Attached files
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2010
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-2700
El Paso Natural Gas Company
(Exact Name of Registrant as Specified in Its Charter)
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Delaware
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74-0608280
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification No.)
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El Paso Building
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1001 Louisiana Street
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Houston, Texas
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77002
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(Address of Principal Executive Offices)
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(Zip Code)
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Telephone Number: (713) 420-2600
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes £No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yes £No R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes£ No£
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R
State the aggregate market value of the voting stock held by non-affiliates of the registrant: None
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Common Stock, par value $1 per share. Shares outstanding on February 25, 2011: 1,000
EL PASO NATURAL GAS COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.
Documents Incorporated by Reference: None
EL PASO NATURAL GAS COMPANY
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We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
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Below is a list of terms that are common to our industry and used throughout this document:
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/d
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per day
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LNG
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liquefied natural gas
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BBtu
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billion British thermal units
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MMcf
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million cubic feet
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Bcf
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billion cubic feet
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When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
When we refer to “us”, “we”, “our”, “ours” or “the company”, we are describing El Paso Natural Gas Company and/or our subsidiaries.
Overview and Strategy
We are a Delaware corporation incorporated in 1928, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business consists of the interstate transportation and storage of natural gas. We conduct our business activities through our natural gas pipeline systems and a storage facility as discussed below.
Each of our pipeline systems and our storage facility operates under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.
Our strategy is to enhance the value of our transportation and storage business by:
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providing outstanding customer service;
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developing new growth projects in our market and supply areas;
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maintaining the integrity and ensuring the safety of our pipeline systems and other assets;
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successfully recontracting expiring contracts for transportation capacity; and
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focusing on increasing utilization, efficiency and cost control in our operations.
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The El Paso Natural Gas (EPNG) System. The EPNG system consists of approximately 10,200 miles of pipeline with a winter sustainable west-flow capacity of 4,850 MMcf/d and east-end deliverability of 800 MMcf/d. During 2010, 2009 and 2008, average throughput was 3,356 BBtu/d, 3,937 BBtu/d and 4,379 BBtu/d. This system delivers natural gas from the San Juan, Permian, and Anadarko basins to markets in California, Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.
The Mojave Pipeline Company (Mojave) System. The Mojave system consists of approximately 500 miles of pipeline with an east to west flow design capacity of approximately 400 MMcf/d. During 2010, 2009 and 2008, average throughput was 421 BBtu/d, 379 BBtu/d and 349 BBtu/d. Mojave’s 2010, 2009 and 2008 throughput includes 382 BBtu/d, 334 BBtu/d and 306 BBtu/d of volumes transported on behalf of the EPNG system. The Mojave system connects with other pipeline systems including, (i) the EPNG system near Cadiz, California, (ii) the EPNG and Transwestern Pipeline Company, LLC (Transwestern) systems at Topock, Arizona and (iii) the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.
Storage Facility. In addition to our pipeline systems, we utilize our Washington Ranch underground storage facility located in New Mexico to manage our transportation needs and to offer interruptible storage services. This storage facility has up to approximately 44 Bcf of underground working natural gas storage capacity.
Markets and Competition
Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline systems connect with multiple pipelines that provide our customers with access to diverse sources of supply, including supply from unconventional sources, and various natural gas markets.
The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shales, is rapidly increasing. This shift will affect the supply patterns, the flows and the rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources.
Exports to Mexico are increasing and expected to increase further over time as demand growth exceeds production growth in that country. The increase in demand for gas and transportation caused by the trends in Mexico could be partially offset by imports of LNG. Imports of LNG have fluctuated in the past in response to changing gas prices within North America, Europe and Asia. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems may also compete with us for transportation of gas into market areas we serve.
Electric power generation has been the source of most of the growth in demand for natural gas over the last 10 years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by competition with coal and increased consumption of electricity as a result of recent economic growth. Short-term market shifts have been driven by relative costs of coal-fired generation versus gas-fired generation. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources.
The EPNG system faces competition in the west and southwest from other existing pipelines, from California storage facilities, and from alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. We also face competition from gas imported into California from Canada and from an LNG facility located in northern Mexico.
The Mojave system faces competition from other existing pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. We also face competition from an LNG facility located in northern Mexico.
For a further discussion of factors impacting our markets and competition, see Item 1A, Risk Factors.
Customers and Contracts
Our existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
Historically, California customers have been the largest holders of capacity on our EPNG system. Currently, California and Arizona customers account for the majority of transportation on the EPNG system, followed by Texas and New Mexico. The Mojave system is largely contracted to EPNG which utilizes the capacity to provide service to EPNG’s customers. The EPNG system also delivers natural gas to the U.S./Mexico border serving customers in Chihuahua, Sonora, and Baja California, which are located in Mexico.
The following table details our customer and contract information for each of our pipeline systems as of December 31, 2010. Firm customers reserve capacity on our pipeline systems and storage facility and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.
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Pipeline System
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Customer Information
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Contract Information
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EPNG
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Approximately 150 firm and interruptible customers.
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Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately three years.
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Major Customers:
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Southern California Gas Company (SoCal)
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(782 BBtu/d)
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Expire in 2011-2014.
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ConocoPhillips Company
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(527 BBtu/d)
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Expire in 2011-2012.
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Southwest Gas Corporation
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(485 BBtu/d)
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Expire in 2011-2018.
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Mojave
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Approximately 10 firm and interruptible customers.
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Approximately two firm transportation contracts. Weighted average remaining contract term of approximately five years.
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Major Customer:
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EPNG
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(510 BBtu/d)
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Expires in 2015.
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Regulatory Environment
Our interstate natural gas transmission systems and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority also extends to:
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rates and charges for natural gas transportation and storage;
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certification and construction of new facilities;
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extension or abandonment of services and facilities;
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maintenance of accounts and records;
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relationships between pipelines and certain affiliates;
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terms and conditions of service;
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depreciation and amortization policies;
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acquisition and disposition of facilities; and
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initiation and discontinuation of services.
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Our interstate pipeline systems are also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our systems are in material compliance with the applicable regulations. For a further discussion of the potential impact of regulatory matters on us, see Item 1A, Risk Factors.
Environmental
A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.
Employees
As of February 21, 2011, we had approximately 530 full-time employees, none of whom are subject to a collective bargaining arrangement.
CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.
Risks Related to Our Business
The success of our business depends on many factors beyond our control.
The results of our business are impacted in the long term by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes we transport and store depend on the actions of third parties that are based on factors beyond our control. Such factors include events that negatively impact our customers’ demand for natural gas and could expose our pipelines to the risk that we will not be able to renew contracts at expiration or that we will be required to discount our rates significantly upon renewal. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their systems in order to grow our business. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.
The volume of gas that we transport and store also depends on the availability of natural gas supplies that are attached to our pipeline systems, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our systems. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our systems. There have been major shifts in supply basins over the last few years, and declining production from conventional sources of supplies. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our systems.
Furthermore, our ability to deliver gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand. For example, during February of 2011, our south system experienced operational difficulties for various reasons, primarily due to the shippers’ taking more gas from the system than they had purchased and delivered into receipt points on our pipeline. Various state and federal agencies are reviewing the causes of such outages and it is uncertain what actions, if any, that the agencies will recommend upon completion of their reviews.
The agencies that regulate us and our customers could affect our profitability.
Our pipeline business is extensively regulated by the FERC, the U.S. Department of Transportation, the Department of Interior, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipelines (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. In 2010, we filed a rate case that will establish new rates in 2011. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, our profitability is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases.
Our existing rates may also be challenged by complaint. The FERC commenced several proceedings in 2009 and 2010 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on us and that a successful complaint against our rates could have an adverse impact on us. For a discussion of our recent rate case filed with the FERC, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.
Certain of our transportation services are subject to negotiated rate contracts that may not allow us to recover our costs of providing the services.
Under FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increases in the cost of capital or taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.
Our revenues are generated under contracts that must be renegotiated periodically.
Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on our pipeline systems could decrease over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. Our ability to extend and replace contracts could be adversely affected by factors we cannot control, as discussed above. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.
The expansion of our pipeline systems by constructing new facilities subjects us to construction and other risks that may adversely affect us.
We frequently expand the capacity of our existing pipeline and storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
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our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that are on terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally, culturally sensitive and more heavily populated areas;
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the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;
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the availability of skilled labor, equipment, and materials to complete expansion projects;
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potential changes in federal, state and local statutes, regulations, and orders;
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impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;
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our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact the return on our investments or could result in financial impairments;
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our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;
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the failure of suppliers and contractors to meet their performance and warranty obligations; and
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the lack of transportation, storage or throughput commitments.
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Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the potential for future expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return.
We depend on certain key customers for a significant portion of our revenues and the loss of any of these key customers could result in a decline in our revenues.
We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2010, ConocoPhillips Company, Southern California Gas Company and Southwest Gas Corporation accounted for approximately 15 percent, 14 percent and 12 percent, respectively of our operating revenues. The loss of any material portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us. For additional information on our revenues from these customers, see Part II, Item 8, Financial Statements and Supplementary Data, Note 9.
The costs to maintain, repair and replace our pipeline systems may exceed our expected levels.
Much of our pipeline infrastructure was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including due to third party excavation near our pipelines, unexpected degradation of our pipelines, as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline systems are located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipelines. In addition, as indicated above there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate, our facilities may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with our operations. Our loss of or interference with these rights could have a material adverse effect on us.
There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.
Accounting policies for FERC regulated pipelines are in certain instances different from U.S. generally accepted accounting principles (GAAP) for nonregulated entities. For example, FERC accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not typically be recorded for nonregulated entities. In determining whether to account for regulatory assets on each of our pipelines, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the pipeline is placed into service.
The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. For example, we are not significantly impacted in the short-term by reductions in the supply or demand for natural gas since we recover most of our revenues from reservation charges under longer-term contracts that are not dependent on the supply and demand of natural gas in the short-term. However, our business can be negatively impacted by sustained downturns in supply and demand for natural gas. One of the major factors that will impact natural gas demand will be the potential growth of natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:
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adverse changes in global economic conditions, including changes that negatively impact general demand for power generation and industrial loads for natural gas;
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adverse changes in geopolitical factors, including unexpected wars, terrorist activities and others acts of aggression;
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technological advancements that may drive further increases in production from natural gas shales;
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competition from imported LNG and alternate fuels;
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increased prices of natural gas that could negatively impact demand;
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increased costs to transport natural gas;
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adoption of various energy efficiency and conservation measures; and
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perceptions of customers on the availability and price volatility of natural gas prices over the longer-term.
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The price for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices will remain depressed for sustained periods, especially in relation to natural gas prices which are at relatively low levels at this time. The degree to which our business is impacted by lower commodity prices varies. For example, we are not as significantly impacted in the short-term by changes in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:
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changes in regional and domestic supply and demand;
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changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain transportation revenues and renew transportation contracts in supply basins that are not as competitive with other alternatives;
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changes in the costs of transporting natural gas;
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increased federal and state taxes, if any, on the transportation of natural gas;
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the price and availability of supplies of alternative energy sources; and
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the amount of capacity available to transport natural gas.
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Our business is subject to competition from third parties which could negatively affect us.
The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies in the transportation and storage of natural gas. We also compete with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes growing competition in many of the markets that we serve, including Transwestern’s pipeline into Phoenix. There have also been various proposals over time to construct LNG terminals along the east and west coasts that could also negatively impact the demand and the transportation rates that our pipeline systems could charge to the extent the LNG terminals were constructed. For example, our EPNG system experienced a loss of demand when an LNG terminal was completed south of the Mexico – California border.
Our operations are subject to operational hazards and uninsured risks which could negatively affect us.
Our operations are subject to a number of inherent risks including fires, earthquakes, adverse weather conditions (such as extreme cold or heat, tornadoes, lightning and flooding) and other natural disasters; terrorist activity or acts of aggression; the collision of equipment of third parties on our infrastructure (such as damage caused to our underground pipelines by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards. Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. In addition, although the potential effects of climate change on our operations (such as flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could have a negative impact upon our operations in the future.
While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms that we find acceptable for certain exposures including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption, named windstorm exposures, and in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.
We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.
Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trading Commission and the FERC to impose penalties for violations of laws or regulations has generally increased over the last few years. In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls, and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands , which are regulated by the Department of the Interior, particularly by the Bureau of Land Management (BLM). We also have operations on Native American tribal lands, which are regulated by the Department of the Interior, particularly by the Bureau of Indian Affairs, as well as local tribal authorities. Operations on these properties are often subject to additional regulations and compliance obligations, which can delay our access to such lands and impose additional compliance costs.
The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.
The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws and regulations may be enacted or existing laws and regulation may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to implement or amend federal, state, local and tribal laws and regulations that could negatively impact our business, which includes among others:
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•
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Climate Change and other Emissions. There have been various legislative and regulatory proposals at the federal and state levels to address climate change and to regulate GHG emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation has the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, including the level of any emission standards; the amount and costs of allowances, offsets and credits granted; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject us to regulation prior to 2016. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas fired power plants over coal-fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has proposed more stringent ozone standards, as well as implemented more stringent emission standards with regard to certain combustion engines on our pipeline systems. It is uncertain what impact new environmental regulations might have on us until further definition is provided in the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by requiring us to monitor emissions, install additional equipment to reduce carbon emissions and possibly to purchase emission credits, as well as potentially delay the receipt of permits and other regulatory approvals. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipelines, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.
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Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.
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Pipeline Safety. Various legislative and regulatory reforms associated with pipeline safety and integrity issues have been recently proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipelines and subjecting additional pipelines (including gathering and intrastate pipeline facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.
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We are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk that our counterparties fail to make payments to us within the time required under our contracts. Our current largest exposures are associated with shippers under long-term transportation contracts on our pipeline systems. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.
We are exposed to the credit and performance risk of our key contractors and suppliers.
As an owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction and we rely on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us.
Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plans.
Our business requires the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. We compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible, which have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain our current employees, (b) successfully complete our knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.
We have certain contingent liabilities that could exceed our estimates.
We have certain contingent liabilities associated with litigation, regulatory and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continue to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 7). Although we believe that we have established appropriate reserves for our litigation, regulatory and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.
We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.
We are subject to interest rate risks.
Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.
Risks Related to Our Affiliation with El Paso
El Paso files reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.
We are an indirect wholly owned subsidiary of El Paso.
As an indirect wholly owned subsidiary of El Paso, subject to limitations in our credit agreements and indentures, El Paso has substantial control over:
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our payment of dividends;
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decisions on our financing and capital raising activities;
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mergers or other business combinations;
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our acquisitions or dispositions of assets; and
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our participation in El Paso’s cash management program.
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El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.
Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.
Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 with a stable outlook by Moody’s Investor Service, BB- with a stable outlook by Standard & Poor’s and BB+ with a stable outlook by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. There is a risk that these credit ratings may be adversely affected in the future as credit rating agencies review their general credit requirements as well as review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets as well as our cost of capital.
El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated note receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.
If El Paso is unable to renew its revolving credit facility that expires in November 2012, then it could negatively impact us.
We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however for our borrowings under the credit agreement, which were zero at December 31, 2010. El Paso’s credit agreement is due to expire November of 2012. Prior to maturity, El Paso plans to renew or extend this credit facility. The amount of credit capacity El Paso is able to obtain and the cost of such credit could have a negative impact on our liquidity position and financial results. In addition, the financial covenants set forth in any new facility may be more restrictive than the current facility and could reduce our financial and operating flexibility.
A default under El Paso’s $1.5 billion credit agreement by any party could accelerate our future borrowings, if any, under the credit agreement and our long-term debt, which could adversely affect our liquidity position.
Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.
Furthermore, the indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. Therefore, if we borrow $25 million or more under El Paso’s $1.5 billion credit agreement and such borrowings are accelerated for any reason, including the default of another party under the credit agreement, our long-term debt that contains these provisions could also be accelerated and, in turn, adversely affect our liquidity position and, in turn, our financial condition.
We may be subject to a change of control if an event of default occurs under El Paso’s credit agreement.
Under El Paso’s $1.5 billion credit agreement, our common stock and the common stock of one of El Paso’s other subsidiaries are pledged as collateral. As a result, our ownership is subject to change if there is a default under the credit agreement and El Paso’s lenders exercise rights over their collateral, even if we do not have any borrowings outstanding under the credit agreement. For additional information concerning El Paso’s credit facility, see Part II, Item 8, Financial Statements and Supplementary Data, Note 6.
We have not included a response to this item since no response is required under Item 1B of Form 10-K.
A description of our properties is included in Item 1, Business, and is incorporated herein by reference.
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.
A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.
All of our common stock, par value $1 per share, is owned by a subsidiary of El Paso and, accordingly, our stock is not publicly traded.
We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. During 2010 and 2009, we utilized $75 million, net of a $50 million cash contribution from our parent, and $200 million of our note receivable from the cash management program to pay dividends to our parent. No common stock dividends were declared or paid in 2008.
Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.
Overview
Our primary business consists of the interstate transportation and storage of natural gas. We face varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.
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Type
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Description
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Percent of 2010
Revenues
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Reservation
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Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems and storage facility. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.
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89
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Usage and Other
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Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.
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11
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The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather. In addition, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to the revaluation of our fuel under or over recoveries, imbalances and system encroachments. Our tariffs continue to provide that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the impact of over or under collecting fuel and lost and unaccounted for gas from our operational gas costs.
We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
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Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately three years as of December 31, 2010. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2010, including those with terms beginning in 2011 or later.
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Contracted
Capacity
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Percent of
Contracted Capacity
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Reservation Revenue
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Percent of
Reservation Revenue
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(BBtu/d) (1)
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(In millions)
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2011
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2,099 | 41 | $ | 126 | 28 | |||||||||||
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2012
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889 | 18 | 110 | 25 | ||||||||||||
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2013
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707 | 14 | 63 | 14 | ||||||||||||
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2014
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257 | 5 | 16 | 4 | ||||||||||||
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2015
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330 | 6 | 53 | 12 | ||||||||||||
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2016 and beyond
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808 | 16 | 77 | 17 | ||||||||||||
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Total
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5,090 | 100 | $ | 445 | 100 | |||||||||||
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(1)
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Excludes EPNG contracted capacity on the Mojave system.
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Results of Operations
Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, 2010 compared with 2009.
Operating Results:
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2010
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2009
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(In millions,
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except for volumes)
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Operating revenues
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$ | 517 | $ | 593 | ||||
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Operating expenses
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(313 | ) | (314 | ) | ||||
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Operating income
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204 | 279 | ||||||
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Other income, net
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3 | 2 | ||||||
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EBIT
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207 | 281 | ||||||
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Interest and debt expense
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(92 | ) | (93 | ) | ||||
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Affiliated interest income, net
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15 | 19 | ||||||
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Income tax expense
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(47 | ) | (79 | ) | ||||
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Net income
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$ | 83 | $ | 128 | ||||
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Throughput volumes (BBtu/d)(1)
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3,395 | 3,982 | ||||||
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(1)
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Throughput volumes exclude throughput transported on the Mojave system on behalf of the EPNG system.
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EBIT Analysis:
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Revenue
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Expense
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Other
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Total
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Favorable/(Unfavorable)
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(In millions)
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Reservation and other services revenues
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$ | (76 | ) | $ | — | — | $ | (76 | ) | |||||||
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Operational gas and revaluations
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— | (4 | ) | — | (4 | ) | ||||||||||
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Operating and general and administrative expenses
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— | 12 | — | 12 | ||||||||||||
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Other (1)
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— | (7 | ) | 1 | (6 | ) | ||||||||||
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Total impact on EBIT
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$ | (76 | ) | $ | 1 | 1 | $ | (74 | ) | |||||||
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(1)
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Consists of individually insignificant items.
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Reservation and Other Services Revenues. For the year ended December 31, 2010, throughput on our EPNG system was down 15 percent compared to 2009 due to lower natural gas and electric generation demand resulting from weak macroeconomic conditions in the southwestern U.S., increased competition in our California and Arizona market areas, including increased activity from an LNG facility, and the nonrenewal of expiring contracts as a result of reduced basis differentials which unfavorably impacted our EBIT by $76 million.
Although approximately 89 percent of our 2010 revenues are derived from reservation charges, lower throughput can affect our short-term results or be an indication of the risks we may face when seeking to recontract or renew any of our existing firm transportation contracts. Continuing negative economic impacts on demand, as well as adverse shifting sources of supply, could negatively impact basis differentials and our ability to renew firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates. Additionally, we may be required to further discount certain transportation rates in order to renew certain firm transportation contracts should these conditions continue.
If we determine there is sufficient change in our revenues, costs or billing determinants, we have the option to file a rate case with the FERC to provide an opportunity to recover our prudently incurred costs. In September 2010, we filed a rate case with the FERC proposing an increase in base tariff rates due, in part, to a change in our billing determinants. The change in gas flows, contractual commitments and the outcome of our rate case can impact the financial performance of our pipeline. For additional information regarding our rate cases see “Regulatory Matters” discussed below.
Gas Not Used in Operations. In October 2009, we received an order from the FERC directing us to remove the cost and revenue components of the fuel tracker on our EPNG system. Our compliance filing to remove the cost and revenue component was approved in the fourth quarter of 2009 and we recorded a favorable adjustment to reflect the impact of unwinding these components of our fuel tracker.
Operating and General and Administrative Expenses. For the year ended December 31, 2010, our operating and general and administrative expenses were lower than in 2009 by approximately $12 million primarily due to lower payroll, benefits and contractor costs partially offset by higher allocated costs from our affiliates related to our shared pipeline services.
Regulatory Matters
EPNG Rate Case. In April 2010, the FERC approved an uncontested partial offer of settlement which increased our base tariff rates effective January 1, 2009. As part of the settlement we made refunds of approximately $76 million, plus interest, in 2010. The settlement resolved all but four issues in the proceeding. In January 2011, the Presiding Administrative Law Judge issued her decision that for the most part found against us on the four issues. We will appeal those decisions to the FERC and may also seek review of any of the FERC’s decisions to the U.S. Court of Appeals. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.
In September 2010, we filed a new rate case with the FERC proposing an increase in base tariff rates as permitted under the settlement of the previous rate case. These new base tariff rates would increase revenue by approximately $107 million annually over previously effective tariff rates. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not currently determinable.
In October 2010, we filed with the FERC to permanently abandon two compressor stations and temporarily idle seven compressor stations along our south mainline system in 2011. This was done to better align our capacity to the current lower level of contract demand resulting from, in part, the weakened economic conditions along this line. Our intent is to bring the idled facilities back into service over the next several years as market demand improves. In our 2011 rate case, we did not seek to earn a return on the original investment in the idled facilities. We will continue to incur related operating costs and depreciation expense until the compressor stations are idled once approved by the FERC. The impact of both the permanent abandonment and the idling of the seven compressor stations to our pre-tax income would be approximately $15 million annually. These filings have been protested by certain interveners and the result is uncertain at this time.
Mojave Rate Case. In August 2010, we filed a petition with the FERC to (i) amend our filing requirement previously approved by the FERC and (ii) approve an uncontested rate case settlement that, among other things, would establish new base transportation rates. Under the terms of the agreement, we may not file a new rate case to be effective any earlier than September 1, 2012, but must file a rate case to be effective no later than September 1, 2014. The FERC approved this settlement in October 2010 with an effective date of December 1, 2010.
Although these rate cases are intended to address significant factors leading to the loss in revenues or increased costs, they will not eliminate all ongoing business risks.
Affiliated Interest Income, Net
Affiliated interest income, net for the year ended December 31, 2010, was $4 million lower than in 2009 primarily due to lower average short-term interest rates on average advances to El Paso under its cash management program. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:
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2010
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2009
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(In billions, except for rates)
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Average advance due from El Paso
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$ | 1.0 | $ | 1.1 | ||||
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Average short-term interest rate
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1.5 | % | 1.7 | % | ||||
Income Taxes
Our effective tax rate of 36 percent and 38 percent for the years ended December 31, 2010 and 2009 was higher than the statutory rate of 35 percent in both periods due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 2.
Liquidity and Capital Resources
Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program. At December 31, 2010, we had a note receivable from El Paso of approximately $0.8 billion. We do not intend to settle any amounts owed under this note within the next twelve months and therefore, classified it as non-current on our balance sheet. During 2010, we utilized $75 million of our note receivable from the cash management program, net of a $50 million cash contribution from our parent, to pay a dividend to our parent. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of El Paso’s cash management program. In August 2010, we repaid approximately $54 million cash of our 7.625% notes that matured. Our primary uses of cash are for working capital, capital expenditures and debt service requirements. For the year ended December 31, 2010 compared with 2009, our operating cash flows decreased by approximately $260 million primarily due to lower reservation revenues, payments of rate refunds and income taxes. Our cash capital expenditures for the year ended December 31, 2010 and those planned for 2011 are listed below.
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2010
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Expected
2011
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(In millions)
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Maintenance
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$ | 80 | $ | 94 | ||||
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Expansion
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— | 2 | ||||||
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Total
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$ | 80 | $ | 96 | ||||
Our expected 2011 maintenance capital expenditures relate to maintaining and improving the integrity of our pipeline, complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. Our expansion capital expenditures primarily relate to expanding the capacity and services of our pipeline systems.
Although financial market conditions have improved, continued volatility in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is partially mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.
We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2010, El Paso had approximately $0.9 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. While we do not anticipate a need to directly access the financial markets in 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.
For further detail on our risk factors including potential adverse general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 7 which is incorporated herein by reference.
We are exposed to the risk of changing interest rates. At December 31, 2010, we had an interest bearing note receivable from El Paso of approximately $0.8 billion, with a variable interest rate of 1.5% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.
The table below shows the carrying value, the related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities based on quoted market prices for the same or similar issues.
|
December 31, 2010
|
|
|||||||||||||||||||||||
|
|
Expected Fiscal Year of Maturity of
Carrying Amounts
|
|
December 31, 2009
|
|||||||||||||||||||||
|
|
2011-2015 |
Thereafter
|
Total
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||||||||
|
(In millions, except for rates)
|
||||||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Long-term debt — fixed rate
|
$ | — | $ | 1,113 | $ | 1,113 | $ | 1,258 | $ | 1,167 | $ | 1,300 | ||||||||||||
|
Average effective interest rate
|
7.5 | % | ||||||||||||||||||||||
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:
|
•
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
|
•
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
|
|
•
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2010.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholder of El Paso Natural Gas Company
We have audited the accompanying consolidated balance sheets of El Paso Natural Gas Company (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule 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. We were not engaged to perform an audit of the Company’s 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Natural Gas Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2011
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
|
2010
|
2009
|
2008
|
|||||||||
|
Operating revenues
|
$ | 517 | $ | 593 | $ | 590 | ||||||
|
Operating expenses
|
||||||||||||
|
Operation and maintenance
|
193 | 202 | 213 | |||||||||
|
Depreciation and amortization
|
88 | 83 | 80 | |||||||||
|
Loss on long-lived assets
|
— | — | 14 | |||||||||
|
Taxes, other than income taxes
|
32 | 29 | 26 | |||||||||
| 313 | 314 | 333 | ||||||||||
|
Operating income
|
204 | 279 | 257 | |||||||||
|
Other income, net
|
3 | 2 | 5 | |||||||||
|
Interest and debt expense
|
(92 | ) | (93 | ) | (90 | ) | ||||||
|
Affiliated interest income, net
|
15 | 19 | 46 | |||||||||
|
Income before income taxes
|
130 | 207 | 218 | |||||||||
|
Income tax expense
|
47 | 79 | 83 | |||||||||
|
Net income
|
$ | 83 | $ | 128 | $ | 135 | ||||||
See accompanying notes.
EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions, except for share amounts)
|
December 31,
|
||||||||
|
|
2010
|
2009
|
||||||
|
ASSETS
|
||||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
$ | — | $ | — | ||||
|
Accounts and note receivable
|
||||||||
|
Customer, net of allowance of $2 in 2010 and 2009
|
4 | 56 | ||||||
|
Affiliates
|
6 | 111 | ||||||
|
Other
|
20 | 3 | ||||||
|
Materials and supplies
|
48 | 47 | ||||||
|
Deferred income taxes
|
9 | 35 | ||||||
|
Prepaids
|
15 | 15 | ||||||
|
Other
|
11 | 11 | ||||||
|
Total current assets
|
113 | 278 | ||||||
|
Property, plant and equipment, at cost
|
3,970 | 3,899 | ||||||
|
Less accumulated depreciation and amortization
|
1,484 | 1,409 | ||||||
|
Total property, plant and equipment, net
|
2,486 | 2,490 | ||||||
|
Other assets
|
||||||||
|
Note receivable from affiliate
|
836 | 886 | ||||||
|
Other
|
110 | 110 | ||||||
| 946 | 996 | |||||||
|
Total assets
|
$ | 3,545 | $ | 3,764 | ||||
|
LIABILITIES AND STOCKHOLDER’S EQUITY
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts payable
|
||||||||
|
Trade
|
$ | 82 | $ | 83 | ||||
|
Affiliates
|
25 | 42 | ||||||
|
Other
|
11 | 14 | ||||||
|
Current maturities of long-term debt
|
— | 54 | ||||||
|
Taxes payable
|
28 | 103 | ||||||
|
Accrued interest
|
18 | 21 | ||||||
|
Accrued liabilities
|
24 | 82 | ||||||
|
Other
|
27 | 47 | ||||||
|
Total current liabilities
|
215 | 446 | ||||||
|
Long-term debt, less current maturities
|
1,113 | 1,113 | ||||||
|
Other liabilities
|
||||||||
|
Deferred income taxes
|
408 | 408 | ||||||
|
Other
|
75 | 71 | ||||||
| 483 | 479 | |||||||
|
Commitments and contingencies (Note 7)
|
||||||||
|
Stockholder’s equity
|
||||||||
|
Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding
|
— | — | ||||||
|
Additional paid-in capital
|
1,268 | 1,268 | ||||||
|
Retained earnings
|
466 | 458 | ||||||
|
Total stockholder’s equity
|
1,734 | 1,726 | ||||||
|
Total liabilities and stockholder’s equity
|
$ | 3,545 | $ | 3,764 | ||||
See accompanying notes.
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
|
2010
|
2009
|
2008
|
|||||||||
|
Cash flows from operating activities
|
||||||||||||
|
Net income
|
$ | 83 | $ | 128 | $ | 135 | ||||||
|
Adjustments to reconcile net income to net cash from operating activities
|
||||||||||||
|
Depreciation and amortization
|
88 | 83 | 80 | |||||||||
|
Deferred income tax expense (benefit)
|
26 | (3 | ) | 14 | ||||||||
|
Loss on long-lived assets
|
— | — | 14 | |||||||||
|
Other non-cash income items
|
22 | (6 | ) | 12 | ||||||||
|
Asset and liability changes
|
||||||||||||
|
Accounts receivable
|
50 | 10 | 3 | |||||||||
|
Change in deferred purchase price from accounts receivable sales
|
(13 | ) | — | — | ||||||||
|
Accounts payable
|
(21 | ) | 55 | (65 | ) | |||||||
|
Taxes payable
|
(66 | ) | 12 | 24 | ||||||||
|
Other current assets
|
(2 | ) | (4 | ) | (13 | ) | ||||||
|
Other current liabilities
|
(103 | ) | 80 | (13 | ) | |||||||
|
Non-current assets
|
(18 | ) | (55 | ) | 56 | |||||||
|
Non-current liabilities
|
5 | 8 | 8 | |||||||||
|
Net cash provided by operating activities
|
51 | 308 | 255 | |||||||||
|
Cash flows from investing activities
|
||||||||||||
|
Capital expenditures
|
(80 | ) | (116 | ) | (186 | ) | ||||||
|
Net change in note receivable from affiliate
|
152 | (3 | ) | 127 | ||||||||
|
Proceeds from disposal of property
|
4 | 14 | — | |||||||||
|
Other
|
2 | (3 | ) | 4 | ||||||||
|
Net cash provided by (used in) investing activities
|
78 | (108 | ) | (55 | ) | |||||||
|
Cash flows from financing activities
|
||||||||||||
|
Dividends paid to parent, net of contribution
|
(75 | ) | (200 | ) | (200 | ) | ||||||
|
Payments to retire long-term debt
|
(54 | ) | — | — | ||||||||
|
Net cash used in financing activities
|
(129 | ) | (200 | ) | (200 | ) | ||||||
|
Net change in cash and cash equivalents
|
— | — | — | |||||||||
|
Cash and cash equivalents
|
||||||||||||
|
Beginning of period
|
— | — | — | |||||||||
|
End of period
|
$ | — | $ | — | $ | — | ||||||
|
Supplemental cash flow information
|
||||||||||||
|
Interest paid, net of amounts capitalized
|
$ | 87 | $ | 88 | $ | 88 | ||||||
|
Income tax payments
|
87 | 71 | 45 | |||||||||
See accompanying notes.
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In millions, except for share amounts)
|
Common Stock
|
Additional | Total | ||||||||||||||||||
|
Shares
|
Amount
|
Paid-in
Capital
|
Retained
Earnings
|
Stockholder’s
Equity
|
||||||||||||||||
|
January 1, 2008
|
1,000 | $ | — | $ | 1,268 | $ | 594 | $ | 1,862 | |||||||||||
|
Net income
|
135 | 135 | ||||||||||||||||||
|
Dividend paid to parent
|
(200 | ) | (200 | ) | ||||||||||||||||
|
Adoption of accounting standard updates related to postretirement benefits, net of income tax of less than $1 (Note 8)
|
1 | 1 | ||||||||||||||||||
|
December 31, 2008
|
1,000 | — | 1,268 | 530 | 1,798 | |||||||||||||||
|
Net income
|
128 | 128 | ||||||||||||||||||
|
Dividend paid to parent
|
(200 | ) | (200 | ) | ||||||||||||||||
|
December 31, 2009
|
1,000 | — | 1,268 | 458 | 1,726 | |||||||||||||||
|
Net income
|
83 | 83 | ||||||||||||||||||
|
Dividend paid to parent, net of contribution
|
(75 | ) | (75 | ) | ||||||||||||||||
|
December 31, 2010
|
1,000 | $ | — | $ | 1,268 | $ | 466 | $ | 1,734 | |||||||||||
See accompanying notes.
EL PASO NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
We are a Delaware corporation incorporated in 1928, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions.
We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
Our natural gas pipelines and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects and other costs included in, or expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Materials and Supplies
We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount to be delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled in cash or in-kind, subject to the terms of our tariff.
Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.
We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we file with the FERC for an increase or decrease in our transportation and storage rates. The majority of our property, plant and equipment are on our El Paso Natural Gas Company (EPNG) system which has depreciation rates ranging from one percent to 50 percent. The depreciation rates on our Mojave Pipeline Company (Mojave) system range from two percent to 33 percent per year.
When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell an entire operating unit, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements.
Included in our property balances are additional acquisition costs, which represent the excess purchase costs associated with purchase business combinations allocated to us. These costs are amortized on a straight-line basis and are not recoverable in our rates under current FERC policies.
We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.
Asset Impairments
We evaluate assets for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows.
During 2008, we recorded impairments of approximately $14 million due to declining real estate values related to our Arizona storage projects, which we are no longer developing.
Revenue Recognition
Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.
Environmental Costs and Other Contingencies
Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.
Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
Income Taxes
El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments.
We record income taxes on a separate return basis. Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.
Accounting for Asset Retirement Obligations
We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.
Postretirement Benefits
We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid under the plan. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded in our income statement and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 8.
In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.
2. Income Taxes
Components of Income Tax Expense. The following table reflects the components of income tax expense included in net income for each of the three years ended December 31:
|
2010
|
2009 | 2008 | ||||||||||
|
(In millions)
|
||||||||||||
|
Current
|
||||||||||||
|
Federal
|
$ | 19 | $ | 72 | $ | 61 | ||||||
|
State
|
2 | 10 | 8 | |||||||||
| 21 | 82 | 69 | ||||||||||
|
Deferred
|
||||||||||||
|
Federal
|
26 | (3 | ) | 12 | ||||||||
|
State
|
— | — | 2 | |||||||||
| 26 | (3 | ) | 14 | |||||||||
|
Total income tax expense
|
$ | 47 | $ | 79 | $ | 83 | ||||||
Effective Tax Rate Reconciliation. Our income tax expense differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions, except for rates)
|
||||||||||||
|
Income tax expense at the statutory federal rate of 35%
|
$ | 46 | $ | 72 | $ | 76 | ||||||
|
State income taxes, net of federal income tax effect
|
1 | 7 | 7 | |||||||||
|
Income tax expense
|
$ | 47 | $ | 79 | $ | 83 | ||||||
|
Effective tax rate
|
36 | % | 38 | % | 38 | % | ||||||
Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Deferred tax liabilities
|
||||||||
|
Property, plant and equipment
|
$ | 483 | $ | 482 | ||||
|
Regulatory and other assets
|
29 | 28 | ||||||
|
Total deferred tax liability
|
512 | 510 | ||||||
|
Deferred tax assets
|
||||||||
|
U.S. net operating loss and tax credit carryovers
|
77 | 77 | ||||||
|
Regulatory and other reserve
|
12 | 33 | ||||||
|
Other liabilities
|
24 | 27 | ||||||
|
Total deferred tax asset
|
113 | 137 | ||||||
|
Net deferred tax liability
|
$ | 399 | $ | 373 | ||||
We believe it is more likely than not that we will realize the benefit of our deferred tax assets due to expected future taxable income, including the effect of future reversals of existing taxable temporary differences primarily related to depreciation.
Tax Credits and Carryovers. As of December 31, 2010, we had approximately $19 million of alternative minimum tax credits that carryover indefinitely. We also have approximately $167 million of net operating loss carryovers that expire between 2021 and 2028. Usage of our carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.
Unrecognized Tax Benefits. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. With a few exceptions, we and El Paso are no longer subject to state and local income tax examinations by tax authorities for years prior to 1999 and U.S. income tax examinations for years prior to 2007. For our open tax years, we have no unrecognized tax benefits.
3. Fair Value of Financial Instruments
At December 31, 2010 and 2009, the carrying amounts of cash and cash equivalents and trade receivables and payables represented fair value because of the short-term nature of these instruments. At December 31, 2010 and 2009, we had an interest bearing note receivable from El Paso of approximately $0.8 billion and $1.0 billion due upon demand, with a variable interest rate of 1.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.
In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:
|
2010
|
2009
|
|||||||||||||||
|
|
Carrying
Amount
|
Fair Value
|
Carrying
Amount
|
Fair Value
|
||||||||||||
|
(In millions)
|
||||||||||||||||
|
Long-term debt, including current maturities
|
$ | 1,113 | $ | 1,258 | $ | 1,167 | $ | 1,300 | ||||||||
4. Regulatory Assets and Liabilities
Our regulatory assets and liabilities are included in other current/non-current assets and liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Current regulatory assets
|
||||||||
|
Difference between gas retained and gas consumed in operations
|
$ | 5 | $ | 7 | ||||
|
Other
|
2 | 3 | ||||||
|
Total current regulatory assets
|
7 | 10 | ||||||
|
Non-current regulatory assets
|
||||||||
|
Taxes on capitalized funds used during construction
|
22 | 24 | ||||||
|
Unamortized loss on reacquired debt
|
21 | 24 | ||||||
|
Postretirement benefits
|
6 | 8 | ||||||
|
Other
|
9 | 9 | ||||||
|
Total non-current regulatory assets
|
58 | 65 | ||||||
|
Total regulatory assets
|
$ | 65 | $ | 75 | ||||
|
Current regulatory liabilities
|
||||||||
|
Property and plant depreciation
|
$ | 1 | $ | 3 | ||||
|
Difference between gas retained and gas consumed in operations
|
5 | 5 | ||||||
|
Other
|
1 | 9 | ||||||
|
Total current regulatory liabilities
|
7 | 17 | ||||||
|
Non-current regulatory liabilities
|
||||||||
|
Property and plant depreciation
|
24 | 30 | ||||||
|
Postretirement benefits
|
17 | 15 | ||||||
|
Other
|
2 | 2 | ||||||
|
Total non-current regulatory liabilities
|
43 | 47 | ||||||
|
Total regulatory liabilities
|
$ | 50 | $ | 64 | ||||
The significant regulatory assets and liabilities include:
Difference Between Gas Retained and Gas Consumed in Operations. These amounts reflect the value of the volumetric difference between the gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers or returned to our customers in subsequent fuel filing periods.
Taxes on Capitalized Funds Used During Construction. Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.
Unamortized Loss on Reacquired Debt. Amount represents the deferred and unamortized portion of losses on reacquired debt which are recovered over the original life of the debt issue through the cost of service.
Postretirement Benefits. Represents unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.
Property and Plant Depreciation. Amounts represent the deferral of customer-funded amounts for costs of future asset retirements.
5. Property, Plant and Equipment
Additional Acquisition Cost. Included in our property balances are additional acquisition costs assigned to utility plant, which represent the excess of allocated purchase costs over the historical costs of the facilities. At December 31, 2010 and 2009, additional acquisition costs assigned to utility plant was approximately $151 million and accumulated depreciation was approximately $99 million and $96 million, respectively. These additional acquisition costs are being amortized on a straight-line basis over a remaining life of 22 years, and are not recoverable in our rates under current FERC policies. Our amortization expense related to additional acquisition cost assigned to utility plant was approximately $2 million for the years ended December 31, 2010, 2009 and 2008.
Capitalized Costs During Construction. Interest costs capitalized were less than $1 million during the years ended December 31, 2010 and 2009 and $1 million during the year ended December 31, 2008. Equity amounts capitalized were $1 million, $1 million and $3 million (exclusive of taxes) during the years ended December 31, 2010, 2009 and 2008.
Construction Work-In-Progress. At December 31, 2010 and 2009, we had $36 million and $63 million of construction work-in-progress included in our property, plant and equipment.
Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipelines, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.
We are required to operate and maintain our natural gas pipelines and storage system, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipelines and storage system assets because these assets have indeterminate lives. Our asset retirement liabilities as of December 31, 2010 and 2009, were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.
6. Debt and Credit Facilities
Debt. Our long-term debt consisted of the following at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
7.625% Notes due August 2010
|
$ | — | $ | 54 | ||||
|
5.95% Notes due April 2017
|
355 | 355 | ||||||
|
8.625% Debentures due January 2022
|
260 | 260 | ||||||
|
7.50% Debentures due November 2026
|
200 | 200 | ||||||
|
8.375% Notes due June 2032
|
300 | 300 | ||||||
| 1,115 | 1,169 | |||||||
|
Less: Current maturities
|
— | 54 | ||||||
|
Unamortized discount
|
2 | 2 | ||||||
|
Total long-term debt
|
$ | 1,113 | $ | 1,113 | ||||
In August 2010, we repaid approximately $54 million of our 7.625% notes that matured.
Credit Facility. We are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2010, El Paso had approximately $0.9 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. Our common stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.
Under El Paso’s $1.5 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; and (vi) potential limitations on our ability to participate in the El Paso’s cash management program. The indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. For the year ended December 31, 2010, we were in compliance with our debt-related covenants.
7. Commitments and Contingencies
Legal Proceedings
Bank of America. We are a named defendant, along with Burlington Resources, Inc. (Burlington), now a subsidiary of ConocoPhillips Company, in a class action lawsuit styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, L.P., filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting royalty underpayment claims related to specified shallow wells in Oklahoma, Texas and New Mexico. The Plaintiffs assert that royalties were underpaid starting in the 1980s when the purchase price of gas was lowered below the Natural Gas Policy Act maximum lawful prices. The Plaintiffs have not alleged an amount of damages against any defendant. We believe that our actions in the 1980s were proper in light of a declining market. We also contend that we are entitled to an indemnity from Burlington under our 1992 separation agreement for all claims related to royalty payments, which Burlington denies. The Plaintiffs assert that royalties were further underpaid by Burlington as a result of post-production cost deductions taken starting in the late 1990s. We have no liability for the post-production claims as they pertain to periods after our separation from Burlington. This action was transferred to Washita County District Court in 2004. A tentative settlement reached in November 2005 was rejected by the court in June 2007. A class certification hearing occurred in April 2009. The court certified a Texas and Oklahoma class of royalty owners and stayed the claims pertaining to New Mexico wells. The class certification has been appealed to the Oklahoma Court of Appeals. The Plaintiffs have proceeded with discovery of the post-production claims against Burlington. Our costs and legal exposure related to this lawsuit are not currently determinable.
In addition to the above proceeding, we and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2010, we had approximately $4 million accrued, which has not been reduced by $4 million of related insurance receivables, for our outstanding legal proceedings.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2010 and 2009, we had accrued approximately $16 million and $19 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $30 million at December 31, 2010. Our accrual at December 31, 2010 includes $15 million for environmental contingencies related to properties we previously owned.
Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for three active sites. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities. Accruals for these issues are included in the environmental reserve discussed above.
For 2011, we estimate that our total remediation expenditures will be approximately $4 million, which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of $3 million in the aggregate for 2011 through 2015, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines, which are subject to regulations with which we have to be in compliance by October 2013.
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Rates and Regulatory Matters
EPNG Rate Case. In April 2010, the FERC approved an uncontested partial offer of settlement which increased our base tariff rates, effective January 1, 2009. As part of the settlement, we made refunds of approximately $76 million, plus interest, in 2010. The settlement resolved all but four issues in the proceeding. In January 2011, the Presiding Administrative Law Judge issued her decision that for the most part found against us on the four issues. We will appeal those decisions to the FERC and may also seek review of any of the FERC’s decisions to the U.S. Court of Appeals. Although the final outcome is not currently determinable, we do not believe our refund exposure is material and we believe our accruals established for this matter are adequate.
In September 2010, we filed a new rate case with the FERC proposing an increase in base tariff rates as permitted under the settlement of the previous rate case. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not currently determinable.
In October 2010, we filed with the FERC to permanently abandon two compressor stations and temporarily idle seven compressor stations along our south mainline system in 2011. This was done to better align our capacity to the current lower level of contract demand resulting from, in part, the weakened economic conditions along this line. Our intent is to bring the idled facilities back into service over the next several years as market demand improves. In our 2011 rate case, we did not seek to earn a return on the original investment in the idled facilities. We will continue to incur related operating costs and depreciation expense until the compressor stations are idled once approved by the FERC. These filings have been protested by certain interveners and the result is uncertain at this time.
Mojave Rate Case. In August 2010, we filed a petition with the FERC to (i) amend our filing requirement previously approved by the FERC and (ii) approve an uncontested rate case settlement that, among other things, would establish new base transportation rates. Under the terms of the agreement, we may not file a new rate case to be effective any earlier than September 1, 2012, but must file a rate case to be effective no later than September 1, 2014. The FERC approved this settlement in October 2010 with an effective date of December 1, 2010.
Other Matter
Tuba City Uranium Milling Facility. For a period of approximately ten years beginning in the mid to late 1950s, Rare Metals Corporation of America, a historical affiliate, conducted uranium mining and milling operations in the vicinity of Tuba City, Arizona, under a contract with the United States government as part of the Cold War nuclear program. The site of the Tuba City uranium mill, which is on land within the Navajo Indian Reservation, reverted to the Navajo Nation after the mill closed in 1966. The tailings at the mill site were encapsulated and a ground water remediation system was installed by the U.S. Department of Energy (DOE) under the Federal Uranium Mill Tailings Radiation Control Act of 1978. In May 2007, we filed suit against the DOE and other federal agencies requesting a judicial determination that the DOE was fully and legally responsible for any remediation of any waste associated with historical uranium production activity at two sites in the vicinity of the mill facilities near Tuba City, Arizona. In March 2009, the United States District Court for the District of Columbia issued an opinion dismissing one of our claims, which has been affirmed by the Court of Appeals for the D.C. Circuit. Also in March 2009, following our close cooperation with the Navajo Nation in joint legislative efforts, President Obama signed the Fiscal Year 2009 Omnibus Appropriations Act, which appropriated $5 million toward the final remediation by the DOE of one of the two sites that are the subject of our lawsuit. The DOE has assigned to the Navajo Nation the obligation to remediate the site. We anticipate that the Navajo Nation will perform the remediation in the near future, and we are continuing to maintain the interim exposure control measures we have installed at the site. Additionally, the EPA and Bureau of Indian Affairs (BIA) have entered into an administrative order of consent, pursuant to which the BIA will conduct a remedial investigation/feasibility study at the second site involved in the lawsuit. Finally, the EPA is currently assessing the environmental condition of all former uranium mines on the Navajo Indian Reservation to determine the need for further environmental response activities. There are approximately 500 abandoned uranium mine sites on the Navajo Indian Reservation, 16 of which were operated by the historical affiliate.
While the outcome of these matters cannot be predicted with certainty, based on current information, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to these matters. The impact of these changes may have a material effect on our results of operations, our financial position, and our cash flows in the periods these events occur.
Other Commitments
Capital Commitments. We have planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2010, were as follows:
|
Year Ending
December 31,
|
(In millions)
|
||||
|
2011
|
$ | 3 | |||
|
2012
|
3 | ||||
|
2013
|
3 | ||||
|
2014
|
3 | ||||
|
2015
|
1 | ||||
|
Thereafter
|
1 | ||||
|
Total
|
$ | 14 | |||
Rental expense for the years ended December 31, 2010, 2009 and 2008 was $23 million, $21 million and $22 million and is reflected in operation and maintenance expense. Included in rental expense is approximately $20 million in each period associated with right-of-way and other arrangements, principally related to a long-term commitment which extends through 2025.
Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems.
Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of financial and performance guarantees that are not recorded in our financial statements. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. During 2010, we terminated our performance guarantees which had a maximum exposure of approximately $11 million.
8. Retirement Benefits
Pension and Retirement Savings Plan. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.
Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, our obligation to accrue for other postretirement employee benefits is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We do not expect to make any contributions to our postretirement benefit plan in 2011.
Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability as allowed by the FERC. These amounts would otherwise be recorded in accumulated other comprehensive income for non-regulated entities.
The table below provides information about our postretirement benefit plan:
|
December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Change in accumulated postretirement benefit obligation:
|
||||||||
|
Accumulated postretirement benefit obligation – beginning of period
|
$ | 47 | $ | 52 | ||||
|
Interest cost
|
2 | 3 | ||||||
|
Actuarial (gain) loss
|
4 | (4 | ) | |||||
|
Benefits paid(1)
|
(3 | ) | (4 | ) | ||||
|
Accumulated postretirement benefit obligation – end of period
|
$ | 50 | $ | 47 | ||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets – beginning period
|
$ | 79 | $ | 71 | ||||
|
Actual return on plan assets
|
9 | 13 | ||||||
|
Benefits paid
|
(4 | ) | (5 | ) | ||||
|
Fair value of plan assets – end of period
|
$ | 84 | $ | 79 | ||||
|
Reconciliation of funded status:
|
||||||||
|
Fair value of plan assets
|
$ | 84 | $ | 79 | ||||
|
Less: accumulated postretirement benefit obligation
|
50 | 47 | ||||||
|
Net asset at December 31
|
$ | 34 | $ | 32 | ||||
____________
(1) Amounts shown net of a subsidy of approximately $1 million for each of the years ended December 31, 2010 and 2009 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.
We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $82 million. As of December 31, 2009, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $77 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawals in certain situations such as market conditions or at the issuer's discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2010 and 2009.
Expected Payment of Future Benefits. As of December 31, 2010, we expect the following benefit payments under our plan:
|
Year Ending
December 31,
|
Expected
Payments(1)
|
||||
|
(In millions)
|
|||||
|
2011
|
$ | 6 | |||
|
2012
|
5 | ||||
|
2013
|
5 | ||||
|
2014
|
5 | ||||
|
2015
|
5 | ||||
|
2016 - 2020
|
19 | ||||
____________
|
(1)
|
Includes a reduction of approximately $1 million in each of the years 2011 – 2015 and approximately $3 million in aggregate for 2016 – 2020 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
|
Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2010, 2009 and 2008:
|
2010
|
2009
|
2008
|
||||||||||
|
(Percent)
|
||||||||||||
|
Assumptions related to benefit obligations at December 31:
|
||||||||||||
|
Discount rate
|
4.53 | 5.14 | 5.90 | |||||||||
|
Assumptions related to benefit costs for the year ended December 31:
|
||||||||||||
|
Discount rate
|
5.14 | 5.90 | 6.05 | |||||||||
|
Expected return on plan assets(1)
|
7.75 | 8.00 | 8.00 | |||||||||
____________
|
(1)
|
The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.
|
Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.4 percent, gradually decreasing to 5.0 percent by the year 2016. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2010 or 2009. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, 2010 and 2009:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
One percentage point increase:
|
||||||||
|
Accumulated postretirement benefit obligation
|
$ | 3 | $ | 3 | ||||
|
One percentage point decrease:
|
||||||||
|
Accumulated postretirement benefit obligation
|
$ | (3 | ) | $ | (3 | ) | ||
Components of Net Benefit Income. For each of the years ended December 31, the components of net benefit income are as follows:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Interest cost
|
$ | 2 | $ | 3 | $ | 4 | ||||||
|
Expected return on plan assets
|
(5 | ) | (5 | ) | (7 | ) | ||||||
|
Amortization of net actuarial gain
|
— | — | (2 | ) | ||||||||
|
Net benefit income
|
$ | (3 | ) | $ | (2 | ) | $ | (5 | ) | |||
9. Transactions with Major Customers
The following table shows revenues from our major customers for each of the three years ended December 31:
|
|
2010(1)
|
2009(1)
|
2008
|
|||||||||
|
(In millions)
|
||||||||||||
|
ConocoPhillips Company
|
$ | 78 | $ | 124 | $ | 82 | ||||||
|
Southern California Gas Company
|
74 | 89 | 85 | |||||||||
|
Southwest Gas Corporation
|
64 | * | * | |||||||||
____________
|
(1)
|
Revenues reflect rates subject to refund.
|
|
*
|
Less than 10% of operating revenues.
|
10. Accounts Receivable Sales Program
In the first quarter of 2010, we entered into an accounts receivable sales program to sell accounts receivable to a third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. Under this program, we sell receivables in their entirety to a third party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third-party financial institution held $42 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $528 million of accounts receivable to the third party financial institution, for which we received approximately $335 million of cash up front and had a deferred purchase price of approximately $193 million. We received approximately $180 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $13 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets). We recognized a loss of less than $1 million on our accounts receivable sales for the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales programs as operating cash flows on our statement of cash flows.
Under the accounts receivable sales program, we service the underlying receivables for a fee. The fair value of this servicing agreement as well as the fees earned were not material to our financial statements for the year ended December 31, 2010.
The third party financial institution involved in this accounts receivable sales program acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.
11. Transactions with Affiliates
Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2010 and 2009, we had a note receivable from El Paso of approximately $0.8 billion and $1.0 billion. At December 31, 2010, we have classified this note receivable as noncurrent on our balance sheet as we do not anticipate using it in the next twelve months considering our available cash sources and needs. The interest rate on this variable rate note at December 31, 2010 and 2009 was 1.5%. During 2010 and 2009, we utilized $75 million, net of a $50 million cash contribution from our parent, and $200 million of our note receivable from the cash management program to pay dividends to our parent.
Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At December 31, 2010 and 2009, we had income taxes payable of $24 million and $90 million. The majority of these balances, as well as our deferred income taxes, will become payable to El Paso. See Note 1 for a discussion of our income tax policy.
Other Affiliate Balances. At both December 31, 2010 and 2009, we had contractual deposits from our affiliates of $9 million and $8 million included in other current liabilities on our balance sheets.
Affiliate Revenues and Expenses. We provide natural gas transportation services to an affiliate under long-term contracts. We entered into these contracts within the ordinary course of business and the services are based on the same terms as non-affiliates.
El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are also allocated costs from Tennessee Gas Pipeline Company (TGP), our affiliate, associated with our pipeline services. We also allocate costs to Colorado Interstate Gas Company, our affiliate, for its share of our pipeline services. The allocations from El Paso and TGP are based on the estimated level of effort devoted to our operations and the relative size of our earnings before interest expense and income taxes, gross property and payroll.
The following table shows overall revenues, expenses and reimbursements from our affiliates for each of the three years ended December 31:
| 2010 | 2009 | 2008 | ||||||||||
|
(In millions)
|
||||||||||||
|
Revenues
|
$ | 19 | $ | 20 | $ | 17 | ||||||
|
Operation and maintenance expenses
|
72 | 62 | 56 | |||||||||
|
Reimbursements of operating expenses
|
11 | 25 | 21 | |||||||||
12. Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.
|
|
Quarters Ended
|
|
||||||||||||||||||
|
|
March 31
|
June 30
|
September 30
|
December 31
|
Total
|
|||||||||||||||
|
(In millions)
|
||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Operating revenues
|
$ | 145 | $ | 126 | $ | 122 | $ | 124 | $ | 517 | ||||||||||
|
Operating income
|
72 | 49 | 43 | 40 | 204 | |||||||||||||||
|
Net income
|
32 | 19 | 15 | 17 | 83 | |||||||||||||||
|
2009
|
||||||||||||||||||||
|
Operating revenues
|
$ | 157 | $ | 144 | $ | 145 | $ | 147 | $ | 593 | ||||||||||
|
Operating income
|
81 | 67 | 66 | 65 | 279 | |||||||||||||||
|
Net income
|
40 | 30 | 30 | 28 | 128 | |||||||||||||||
SCHEDULE II
EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
(In millions)
|
Description
|
Balance at
Beginning
of Period
|
Charged to
Costs and
Expenses
|
Deductions
|
Balance at
End of
Period
|
||||||||||||
|
2010
|
||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 2 | $ | — | $ | — | $ | 2 | ||||||||
|
Legal reserves
|
2 | 5 | (3 | ) | 4 | |||||||||||
|
Environmental reserves
|
19 | (1 | ) | (2 | ) | 16 | ||||||||||
|
Regulatory reserves(1)
|
74 | 21 | (76 | ) | 19 | |||||||||||
|
2009
|
||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 2 | $ | — | $ | — | $ | 2 | ||||||||
|
Legal reserves
|
6 | 4 | (8 | ) | 2 | |||||||||||
|
Environmental reserves
|
22 | 1 | (4 | ) | 19 | |||||||||||
|
Regulatory reserves(1)
|
— | 74 | — | 74 | ||||||||||||
|
2008
|
||||||||||||||||
|
Allowance for doubtful accounts
|
$ | 4 | $ | (2 | ) | $ | — | $ | 2 | |||||||
|
Legal reserves
|
4 | 8 | (6 | ) | 6 | |||||||||||
|
Environmental reserves
|
25 | 1 | (4 | ) | 22 | |||||||||||
|
Regulatory reserves
|
10 | — | (10 | ) | — | |||||||||||
____________
|
(1)
|
See Financial Statements and Supplementary Data Note 7 for EPNG’s rate case discussion.
|
None.
Evaluation of Disclosure Controls and Procedures
As of December 31, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) were effective as of December 31, 2010. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
None.
Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
Audit Fees
The audit fees for the years ended December 31, 2010 and 2009 of $982,000 and $796,000, respectively, were primarily for professional services rendered by Ernst & Young LLP and for the audits of the consolidated financial statements of El Paso Natural Gas Company and its subsidiaries as well as the review of documents filed with the SEC and related consents.
All Other Fees
No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2010 and 2009.
Policy for Approval of Audit and Non-Audit Fees
We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2011 Annual Meeting of Stockholders.
|
(a)
|
The following documents are filed as a part of this report:
|
1. Financial statements
The following consolidated financial statements are included in Part II, Item 8 of this report:
|
Page
|
|
|
Report of Independent Registered Public Accounting Firm
|
22
|
|
Consolidated Statements of Income
|
23
|
|
Consolidated Balance Sheets
|
24
|
|
Consolidated Statements of Cash Flows
|
25
|
|
Consolidated Statements of Stockholder’s Equity
|
26
|
|
Notes to Consolidated Financial Statements
|
27
|
|
2. Financial statement schedules
|
|
|
Schedule II — Valuation and Qualifying Accounts
|
43
|
All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. Exhibits
The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
|
•
|
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
|
|
•
|
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
|
|
•
|
may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
|
|
•
|
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
|
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
Undertaking
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28th day of February 2011.
| EL PASO NATURAL GAS COMPANY | |||
|
|
|||
|
|
By:
|
/s/ James J. Cleary | |
| James J. Cleary | |||
| President | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of El Paso Natural Gas Company and in the capacities and on the dates indicated:
|
Signature
|
Title
|
Date
|
||
|
|
||||
|
/s/ James J. Cleary
|
President and Director
|
February 28, 2011
|
||
|
James J. Cleary
|
(Principal Executive Officer)
|
|||
|
/s/ John R. Sult
|
Executive Vice President and Chief Financial Officer
|
February 28, 2011
|
||
|
John R. Sult
|
(Principal Financial Officer)
|
|||
|
|
||||
| /s/ Rosa P. Jackson |
Vice President and Controller
|
February 28, 2011
|
||
|
Rosa P. Jackson
|
(Principal Accounting Officer)
|
|||
|
|
||||
|
/s/ James C. Yardley
|
Chairman of the Board and Director
|
February 28, 2011
|
||
|
James C. Yardley
|
||||
|
|
||||
|
/s/ Daniel B. Martin
|
Director
|
February 28, 2011
|
||
|
Daniel B. Martin
|
||||
|
|
||||
|
/s/ Robert L. Perez
|
Director
|
February 28, 2011
|
||
|
Robert L. Perez
|
||||
EL PASO NATURAL GAS COMPANY
EXHIBIT INDEX
December 31, 2010
Each exhibit identified below is filed as part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
|
Exhibit
Number
|
Description
|
|
3.A
|
Restated Certificate of Incorporation dated April 8, 2003 (incorporated by reference to Exhibit 3.A to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
|
|
3.B
|
By-laws dated June 2, 2008 (incorporated by reference to Exhibit 3.B to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
|
|
4.A
|
Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.), as Trustee (incorporated by reference to Exhibit 4.A to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
4.B
|
Indenture dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.B to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
4.C
|
Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee (incorporated by reference to Exhibit 4.C to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
|
|
4.D
|
First Supplemental Indenture dated as of June 10, 2002 between El Paso Natural Gas Company and Wilmington Trust Company (as successor in interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, to indenture dated November 13, 1996 (incorporated by reference to Exhibit 4.D to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
|
|
4.E
|
Second Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee, to indenture dated November 13, 1996 (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
|
|
4.F
|
First Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as trustee, to indenture dated as of July 23, 2003 (incorporated by reference to Exhibit 4.C to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
|
|
4.G
|
Form of 5.95% Senior Note due 2017 (included in Exhibit 4.E).
|
|
10.A
|
Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.A to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
10.B
|
Third Amendment and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (incorporated by reference to Exhibit 4.A to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
10.C
|
Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (incorporated by reference to Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007.)
|
|
21
|
Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
|
|
*23
|
Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.
|
|
*31.A
|
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
*31.B
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
*32.A
|
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
*32.B
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
49