, Texas Genco, to Texas Genco LLC (formerly known as GC Power Acquisition LLC), an entity owned in equal parts by affiliates of The Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas Pacific Group. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco distributed $2.231 billion in cash to the Company. Texas Genco's principal remaining asset was its ownership interest in a nuclear generating facility. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to the Company of $700 million, was completed on April 13, 2005. The Company recorded after tax losses of $366 million and $14 million in 2004 and 2005, respectively, related to the sale of Texas Genco.
(5) In March 2005, the Company replaced its $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at the London interbank offered rate (LIBOR) plus 87.5 basis points based on current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of December 31, 2005, borrowings of $3 million in commercial paper were backstopped by the revolving credit facility and $27 million in letters of credit were outstanding under the revolving credit facility.
On May 19, 2003, the Company issued $575 million aggregate principal amount of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. Holders may convert each of their notes into shares of CenterPoint Energy common stock, initially at a conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes at any time prior to maturity, under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or
equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Ratings Services (S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company's assets, debt securities or certain rights to purchase the Company's securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. Holders have the right to require the Company to purchase all or any portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of notes commencing on or after May 15, 2008, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.
In August 2005, the Company accepted for exchange approximately $572 million aggregate principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes due 2023 (New Notes). Old Notes of approximately $3 million remain outstanding. The Company commenced the exchange offer in response to the guidance set forth in Emerging Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the principal portion of the New Notes will be made in cash rather than stock, the exchange of New Notes for Old Notes will allow the Company to exclude the portion of the conversion value of the New Notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. See Note 12 for the impact on diluted earnings per share related to these securities. The Company determined that the New Notes did not have substantially different terms than the Old Notes, and thus, in accordance with EITF Issue No. 96-19 "Debtor's Accounting for a Modification or Exchange of Debt Instruments", the exchange transaction was accounted for as a modification of the original instrument and not as an extinguishment of debt. Accordingly, a new effective interest rate was determined based on the carrying amount of the original debt instrument and the revised cash flows, and the recorded discount will be amortized as an adjustment to interest expense in future periods.
On December 17, 2003, the Company issued $255 million aggregate principal amount of convertible senior notes due January 15, 2024 with an interest rate of 2.875%. Holders may convert each of their notes into shares of CenterPoint Energy common stock, initially at a conversion rate of 78.064 shares of common stock per $1,000 principal amount of notes at any time prior to maturity, under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody's and S&P are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company's assets, debt securities or certain rights to purchase the Company's securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading
day immediately preceding the declaration date for such distribution. Under the original terms of these convertible senior notes, CenterPoint Energy could elect to satisfy part or all of its conversion obligation by delivering cash in lieu of shares of CenterPoint Energy. On December 13, 2004, the Company entered into a supplemental indenture with respect to these convertible senior notes in order to eliminate its right to settle the conversion of the notes solely in shares of its common stock. Holders have the right to require the Company to purchase all or any portion of the notes for cash on January 15, 2007, January 15, 2012 and January 15, 2017 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of notes commencing on or after January 15, 2007, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.
(6) CenterPoint Energy Intrastate Pipelines, Inc., CenterPoint Energy Services, Inc. and other wholly owned subsidiaries of CERC Corp. provide comprehensive natural gas sales and services to industrial and commercial customers which are primarily located within or near the territories served by the Company's pipelines and distribution subsidiaries. In order to hedge their exposure to natural gas prices, these CERC Corp. subsidiaries have entered standard purchase and sale agreements with various counterparties. CenterPoint Energy has guaranteed the payment obligations of these subsidiaries under certain of these agreements, typically for one-year terms. As of December 31, 2005, CenterPoint Energy had guaranteed $182 million under these agreements.
CENTERPOINT ENERGY, INC.
SCHEDULE II -- QUALIFYING VALUATION ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 2005
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(1) Charges to other accounts represent changes in presentation to reflect state tax attributes net of federal tax benefit as well as to reflect amounts that were netted against related attribute balances in prior years.
(2) Deductions from reserves represent losses or expenses for which the respective reserves were created. In the case of the uncollectible accounts reserve, such deductions are net of recoveries of amounts previously written off.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on the 15th day of March, 2006.
CENTERPOINT ENERGY, INC. (Registrant)
By: /s/ DAVID M. MCCLANAHAN ------------------------------------ David M. McClanahan, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 15, 2006.
CENTERPOINT ENERGY, INC.
EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2005
INDEX OF EXHIBITS
Exhibits included with this report are designated by a cross (+); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated by an asterisk (*) are management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K. CenterPoint Energy has not filed the exhibits and schedules to Exhibit 2. CenterPoint Energy hereby agrees to furnish supplementally a copy of any schedule omitted from Exhibit 2 to the SEC upon request.
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of
securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request.