Item 1. Business
OUR BUSINESS
Overview
We own and operate natural gas distribution systems in six states. Subsidiaries of ours own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of ours offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. References to “we,” “us,” and “our” mean CenterPoint Energy Resources Corp. (CERC Corp., together with our subsidiaries, CERC). We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company.
Our reportable business segments are Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. From time to time, we consider the acquisition or the disposition of assets or businesses.
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 parent company’s 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). Our parent company’s website address is www.centerpointenergy.com. Except to the extent explicitly stated herein, documents and information on our parent company’s website are not incorporated by reference herein.
Natural Gas Distribution
Our natural gas distribution business (Gas Operations) engages in regulated intrastate natural gas sales to, and natural gas transportation for, approximately 3.2 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest metropolitan areas served in each state by Gas Operations are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. In 2009, approximately 43% of Gas Operations’ total throughput was to residential customers and approximately 57% was to commercial and industrial customers.
Gas Operations also provides unregulated services consisting of heating, ventilating and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC, hearth and water heating equipment in Minnesota.
The demand for intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers is seasonal. In 2009, approximately 70% of the total throughput of Gas Operations’ business occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during those periods.
Gas Operations suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana as a result of Hurricane Ike, which struck the upper Texas coast in September 2008. As of December 31, 2009, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of natural gas distribution rate proceedings.
Supply and Transportation. In 2009, Gas Operations purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Major suppliers in 2009 included BP Canada Energy Marketing Corp. (20.5% of supply volumes), Coral Energy Resources (8.3%), Tenaska Marketing Ventures (8.2%), Kinder Morgan (8.0%), ConocoPhillips Company (7.4%), and Cargill, Inc. (5.7%). Numerous other suppliers provided the remaining 41.9% of Gas Operations’ natural gas supply requirements. Gas Operations transports its natural gas supplies through various intrastate and interstate pipelines, including those owned by our
other subsidiaries, under contracts with remaining terms, including extensions, varying from one to fifteen years. Gas Operations anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.
We actively engage in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of our state regulatory authorities. These price stabilization activities include use of storage gas, contractually establishing fixed prices with our physical gas suppliers and utilizing financial derivative instruments to achieve a variety of pricing structures (e.g., fixed price, costless collars and caps). Our gas supply plans generally call for 25-50% of winter supplies to be hedged in some fashion.
Generally, the regulations of the states in which Gas Operations operates allow it to pass through changes in the cost of natural gas, including gains and losses on financial derivatives associated with the index-priced physical supply, 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.
Gas Operations uses various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather and may also supplement contracted supplies and storage from time to time with stored liquefied natural gas and propane-air plant production.
Gas Operations owns and operates an underground natural gas storage facility with a capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.0 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 production rate of 200 Dekatherms (DTH) per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a liquefied natural gas plant facility with a 12 million-gallon liquefied natural gas storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72 DTH per day.
On an ongoing basis, Gas Operations enters into contracts to provide sufficient supplies and pipeline capacity to meet its customer requirements. However, it is possible for limited service disruptions 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.
Gas Operations has entered into various asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization. Gas Operations has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the asset management agreement proceeds, although the percentage of payments to be retained by Gas Operations varies based on the jurisdiction, with the majority of the payments to benefit customers. The agreements have varying terms, the longest of which expires in 2016.
Assets
As of December 31, 2009, Gas Operations owned approximately 70,700 linear miles of natural 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 Gas Operations, it owns 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 Gas Operations 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
Gas Operations 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 Gas Operations’ facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.
Competitive Natural Gas Sales and Services
We offer variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities through CenterPoint Energy Services, Inc. (CES) and its subsidiary, CenterPoint Energy Intrastate Pipelines, LLC (CEIP).
In 2009, CES marketed approximately 504 Bcf of natural gas, related energy services and transportation to approximately 11,100 customers (including approximately 3 Bcf to affiliates). CES customers vary in size from small commercial customers to large utility companies in the central and eastern regions of the United States. The business has three operational divisions: wholesale, retail and intrastate pipelines, which are further described below.
Wholesale Division. 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 interstate and intrastate pipeline companies, and include gas utilities, large industrial customers and electric generation customers. This division includes the supply function for the procurement of natural gas and the management and optimization of transportation and storage assets for CES.
Retail Division. CES offers a variety of natural gas management services to smaller commercial and industrial customers, municipalities, educational institutions and hospitals, whose facilities are typically located downstream of natural gas distribution utility city gate stations. These services include 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 18 states.
Intrastate Pipeline Division. CEIP provides transportation services to shippers and end-users and contracts out approximately 2.3 Bcf of storage at its Pierce Junction facility in Texas.
CES currently transports natural gas on over 41 interstate and intrastate pipelines within states located throughout the central and eastern United States. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage 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, storage 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 imbalances on a real-time basis to ensure that CES’ exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate Value at Risk (VaR). In 2009, CES’ VaR averaged $0.6 million with a high of $1.6 million.
Our risk control policy, governed by our Risk Oversight Committee, defines authorized and prohibited trading instruments and 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, $4 million maximum, 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.
Assets
CEIP owns and operates approximately 230 miles of intrastate pipeline in Louisiana and Texas and holds storage facilities of approximately 2.3 Bcf in Texas under long-term leases. In addition, CES leases transportation capacity of approximately 0.8 Bcf per day on various interstate and intrastate pipelines and approximately 12.5 Bcf of storage to service its customer base.
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.
Interstate Pipelines
Our pipelines business operates interstate natural gas pipelines with gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. Our interstate pipeline operations are primarily conducted by two wholly owned subsidiaries that provide gas transportation and storage services primarily to industrial customers and local distribution companies:
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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
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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.
The rates charged by CEGT and MRT for interstate transportation and storage services are regulated by the Federal Energy Regulatory Commission (FERC). Our interstate pipelines business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.
In 2009, approximately 16% of CEGT and MRT’s total operating revenue was attributable to services provided to Gas Operations, an affiliate, 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 Gas Operations and Laclede are provided under several long-term firm storage and transportation agreements. The primary term of MRT’s firm transportation and storage contracts with Laclede will expire in 2013. The primary term of CEGT’s agreements for firm transportation, “no notice” transportation service and storage services in certain of Gas Operations’ service areas (Arkansas, Louisiana, Oklahoma and Texas) will expire in 2012.
Carthage to Perryville. In February 2010, CEGT completed the expansion of the capacity of its Carthage to Perryville pipeline to approximately 1.9 Bcf per day. The expansion includes new compressor units at two of CEGT’s existing stations.
Southeast Supply Header, LLC. CenterPoint Southeastern Pipelines Holding, LLC, our wholly-owned subsidiary, owns a 50% interest in Southeast Supply Header, LLC (SESH). SESH owns a 1.0 Bcf per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama. The pipeline was placed into service in September 2008. The rates charged by SESH for interstate transportation services are regulated by the FERC. A wholly-owned, indirect subsidiary of Spectra Energy Corp. owns the remaining 50% interest in SESH.
Assets
Our interstate pipelines business currently owns and operates approximately 8,000 miles of natural gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. Our interstate pipeline business also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.2 Bcf and a combined working gas capacity of approximately 59 Bcf. Our interstate pipeline business also owns a 10% interest in the Bistineau storage facility located in Bienville Parish, Louisiana, with the remaining interest owned and operated by Gulf South Pipeline Company, LP. Our interstate pipeline business' 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.
Competition
Our interstate pipelines business competes with other interstate and intrastate pipelines 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 interstate pipelines business competes indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. 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.
Field Services
Our field services business operates gas gathering, treating and processing facilities and also provides operating and technical services and remote data monitoring and communication services.
Our 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 Mid-continent region of the United States that interconnect with CEGT’s and MRT’s pipelines, as well as other interstate and intrastate pipelines. CEFS gathers approximately 1.4 Bcf per day of natural gas and, either directly or through its 50% interest in a joint venture, processes in excess of 250 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.
Our field services business operations may be affected by changes in the demand for natural gas and natural gas liquids (NGLs), the available supply and relative price of natural gas and NGLs in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.
Long-Term Gas Gathering and Treating Agreements. In September 2009, CEFS entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and EnCana’s natural gas production from the dedicated areas.
In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 MMcf per day of natural gas. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes. The construction necessary to reach the contractual capacity of 700 MMcf per day includes more than 200 miles of gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.
CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction are being provided from
anticipated cash flows from operations, lines of credit, proceeds from the sale of debt securities or capital contributions. As of December 31, 2009, approximately $176 million has been spent on this project, including the purchase of existing facilities.
Waskom Gas Processing Company. CenterPoint Energy Gas Processing Company, our wholly-owned, indirect subsidiary (CEGP), owns a 50% general partnership interest in Waskom Gas Processing Company (Waskom). Waskom owns a gas processing plant located in East Texas. The plant is capable of processing approximately 285 MMcf per day of natural gas.
Assets
Our field services business owns and operates approximately 3,700 miles of gathering lines and processing plants that collect, treat and process natural gas from approximately 140 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
Competition
Our field services business competes with other companies in the natural gas gathering, treating and processing business. The principal elements of competition are rates, terms of service and reliability of services. Our field services business competes indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. 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 gathering, treating, and processing services. In addition, competition among forms of energy is affected by commodity pricing levels and influences the level of drilling activity and demand for our gathering operations.
Other Operations
Our Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.
Financial Information About Segments
For financial information about our segments, see Note 12 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.
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 interstate 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 Policy Act of 2005 (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 significant civil and criminal penalties for statutory violations and violations of the FERC’s rules or orders and also expanded criminal penalties for such violations. Our competitive natural gas sales and services subsidiary markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.
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.
Under the Public Utility Holding Company Act of 2005 (PUHCA 2005), the FERC has 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. In December 2005, the FERC issued rules implementing PUHCA 2005. Pursuant to those rules, in June 2006, CenterPoint Energy filed with the FERC the required notification of its status as a public utility holding company. In October 2006 and December 2009, the FERC adopted additional rules regarding maintenance of books and records by utility holding companies and additional reporting and accounting requirements for centralized service companies that provide non-power goods and services to public utilities, natural gas companies or both, in the same holding company system.
State and Local Regulation
In almost all communities in which Gas Operations 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, although franchises in Arkansas are perpetual. Gas Operations expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.
Substantially all of Gas Operations is subject to cost-of-service regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and those municipalities served by Gas Operations that have retained original jurisdiction.
Texas. In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, Gas Operations implemented rates increasing annual revenues by approximately $3.5 million. The implemented rates were contested by nine cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. The court concluded that the Railroad Commission did not have statutory authority to impose on the complaining cities the cost of service adjustment mechanism which the Railroad Commission had approved in its order. Certain parties filed a motion to modify the district court’s judgment and a final decision is not expected until April 2010. We do not expect the outcome of this matter to have a material adverse impact on our financial condition, results of operations or cash flows.
In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $20.4 million, excluding carrying costs on gas inventory of approximately $2 million. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates of $1.2 million. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years.
Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court. In July 2009, the Minnesota Supreme Court reversed the decision of the Minnesota
Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no negative impact on our financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed.
In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. In January 2010, the MPUC issued its decision authorizing a revenue increase of $41 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The difference between the rates approved by the MPUC and amounts collected under the interim rates, $10 million as of December 31, 2009, is recorded in other current liabilities and will be refunded to customers. The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In February 2010, we filed a request for rehearing of the order by the MPUC. No other party to the case filed such a request. We do not expect a final order to be issued in this proceeding until spring 2010.
Mississippi. In July 2009, Gas Operations filed a request to increase its rates for utility distribution service with the Mississippi Public Service Commission (MPSC). In November 2009, as part of a settlement agreement in which the MPSC approved Gas Operations’ retention of the compensation paid under the terms of an asset management agreement, Gas Operations withdrew its rate request.
Department of Transportation
In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 Act), which reauthorized the programs adopted under the Pipeline Safety Improvement Act of 2002 (2002 Act). These programs included several requirements related to ensuring pipeline safety, and a requirement to assess the integrity of pipeline transmission facilities in areas of high population concentration. Under the legislation, remediation activities are to be performed over a 10-year period. Our pipeline subsidiaries are on schedule to comply with the timeframe mandated for completion of integrity assessment and remediation.
Pursuant to the 2002 Act, and then the 2006 Act, the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the U.S. Department of Transportation (DOT) has adopted a number of rules concerning, among other things, distinguishing between gathering lines and transmission facilities, requiring certain design and construction features in new and replaced lines to reduce corrosion and requiring pipeline operators to amend existing written operations and maintenance procedures and operator qualification programs.
We anticipate that compliance with these regulations and performance of the remediation activities by our interstate and intrastate pipelines, and natural gas distribution companies will require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. Based on our interpretation of the rules written to date and preliminary technical reviews, we believe compliance will require annual expenditures (capital and operating costs combined) of approximately $16 million to $18 million during the next three years.
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 and distribution systems, gas gathering and processing 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:
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restricting the way we can handle or dispose of wastes;
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limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;
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requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and
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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:
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construct or acquire new equipment;
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acquire permits for facility operations;
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modify or replace existing and proposed equipment; and
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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, results of operations or cash flows. In addition, we believe that our current environmental remediation activities 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.
Global Climate Change
In recent years, there has been increasing public debate regarding the potential impact on global climate change by various “greenhouse gases” such as carbon dioxide, a byproduct of burning fossil fuels, and methane, the principal component of the natural gas that we transport and deliver to customers. Legislation to regulate emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries such as the utility industry to meet stringent new standards that would require substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. Some proposals would provide for credits to those who reduce emissions below certain levels and would allow those credits to be traded and/or sold to others. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the U.S. Environmental Protection Agency (EPA) has undertaken new efforts to collect information regarding greenhouse gas emissions and their effects. Recently, the EPA declared that certain greenhouse gases represent an endangerment to human health and proposed to expand its regulations relating to those emissions.
It is too early to determine whether, or in what form, further regulatory action regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory action might have on us and our subsidiaries. However, as a distributor and transporter of natural gas and consumer of natural gas in our pipeline and gathering businesses, our revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of our operations or would have the effect of reducing the consumption of natural gas. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emission characteristics, would be expected to beneficially affect us. At this point in time, however, it would be speculative to try to quantify the magnitude of the impacts from possible new regulatory actions related to greenhouse gas emissions, either positive or negative, on our businesses.
To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. Another possible climate change that has been widely discussed in recent years is the possibility of more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.
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. In recent years the EPA has adopted amendments to its regulations regarding maximum achievable control technology for stationary internal combustion engines (sometimes referred to as the RICE MACT rule) and continues to consider additional amendments. Compressors used by our Pipelines and Field Services segments are affected by these rules. While the final structure and effective dates of these revised rules are still uncertain, we currently believe the rules, if adopted in their current form and on the anticipated schedule, could require expenditures over the next three years of less than $100 million in order to ensure our compliance with the revised rules. We believe, however, that our operations will not be materially adversely affected by such requirements.
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 would be 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 the 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 EPA and, in some cases, third parties to take action 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
Manufactured Gas Plant Sites. We and our predecessors operated manufactured gas plants (MGPs) in the past. In Minnesota, we have completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory. We believe that we have no liability with respect to two of these sites.
At December 31, 2009, we had accrued $14 million for remediation of these Minnesota sites and 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 (PRPs), if any, and the remediation methods used. We have utilized an environmental expense tracker mechanism in our rates in Minnesota to recover estimated costs in excess of insurance recovery. As of December 31, 2009, we had collected $13 million from insurance companies and rate payers to be used for future environmental remediation. In January 2010, as part of our Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechanism and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers. As of December 31, 2009, the balance in the environmental expense tracker account was $8.7 million. The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. We were not required to refund to customers the amount collected from insurance companies, $4.6 million at December 31, 2009, to be used to mitigate future environmental costs. The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs we incur in the future will be rate-recoverable under normal regulatory principles and procedures. This provision had no effect on earnings.
In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by us or may have been owned by one of our former affiliates. We have been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, 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 ours or our divisions. We have also been identified as a PRP by the State of Maine for a site that is the subject of
the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing would be required to determine if other potentially responsible parties, including us, would have to contribute to that remediation. In September 2009, the federal district court granted our motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. We believe we are not liable as a former owner or operator of the site under CERCLA and applicable state statutes, and are vigorously contesting the suit and our designation as a PRP. We do not expect the ultimate outcome to have a material adverse impact on our financial condition, results of operations or cash flows.
Mercury Contamination. Our 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. 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 is not 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.
Asbestos. Some facilities formerly owned by our predecessors have contained asbestos insulation and other asbestos-containing materials. We or our predecessor companies have been named, along with numerous others, as a defendant in lawsuits filed by certain individuals who claim injury due to exposure to asbestos during work at such formerly owned facilities. We anticipate that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that are not considered 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.
Groundwater Contamination Litigation. Predecessor entities of ours, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of ours held an interest in two oil and gas leases on a portion of the property at issue, neither we nor any other entities of ours drilled or conducted other oil and gas operations on those leases. In January 2009, we and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. We do not expect the outcome of this litigation to have a material adverse impact on 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. In addition, we have 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, we 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.
EMPLOYEES
As of December 31, 2009, we had 4,678 full-time employees. The following table sets forth the number of our employees by business segment:
As of December 31, 2009, approximately 30% of our employees are subject to collective bargaining agreements.
Item 1A.
Item 1A. Risk Factors
The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with our business.
Risk Factors Affecting Our Businesses
Rate regulation of our business may delay or deny our ability to earn a reasonable return and fully recover our costs.
Our rates for Gas Operations are regulated by certain municipalities and state commissions, and for our interstate pipelines by the FERC, based on an analysis of our invested capital and our expenses in a test year. Thus, the rates that we are allowed to charge may not match our 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 our costs and enable us to earn a reasonable return on our invested capital.
Our businesses must compete with alternate energy sources, which could result in our marketing less natural gas, and our interstate 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 and reduced volumes, either of which could have an adverse impact on our results of operations, financial condition and cash flows.
We compete 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 us 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 our 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 us as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows.
Our two interstate pipelines and our 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. We also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. The actions of our competitors could lead to lower prices, which may have an adverse impact on our results of operations, financial condition and cash flows. Additionally, any reduction in the volume of natural gas transported or stored may have an adverse impact on our results of operations, financial condition and cash flows.
Our natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas prices, which could affect the ability of our suppliers and customers to meet their obligations or otherwise adversely affect our liquidity and results of operations.
We are subject to risk associated with changes in the price of natural gas. Increases in natural gas prices might affect our ability to collect balances due from our customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into our tariff rates. In addition, a sustained period of high natural gas prices could (i) apply downward demand pressure on natural gas consumption in the areas in which we operate thereby resulting in decreased sales volumes and revenues and (ii) increase the risk that our suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase our working capital requirements by increasing the investment that must be made in order to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that we must provide under our hedging arrangements.
A decline in our credit rating could result in our having to provide collateral in order to purchase natural gas or under our shipping or hedging arrangements.
If our credit rating were to decline, we might be required to post cash collateral in order to purchase natural gas or under our shipping or hedging arrangements. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations, financial condition and cash flows could be adversely affected.
The revenues and results of operations of our interstate pipelines and field services businesses are subject to fluctuations in the supply and price of natural gas and natural gas liquids.
Our interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by our gathering and pipeline transportation systems and our natural gas treating and processing activities. A sustained decline could also lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production costs relative to other available production, producers’ access to needed capital and the cost of that capital, the ability of producers to obtain necessary drilling and other governmental permits, access to drilling rigs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves or to shut in production from existing reserves. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on our results of operations, financial condition and cash flows.
Our revenues from these businesses are also affected by the prices of natural gas and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.
Our revenues and results of operations are seasonal.
A substantial portion of our revenues is derived from natural gas sales and transportation. Thus, our 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.
The actual cost of pipelines under construction, future pipeline, gathering and treating systems and related compression facilities may be significantly higher than we had planned.
Our subsidiaries have been recently involved in significant pipeline construction projects and, depending on available opportunities, may, from time to time, be involved in additional significant pipeline construction and gathering and treating system projects in the future. The construction of new pipelines, gathering and treating systems and related compression facilities may require the expenditure of significant amounts of capital, which may exceed our estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows.
The states in which we provide regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to or broader than those under the Public Utility Holding Company Act of 1935 regarding organization, financing and affiliate transactions that could have significant adverse impacts on our ability to operate.
The Public Utility Holding Company Act of 1935, to which CenterPoint Energy and its subsidiaries were subject prior to its repeal in the Energy Act, provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, some states in which we do business have sought to expand their own regulatory frameworks to give their regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility business that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.
These regulatory frameworks could have adverse effects on our ability to conduct our utility operations, to finance our business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for us to comply with competing regulatory requirements.
The revenues and results of operations of our interstate pipelines and field services businesses could be adversely impacted by new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and the protection of water supplies in the areas in and around shale fields.
Our interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. To extract natural gas from the shale fields in this area, producers have historically used a process called hydraulic fracturing. Recently, new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and the protection of water supplies in the areas in and around the shale fields have been considered by the federal government. If enacted, such regulations could increase operating costs of the producers in these regions or cause delays, interruptions or termination of drilling operations, all of which could result in a decrease in demand for the services provided by our interstate pipelines and field services businesses in the shale fields, which could have an adverse effect on our results of operations, financial condition and cash flows.
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, 2009, we had $3.3 billion of outstanding indebtedness on a consolidated basis. As of December 31, 2009, approximately $649 million principal amount of this debt is required to be paid through 2012, including $45 million of debentures redeemed in 2010, but excluding $432 million borrowed from the money pool. Our future financing activities may be significantly affected by, among other things:
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general economic and capital market conditions;
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credit availability from financial institutions and other lenders;
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investor confidence in us and the markets in which we operate;
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maintenance of acceptable credit ratings by us and CenterPoint Energy;
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market expectations regarding our future earnings and cash flows;
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market perceptions of our and CenterPoint Energy's ability to access capital markets on reasonable terms;
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our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from CenterPoint Energy; and
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provisions of relevant tax and securities laws.
Our current credit ratings are discussed in “Management’s Narrative Analysis of Results of Operations- Liquidity - 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.
The creditworthiness and liquidity of our parent company and our affiliates could affect our creditworthiness and liquidity.
Our credit ratings and liquidity may be impacted by the creditworthiness and liquidity of our parent company and our affiliates. As of December 31, 2009, CenterPoint Energy and its subsidiaries other than us have approximately $562 million principal amount of debt required to be paid through 2012. This amount excludes amounts related to capital leases, principal repayments of approximately $831 million on transition and system restoration bonds and indexed debt securities obligations, but includes $290 million of pollution control bonds issued on CenterPoint Energy’s behalf which CenterPoint Energy purchased in January 2010 (and which may be remarketed). If CenterPoint Energy were to experience a deterioration in its creditworthiness or liquidity, our creditworthiness and liquidity could be adversely affected. In addition, from time to time we and other affiliates invest or borrow funds in the money pool maintained by CenterPoint Energy. If CenterPoint Energy or the affiliates that borrow any funds that we might invest from time to time in the money pool were to experience a deterioration in their creditworthiness or liquidity, our creditworthiness, liquidity and the repayment of notes receivable from CenterPoint Energy and our affiliates under the money pool could be adversely impacted.
We are an indirect wholly owned subsidiary of CenterPoint Energy. CenterPoint Energy can exercise substantial control over our dividend policy and business and operations and could do so in a manner that is adverse to our interests.
We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following:
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our payment of dividends;
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decisions on our financings and our capital raising activities;
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mergers or other business combinations; and
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our acquisition or disposition of assets.
Other than the financial covenants contained in our credit facility and receivables facility (described under “Liquidity” in Item 7 of this report), which could have the practical effect of limiting the payment of dividends under certain circumstances, there are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. However, under our credit facility and our receivables facility, our ability to pay dividends is restricted by a covenant that debt as a percentage of total capitalization may not exceed 65%.
The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could 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, weather 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.
We derive a substantial portion of our operating income from subsidiaries through which we hold a substantial portion of our assets.
We derive a substantial portion of our operating income from, and hold a substantial portion of our assets through, our subsidiaries. As a result, we 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 our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries 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.
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, and gas gathering and
processing 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:
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restricting the way we can handle or dispose of wastes;
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limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
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requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and
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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:
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construct or acquire new equipment;
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acquire permits for facility operations;
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modify or replace existing and proposed equipment; and
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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.
We and CenterPoint Energy could incur liabilities associated with businesses and assets that we have transferred to others.
Under some circumstances, we and CenterPoint Energy could incur liabilities associated with assets and businesses we and CenterPoint Energy no longer own.
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, CenterPoint Energy and its subsidiaries, including us, with respect to liabilities associated with the transferred assets and businesses. These 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 were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not
released from the liability in connection with the transfer, we and CenterPoint Energy could be responsible for satisfying the liability.
Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, we had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure us against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to us cash or letters of credit as security against our obligations under our remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose us to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $96 million as of December 31, 2009. As of December 31, 2009, RRI was not required to provide security to us. If RRI should fail to perform the contractual obligations, we could have to honor our guarantee and, in such event, collateral provided as security may be insufficient to satisfy our obligations.
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 CenterPoint Energy as its former owner.
On May 1, 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. The sale does not alter RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including us, for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts discussed above.
Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of sales of natural gas in California and other markets. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include liability of Reliant Energy as a controlling shareholder of RRI. We and CenterPoint Energy could incur liability if claims in one or more of these lawsuits were successfully asserted against us and CenterPoint Energy and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.
The unsettled conditions in the global financial system may have impacts on our business, liquidity and financial condition that we currently cannot predict.
The recent credit crisis and unsettled conditions in the global financial system may have an impact on our business, liquidity and financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facilities, should they further occur, could adversely affect our liquidity. Capital market turmoil was also reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of CenterPoint Energy’s pension plan. These reductions increased pension expense in 2009.
In addition to the credit and financial market issues, a recurrence of national and local recessionary conditions may impact our business in a variety of ways. These include, among other things, reduced customer usage, increased customer default rates and wide swings in commodity prices.
Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our services.
Legislation to regulate emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the EPA has undertaken new efforts to collect information regarding greenhouse gas emissions and their effects. Recently, the
EPA declared that certain greenhouse gases represent an endangerment to human health and proposed to expand its regulations relating to those emissions. It is too early to determine whether, or in what form, further regulatory action regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory action might have on us and our subsidiaries. However, as a distributor and transporter of natural gas and consumer of natural gas in our pipeline and gathering businesses, our revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of our operations or would have the effect of reducing the consumption of natural gas. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.
Climate changes could result in more frequent severe weather events and warmer temperatures which could adversely affect the results of operations of our businesses.
To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. Another possible climate change that has been widely discussed in recent years is the possibility of more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2.
Item 2. Properties
Character of Ownership
We own our principal properties in fee. Most of our gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.
Natural Gas Distribution
For information regarding the properties of our Natural Gas Distribution business segment, please read “Business - Our Business - Natural Gas Distribution - Assets” in Item 1 of this report, which information is incorporated herein by reference.
Competitive Natural Gas Sales and Services
For information regarding the properties of our Competitive Natural Gas Sales and Services business segment, please read “Business - Our Business - Competitive Natural Gas Sales and Services - Assets” in Item 1 of this report, which information is incorporated herein by reference.
Interstate Pipelines
For information regarding the properties of our Interstate Pipelines business segment, please read “Business - Our Business - Interstate Pipelines - Assets” in Item 1 of this report, which information is incorporated herein by reference.
Field Services
For information regarding the properties of our Field Services business segment, please read “Business - Our Business - Field Services - Assets” 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 “Business - Regulation” and “Business - Environmental Matters” in Item 1 of this report and Notes 3 and 9(e) to our consolidated financial statements, which information is incorporated herein by reference.
Item 4.
Item 4. Reserved
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
All of the 1,000 outstanding shares of CERC Corp.’s common stock are held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy.
In each of 2007, 2008 and 2009, we paid dividends on our common stock of $100 million to Utility Holding, LLC.
Our revolving credit facility and our receivables facility limit our debt as a percentage of total capitalization to 65%. These covenants could restrict our ability to distribute dividends.
Item 6.
Item 6. Selected Financial Data
The information called for by Item 6 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 7.
Item 7. Management’s Narrative Analysis of Results of Operations
The following narrative analysis should be read in combination with our consolidated financial statements and notes contained in Item 8 of this report.
Background
We own and operate natural gas distribution systems in six states. Our subsidiaries own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of ours offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy).
Business Segments
Because we are an indirect wholly owned subsidiary of CenterPoint Energy, our determination of reportable segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. In this section, we discuss our results on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and critical accounting policies. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to which we are subject. Our natural gas distribution services and interstate pipelines business segments are subject to rate regulation. A summary of our reportable business segments as of December 31, 2009 is set forth below:
Natural Gas Distribution
We own and operate our regulated natural gas distribution business (Gas Operations), which engages in intrastate natural gas sales to, and natural gas transportation for, approximately 3.2 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.
Competitive Natural Gas Sales and Services
Our operations also include non-rate regulated retail and wholesale natural gas sales to, and transportation services for, commercial and industrial customers in 18 states in the central and eastern regions of the United States.
Interstate Pipelines
Our interstate pipelines business owns and operates approximately 8,000 miles of natural gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. It also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.2 billion cubic feet (Bcf) and a combined working gas capacity of approximately 59 Bcf. It also owns a 10% interest in an 80 Bcf Bistineau storage facility located in Bienville Parish, Louisiana, with the remaining interest owned and operated by Gulf South Pipeline Company, LP. Most storage operations are in north Louisiana and Oklahoma.
Field Services
Our field services business owns and operates approximately 3,700 miles of gathering pipelines and processing plants that collect, treat and process natural gas from approximately 140 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
Other Operations
Our other operations business segment includes unallocated corporate costs and inter-segment eliminations.
EXECUTIVE SUMMARY
Factors Influencing Our Business
We are an energy delivery company. The majority of our revenues are generated from the gathering, processing, transportation and sale of natural gas by our subsidiaries. To assess our financial performance, our management primarily monitors operating income and cash flows from our four business segments. Within these broader financial measures, we monitor margins, operation and maintenance expense, interest expense, capital spending and working capital requirements. In addition to these financial measures we also monitor a number of variables that management considers important to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.
To the extent the adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. Reduced demand and lower energy prices could lead to financial pressure on some of our customers who operate within the energy industry. Also, adverse economic conditions, coupled with concerns for protecting the environment, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services.
Performance of our Natural Gas Distribution business segment is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results to weather on an adjusted basis. During 2009, we continued to see evidence that customers are seeking to conserve in their energy consumption, particularly during periods of high energy prices or in times of economic distress. That conservation can have adverse effects on our results. In many of our service areas, particularly in the Houston area and in Minnesota, we have benefited from customer growth that tends to mitigate the effects of reduced consumption. We anticipate that this growth will continue despite recent economic downturns, though that growth may be lower than we have recently experienced in these areas. In addition, the
profitability of these businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our gas distribution rates. In our recent Gas Operations rate filings, we have sought rate mechanisms that help to decouple our results from the impacts of weather and conservation, but such rate mechanisms have not yet been approved in all jurisdictions. We plan to continue to pursue such decoupling mechanisms in our rate filings.
Our Field Services and Interstate Pipelines business segments are currently benefiting from their proximity to new natural gas producing regions in Texas, Arkansas, Oklahoma and Louisiana. Our Interstate Pipelines business segment benefited from new projects placed into service in 2009 on our Carthage to Perryville line. In our Field Services business segment, strong drilling activity in the new shale producing regions has helped offset declines in drilling activity in traditional producing regions due to the effects of the economic downturn and significantly lower commodity prices in 2009. In monitoring performance of the segments, we focus on throughput of the pipelines and gathering systems, and in the case of Field Services, on well-connects.
Our Competitive Natural Gas Sales and Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis. Its operations serve customers in the central and eastern regions of the United States. The segment benefits from favorable price differentials, either on a geographic basis or on a seasonal basis. While it utilizes financial derivatives to hedge its exposure to price movements, it does not engage in speculative or proprietary trading and maintains a low value at risk level or VaR to avoid significant financial exposures. Lower commodity prices and low price differentials during 2009 adversely affected results for this business segment.
The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities, issuances of debt in the capital markets and capital contributions from our parent to satisfy these capital needs. We strive to maintain investment grade ratings for our securities in order to access the capital markets on terms we consider reasonable. Our goal is to improve our credit ratings over time. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facility. Disruptions in the financial markets, such as occurred in the last half of 2008 and continued during 2009, can also affect the availability of new capital on terms we consider attractive. In those circumstances companies like us may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through our existing credit facility and prudent refinancing of existing debt. We expect to experience higher borrowing costs and greater uncertainty in executing capital markets transactions given the current uncertainties in the financial markets.
As it did with many businesses, the sharp decline in stock market values during the latter part of 2008 had a significant adverse impact on the value of CenterPoint Energy’s pension plan assets. While that impact did not require us to make additional contributions to the pension plan, it significantly increased the pension expense we recognized during 2009 and expect to recognize in 2010 for all our business segments, and we may need to make significant cash contributions to CenterPoint Energy’s pension plan subsequent to 2010.
Significant Events
Hurricane Ike
Gas Operations suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana as a result of Hurricane Ike, which struck the upper Texas coast in September 2008. As of December 31, 2009, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of natural gas distribution rate proceedings.
Long-Term Gas Gathering and Treatment Agreements
In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), our wholly-owned natural gas gathering and treating subsidiary, entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from EnCana and Shell in De Soto
and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and EnCana’s natural gas production from the dedicated areas.
In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes. The construction necessary to reach the contractual capacity of 700 MMcf per day includes more than 200 miles of gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.
CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction are being provided from anticipated cash flows from operations, lines of credit, proceeds from the sale of debt securities or capital contributions from our parent. As of December 31, 2009, $176 million had been spent on the project, including the purchase of existing facilities.
Debt Financing Transactions
In August 2009, Southeast Supply Header, LLC (SESH) closed on a private debt offering in the amount of $375 million. Also during 2009, we made a capital contribution to SESH in the amount of $137 million. Using $186 million of its proceeds from the debt offering and the capital contribution, SESH repaid the note receivable it owed to us, which note had a principal balance of $323 million at the time of the repayment. We used the proceeds to repay borrowings under CERC Corp.’s credit facility.
In October 2009, the size of CERC Corp.’s revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.
In October 2009, we amended our receivables facility to extend the termination date to October 8, 2010. Availability under our 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances.
In January 2010, we redeemed $45 million of our outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.
Asset Management Agreements
In 2009, Gas Operations entered into various asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization. Gas Operations has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the asset management agreement proceeds, although the percentage of payments to be retained by Gas Operations varies based on the jurisdiction, with the majority of the payments to benefit customers. The agreements have varying terms, the longest of which expires in 2016.
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:
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state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, health care reform, and changes in or application of laws or regulations applicable to the various aspects of our business;
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state and federal legislative and regulatory actions, developments or regulations relating to the environment, including those related to global climate change;
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timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
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cost overruns on major capital projects that cannot be recouped in prices;
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industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;
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the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids;
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the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business;
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the timing and extent of changes in natural gas basis differentials;
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weather variations and other natural phenomena;
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changes in interest rates or rates of inflation;
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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;
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actions by rating agencies;
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effectiveness of our risk management activities;
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inability of various counterparties to meet their obligations to us;
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non-payment for our services due to financial distress of our customers;
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the ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;
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the outcome of litigation brought by or against us;
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our ability to control costs;
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the investment performance of CenterPoint Energy’s employee benefit plans;
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our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;
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acquisition and merger activities involving our parent or our competitors; and
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other factors we discuss under “Risk Factors” in Item 1A of this report and in other reports we file from time to time with the Securities and Exchange Commission.
CONSOLIDATED RESULTS OF OPERATIONS
Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. Our results of operations are also affected by, among other things, the actions of various federal and state governmental authorities having jurisdiction over rates we charge, competition in our various business operations, debt service costs and income tax expense.
The following table sets forth selected financial data (in millions) for the years ended December 31, 2007, 2008 and 2009, followed by a discussion of our consolidated results of operations based on operating income. We have provided a reconciliation of consolidated operating income to net income below.
2009 Compared to 2008. We reported net income of $230 million for 2009 compared to $343 million for 2008. The decrease in net income of $113 million was primarily due to a $148 million decrease in operating income from our business segments as discussed below, a $36 million decrease in equity in earnings of unconsolidated affiliates and a $7 million increase in interest expense, partially offset by an $82 million decrease in income tax expense due to lower earnings.
Income Tax Expense. Our 2009 effective tax rate of 38.8% differed from the 2008 effective tax rate of 40.0% primarily due to a reduction in state income taxes related to adjustments in prior years’ state estimates in 2009. For more information, see Note 8 to our consolidated financial statements.
2008 Compared to 2007. We reported net income of $343 million for 2008 compared to $287 million for 2007. The increase in net income of $56 million was primarily due to a $91 million increase in operating income from our business segments as discussed below and a $35 million increase in equity in earnings of unconsolidated affiliates related primarily to SESH, partially offset by a $55 million increase in income tax expense due to higher earnings and a $19 million increase in interest expense.
Income Tax Expense. Our 2008 effective tax rate of 40.0% differed from the 2007 effective tax rate of 37.6% primarily due to the settlement in 2007 of our prior-year state income tax return examinations.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income (in millions) for each of our business segments for 2007, 2008 and 2009. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.
Operating Income (Loss) by Business Segment
Natural Gas Distribution
The following table provides summary data of our Natural Gas Distribution business segment for 2007, 2008 and 2009 (in millions, except throughput and customer data):
2009 Compared to 2008. Our Natural Gas Distribution business segment reported operating income of $204 million for 2009 compared to $215 million for 2008. Operating income declined ($11 million) primarily as a result of increased pension expense ($37 million) and higher labor and other benefit costs ($16 million), partially offset by increased revenues from rate increases ($36 million) and lower bad debt expense ($15 million). Revenues related to both energy-efficiency costs and gross receipts taxes are substantially offset by the related expenses. Depreciation and amortization expense increased $4 million primarily due to higher plant balances. Taxes other than income taxes, net of the decrease in gross receipts taxes ($16 million), increased $4 million also primarily due to higher plant balances.
2008 Compared to 2007. Our Natural Gas Distribution business segment reported operating income of $215 million for 2008 compared to $218 million for 2007. Operating income declined in 2008 due to a combination of non-weather-related usage ($13 million), due in part to higher gas prices, higher customer-related and support services costs ($9 million), higher bad debts and collection costs ($4 million), increased costs of materials and supplies ($4 million), and an increase in depreciation and amortization and taxes other than income taxes ($3 million) resulting from increased investment in property, plant and equipment. The adverse impacts on operating income were partially offset by the net impact of rate increases ($11 million), lower labor and benefits costs ($14 million), and customer growth from the addition of approximately 25,000 customers in 2008 ($6 million).
Competitive Natural Gas Sales and Services
The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for 2007, 2008 and 2009 (in millions, except throughput and customer data):
2009 Compared to 2008. Our Competitive Natural Gas Sales and Services business segment reported operating income of $21 million for 2009 compared to $62 million for 2008. The decrease in operating income of $41 million was due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for 2009 of $23 million versus a favorable impact of $13 million for the same period in 2008. A further $28 million decrease in margin is attributable to reduced basis spreads on pipeline transport opportunities and an absence of summer storage spreads. These decreases in operating income were partially offset by a $6 million write-down of natural gas inventory to the lower of cost or market for 2009 compared to a $30 million write-down in the same period last year. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales.
2008 Compared to 2007. Our Competitive Natural Gas Sales and Services business segment reported operating income of $62 million for the year ended December 31, 2008 compared to $75 million for the year ended December 31, 2007. The decrease in operating income in 2008 of $13 million primarily resulted from lower gains on sales of gas from previously written down inventory ($24 million) and higher operation and maintenance costs ($6 million), which were partially offset by improved margin as basis and summer/winter spreads increased ($12 million). In addition, 2008 included a gain from mark-to-market accounting ($13 million) and a write-down of natural gas inventory to the lower of average cost or market ($30 million), compared to a charge to income from mark-to-market accounting for non-trading derivatives ($10 million) and a write-down of natural gas inventory to the lower of average cost or market ($11 million) for 2007.
Interstate Pipelines
The following table provides summary data of our Interstate Pipelines business segment for 2007, 2008 and 2009 (in millions, except throughput data):
2009 Compared to 2008. Our Interstate Pipeline business segment reported operating income of $256 million for 2009 compared to $293 million for 2008. Margins (revenues less natural gas costs) increased $6 million primarily due to the Carthage to Perryville pipeline ($28 million) and new contracts with power generation customers ($20 million), partially offset by reduced other transportation margins and ancillary services ($42 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008. Operations and maintenance expenses increased due to a gain on the sale of two storage development projects in 2008 ($18 million) and costs associated with incremental facilities ($12 million) and increased pension expenses ($9 million). These expenses were partially offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million). Depreciation and amortization expenses increased $2 million and taxes other than income taxes increased by $8 million, $2 million of which was due to 2008 tax refunds.
2008 Compared to 2007. Our Interstate Pipeline business segment reported operating income of $293 million for 2008 compared to $237 million for 2007. The increase in operating income in 2008 was primarily driven by increased margins (revenues less natural gas costs) on the Carthage to Perryville pipeline that went into service in May 2007 ($51 million), increased transportation and ancillary services ($27 million), and a gain on the sale of two storage development projects ($18 million). These increases were partially offset by higher operation and maintenance expenses ($19 million), a write-down associated with pipeline assets removed from service ($7 million), increased depreciation expense ($2 million), and higher taxes other than income taxes ($12 million), largely due to tax refunds in 2007.
Equity Earnings. In addition, this business segment recorded equity income of $6 million, $36 million and $7 million in the years ended December 31, 2007, 2008 and 2009, respectively, from its 50% interest in SESH, a jointly-owned pipeline. The 2007 and 2008 year-end results include $6 million and $33 million of pre-operating allowance for funds used during construction, respectively. The 2009 results include a non-cash pre-tax charge of $16 million to reflect SESH’s decision to discontinue the use of guidance for accounting for regulated operations, which was partially offset by the receipt of a one-time payment related to the construction of the pipeline and a reduction in estimated property taxes, of which our 50% share was $5 million. Excluding the effect of these adjustments, equity earnings from normal operations was $3 million and $18 million in 2008 and 2009, respectively. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption.
Field Services
The following table provides summary data of our Field Services business segment for 2007, 2008 and 2009 (in millions, except throughput data):
2009 Compared to 2008. Our Field Services business segment reported operating income of $94 million for 2009 compared to $147 million for 2008. Operating margin from new projects and core gathering services increased approximately $24 million for 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays. This increase was offset primarily by the effect of a decline in commodity prices of approximately $54 million from the significantly higher prices experienced in 2008. Operating income for 2009 also included higher costs associated with incremental facilities ($4 million) and increased pension cost ($2 million). Operating income for 2008 benefited from a one-time gain ($11 million) related to a settlement and contract buyout of one of our customers and a gain on sale of assets ($6 million).
2008 Compared to 2007. Our Field Services business segment reported operating income of $147 million for 2008 compared to $99 million for 2007. The increase in operating income of $48 million resulted from higher margins (revenue less natural gas costs) from gas gathering, ancillary services and higher commodity prices ($34 million) and a one-time gain related to a settlement and contract buyout of one of our customers ($11 million). Operating expenses increased from 2007 to 2008 due to higher expenses associated with new assets and general cost increases, partially offset by a gain related to the sale of assets in 2008 ($6 million).
Equity Earnings. In addition, this business segment recorded equity income of $10 million, $15 million and $8 million for the years ended December 31, 2007, 2008 and 2009, respectively, from its 50% interest in a jointly-owned gas processing plant. The decrease is driven by a decrease in natural gas liquid prices. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption.
Fluctuations in Commodity Prices and Derivative Instruments
For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read “Quantitative and Qualitative Disclosures About Market Risk” in 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:
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Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, natural gas liquids and other energy commodities.
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Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.
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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 commodity price risk 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
As of December 31, 2009, we had outstanding long-term debt and bank loans from affiliates that subject us to the risk of loss associated with movements in market interest rates.
Our floating-rate obligations aggregated $1.0 billion and $432 million at December 31, 2008 and 2009, respectively. If the floating interest rates were to increase by 10% from December 31, 2009 rates, our combined interest expense would increase by less than $1 million annually.
At both December 31, 2008 and 2009, we had outstanding fixed-rate debt aggregating $2.8 billion in principal amount and having a fair value of $2.6 billion and $3.0 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 7 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $79 million if interest rates were to decline by 10% from their levels at December 31, 2009. 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.
Commodity Price Risk From Non-Trading Activities
We use derivative instruments as economic hedges to offset the commodity price 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 fair value based on a hypothetical 10% movement in energy prices. At December 31, 2009, the recorded fair value of our non-trading energy derivatives was a net liability of $134 million (before collateral). The net liability consisted of a net liability of $143 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of $9 million related to our Competitive Natural Gas Sales and Services business segment. Net assets or liabilities related to the price stabilization activities correspond directly with net over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the market prices of energy commodities from their December 31, 2009 levels would have increased the fair value of our non-trading energy derivatives net liability by $31 million. However, the consolidated income statement impact of this same 10% decrease in market prices would be an increase in income of $3 million.
The above analysis of the non-trading energy derivatives utilized for commodity price risk management 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 is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.
Item 8.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of
CenterPoint Energy Resources Corp.
Houston, Texas
We have audited the accompanying consolidated balance sheets of CenterPoint Energy Resources Corp. and subsidiaries (the “Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.) as of December 31, 2009 and 2008, and the related statements of consolidated income, comprehensive income, cash flows and stockholder’s equity for each of the three years in the period ended December 31, 2009. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy Resources Corp. and subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 11,
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:
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Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
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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
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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, 2009.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.
/s/ DAVID M. MCCLANAHAN
President and Chief Executive Officer
/s/ GARY L. WHITLOCK
Executive Vice President and Chief
Financial Officer
March 11,
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS OF CONSOLIDATED INCOME
See Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
See Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS OF CONSOLIDATED STOCKHOLDER’S EQUITY
See Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
Background
CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), owns and operates natural gas distribution systems in six states. Subsidiaries of CERC Corp. own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. CERC Corp. is a Delaware corporation.
CERC Corp. is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company.
For a description of CERC's reportable business segments, see Note 12.
(2)
Summary of Significant Accounting Policies
(a) Use of Estimates
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 CERC Corp. and its wholly owned and majority owned subsidiaries are included in CERC's consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. CERC uses the equity method of accounting for investments in entities in which CERC has an ownership interest between 20% and 50% and exercises significant influence. CERC’s investments in unconsolidated affiliates include a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and operates a 270-mile interstate natural gas pipeline and a 50% interest in Waskom Gas Processing Company, a Texas general partnership, which owns and operates a natural gas processing plant. Other investments, excluding marketable securities, are carried at cost. During 2009, CERC invested $137 million in SESH and received a capital distribution of $23 million from SESH.
(c) Revenues
CERC records revenue for natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. 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 Interstate Pipelines and Field Services business segments record revenues as transportation and processing services are provided.
(d) Long-Lived Assets and Intangibles
CERC records property, plant and equipment at historical cost. CERC expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:
Goodwill by reportable business segment as of December 31, 2008 and 2009 is as follows (in millions):
CERC performs its goodwill impairment tests 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.
CERC performed the test at July 1, 2009, its annual impairment testing date, and determined that no impairment charge for goodwill was required.
CERC 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
CERC applies the guidance for accounting for regulated operations to the Natural Gas Distribution business segment and to portions of the Interstate Pipelines business segment.
The following is a list of regulatory assets/liabilities reflected on CERC's Consolidated Balance Sheets as of December 31, 2008 and 2009:
(1)
Regulatory assets that are not earning a return were not material at December 31, 2008 and 2009.
CERC’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2008 and 2009, these removal costs of $478 million and $510 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 has been reclassified from a regulatory liability to an asset retirement liability in accordance with accounting guidance for conditional asset retirement obligations. At December 31, 2008 and 2009, CERC’s asset retirement obligations were $46 million and $60 million, respectively. The increase in asset retirement obligations in 2009 of $14 million is primarily attributable to the decrease in the credit-adjusted risk-free rate used to value the asset retirement obligations as of the end of the period.
(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.
The following table presents depreciation and amortization expense for 2007, 2008 and 2009:
(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 when the assets are included in rates for subsidiaries that apply guidance for accounting for regulated operations. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. During 2007, 2008 and 2009, CERC capitalized interest and AFUDC of $12 million, $5 million and $2 million, respectively.
(h) Income Taxes
CERC is included in the consolidated income tax returns of CenterPoint Energy. CERC calculates its income tax provision on a separate return basis under a tax sharing agreement with CenterPoint Energy. CERC uses the asset and liability method of accounting for deferred income taxes in accordance with accounting guidance for income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective
tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered more likely than not. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy. CERC recognizes interest and penalties as a component of income tax expense. For more information, see Note 8 to our consolidated financial statements.
(i) Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are net of an allowance for doubtful accounts of $33 million and $23 million at December 31, 2008 and 2009, respectively. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2007, 2008 and 2009 was $42 million, $53 million and $35 million, respectively.
On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. At December 31, 2008 and 2009, the facility size was $128 million and $150 million, respectively. As of December 31, 2008 and 2009, advances under the receivables facilities were $78 million and $-0-, 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. Natural gas inventories of CERC’s Competitive Natural Gas Sales and Services business segment are also primarily valued at the lower of average cost or market. Natural gas inventories of CERC’s Natural Gas Distribution business segment are primarily valued at weighted average cost. During 2008 and 2009, CERC recorded $30 million and $6 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.
(k) Derivative Instruments
CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CERC utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on its operating results and cash flows. Such derivatives are recognized in CERC's Consolidated Balance Sheets at their fair value unless CERC elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.
CenterPoint Energy has a Risk Oversight Committee composed of corporate and business segment officers that oversees all commodity price, weather and credit risk activities, including CERC's marketing, risk management services and hedging activities. The committee’s duties are to establish CERC's commodity risk policies, allocate board-approved commercial risk limits, approve use of new products and commodities, monitor positions and ensure compliance with CERC's risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.
CERC'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.
(l) Environmental Costs
CERC expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. CERC expenses amounts that relate to an existing condition caused by past operations that do not have
future economic benefit. CERC 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, CERC considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase.
(n) New Accounting Pronouncements
Effective January 1, 2009, CERC adopted new accounting guidance which requires enhanced disclosures of derivative instruments and hedging activities such as the fair value of derivative instruments and presentation of their gains or losses in tabular format, as well as disclosures regarding credit risks and strategies and objectives for using derivative instruments. These disclosures are included as part of CERC's Derivatives Instruments footnote (see Note 5).
Effective January 1, 2009, CERC adopted new accounting guidance on employers’ disclosures about postretirement benefit plan assets which expands the disclosures about employers’ plan assets to include more detailed disclosures about the employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. See Note 2(o) below for the required disclosures.
Effective June 30, 2009, CERC adopted new accounting guidance on interim disclosures about fair value of financial instruments which expands the fair value disclosures required for all financial instruments to interim periods. This new guidance also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. CERC's adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows.
Effective June 30, 2009, CERC adopted new accounting guidance on subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. CERC’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows.
Effective July 1, 2009, CERC adopted new accounting guidance on the Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification) and the hierarchy of generally accepted accounting principles. This new accounting guidance establishes the Codification as the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative U.S. generally accepted accounting principles for SEC registrants. CERC’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.
In June 2009, the FASB issued new accounting guidance on consolidation of variable interest entities (VIEs) that changes how a reporting entity determines a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards approach to a qualitative approach based on which variable interest holder has the power to direct the economic performance related activities of the VIE as well as the obligation to absorb losses or right to receive benefits that could potentially be significant to the VIE. This new guidance requires the primary beneficiary assessment to be performed on an ongoing basis and also requires enhanced disclosures that will provide more transparency about a company’s involvement in a VIE. This new guidance is effective for a reporting entity’s first annual reporting period that begins after November 15, 2009. CERC expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.
In January 2010, the FASB issued new accounting guidance to require additional fair value related disclosures including transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosure guidance about the level of disaggregation and about inputs and valuation techniques. This new guidance is effective for the first reporting period beginning after December 15, 2009. The adoption of this new guidance will not have a material impact on CERC’s financial position, results of operation or cash flows.
Management believes the impact of other recently issued standards, which are not yet effective, will not have a material impact on CERC's consolidated financial position, results of operations or cash flows upon adoption.
(o) Employee Benefit Plans
Pension Plans
Substantially all of CERC’s employees participate in CenterPoint Energy’s qualified non-contributory defined benefit pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 5% of eligible earnings, which increased from 4% effective January 1, 2009, 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.
CenterPoint Energy’s funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to CERC based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy’s participating subsidiaries. CERC recognized pension expense of $5 million, income of $3 million and expense of $45 million for the years ended December 31, 2007, 2008 and 2009, respectively.
In addition to the plan, CERC participates in CenterPoint Energy’s non-qualified benefit restoration plans, which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory pension plan except for 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 the non-qualified pension plan was less than $1 million, less than $1 million and $2 million for the years ended December 31, 2007, 2008 and 2009, respectively.
Savings Plan
CERC participates in CenterPoint Energy’s qualified savings plan, which includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended. 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 50%, which increased from 16% in prior years, of compensation. Effective January 1, 2009, CERC matches 100% of the first 6% of each employee’s compensation contributed. CERC previously matched 75% of the first 6% of each employee’s compensation contributed with the potential for an additional discretionary match of up to 50% of the first 6% of each employee’s compensation contributed. The matching contributions are fully vested at all times. CenterPoint Energy allocates to CERC the savings plan benefit expense related to CERC’s employees. Savings plan benefit expense was $17 million, $18 million and $15 million for each of the years ended December 31, 2007, 2008, and 2009, respectively.
Postretirement Benefits
CERC’s employees participate in CenterPoint Energy’s plans which provide 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. CERC is required to fund a portion of its obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.
The net postretirement benefit cost includes the following components:
CERC used the following assumptions to determine net postretirement benefit costs:
In determining net periodic benefits cost, CERC uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets.
Following are reconciliations of CERC’s beginning and ending balances of its postretirement benefit plan’s benefit obligation, plan assets and funded status for 2008 and 2009. The measurement dates for plan assets and obligations were December 31, 2008 and 2009.
The discount rate assumption was determined by matching the accrued cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to thirty years.
The expected rate of return assumption was developed by a weighted-average return analysis of the targeted asset allocation of the CenterPoint Energy’s plans and the expected real return for each asset class, based on the long-term capital market assumptions, adjusted for investment fees and diversification effects, in addition to expected inflation.
For measurement purposes, healthcare costs are assumed to increase 7.50% during 2010, after which this rate decreases until reaching the ultimate rate of 5.50% in 2014. Prescription drug costs are assumed to increase 8.00% in 2010, after which this rate decreases until reaching the ultimate rate of 5.50% in 2015.
Amounts recognized in accumulated other comprehensive loss consist of the following:
(1)
CERC’s postretirement benefit obligation is reduced by the impact of non-taxable government subsidies under the Medicare Prescription Drug Act. Because the subsidies are non-taxable, the temporary difference used in measuring the deferred tax impact is determined on the unrecognized losses excluding such subsidies. Accordingly, the unrecognized losses used for determining deferred taxes were $54 million and $60 million as of December 31, 2008 and 2009, respectively.
The changes in plan assets and benefit obligations recognized in other comprehensive income during 2009 are as follows:
The total expense recognized in net periodic costs and other comprehensive income was $15 million for postretirement benefits for the year ended December 31, 2009.
The amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost during 2010 are as follows:
Assumed healthcare cost trend rates have a significant effect on the reported amounts for CERC’s postretirement benefit plans. A 1% change in the assumed healthcare cost trend rate would have the following effects:
In managing the investments associated with the postretirement benefit plan, CERC’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.
As part of the investment strategy discussed above, CERC adopted and maintained the following asset allocation ranges for its postretirement benefit plan:
The fair values of CERC’s postretirement plan assets at December 31, 2009, by asset category are as follows:
(1)
95% of the amount invested in mutual funds was in fixed income securities and 5% was in U.S equities.
CERC expects to contribute $9 million to its postretirement benefits plan in 2010. The following benefit payments are expected to be paid by the postretirement benefit plan:
Postemployment Benefits
CERC participates in CenterPoint Energy’s plan that provides postemployment benefits 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). CERC recorded postemployment benefit income of $2 million, expense of $1 million, and $-0- for the years ended December 31, 2007, 2008 and 2009, respectively. Amounts relating to postemployment benefits included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2008 and 2009, were $16 million and $14 million, respectively.
Other Non-Qualified Plans
CERC participates in CenterPoint Energy’s 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 CERC. During 2007, 2008 and 2009, the benefit expense relating to these programs was less than $1 million each year. Amounts relating to deferred compensation plans included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2008 and 2009 were $1 million and $2 million, respectively.
Other Employee Matters
As of December 31, 2009, approximately 30% of CERC’s employees are subject to collective bargaining agreements.
(p) Other Current Assets and Liabilities
Included in other current assets on the Consolidated Balance Sheets at December 31, 2008 and 2009 was $42 million and $19 million, respectively, of margin deposits and $128 million and $80 million, respectively of under recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2008 and 2009 was $79 million and $70 million, respectively, of over recovered gas cost.
(3)
Regulatory Matters
(a) Hurricane Ike
CERC’s natural gas distribution business (Gas Operations) suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana as a result of Hurricane Ike, which struck the upper Texas coast in September 2008. As of December 31, 2009, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of natural gas distribution rate proceedings.
(b) Rate Proceedings
Texas. In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, Gas Operations implemented rates increasing annual revenues by approximately $3.5 million. The implemented rates were contested by 9 cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. The court concluded that the Railroad Commission did not have statutory authority to impose on the complaining cities the cost of service adjustment mechanism which the Railroad Commission had approved in its order. Certain parties filed a motion to modify the district court’s judgment and a final decision is not expected until April 2010. CERC does not expect the outcome of this matter to have a material adverse impact on its financial condition, results of operations or cash flows.
In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $20.4 million, excluding carrying costs on gas inventory of approximately $2 million. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates of $1.2 million. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years.
Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court. In July 2009, the Minnesota Supreme Court reversed the decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no
negative impact on CERC’s financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed.
In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. In January 2010, the MPUC issued its decision authorizing a revenue increase of $41 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The difference between the rates approved by the MPUC and amounts collected under the interim rates, $10 million as of December 31, 2009, is recorded in other current liabilities and will be refunded to customers. The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In February 2010, CERC filed a request for rehearing of the order by the MPUC. No other party to the case filed such a request. CERC does not expect a final order to be issued in this proceeding until spring 2010.
Mississippi. In July 2009, Gas Operations filed a request to increase its rates for utility distribution service with the Mississippi Public Service Commission (MPSC). In November 2009, as part of a settlement agreement in which the MPSC approved Gas Operations’ retention of the compensation paid under the terms of an asset management agreement, Gas Operations withdrew its rate request.
(c) Regulatory Accounting
CERC has a 50% ownership interest in SESH which owns and operates a 270-mile interstate natural gas pipeline. In 2009, SESH discontinued the use of guidance for accounting for regulated operations, which resulted in CERC recording its share of the effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax charges for the year ended December 31, 2009 of $16 million. These non-cash charges are reflected in equity in earnings of unconsolidated affiliates in the Statements of Consolidated Income. The related tax benefits of $6 million are reflected in the Income Tax Expense line in the Statements of Consolidated Income.
(4)
Related Party Transactions
CERC participates in a “money pool” through which it 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 CenterPoint Energy’s commercial paper. CERC had money pool borrowings of $-0- and $432 million at December 31, 2008 and 2009, respectively, which are included in accounts and notes payable-affiliated companies in the Consolidated Balance Sheets. At December 31, 2009, CERC’s money pool borrowings had a weighted-average interest rate of 0.18%.
CERC had net interest expense related to affiliate borrowings of $3 million, $1 million and less than $1 million for the years ended December 31, 2007, 2008 and 2009, respectively.
CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate. Amounts charged to CERC for these services were $133 million, $140 million and $154 million for 2007, 2008 and 2009, respectively, and are included primarily in operation and maintenance expenses.
In each of 2007, 2008 and 2009, CERC paid dividends of $100 million to its parent.
(5)
Derivative Instruments
CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CERC utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows.
(a) Non-Trading Activities
Derivative Instruments. CERC enters into certain derivative instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. These financial instruments do not qualify or are not designated as cash flow or fair value hedges.
During the year ended December 31, 2007, CERC recorded increased natural gas expense from unrealized net losses of $10 million. During the year ended December 31, 2008, CERC recorded increased natural gas revenues from unrealized net gains of $101 million and increased natural gas expense from unrealized net losses of $88 million, a net unrealized gain of $13 million. During the year ended December 31, 2009, CERC recorded decreased revenues from unrealized net losses of $80 million and decreased natural gas expense from unrealized net gains of $57 million, a net unrealized loss of $23 million.
In prior years, CERC entered into certain derivative instruments that were designated as cash flow hedges. The objective of these derivative instruments was to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting CERC's wholesale and retail customer obligations. In 2007, CERC discontinued designating these instruments as cash flow hedges. As of December 31, 2009, there are no remaining amounts deferred in other comprehensive income related to these instruments that had previously been designated as cash flow hedges.
Weather Hedges. CERC has weather normalization or other rate mechanisms that mitigate the impact of weather on its gas operations in Arkansas, Louisiana, Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of the gas operations in the remaining jurisdictions.
In 2007, 2008 and 2009, CERC entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the respective winter heating seasons. The swaps were based on ten-year normal weather. During the years ended December 31, 2007, 2008 and 2009, CERC recognized losses of $-0-, $17 million and $6 million, respectively, related to these swaps. The losses were substantially offset by increased revenues due to colder than normal weather. Weather hedge losses are included in revenues in the Statements of Consolidated Income.
(b) Derivative Fair Values and Income Statement Impacts
The following tables present information about CERC’s derivative instruments and hedging activities. The first table provides a balance sheet overview of CERC’s Non-trading Derivative Assets and Liabilities as of December 31, 2009, while the latter table provides a breakdown of the related income statement impact for the year ended December 31, 2009.
(1)
Commodity contracts are subject to master netting arrangements and are presented on a net basis in the Consolidated Balance Sheets. This netting causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets.
(2)
The fair value shown for commodity contracts is comprised of derivative gross volumes totaling 674 billion cubic feet (Bcf) or a net 152 Bcf long position. Of the net long position, basis swaps constitute 71 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 51 Bcf.
(3)
The net of total non-trading derivative assets and liabilities is a $39 million liability as shown on CERC’s Consolidated Balance Sheets, and is comprised of the commodity contracts derivative assets and liabilities separately shown above offset by collateral netting of $95 million.
For CERC’s price stabilization activities of the Natural Gas Distribution business segment, the settled costs of derivatives are ultimately recovered through purchased gas adjustments. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of recovery through purchased gas adjustments are recorded as net regulatory assets. For those derivatives that are not included in purchased gas adjustments, unrealized gains and losses and settled amounts are recognized on the Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for natural gas derivatives and non-retail related physical gas derivatives.
(1)
The Gains (Losses) in Expense: Natural Gas includes $(181) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.
(c) Credit Risk Contingent Features
CERC enters into financial derivative contracts containing material adverse change provisions. These provisions require CERC to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CERC is downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at December 31, 2009 is $140 million. The aggregate fair value of assets that are already posted as collateral at December 31, 2009 is $65 million. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2009, $75 million of additional assets would be required to be posted as collateral.
(d) Credit Quality of Counterparties
In addition to the risk associated with price movements, credit risk is also inherent in CERC’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 counterparties to the non-trading derivative assets of CERC as of December 31, 2008 and 2009 (in millions):
(1)
“Investment grade” is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guaranties) and collateral, which encompass cash and standby letters of credit. For unrated counterparties, CERC performs financial statement analysis, considering contractual rights and restrictions and collateral, to create a synthetic credit rating.
(2)
Retail end users represent commercial and industrial customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.
(6)
Fair Value Measurements
Effective January 1, 2008, CERC adopted new accounting guidance on fair value measurements which requires additional disclosures about CERC’s financial assets and liabilities that are measured at fair value. Effective January 1, 2009, CERC adopted this new guidance for nonfinancial assets and liabilities, which adoption had no impact on CERC’s financial position, results of operations or cash flows. Beginning in January 2008, assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in this guidance and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are financial derivatives, investments and equity securities listed in active markets.
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets.
Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. Unobservable inputs reflect CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. CERC’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.
The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2008 and 2009, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.
(1)
Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $187 million posted with the same counterparties.
(1)
Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $95 million posted with the same counterparties.
The following tables present additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CERC has utilized Level 3 inputs to determine fair value:
(1)
Purchases, sales, other settlements, net include a $41 million loss and a $66 million gain in 2008 and 2009, respectively, associated with price stabilization activities of CERC's Natural Gas Distribution business segment.
(7)
Short-term Borrowings and Long-term Debt
(1)
Includes amounts due or exchangeable within one year of the date noted.
(2)
In January 2010, pursuant to a notice of redemption dated December 11, 2009, CERC redeemed all of its outstanding 6% convertible subordinated debentures due in 2012.
(3)
Classified as long-term debt because the termination date of the facility under which the funds were borrowed is more than one year beyond the dates referenced in the table.
(4)
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 $3 million and $2 million, respectively, at December 31, 2008 and 2009, which is being amortized over the respective remaining term of the related long-term debt.
(a) Short-term Borrowings
Receivables Facility. On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010. Availability under CERC’s 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances. At December 31, 2008 and 2009, the facility size was $128 million and $150 million, respectively. As of December 31, 2008 and 2009, advances under the receivables facilities were $78 million and $-0-, respectively.
Inventory Financing. In December 2008, Gas Operations entered into an asset management agreement whereby it sold $110 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2008-2009 winter heating season for payments totaling $114 million. This transaction was accounted for as a financing and was paid in full during 2009.
In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, Louisiana and Oklahoma. Pursuant to the provisions of the agreements, Gas Operations sold $104 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2009-2010 winter heating season at the same cost, plus a financing charge. This transaction was accounted for as a financing and, as of December 31, 2009, a principal obligation of $55 million remained.
Also in October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Louisiana, Mississippi and Texas. In connection with these asset management agreements, Gas Operations exchanged natural gas in storage for the right to receive an equivalent amount of natural gas during the 2009-2010 winter heating season. Although title to the natural gas in storage was transferred to the third party, the natural gas continues to be accounted for as inventory due to the right to receive an equivalent amount of natural gas during the current winter heating season. As of December 31, 2009, CenterPoint Energy’s Consolidated Balance Sheets reflect $10 million in Inventory related to these agreements.
(b) Long-term Debt
Revolving Credit Facility. On October 7, 2009, the size of the CERC Corp. revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a $35 million commitment to lend. All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009. CERC Corp.’s $915 million credit facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.
Under CERC Corp.’s $915 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on CERC Corp.’s credit rating.
As of December 31, 2008 and 2009, CERC Corp. had $926 million and $-0-, respectively, of borrowings under its $915 million credit facility. There was no outstanding commercial paper backstopped by CERC Corp.’s credit facility as of December 31, 2008 and 2009. CERC Corp. was in compliance with all debt covenants as of December 31, 2009.
Maturities. CERC’s consolidated maturities of long-term debt are $44 million in 2010, $550 million in 2011, $-0- in 2012, $764 million in 2013 and $160 million in 2014.
(8)
Income Taxes
The components of CERC’s income tax expense were as follows:
A reconciliation of the expected federal income tax expense using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:
The state income tax expense of $18 million for 2009 includes a benefit of approximately $8 million, net of federal income tax effect, related to adjustments in prior years’ state estimates.
The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:
CERC is included in the consolidated income tax returns of CenterPoint Energy. CERC calculates its income tax provision on a separate return basis under a tax sharing agreement with CenterPoint Energy.
Tax Attribute Carryforwards and Valuation Allowance. At December 31, 2009, CERC has approximately $213 million of state net operating loss carryforwards which expire in various years between 2010 and 2029. A valuation allowance has been established for approximately $49 million of the state net operating loss carryforwards that may not be realized. CERC has approximately $244 million of state capital loss carryforwards which expire in 2017 for which a valuation allowance has been established.
Uncertain Income Tax Positions. The following table reconciles the beginning and ending balance of CERC’s unrecognized tax benefits:
CERC had approximately $1 million, $1 million and $-0- of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate for 2007, 2008 and 2009, respectively. CERC recognizes interest and penalties as a component of income tax expense. CERC recognized approximately $3 million, $1 million and $1 million of benefit for interest on uncertain income tax positions during 2007, 2008 and 2009, respectively. CERC had an accrued balance of $4 million and $5 million of interest receivables on uncertain income tax positions at
December 31, 2008 and 2009, respectively. CERC does not expect the amount of unrecognized tax benefits to change significantly over the next 12 months.
Tax Audits and Settlements. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through the 2005 tax year. CERC is currently under examination by the IRS for tax years 2006 and 2007 and is at various stages of the examination process. CERC has considered the effects of these examinations in its accrual for settled issues and liability for uncertain income tax positions as of December 31, 2009.
(9)
Commitments and Contingencies
(a) Natural Gas Supply Commitments
Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Consolidated Balance Sheets as of December 31, 2008 and 2009 as these contracts meet the exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of December 31, 2009, minimum payment obligations for natural gas supply commitments are approximately $439 million in 2010, $490 million in 2011, $427 million in 2012, $390 million in 2013, $269 million in 2014 and $543 million after 2014.
(b) Asset Management Agreements
Gas Operations has entered into asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization. Under the provisions of these asset management agreements, Gas Operations has an obligation to purchase its winter storage requirements from the asset manager. The agreements have varying terms, the longest of which expires in 2016.
(c) Lease Commitments
The following table sets forth information concerning CERC’s obligations under non-cancelable long-term operating leases at December 31, 2009, which primarily consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions):
Total rental expense for all operating leases was $43 million, $41 million and $36 million in 2007, 2008 and 2009, respectively.
(d) Capital Commitments
Long-Term Gas Gathering and Treating Agreements. In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC Corp., entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and EnCana’s natural gas production from the dedicated areas.
In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes. The construction necessary to reach the contractual capacity of 700 MMcf per day includes more than 200 miles of gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.
CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction are being provided from anticipated cash flows from operations, lines of credit, proceeds from the sale of debt securities or capital contributions. As of December 31, 2009, approximately $176 million has been spent on this project, including the purchase of existing facilities.
(e) Legal, Environmental and Other Matters
Legal Matters
Gas Market Manipulation Cases. CenterPoint Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits. Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2009. CenterPoint Energy and its affiliates have been released or dismissed from all but two of such cases. CenterPoint Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000-2002. Additionally, CenterPoint Energy was a defendant in a lawsuit filed in state court in Nevada that was dismissed in 2007, but the plaintiffs have indicated that they will appeal the dismissal. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases. CenterPoint Energy does not expect the ultimate outcome of these remaining matters to have a material impact on its financial condition, results of operations or cash flows.
On May 1, 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. The sale does not alter RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts discussed below.
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries, along with 76 other natural gas pipelines, their subsidiaries and affiliates, were defendants in a lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit sought undisclosed damages, along with statutory penalties, interest, costs and fees. This case was consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In October 2006, the judge considering this matter granted the defendants’ motion to dismiss the suit on the ground that the court lacked subject matter jurisdiction over the claims asserted. The plaintiff sought review of that dismissal from the Tenth Circuit Court of Appeals, which affirmed the district court’s dismissal in March 2009. Following dismissal of the plaintiff’s motion to the Tenth Circuit for rehearing, the plaintiff sought review by the United States Supreme Court, but his petition for certiorari was denied in October 2009.
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 Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative 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. In September 2009, the district court in Stevens County, Kansas, denied plaintiffs’ request for class certification of their case. The plaintiffs are seeking reconsideration of that denial.
CERC believes that there has been no systematic mismeasurement of gas and that these lawsuits are without merit. CERC does not expect the ultimate outcome of the lawsuits to have a material impact on its financial condition, results of operations or cash flows.
Gas Cost Recovery Litigation. In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against CenterPoint Energy, CERC Corp., certain other subsidiaries of CenterPoint Energy and CERC Corp. and various non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC) and in February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction.
In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to CERC. In February 2009, the Arkansas plaintiff notified the APSC that he would no longer pursue his claims, and in July 2009 the complaint proceeding was dismissed by the APSC. All appellate deadlines expired without an appeal of the dismissal order.
In June 2007, CenterPoint Energy, CERC Corp., and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has exclusive original jurisdiction over the Texas claims asserted in the Miller County case. In January 2009, the district court entered a final declaratory judgment ruling that the Railroad Commission has exclusive jurisdiction over the Texas claims asserted against CenterPoint Energy, and the other defendants in the Miller County case.
Environmental Matters
Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGPs) 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, 2009, CERC had accrued $14 million for remediation of these Minnesota sites and 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, 2009, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation. In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechanism and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers. As of December 31, 2009, the balance in the environmental expense tracker account was $8.7 million. The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs. CERC was not required to refund to customers the amount collected from insurance companies, $4.6 million at December 31, 2009, to be used to mitigate future environmental costs. The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures. This provision had no impact on earnings.
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 a lawsuit filed in the United States District Court, District of Maine, 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 the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing would be required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. CERC believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP. CERC does not expect the ultimate outcome to have a material adverse impact on its financial condition, results of operations or cash flows.
Mercury Contamination. CERC'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. CERC has found this type of contamination at some sites in the past, and CERC 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 is not known at this time, based on CERC's experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CERC believes that the costs of any remediation of these sites will not be material to its financial condition, results of operations or cash flows.
Asbestos. Some facilities formerly owned by CERC’s predecessors have contained asbestos insulation and other asbestos-containing materials. CERC or its predecessor companies have been named, along with numerous others, as a defendant in lawsuits filed by certain individuals who claim injury due to exposure to asbestos during work at such formerly owned facilities. CERC anticipates that additional claims like those received may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CERC 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 its financial condition, results of operations or cash flows.
Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans
Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CERC does not expect the outcome of this litigation to have a material adverse impact on its financial condition, results of operations or cash flows.
Other Environmental. From time to time CERC 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, CERC 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, CERC does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.
Other Proceedings
CERC 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. CERC regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. CERC does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.
(f) Guaranties
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. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $96 million as of December 31, 2009. As of December 31, 2009, RRI was not required to provide security to CERC. If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.
(10)
Estimated Fair Value of Financial Instruments
The fair values of cash and cash equivalents and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. Non-trading derivative assets and liabilities are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price.
(11)
Unaudited Quarterly Information
Summarized quarterly financial data is as follows:
(12)
Reportable Business Segments
Because CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy 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. CERC uses operating income as the measure of profit or loss for its business segments.
CERC’s reportable business segments include the following: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. Natural Gas Distribution consists of rate-regulated intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents CERC’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Our Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.
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):
(1)
Interstate Pipelines recorded equity income of $6 million, $36 million, and $7 million (including $6 million and $33 million related to pre-operating allowance for funds used during construction during 2007 and 2008, respectively) in the years ended December 31, 2007, 2008 and 2009, respectively, from its 50% interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Interstate Pipelines’ investment in SESH was $58 million, $307 million and $422 million as of December 31, 2007, 2008 and 2009 and is included in Investment in unconsolidated affiliates.
(2)
Field Services recorded equity income of $10 million, $15 million and $8 million for the years ended December 31, 2007, 2008 and 2009, respectively, from its 50% interest in a jointly-owned gas processing plant. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption. Field Services’ investment in the jointly-owned gas processing plant was $30 million, $38 million and $40 million as of December 31, 2007, 2008 and 2009, respectively, and is included in Investment in unconsolidated affiliates.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A(T).
Item 9A(T). 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, 2009 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 and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.
There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
See report set forth above in Item 8, “Financial Statements and Supplementary Data.”
Item 9B.
Item 9B. Other Information
The ratio of earnings to fixed charges as calculated pursuant to Securities and Exchange Commission rules was 2.61, 2.64, 3.04, 3.30, and 2.63 for the years ended December 31, 2005, 2006, 2007, 2008 and 2009, respectively.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 11.
Item 11. Executive Compensation
The information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
Item 14.
Item 14. Principal Accounting Fees and Services
Aggregate fees billed to CERC during the fiscal years ending December 31, 2008 and 2009 by its principal accounting firm, Deloitte & Touche LLP, are set forth below.
(1)
For 2009 and 2008, amounts include fees for services provided by the principal accounting firm relating to the integrated audit of financial statements and internal control over financial reporting, statutory audits, attest services, and regulatory filings.
(2)
For 2009 and 2008, includes fees for consultations concerning financial accounting and reporting standards and various agreed-upon or expanded procedures related to accounting records to comply with financial accounting or regulatory reporting matters.
CERC is not required to have, and does not have, an audit committee.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
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:
I, III, IV and V.
(a)(3) Exhibits.
See Index of Exhibits beginning on page 75.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of
CenterPoint Energy Resources Corp.
Houston, Texas
We have audited the consolidated financial statements of CenterPoint Energy Resources Corp. and subsidiaries (the “Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.) as of December 31, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, and have issued our report thereon dated March 11, 2010; such report is included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company listed in the index at Item 15(a)(2). This consolidated financial statement schedule is 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 schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 11,
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Three Years Ended December 31, 2009
(1)
The 2008 change to the deferred tax asset valuation allowance charged to other accounts represents a reduction equal to the related deferred tax asset reduction in 2008 for re-measurement of state tax attributes, net of federal tax benefit. A full valuation allowance for this deferred tax asset was established in prior periods.
(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 11th day of March, 2010.
CENTERPOINT ENERGY RESOURCES CORP.
(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 11, 2010.
Signature
Title
/s/ DAVID M. MCCLANAHAN
Chairman, President and Chief Executive Officer
(David M. McClanahan)
(Principal Executive Officer and Director)
/s/ GARY L. WHITLOCK
Executive Vice President and Chief Financial Officer
(Gary L. Whitlock)
(Principal Financial Officer)
/s/ WALTER L. FITZGERALD
Senior Vice President and Chief Accounting Officer
(Walter L. Fitzgerald)
(Principal Accounting Officer)
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2009
INDEX OF EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
Exhibit
Number
Description
Report or
Registration Statement
SEC File or
Registration
Number
Exhibit
Reference
2(a)(1)
Agreement and Plan of Merger among CERC, Houston Lighting and Power Company (“HL&P”), HI Merger, Inc. and NorAm Energy Corp. (“NorAm”) dated August 11, 1996
Houston Industries’ (“HI’s”) Form 8-K dated August 11, 1996
1-7629
2(a)(2)
Amendment to Agreement and Plan of Merger among CERC, HL&P, HI Merger, Inc. and NorAm dated August 11, 1996
Registration Statement on Form S-4
333-11329
2(c)
2(b)
Agreement and Plan of Merger dated December 29, 2000 merging Reliant Resources Merger Sub, Inc. with and into Reliant Energy Services, Inc.
Registration Statement on Form S-3
333-54526
3(a)(1)
Certificate of Incorporation of Reliant Energy Resources Corp. (“RERC Corp.”)
Form 10-K for the year ended December 31, 1997
1-3187
3(a)(1)
3(a)(2)
Certificate of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc. dated August 6, 1997
Form 10-K for the year ended December 31, 1997
1-3187
3(a)(2)
3(a)(3)
Certificate of Amendment changing the name to Reliant Energy Resources Corp.
Form 10-K for the year ended December 31, 1998
1-3187
3(a)(3)
3(a)(4)
Certificate of Amendment changing the name to CenterPoint Energy Resources Corp.
Form 10-Q for the quarter ended June 30, 2003
1-13265
3(a)(4)
3(b)
Bylaws of RERC Corp.
Form 10-K for the year ended December 31, 1997
1-3187
3(b)
4(a)(1)
Indenture, dated as of February 1, 1998, between RERC Corp. and Chase Bank of Texas, National Association, as Trustee
Form 8-K dated February 5, 1998
1-13265
4.1
4(a)(2)
Supplemental Indenture No. 1, dated as of February 1, 1998, providing for the issuance of RERC Corp.’s 6 1/2%
Debentures due February 1, 2008
Form 8-K dated February 5, 1998
1-13265
4.2
Exhibit
Number
Description
Report or
Registration Statement
SEC File or
Registration
Number
Exhibit
Reference
4(a)(3)
Supplemental Indenture No. 2, dated as of November 1, 1998, providing for the issuance of RERC Corp.’s 6 3/8% Term Enhanced ReMarketable Securities
Form 8-K dated November 9, 1998
1-13265
4.1
4(a)(4)
Supplemental Indenture No. 3, dated as of July 1, 2000, providing for the issuance of RERC Corp.’s 8.125% Notes due 2005
Registration Statement on Form S-4
333-49162
4.2
4(a)(5)
Supplemental Indenture No. 4, dated as of February 15, 2001, providing for the issuance of RERC Corp.’s 7.75% Notes due 2011
Form 8-K dated February 21, 2001
1-13265
4.1
4(a)(6)
Supplemental Indenture No. 5, dated as of March 25, 2003, providing for the issuance of CERC Corp.’s 7.875% Senior Notes due 2013
Form 8-K dated March 18, 2003
1-13265
4.1
4(a)(7)
Supplemental Indenture No. 6, dated as of April 14, 2003, providing for the issuance of CERC Corp.’s 7.875% Senior Notes due 2013
Form 8-K dated April 7, 2003
1-13265
4.2
4(a)(8)
Supplemental Indenture No. 7, dated as of November 3, 2003, providing for the issuance of CERC Corp.’s 5.95% Senior Notes due 2014
Form 8-K dated October 29, 2003
1-13265
4.2
4(a)(9)
Supplemental Indenture No. 8, dated as of December 28, 2005, providing for the issuance of CERC Corp.’s 6 1/2% Debentures due 2008
CenterPoint Energy, Inc.’s (“CNP’s”) Form 10-K for the year ended December 31, 2005
1-31447
4(f)(9)
4(a)(10)
Supplemental Indenture No. 9, dated as of May 18, 2006, providing for the issuance of CERC Corp.’s 6.15% Senior Notes due 2016
CNP’s Form 10-Q for the quarter ended June 30, 2006
1-31447
4.7
4(a)(11)
Supplemental Indenture No. 10, dated as of February 6, 2007, providing for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037
CNP’s Form 10-K for the year ended December 31, 2007
1-31447
4(f)(11)
4(a)(12)
Supplemental Indenture No. 11 dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.125% Senior Notes due 2017
CNP’s Form 10-Q for quarter ended September 30, 2007
1-31447
4.8
4(a)(13)
Supplemental Indenture No. 12 dated as of October 23, 2007, providing for the issuance of CERC Corp.’s 6.625% Senior Notes due
CNP’s Form 10-Q for quarter ended September 30, 2007
1-31447
4.9
4(a)(14)
Supplemental Indenture No. 13 dated as of May 15, 2008, providing for the issuance of CERC Corp.’s 6.00% Senior Notes due 2018
CNP’s Form 10-Q for quarter ended June 30, 2008
1-31447
4.9
Exhibit
Number
Description
Report or
Registration Statement
SEC File or
Registration
Number
Exhibit
Reference
4(b)
$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein
CNP’s Form 10-Q for the quarter ended June 30, 2007
1-31447
4.5
There have not been filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of securities do not exceed 10% of the total assets of CERC. CERC hereby agrees to furnish a copy of any such instrument to the SEC upon request.
Exhibit
Number
Description
Report or
Registration Statement
SEC File or
Registration
Number
Exhibit
Reference
10(a)
Service Agreement by and between Mississippi River Transmission Corporation and Laclede Gas Company dated August 22, 1989
NorAm’s Form 10-K for the year ended December 31, 1989
1-13265
10.20
+12
Computation of Ratios of Earnings to Fixed Charges
+23
Consent of Deloitte & Touche LLP
+31.1
Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2
Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1
Section 1350 Certification of David M. McClanahan
+32.2
Section 1350 Certification of Gary L. Whitlock