ITEM 1. BUSINESS
GENERAL
We are a Delaware corporation incorporated in 1928, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business is the interstate transportation of natural gas. We conduct our business activities through two pipeline systems, each of which is discussed below.
The EPNG system. The El Paso Natural Gas system consists of approximately 10,600 miles of pipeline with a winter sustainable west-flow capacity of 4,650 MMcf/d (including 120 MMcf/d related to our Phase I Line 2000 Power-up expansion which went into service on February 27, 2004) and approximately 800 MMcf/d of east-end deliverability. EPNG is currently expanding its Line 2000 system which extends from West Texas to the Arizona and California border and is expected to increase capacity by an additional 200 MMcf/d by mid-2004. During 2003, 2002 and 2001, average throughput on the EPNG system was 3,874 BBtu/d, 3,799 BBtu/d and 4,253 BBtu/d. This system delivers natural gas from the San Juan, Permian and Anadarko Basins to California, which is our single largest market, as well as markets in Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.
The Mojave system. The Mojave Pipeline system consists of approximately 400 miles of pipeline with a design capacity of approximately 400 MMcf/d. During 2003, 2002 and 2001, average throughput on the Mojave system was 192 BBtu/d, 266 BBtu/d and 283 BBtu/d. This system connects with the EPNG and Transwestern transmission systems at Topock, Arizona, the Kern River Gas Transmission Company transmission system in California and extends to customers in the vicinity of Bakersfield, California.
REGULATORY ENVIRONMENT
Our interstate natural gas transmission systems are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Our systems operate under FERC-approved tariffs that establish rates, terms and conditions for service to our customers. Generally, the FERC's authority extends to:
- rates and charges for natural gas transportation;
- certification and construction of new facilities;
- extension or abandonment of facilities;
- maintenance of accounts and records;
- relationships between pipeline and energy affiliates;
- terms and conditions of services;
- depreciation and amortization policies;
- acquisition and disposition of facilities; and
- initiation and discontinuation of services.
The fees or rates established under our tariffs are a function of our costs of providing service to our customers, including a reasonable return on our invested capital. Approximately 93 percent of our transportation services revenue is attributable to a capacity reservation (demand charge) paid by firm customers. These firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they transport, for the term of their contracts. The remaining 7 percent of our transportation services revenue is attributable to charges based solely on the volumes of gas actually transported on our pipeline systems. Consequently, our financial results have historically been relatively stable; however, they can
be subject to volatility due to factors such as weather, changes in natural gas prices and market conditions, regulatory actions, competition and the credit-worthiness of our customers.
Our interstate pipeline systems are also subject to federal, state and local pipeline safety and environmental statutes and regulations. We have continuing programs designed to keep all of our facilities in compliance with pipeline safety and environmental requirements. We believe that our systems are in material compliance with the applicable requirements.
A discussion of significant rate and regulatory matters is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 10, and is incorporated herein by reference.
MARKETS AND COMPETITION
We serve major markets in the southwestern United States and California as well as northern Mexico. These have recently been among the fastest growing regions in the U.S. and Mexico; therefore the market demand for natural gas distribution as well as gas-fired electric generation capacity has experienced considerable growth. While this demand growth has slowed somewhat from the levels in 2000-2002, we expect it to continue at a slower rate. Our markets consist of distribution and industrial companies, electric generation companies, natural gas producers, other interstate and intrastate natural gas pipelines, and natural gas marketing and trading companies. We provide transportation services in both our natural gas supply and market areas. Our pipeline systems connect with multiple pipelines that provide our shippers with access to diverse sources of supply and various natural gas markets serviced by these pipelines.
The combined capacity of all pipeline companies serving the California market is approximately 8.5 Bcf/d and we provide approximately 39 percent of this capacity. In 2003, the demand for interstate pipeline capacity to California averaged 4.9 Bcf/d, equivalent to approximately 57 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California across our system represented approximately 28 percent of the natural gas consumed in the state in 2003.
A number of large natural gas consumers are electric utility companies who use natural gas to fuel electric power generation facilities. Electric power generation is the fastest growing demand sector of the natural gas market. The potential consequences of proposed and ongoing restructuring and deregulation of the electric power industry are currently unclear. Restructuring and deregulation potentially benefit the natural gas
industry by creating more demand for natural gas turbine generated electric power, but this effect is offset, in varying degrees, by increased efficiency in generation and the use of surplus electric capacity as a result of open market access.
Our existing contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or re-market expiring capacity at maximum rates 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 re-negotiated contracts will be affected by current prices, competitive conditions and judgments concerning future trends and volatility.
ENVIRONMENTAL
A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 10, and is incorporated herein by reference.
EMPLOYEES
As of March 9, 2004, we had approximately 740 full-time employees, none of whom are subject to collective bargaining arrangements.
ITEM 2.
ITEM 2. PROPERTIES
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 businesses, 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 businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The fifteen California cases discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 10, include five filed in the Superior Court of Los Angeles County (Continental Forge Company, et al. v. Southern California Gas Company, et al., filed September 25, 2000*; Berg v. Southern California Gas Company, et al., filed December 18, 2000*; County of Los Angeles v. Southern California Gas Company, et al., filed January 8, 2002**; The City of Los Angeles, et al. v. Southern California Gas Company, et al. and The City of Long Beach, et al. v. Southern California Gas Company, et al., both filed March 20, 2001*); two filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso Merchant Energy; and John Phillip v. El Paso Merchant Energy, both filed December 13, 2000*); and two filed in the Superior Court of San Francisco County (Sweetie's et al. v. El Paso Corporation, et al., filed March 22, 2001*; and California Dairies, Inc., et al. v. El Paso Corporation, et al., filed May 21, 2001***); and one filed in the Superior Court of the State of California, County of Alameda (Dry Creek Corporation v. El Paso Natural Gas Company, et al. filed December 10, 2001**); and six filed in the Superior Court of Los Angeles County (The City of San Bernardino v. Southern California Gas Company, et al.; The City of Vernon v. Southern California Gas Company; The City of Upland v. Southern California Gas Company, et al.; Edgington Oil Company v. Southern California Gas Company, et al.; World Oil Corp. v. Southern California Gas Company, et al., filed December 27, 2002**; The City of Culver City v. Southern California Gas, et al., filed April 11, 2002); The State of Nevada et al v. El Paso Corporation, El Paso Natural Gas Company, et. al. filed November 2002 in the District Court for Clark County, Nevada**; Gus N. Bustamante v. The McGraw-Hill Companies filed in the Superior Court of California, County of Los Angeles in November 2002**. - --------------- * We have been dismissed from these cases and judgment has been entered. An appeal of that judgment is pending. ** Cases to be dismissed in conjunction with final approval of the Western Energy Settlement. *** We have been dismissed from this case in a settlement separate from the Western Energy Settlement.
More details on the above cases, and a description of our other legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 10, and is incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
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. In 2002, we declared and paid to El Paso a non-cash dividend of non-regulated assets in the amount of $19 million. There were no common stock dividends declared during 2003.
During late 2003 and early 2004, El Paso issued a total of 26.4 million shares of common stock pursuant to the Western Energy Settlement (WES). A discussion of the WES is included in Item 8, Financial Statements and Supplementary Data, Notes 3 and 10. El Paso contributed to us gross proceeds of approximately $195 million from the sales of its common stock, which we in turn funded to an escrow account for the benefit of the settling parties in the WES.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. The notes to our consolidated financial statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies.
GENERAL
Our business is the interstate transportation of natural gas. Our interstate natural gas transportation systems face varying degrees of competition from other pipelines, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, nuclear, coal and fuel oil. We are regulated by the FERC which regulates the rates we can charge our customers. These rates are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. As a result, our financial results have historically been relatively stable; however, they can be subject to volatility due to factors such as weather, changes in natural gas prices and market conditions, regulatory actions, competition and the credit-worthiness of our customers. In addition, our ability to extend our existing customer contracts or re-market expiring contracted capacity at maximum rates is dependent on competitive alternatives, the regulatory environment and supply and demand factors at the relevant dates these contracts are extended or expire.
RESULTS OF OPERATIONS
Our management, as well as El Paso's management, uses earnings before interest and income taxes (EBIT) to assess the operating results and effectiveness of our business. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, such as the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that our management can evaluate our operating results without regard to our financing methods. We believe the discussion of our results of operations based on EBIT is useful to our investors because it allows them to more effectively evaluate the operating performance of our business using the same performance measure analyzed internally by our management. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. The following is a reconciliation of our operating income to our EBIT and our EBIT to our net income for the years ended December 31:
OPERATING RESULTS (EBIT)
Our EBIT for the year ended December 31, 2003 was $252 million higher than in 2002. The increase in EBIT was primarily the result of a decrease in operating expenses due to a net decrease of $272 million in Western Energy Settlement charges incurred in 2003 as compared to 2002. For a further discussion of the Western Energy Settlement, see Item 8, Financial Statements and Supplementary Data, Notes 3 and 10. In addition, our EBIT in 2003 was higher due to bad debt expense in 2002 of $12 million related to the bankruptcy of Enron Corp. and reduced corporate and legal charges of $8 million in 2003. Our EBIT results were negatively impacted by a decrease of $35 million in operating revenues in 2003 related to the expiration of capacity contracts which we were prohibited from remarketing due to various FERC orders and obligations to make capacity available to our former full requirement customers until our Line 2000 Power-up project is phased-in during 2004. Each of the capacity related items discussed below had no impact on our operating expenses in 2003. Property additions in 2003 resulted in higher depreciation expense and ad valorem taxes of $8 million and higher other income from allowances for equity funds used during construction in 2003 of $7 million. We also had higher expenses related to natural gas used in operations in excess of amounts recovered from customers of $11 million resulting in a negative impact on our 2003 EBIT.
As discussed above and in Item 8, Financial Statements and Supplementary Data, Note 10, the FERC issued various orders related to the allocation of capacity on our EPNG system. These orders impacted our 2003 revenues and will continue to impact our future results. Based on these orders:
- Reservation charges will be credited to our firm shippers if we fail to schedule the shipper's confirmed volumes (except in the case of force majeure, in which case partial credits will be given);
- We must refrain from entering into any new contracts unless we can demonstrate that we have capacity available to provide the new service;
- We refrained from remarketing turned-back capacity under contracts terminating or expiring between May 31, 2002 and May 1, 2003, because that capacity was allocated to our full requirement (FR) shippers; and
- We are adding additional compression to our Line 2000 project increasing the capacity by 320 MMcf/d without the opportunity to recover these costs in our rates until our next rate case which will be effective January 1, 2006.
As a result, we were unable to remarket approximately 471 MMDth/d of turned-back capacity, of which approximately 200 MMDth/d relates to capacity rejected by Enron Corp. in May 2002 in its bankruptcy proceeding and the remaining 271 MMDth/d relates to contracts that expired within the time frame specified under these orders. By order, this 471 MMDth/d of capacity was made available to converting full requirement shippers without an increase in their reservation charge obligation until January 1, 2006. At that time, we will seek to recover these costs by adjusting our rates. Prior to the rejection and expiration of this capacity, we were earning revenues on this capacity (net of revenue credits) of approximately $3.5 million per month.
In July 2003, the FERC (i) reaffirmed its decision that our full requirements contracts must be converted to contract demand contracts effective September 1, 2003, (ii) supported our position relative to the maximum amount of capacity we can make available to our shippers and (iii) confirmed that we have honored our obligations under our existing rate settlement, our contracts, the FERC's regulations and our certificates. We were required to establish a pool of 110 MMcf/d for use by our full requirement shippers until our Line 2000 expansion project is phased into service which is expected to occur by the end of the first quarter of 2004. Effective September 1, 2003, we acquired this capacity, primarily on a permanent basis, and will be at risk for remarketing this capacity. We estimate this will reduce our revenues for the first six months of 2004 by approximately $3.9 million as compared to the first six months of 2003.
In addition, we had risk sharing mechanisms under our most recent rate case settlement. This risk sharing period expired on December 31, 2003. Under these risk sharing mechanisms, we collected cash from our customers, refunded a portion of the cash received as required by the mechanisms and then recognized the difference as revenues over the risk sharing period. We estimate that the expiration of the risk sharing mechanisms will decrease our annual revenues by approximately $22 million. See Item 8, Financial Statements and Supplementary Data, Note 10, for a further discussion of our risk sharing mechanisms.
INTEREST AND DEBT EXPENSE
Interest and debt expense for the year ended December 31, 2003, was $18 million higher than in 2002. The increase in interest expense resulted from the issuances of $300 million of long-term 8.375% notes in June 2002 and $355 million of long-term 7.625% notes in July 2003, and decreases in interest capitalized on construction projects due to a lower capitalization base in 2003. These increases were partially offset by decreases in commercial paper interest expense due to the discontinuation of commercial paper borrowings in the fourth quarter of 2002.
AFFILIATED INTEREST INCOME
Affiliated interest income for the year ended December 31, 2003, was $2 million lower than in 2002 due to lower average advances to El Paso under the cash management program in 2003 offset by higher short-term rates in 2003 on which we earned interest. The average advance balance due from El Paso of $1.2 billion in 2002 decreased to $996 million in 2003. The average short-term interest rates increased from 1.9% in 2002 to 2% in 2003.
INCOME TAXES
Our effective tax rates were different than the statutory rate of 35 percent in all periods, primarily due to state income taxes. For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 6.
Included in our deferred tax assets as of December 31, 2003 was $200 million related to the Western Energy Settlement. Proposed tax legislation has been introduced in the U.S. Senate which would disallow deductions for certain settlements made to or on behalf of governmental entities. If enacted, this tax legislation could impact the deductibility of the Western Energy Settlement and could result in a write-off of some or all of the associated deferred tax assets. In such event, our tax expense would increase.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
Our liquidity needs have been provided by cash flow from operating activities and the use of El Paso's cash management program. Under El Paso's cash management program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso or El Paso provides cash to us. We have historically provided cash advances to El Paso, and we reflect these net advances to our parent as investing activities in our statement of cash flows. As of December 31, 2003, we had receivables from El Paso of $779 million as a result of this program. These receivables are due upon demand; however, we do not anticipate settlement within twelve months. As of December 31, 2003 these receivables were classified as non-current notes receivable from affiliates in our balance sheet. We believe that cash flows from operating activities will be adequate to meet our short-term capital and debt servicing requirements for existing operations. However, as a result of recent announcements by El Paso related to a revision of its estimates of its natural gas and oil reserves, our ability to borrow or recover the amounts advanced under El Paso's cash management program could be impacted. See Item 8, Financial Statements and Supplementary Data, Note 2 for a discussion of these matters. Our cash flows for the years ended December 31 were as follows:
In a series of credit rating agency actions beginning in 2002, and contemporaneously with the downgrades of the senior unsecured indebtedness of El Paso, our senior unsecured indebtedness was downgraded to below investment grade and is currently rated B1 by Moody's (with a negative outlook and under review for a
possible downgrade) and B- by Standard & Poor's (with a negative outlook). These downgrades will increase our cost of capital and collateral requirements and could impede our access to capital markets in the future.
CAPITAL EXPENDITURES
Our capital expenditures during the periods indicated are listed below:
Under our current plan, we expect to spend between approximately $120 million and $175 million in each of the next three years for capital expenditures to maintain the integrity of our pipelines and ensure the reliable delivery of natural gas to our customers. In addition, we have budgeted to spend between approximately $10 million and $70 million in each of the next three years to expand the capacity of our pipeline systems contingent upon customer commitments to the projects. We expect to fund our maintenance and expansion capital expenditures using a combination of internally generated funds and external financing.
DEBT
As of December 31, 2003, we had long-term debt outstanding of $1,109 million, net of a $6 million discount, none of which matures within the next five years. For a discussion of our debt and other credit facilities, see Item 8, Financial Statements and Supplementary Data, Note 9, which is incorporated herein by reference.
COMMITMENTS AND CONTINGENCIES
For a discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 10, which is incorporated herein by reference.
NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED
As of December 31, 2003, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. Based on our assessment of those standards, we do not believe there are any that could have a material impact on us.
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management 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 statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate," "plan," "budget" and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.
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 forward-looking statement made by us or on our behalf.
RISKS RELATED TO OUR BUSINESS
OUR SUCCESS DEPENDS ON FACTORS BEYOND OUR CONTROL.
Our business is the transportation of natural gas for third parties. As a result, the volume of natural gas involved in these activities depends on the actions of those third parties, and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current transmission volumes and rates, to renegotiate existing contracts as they expire, or to remarket unsubscribed capacity:
- future weather conditions, including those that favor alternative energy sources such as hydroelectric power;
- price competition;
- drilling activity and supply availability of natural gas;
- expiration and/or turn back of significant contracts;
- service area competition;
- changes in regulation and actions of regulatory bodies;
- credit risk of our customer base;
- increased cost of capital;
- opposition to energy infrastructure development, especially in environmentally sensitive areas;
- adverse general economic conditions;
- expiration and/or renewal of existing interests in real property associated with our pipeline; and
- unfavorable movements in natural gas and liquids prices.
THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST BE RENEGOTIATED PERIODICALLY.
Our revenues are generated under transportation contracts which expire periodically and must be renegotiated and extended or replaced. We cannot assure that we will be able to extend or replace our contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts. For example, Southern California Gas Company, our largest customer, filed a proposal in January 2004 with the California Public Utilities Commission asking for permission to give notice to terminate certain of its transportation agreements with us by February 25, 2005, with the intent of negotiating to reduce their capacity holdings on our pipeline system as part of an effort to diversify their capacity holdings. The outcome of this proceeding is uncertain at this time. For a further discussion of these matters, see Part I, Item 1, Business -- Markets and Competition.
In particular, our ability to extend and/or replace transportation contracts could be adversely affected by factors we cannot control, including:
- competition by other pipelines, including the proposed construction by other companies of additional pipeline capacity or LNG terminals in markets served by us;
- changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;
- reduced demand and market conditions in the areas we serve;
- the availability of alternative energy sources or gas supply points; and
- regulatory actions.
If we are unable to renew, extend or replace these contracts or if we renew them on less favorable terms, we may suffer a material reduction in our revenues and earnings.
FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.
Revenues generated by our contracts depend on volumes and rates, both of which can be affected by the prices of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, such as power companies who, depending on the price of fuel, may not dispatch gas fired power plants. Increased prices could also result from industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies' loss of customer base. The success of our operations is subject to continued development of additional oil and natural gas reserves in the vicinity of our facilities and our ability to access additional suppliers from interconnecting pipelines to offset the natural decline from existing wells connected to our systems. A decline in energy prices could precipitate a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission on our system. If natural gas prices in the supply basins connected to our pipeline systems are higher on a delivered basis to our off-system markets than delivered prices from other natural gas producing regions, our ability to compete with other transporters may be negatively impacted. Fluctuations in energy prices are caused by a number of factors, including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation facilities;
- energy legislation;
- federal and state taxes, if any, on the transportation of natural gas;
- abundance of supplies of alternative energy sources; and
- political unrest among oil-producing countries.
THE AGENCIES THAT REGULATE US AND OUR CUSTOMERS AFFECT OUR PROFITABILITY.
Our pipeline businesses are regulated by the FERC, the U.S. Department of Transportation, and various state and local regulatory agencies. Regulatory actions taken by those agencies have the potential to adversely
affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services. If our tariff rates were reduced in a future rate proceeding, if our volume of business under our currently permitted rates was decreased significantly or if we were required to substantially discount the rates for our services because of competition, our profitability and liquidity could be reduced.
Further, state agencies and local governments that regulate our local distribution company customers could impose requirements that could impact demand for our services.
COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR ESTIMATES.
Our operations are subject to various environmental laws and regulations. These laws and regulations obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. We are also party to legal proceedings involving environmental matters pending in various courts and agencies.
It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:
- the uncertainties in estimating clean up costs;
- the discovery of new sites or information;
- the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;
- the nature of environmental laws and regulations; and
- the possible introduction of future environmental laws and regulations.
Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, and these amounts could be material. For additional information, see Item 8, Financial Statements and Supplementary Data, Note 10.
WE FACE UNCERTAINTY RELATED TO EXPIRING REAL PROPERTY INTERESTS RELATED TO OUR PIPELINE.
Nearly 900 miles of the north mainline of our pipeline system are currently located on property inside the Navajo Nation. We currently pay approximately $2.3 million per year for the real property interests, such as easements, leases and rights-of-way, located on Navajo Nation trust lands. These real property interests are scheduled to expire in October 2005. We are beginning negotiations with the Navajo Nation to renew these interests. The outcome of this process is uncertain but we may incur future costs arising from potential litigation or increased right-of-way fees.
OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.
Our operations are subject to the inherent risks normally associated with those operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires and adverse weather conditions, and other hazards, each of which could result in damage to or destruction of our facilities or damages to persons and property. In addition, our operations face possible risks associated with acts of aggression on our assets. If any of these events were to occur, we could suffer substantial losses.
While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.
ONE CUSTOMER CONTRACTS FOR A SUBSTANTIAL PORTION OF OUR FIRM TRANSPORTATION CAPACITY.
For 2003, contracts with Southern California Gas Company were substantial. For additional information on our contracts with Southern California Gas Company, see Part I, Item 1, Business -- Markets and
Competition and Part II, Item 8, Financial Statements and Supplementary Data, Note 14. The loss of this customer or a decline in its credit-worthiness could adversely affect our results of operations, financial position and cash flow.
ONGOING LITIGATION AND INVESTIGATIONS REGARDING US AND EL PASO COULD SIGNIFICANTLY ADVERSELY AFFECT OUR BUSINESS.
A listing of legal proceedings is included in Part I, Item 3, Legal Proceedings. A description of our legal proceedings and investigations is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 10.
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 incorporated by reference herein.
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 could adversely affect our financial condition, even if we have not suffered any similar development. The senior unsecured indebtedness of El Paso has been downgraded to below investment grade, currently rated Caa1 by Moody's (with a negative outlook and under review for a possible downgrade) and CCC+ by Standard & Poor's (with a negative outlook). Our senior unsecured indebtedness is rated B1 by Moody's (with a negative outlook and under review for a possible downgrade) and B- by Standard & Poor's (with a negative outlook). These downgrades will increase our cost of capital and collateral requirements, and could impede our access to capital markets. As a result of these downgrades, El Paso has realized substantial demands on its liquidity. These downgrades are a result, at least in part, of the outlook generally for the consolidated businesses of El Paso and its needs for liquidity.
El Paso has embarked on its 2003 Long-Range Plan that, among other things, defines, El Paso's future businesses, targets significant debt reduction and establishes financial goals. An inability to meet these objectives could adversely affect El Paso's liquidity position, and in turn affect our financial condition.
Pursuant to El Paso's cash management program, surplus cash is made available to El Paso in exchange for an affiliated receivable. In addition, we conduct commercial transactions with some of our affiliates. As of December 31, 2003, we have net receivables of approximately $770 million from El Paso and its affiliates. El Paso provides cash management and other corporate services for us. If El Paso is unable to meet its liquidity needs, there can be no assurance that we will be able to access cash under the cash management program, or that our affiliates would pay their obligations to us. However, we might still be required to satisfy affiliated company payables. Our inability to recover any intercompany receivables owed to us could adversely affect our ability to repay our outstanding indebtedness. For a further discussion of these matters, see Item 8, Financial Statements and Supplementary Data, Note 13.
Furthermore, in February 2004, El Paso announced that it had completed a review of its estimates of natural gas and oil reserves. As a result of this review, El Paso announced that it was reducing its proved natural gas and oil reserves by approximately 1.8 Tcfe. El Paso also announced that this reserve revision would result in a 2003 charge of approximately $1 billion if the full impact of the revision was taken in that period. In March 2004, El Paso provided an update and stated that the revisions would likely result in a restatement of its historical financial statements, the timing and magnitude of which are still being determined. El Paso has retained a law firm to conduct an internal investigation, which is ongoing. Also, as a result of the reduction in reserve estimates, several class action suits have been filed against El Paso and several of its subsidiaries, but not against us. The reduction in reserve estimates may also become the subject of an SEC investigation or
separate inquiries by other governmental regulatory agencies. These investigations and lawsuits may further negatively impact El Paso's credit ratings and place further demands on its liquidity. See Item 8, Financial Statements and Supplementary Data, Note 2 for a further discussion of the possible impacts of this announcement.
WE MAY BE SUBJECT TO A CHANGE OF CONTROL UNDER CERTAIN CIRCUMSTANCES.
One of our subsidiaries is one of many subsidiary guarantors of El Paso's $3 billion revolving credit facility. In connection with its guarantee of the $3 billion revolving credit facility, the subsidiary pledged as collateral its ownership of Mojave Pipeline, its sole asset. In addition, in connection with its guarantee of El Paso's $3 billion revolving credit facility, our direct parent, El Paso EPNG Investments, L.L.C. pledged as collateral its equity interests in us. As a result, our ownership is subject to change if El Paso's lenders under the $3 billion revolving credit facility exercise rights over their collateral. El Paso EPNG Investments' equity in us and our ownership of the above-referenced subsidiary also collateralizes approximately $1 billion of other financing arrangements, including leases, letters of credit and other facilities.
A DEFAULT UNDER EL PASO'S $3 BILLION REVOLVING CREDIT FACILITY BY ANY PARTY COULD ACCELERATE OUR FUTURE BORROWINGS, IF ANY, UNDER THE FACILITY AND OUR LONG-TERM DEBT, WHICH COULD ADVERSELY AFFECT OUR LIQUIDITY POSITION.
We are a party to El Paso's $3 billion revolving credit facility. We are only liable, however, for our borrowings under the facility, which were zero as of December 31, 2003. Under the facility, a default by El Paso, or any other party, could result in the acceleration of all outstanding borrowings under the facility, including the borrowings of any non-defaulting party. El Paso's revisions to its reserve estimates would likely result in a restatement of its historical financial statements. Any such material restatement would result in an event of default under El Paso's revolving credit facility, which could result in the acceleration of any outstanding borrowings by El Paso, and would preclude us from borrowing under the facility in the future. The acceleration of our future borrowings, if any, under the credit facility, or the inability to borrow under the credit facility, could adversely affect our liquidity position and, in turn, our financial condition.
Furthermore, the indentures governing our long-term debt include cross-acceleration provisions. Therefore, if we borrow $25 million or more under the credit facility and such borrowings are accelerated for any reason, including the default of another party, our long-term debt could also be accelerated. The acceleration of our long-term debt could also adversely affect our liquidity position and, in turn, our financial condition.
WE COULD BE SUBSTANTIVELY CONSOLIDATED WITH EL PASO IF EL PASO WERE FORCED TO SEEK PROTECTION FROM ITS CREDITORS IN BANKRUPTCY.
If El Paso were the subject of voluntary or involuntary bankruptcy proceedings, El Paso and its other subsidiaries and their creditors could attempt to make claims against us, including claims to substantively consolidate our assets and liabilities with those of El Paso and its other subsidiaries. The equitable doctrine of substantive consolidation permits a bankruptcy court to disregard the separateness of related entities and to consolidate and pool the entities' assets and liabilities and treat them as though held and incurred by one entity where the interrelationship between the entities warrants such consolidation. We believe that any effort to substantively consolidate us with El Paso and/or its other subsidiaries would be without merit. However, we cannot assure you that El Paso and/or its other subsidiaries or their respective creditors would not attempt to advance such claims in a bankruptcy proceeding or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy court were to substantively consolidate us with El Paso and/or its other subsidiaries, there could be a material adverse effect on our financial condition and liquidity.
WE ARE A WHOLLY OWNED DIRECT SUBSIDIARY OF EL PASO EPNG INVESTMENTS, L.L.C., A DIRECT SUBSIDIARY OF EL PASO.
As we are an indirect subsidiary of El Paso, El Paso has substantial control over:
- our payment of dividends;
- decisions on our financings and our capital raising activities;
- mergers or other business combinations;
- our acquisitions or dispositions of assets; and
- our participation in El Paso's cash management program.
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.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk is exposure to changing interest rates. The table below shows the carrying value and related weighted average effective interest rates of our interest bearing securities, by expected maturity dates, and the fair value of those securities. The carrying amounts of short-term borrowings are representative of fair values because of the short-term maturity of these instruments. The fair values of our fixed rate long-term debt securities have been estimated based on quoted market prices for the same or similar issues.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS)
See accompanying notes.
EL PASO NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS)
See accompanying notes.
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS)
See accompanying notes.
EL PASO NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (IN MILLIONS, EXCEPT SHARE AMOUNTS)
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
Our consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. We consolidate entities when we have the ability to control the operating and financial decisions and policies of that entity. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications had no impact on reported net income or stockholder's equity.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 systems are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we currently apply the provisions of Statements of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Type of Regulation. We perform an annual study to assess the ongoing applicability of SFAS No. 71. The accounting required by SFAS No. 71 differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include capitalizing an equity return component on regulated capital projects, post retirement employee benefit plans, 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 an outstanding receivable balance. We regularly review collectibility 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 actual amount of natural gas delivered from or received by a pipeline system differs from the contractual amount scheduled to be delivered or received. We value these imbalances due to or from shippers and operators at the end of year actual or appropriate market index price. Imbalances are settled in cash or made up in kind, subject to the contractual terms of settlement.
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. In addition, all imbalances are classified as current.
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. We capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and an allowance for funds used during construction for our regulated business as allowed by FERC. We capitalize the major units of property replacements or improvements and expense minor items. Included in our pipeline property balances are additional acquisition costs which represent the excess purchase costs associated with purchase method business combinations allocated to our regulated interstate systems. These costs are amortized on a straight-line basis over 36 years, and we do not recover these excess costs in our rates. As of December 31, 2003, we had unamortized additional acquisition costs of $69 million net of accumulated amortization of $82 million.
We use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar lives and other characteristics are grouped and depreciated as one asset. For aircraft, we apply the depreciation rates to the total cost of the group until its net book value equals its salvage value. For all other property, plant and equipment we depreciate the asset to zero. Currently, our depreciation rates vary from 2 to 33 percent. Using these rates, the average remaining depreciable lives of these assets range from one to 40 years.
When we retire regulated property, plant and equipment, we charge accumulated depreciation and amortization for the original cost, plus the cost to remove, sell or dispose, less its salvage value. We do not recognize a gain or loss unless we sell an entire operating unit. We include gains or losses on dispositions of operating units in income. On non-regulated property, plant and equipment, we record a gain or loss in income for the difference between the net book value relative to the proceeds received, if any, when the asset is sold or retired.
At December 31, 2003 and 2002, we had approximately $218 million and $146 million of construction work in progress included in our property, plant and equipment.
As a FERC-regulated company, we capitalize a carrying cost (an allowance for funds used during construction, or AFUDC) on funds invested in our 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 our average cost of debt. Debt amounts capitalized during the years ended December 31, 2003, 2002 and 2001, were $3 million, $6 million and $9 million. These amounts are included as an offset to interest expense in our income statement. The equity portion is calculated using the most recent FERC approved equity rate of return. The equity amount capitalized for the year ended December 31, 2003, was $4 million (exclusive of any tax related impacts). Equity amounts capitalized for the year ended December 31, 2002 and 2001 were immaterial. These amounts are included as other non-operating income on our income statement. Capitalized carrying costs for debt and equity financed construction are reflected as an increase in the cost of the asset on our balance sheet.
Asset Impairments
We evaluate our assets for impairment when events or circumstances indicate that a long-lived asset's carrying value may not be recovered. These events include market declines, changes in the manner in which we intend to use an asset or decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. At the time we decide to exit an activity or sell a long-lived asset or group of assets, we adjust the carrying value of those assets downward, if necessary, to the estimated sales price, less costs to sell. We also classify these asset or assets as either held for sale or as discontinued operations, depending on whether the asset or assets have independently determinable cash flows.
Revenue Recognition
Our revenues consist primarily of demand and throughput-based transportation services. We recognize demand revenues on firm contracted capacity monthly over the contract period regardless of the amount of capacity that is actually used. For throughput-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point. Revenues are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract or tariff. We are subject to FERC regulations and, as a result, revenues we collect may be refunded in a final order of a pending rate proceeding or as a result of a rate settlement. We establish reserves for these potential refunds.
Through 2003, we also recorded risk sharing revenues related to our most recent rate settlement. The majority of the risk sharing amounts were collected in advance from our customers. These collections were initially deferred and are then amortized over the risk sharing period as specified in our tariff. See Note 10 for a further discussion of our rate settlement and these risk sharing provisions.
Environmental Costs and Other Contingencies
We record environmental liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. We recognize a current period expense when clean-up efforts do not benefit future periods. We capitalize costs that benefit more than one accounting period, except in instances where separate agreements or legal and regulatory guidelines dictate otherwise. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into account the likely effects of inflation and 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. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our balance sheet in other current and long-term liabilities at their undiscounted amounts. We evaluate recoveries from insurance coverage, rate recovery, government sponsored and other programs separately from our liability and, when recovery is assured, we record and report an asset separately from the associated liability in our financial statements.
We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against a reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount, or at least the minimum of the range of probable loss.
Income Taxes
We report current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments or 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.
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.
2. LIQUIDITY
In February 2004, El Paso announced that it had completed a review of its estimates of natural gas and oil reserves. As a result of this review, El Paso announced that it was reducing its proved natural gas and oil reserves by approximately 1.8 Tcfe. El Paso also announced that this reserve revision would result in a 2003 charge of approximately $1 billion if the full impact of the revision was taken in that period. In March 2004, El Paso provided an update and stated that the revision would likely result in a restatement of its historical financial statements, the timing and magnitude of which are still being determined.
A material restatement of El Paso's prior period financial statements may result in an "event of default" under El Paso's revolving credit facility and various other financing transactions; specifically under the provisions of the facility related to representations and warranties on the accuracy of its historical financial statements and its debt to total capitalization ratio. El Paso has received waivers on its revolving credit facility and two other transactions. These waivers have a condition that provides for the expiration of the waiver in thirty days, unless El Paso successfully receives waivers on other specified transactions within that time period. El Paso is pursuing these additional waivers and expects to receive them. However, if El Paso is unable to obtain these additional waivers, and there is an existing event of default, El Paso could be required to immediately repay the amounts outstanding under the revolving credit facility, and El Paso and we would be precluded from borrowing under this facility. We currently have no outstanding borrowings under the facility, have never borrowed under the facility and do not believe we will need to borrow from the facility in the future. In addition, based upon a review of the covenants and indentures of our other outstanding indebtedness, we do not believe that a default on the revolving credit facility would constitute an event of default on our other debt securities.
El Paso is a significant potential source of liquidity to us. We participate in El Paso's cash management program. Under this program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso or El Paso provides cash to us. We have historically provided cash to El Paso under this program, and as of December 31, 2003, we had a cash advance receivable from El Paso of $779 million, classified as a non-current asset in our balance sheet. If El Paso were unable to meet its liquidity needs, we would not have access to this source of liquidity and there is no assurance that El Paso could repay the entire amounts owed to us. In that event, we could be required to write-off some amount of these advances, which could have a material impact on our stockholder's equity. Furthermore, we would still be required to repay affiliated company payables. Non-cash write-downs that cause our debt to EBITDA (as defined in our agreements) ratio to fall below 5 to 1 could prohibit us from incurring additional debt. However, this non-cash equity reduction would not result in an event of default under our existing debt securities. In addition, based on our current estimates of cash flows, we do not believe we will need to seek repayment of all or part of these advances in the next year.
El Paso's ownership in us and our ownership in Mojave Pipeline Company serve as collateral under El Paso's revolving credit facility and other of El Paso's borrowings. If El Paso's lenders under this facility or those borrowings were to exercise their rights to this collateral, our ownership could change and our ownership interests in Mojave could be liquidated. However, this change of control and liquidation would not constitute an event of default under our existing debt securities.
If, as a result of the events described above, El Paso were subject to voluntary or involuntary bankruptcy proceedings, El Paso and its other subsidiaries and their creditors could attempt to make claims against us, including claims to substantively consolidate our assets and liabilities with those of El Paso and its other subsidiaries. We believe that claims to substantively consolidate us with El Paso and/or its other subsidiaries would be without merit. However, there is no assurance that El Paso and/or its other subsidiaries or their creditors would not advance such a claim in a bankruptcy proceeding. If we were to be substantively consolidated in a bankruptcy proceeding with El Paso and/or its other subsidiaries, there could be a material adverse effect on our financial condition and our liquidity.
Finally, we have cross-acceleration provisions in our long-term debt that state that should we incur an event of default under which borrowings in excess of $25 million are accelerated, our long-term debt
could also be accelerated. The acceleration of our long-term debt would adversely affect our liquidity position and, in turn, our financial condition.
3. WESTERN ENERGY SETTLEMENT
As a result of the Western Energy Settlement discussed in Note 10, we recorded an initial pretax charge and obligation of $412 million in 2002. Upon entering the definitive agreements and during the remainder of 2003, we recorded an additional obligation and a net pretax charge in 2003 of approximately $127 million. The additional charge was primarily a result of changes in the value of the common stock to be issued in connection with the definitive settlement agreements and changes in the timing of settlement payments. During 2003, we also recorded accretion expense on the discounted Western Energy Settlement obligation of $9 million and paid other charges of $4 million both of which are included as part of operation and maintenance expense in our income statement. As of December 31, 2003, our total Western Energy settlement obligation was $538 million, all of which is reflected as a current liability since we estimate the finalization of the settlement in the next twelve months. As of December 31, 2003, $10 million of the total obligation had been paid to certain settling parties.
El Paso established an escrow account for amounts funded by us and its affiliates until final approval of the settlement agreements. As of December 31, 2003, total amounts in this account were $443 million, which is reflected as restricted cash in our balance sheet and as an investing activity in our statement of cash flows. We funded $322 million of this account by using the majority of the net proceeds from the issuance of $355 million in senior notes in July 2003. Additionally, during the fourth quarter of 2003, El Paso issued a total of 17.6 million shares of its common stock on our behalf for $121 million, the proceeds from which were placed in the escrow account. In January 2004, El Paso issued the remaining 8.8 million shares for approximately $74 million, which was also placed in the escrow account. Future payments from this account, upon final approval of the settlement agreements, will be reflected as a reduction of our cash flow from operations.
4. ACQUISITIONS AND DIVESTITURES
In August 2003, we announced the purchase of Copper Eagle Gas Storage, L.L.C., which is developing a natural gas storage project located outside of Phoenix, Arizona. We purchased Copper Eagle from Arizona Gas Storage, L.L.C. and APACS Holding L.L.C. Arizona Gas Storage is owned by our affiliate, GulfTerra Energy Partners, L.P. The purchase price was $12 million, and under the current terms of the purchase agreement, we paid $2.5 million in cash at the closing. In the fourth quarter of 2003, we made a payment of $2.3 million. The remaining balance at December 31, 2003 of $7 million is scheduled to be paid in three quarterly installments ending September 2004. We also acquired land for approximately $9 million that will allow for further development of that project.
During 2003, we sold a non-pipeline asset with a net book value of approximately $38 million. Net proceeds from the sale were approximately $38 million, including approximately $8 million from our parent, and no gain or loss was recognized on the sale.
5. MERGER-RELATED COSTS
During the year ended December 31, 2001, we incurred merger-related costs of $98 million associated with El Paso's 2001 merger with The Coastal Corporation and the relocation of our headquarters from El Paso, Texas to Colorado Springs, Colorado. Our merger-related costs include employee severance, retention and transition costs for severed employees totaling $6 million that occurred as a result of El Paso's merger-related workforce reduction and consolidation. All employee severance, retention and transition costs have been paid. Merger-related costs also include estimated net lease payments on a non-cancelable lease for office space and facility-related costs of $92 million to close our offices in El Paso and relocate our headquarters to Colorado Springs. These charges were accrued in 2001 at the time we completed our relocations and closed these offices. As of December 31, 2003, we have paid $40 million of the accrual leaving a remaining balance of $52 million. The amounts accrued will be paid over the term of the applicable
non-cancelable lease agreements. Future developments, such as our ability to terminate the lease or to recover lease costs through sub-leases, could impact the accrued amounts.
6. INCOME TAXES
The following table reflects the components of income taxes included in net income for each of the three years ended December 31:
Our income taxes included in net income differ 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:
The following are the components of our net deferred tax liability as of December 31:
Included in deferred tax assets are amounts related to the Western Energy Settlement. Proposed tax legislation has been introduced in the U.S. Senate which would disallow deductions for certain settlements made to or on behalf of governmental entities. If enacted, this tax legislation could impact the deductibility of the expenses related to the Western Energy Settlement and could result in a write-off of some or all of the associated deferred tax assets.
Under El Paso's tax accrual policy, we are allocated the tax effects associated with our employees' non-qualified dispositions of employee stock purchase plan stock, the exercise of non-qualified stock options and the vesting of restricted stock as well as restricted stock dividends. This allocation increased taxes payable by $1 million in 2003 and reduced taxes payable by $1 million in 2002 and $4 million in 2001. These tax effects are included in additional paid-in capital in our balance sheet.
As of December 31, 2003, we had approximately $17 million of alternative minimum tax credits and $1 million of net operating loss carryovers available to offset future regular tax liabilities. The alternative minimum tax credits carryover indefinitely. The net operating loss carryover period ends in 2021. Usage of these 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.
7. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of our financial instruments are as follows at December 31:
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(1) We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues.
As of December 31, 2003 and 2002, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables are representative of fair value because of the short-term maturity of these instruments.
8. REGULATORY ASSETS AND LIABILITIES
Our regulatory assets and regulatory liabilities as of December 31, 2003 and 2002 are presented below.
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(1) This amount is not included in our rate base on which we earn a current return.
(2) Amounts are included as other non-current assets and liabilities in our balance sheet.
9. DEBT AND OTHER CREDIT FACILITIES
Debt
Our long-term debt outstanding consisted of the following at December 31:
In June 2002, we issued $300 million aggregate principal amount 8.375% notes due 2032. Proceeds were approximately $296 million, net of issuance costs.
In July 2003, we issued $355 million of senior unsecured notes with an annual interest rate of 7.625% due 2010. Net proceeds were approximately $347 million. In November 2003, we retired $200 million of 6.75% notes due 2003.
None of the principal amounts of our long-term debt matures in the next 5 years.
Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $25 million cross-acceleration clause. If triggered, repayment of our long-term debt, could be accelerated.
Letters of Credit
In 2001, we issued $3 million of letters of credit for an unconsolidated affiliate, $2 million of which matures in April 2005. We cancelled $1 million of these letters of credit in January 2004, undrawn.
Other Financing Arrangements
In April 2003, El Paso entered into a new $3 billion revolving credit facility, with a $1.5 billion letter of credit sublimit, which matures on June 30, 2005. The credit facility has a borrowing cost of LIBOR plus 350 basis points, letter of credit fees of 350 basis points and a commitment fee of 75 basis points on the unused portion of the facility. This facility replaced El Paso's previous $3 billion revolving credit facility. El Paso's $1 billion revolving credit facility which matured in August 2003, and approximately $1 billion of other El Paso financing arrangements (including leases, letters of credit and other facilities) were also amended to conform El Paso's obligations under those arrangements to the new credit facility. We, along with El Paso and our affiliates, ANR Pipeline Company, Tennessee Gas Pipeline Company (TGP) and Colorado Interstate Gas Company (CIG), are borrowers under El Paso's $3 billion revolving credit facility, and El Paso's equity in several of its subsidiaries, including its equity in us and our equity in Mojave Pipeline Company, collateralize the credit facility and the other financing arrangements. We are only liable for amounts we directly borrow. As of December 31, 2003, $850 million was outstanding and $1.2 billion in letters of credit were issued under the $3 billion revolving credit facility, none of which were borrowed by or issued on behalf of us. See Note 2 for a discussion regarding El Paso's possible default on the $3 billion revolving credit facility.
We were jointly and severally liable for any outstanding amounts under El Paso's $1 billion revolving credit facility through its maturity in August 2003, and under El Paso's $3 billion revolving credit facility through August 2003.
Under the new $3 billion revolving credit facility and other 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); (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 cash management program discussed in Note 13. For the year ended December 31, 2003, we were in compliance with these covenants.
10. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
Western Energy Settlement. On June 26, 2003, El Paso announced that it had executed a Master Settlement Agreement, or MSA, to resolve the principal litigation relating to the sale or delivery of natural gas and/or electricity to or in the Western United States. The MSA settles California lawsuits in state court, the California Public Utilities Commission (CPUC) proceeding at the FERC, and the California Attorney General investigation discussed herein. Parties to the settlement agreements include private class action litigants in California; the governor and lieutenant governor of California; the attorneys general of California, Washington, Oregon and Nevada; the CPUC; the California Electricity Oversight Board; the California Department of Water Resources; Pacific Gas and Electric Company (PG&E), Southern California Edison Company, five California municipalities and six non-class private plaintiffs. We are a party to the MSA and, as such, will bear a portion of the costs and obligations of the settlements, as discussed more fully below. For a discussion of the charges taken in connection with the Western Energy Settlement, see Note 3.
The MSA is in addition to the Joint Settlement Agreement, or JSA, announced earlier in June 2003 where we agreed to provide structural relief to the settling parties. In the JSA, we agreed to do the following:
- Subject to the conditions in the settlement, provide 3.29 Bcf/d of primary firm pipeline capacity on our system to California delivery points during a five year period from the date of settlement, and not add any firm incremental load to our system that would prevent us from satisfying our obligation to provide this capacity;
- Construct a new $173 million, 320 MMcf/d, Line 2000 Power-up expansion project, and forgo recovery of the cost of service of this expansion until our next rate case before the FERC;
- Clarify the rights of Northern California shippers to recall some of our system capacity (Block II capacity) to serve markets in PG&E's service area; and
- With limited exceptions, bar any of our affiliated companies from obtaining additional firm capacity on our pipeline system during a five year period from the effective date of the settlement.
In connection with the JSA, a Stipulated Judgment will be filed with the United States District Court for the Central District of California. This Stipulated Judgment provides for the enforcement of some of the obligations contained in the JSA.
In the MSA, we agreed to the following terms:
- We admitted to no wrongdoing;
- We would make cash payments totaling $93.5 million for the benefit of the parties to the definitive settlement agreements subsequent to the signing of these agreements. This amount represents the originally announced $100 million cash payment less credits for amounts that have been paid to other settling parties;
- We agreed to pay amounts equal to the proceeds from the issuance of approximately 26.4 million shares by El Paso of El Paso common stock on behalf of the settling parties. In this transaction, El Paso sold its common stock and provided the proceeds from the issuance to us through an equity contribution to satisfy this obligation; and
- We would eliminate the originally announced 20-year obligation to pay $22 million per year in cash by depositing $250 million in escrow for the benefit of the settling parties within 180 days of the signing of the definitive settlement agreements. This prepayment eliminates any collateral that might have been required on the $22 million per year payment over the next 20 years.
As of December 31, 2003, $443 million had been deposited into an escrow account for the benefit of the settling parties related to the items discussed above. In January 2004, we deposited an additional $74 million in the escrow account (see Note 3).
El Paso Merchant Energy L.P. (EPME), our affiliate, was also a party to the settlement agreements and, along with El Paso, is obligated to provide a total of $1,027 million (on an undiscounted basis) under these agreements. Of this amount, $2 million will be paid by El Paso upon final approval of the definitive settlement agreements, $125 million represents a contractual price discount that will be realized over the remaining 30-month life of an existing power contract between EPME and one of the settling parties, and $900 million will be paid by EPME or El Paso in installments over the next 20 years. The long-term payment obligation is a direct obligation of El Paso and EPME and will be supported by collateral posted by El Paso's affiliates in amounts specified by the settlement agreements. We have guaranteed the payment of these obligations in the event El Paso and EPME fail to pay these amounts.
In June 2003, in anticipation of the execution of the MSA, El Paso, the CPUC, PG&E, Southern California Edison Company, and the City of Los Angeles filed the JSA described above with the FERC in resolution of specific proceedings before that agency. In November 2003, the FERC approved the JSA with minor modifications. Our east of California shippers have filed a request for rehearing and the matter is currently pending before the FERC.
We were named as a defendant in fifteen purported class action, municipal or individual lawsuits, filed in California state courts. These suits contend that we acted improperly to limit the construction of new pipeline capacity to California and/or to manipulate the price of natural gas sold into the California marketplace. In December 2003, the California State Court in San Diego dismissed us from seven of the fifteen class action suits and entered judgment approving the MSA. The judgment was appealed. This appeal will delay the effective date of the settlement. Seven other cases will be dismissed after the MSA becomes effective. The fifteenth lawsuit was settled in May 2003.
In November 2002, a lawsuit was filed in the Superior Court of California, County of Los Angeles against us, as well as numerous other unrelated entities, alleging the creation of artificially high natural gas index prices via the reporting of false price and volume information. This purported class action on behalf of California consumers alleges various unfair business practices and seeks restitution, disgorgement of profits, compensatory and punitive damages, and civil fines. This lawsuit will be resolved upon approval of the Western Energy Settlement.
In September 2001, we received a civil document subpoena from the California Attorney General, seeking information said to be relevant to the Attorney General's ongoing investigation into the high electricity prices in California. This proceeding will be resolved upon approval of the Western Energy Settlement.
In February 2003, the state of Nevada and two individuals filed a class action lawsuit in Nevada state court naming us and a number of our affiliates as defendants. The allegations are similar to those in the California cases. The suit seeks monetary damages and other relief under Nevada antitrust and consumer protection laws. This proceeding will be resolved upon approval of the Western Energy Settlement.
Proposed tax legislation has been introduced in the U.S. Senate which could impact the deductibility of the expenses related to the Western Energy Settlement. More details on its impact may be found in Note 6.
Other Energy Market Lawsuits. In April 2003, Sierra Pacific Resources and Nevada Power Company filed a suit against us. The allegations were similar to those in the California cases. On January 27, 2004, the Court dismissed the lawsuit. An appeal is likely. Our costs and legal exposure related to this lawsuit are not currently determinable.
In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed in California state court against us and our affiliates. The suit arose out of a gas supply contract between IMC Chemicals (IMCC) and EPME and sought to void the Gas Purchase Agreement between IMCC and EPME for gas purchases until December 2003. IMCC contended that EPME and its affiliates manipulated market prices for natural gas and, as part of that manipulation, induced IMCC to enter into the contract. In furtherance of its attempt to void the contract, IMCC repeated the allegations and claims of the California lawsuits described above. EPME intends to enforce the terms of the contract and counterclaim for contract damages. EPME has filed a counterclaim for contract damages in excess of $5 million. IMCC's claim is undeterminable but appears to be in excess of $20 million. Our costs and legal exposure related to this lawsuit are not currently determinable.
Henry W. Perlman et. al. v. El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., et al. A purported class action suit was filed in federal court in New York City in December 2002 alleging that the defendants manipulated California's natural gas market by manipulating the spot market of gas traded on the NYMEX. This lawsuit has been voluntarily dismissed.
State of Arizona v. El Paso et. al. In March 2003, the State of Arizona sued us, our affiliates and other unrelated entities on behalf of Arizona consumers. The suit alleges that the defendants conspired to artificially inflate prices of natural gas and electricity during 2000 and 2001. Making allegations similar to those alleged in the California cases, the suit seeks relief similar to the California cases, but under Arizona antitrust and consumer fraud statutes. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.
Phelps Dodge vs. EPNG. On February 3, 2004, one of our customers, Phelps Dodge, and a number of its affiliates filed a lawsuit against us in the State Court of Arizona. Plaintiffs claim we violated Arizona anti-trust statutes and allege that during 2000-2001, we unlawfully manipulated and inflated gas prices. Our costs and legal exposure related to this lawsuit are not currently determinable.
Shareholder Class Action Suit. In November 2002, we were named as a defendant in a shareholder derivative suit titled Marilyn Clark v. Byron Allumbaugh, David A. Arledge, John M. Bissell, Juan Carlos Braniff, James F. Gibbons, Anthony W. Hall, Ronald L. Kuehn, J. Carleton MacNeil, Thomas McDade, Malcolm Wallop, William Wise, Joe B. Wyatt, El Paso Natural Gas Company and El Paso Merchant Energy Company filed in state court in Houston. This shareholder derivative suit generally alleges that manipulation of California gas supply and gas prices exposed our parent, El Paso, to claims of antitrust conspiracy, FERC penalties and erosion of share value. The plaintiffs have not asked for any relief with regard to us. Our costs and legal exposure related to this proceeding are not currently determinable.
Carlsbad. In August 2000, a main transmission line owned and operated by us ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. As a result, the U.S. Department of Transportation's Office of Pipeline Safety issued a Notice of Probable Violation and Proposed Civil Penalty to us proposing a fine of $2.5 million. We have fully accrued for these fines. In October 2001, we filed a response with the Office of Pipeline Safety disputing each of the alleged violations. In December 2003, the matter was referred to the Department of Justice.
In addition, after a public hearing conducted by the National Transportation Safety Board (NTSB) on its investigation of the Carlsbad rupture, the NTSB published its final report in April 2003. The NTSB stated that it had determined that the probable cause of the August 19, 2000 rupture was a significant reduction in pipe wall thickness due to severe internal corrosion, which occurred because our corrosion control program "failed to prevent, detect, or control internal corrosion" in the pipeline. The NTSB also determined that ineffective federal preaccident inspections contributed to the accident by not identifying deficiencies in our internal corrosion control program.
On November 1, 2002, we received a federal grand jury subpoena for documents relating to the rupture and we cooperated fully in responding to the subpoena. That subpoena has since expired. In December 2003 and January 2004, eight current and former employees were served with testimonial subpoenas issued by the grand jury. Testimony by six of these individuals occurred in March 2004. Additional testimonial and documentary subpoenas may be issued by the grand jury.
A number of personal injury and wrongful death lawsuits were filed against us in connection with the rupture and have been settled. The settlement payments were fully covered by insurance. In connection with the settlement of the cases, we contributed $10 million to a charitable foundation as a memorial to the families involved. The contribution was not covered by insurance.
Parties to four of the settled lawsuits have since filed an additional lawsuit titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas, on November 20, 2002, seeking additional sums based upon their interpretation of earlier agreements. In addition, a lawsuit entitled Baldonado et al. vs. EPNG was filed on June 30, 2003, in state court in Eddy County, New Mexico, on behalf of firemen and EMS personnel who responded to the fire and who allegedly have suffered psychological trauma. The Baldonado lawsuit was dismissed by the court. We expect it will be appealed. Our costs and legal exposure related to the Heady and Baldonado lawsuits are currently not determinable, however, we believe these matters will be fully covered by insurance.
Grynberg. In 1997, we and a number of our affiliates were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). Discovery is proceeding. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.
Will Price (formerly Quinque). We and a number of our affiliates are named defendants in Will Price et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek certification of a nationwide class of natural gas working interest owners and natural gas royalty owners to recover royalties that they contend these owners should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorneys' fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied on April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado, and removes claims as to heating content. A second class action has since been filed as to the heating content claims. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.
Bank of America. We are a named defendant, with Burlington Resources, Inc., in two class action lawsuits styled Bank of America, et al. v. El Paso Natural Gas Company, et al., and Deane W. Moore, et al. v. Burlington Northern, Inc., et. al., each filed in 1997 in the District Court of Washita County, State of Oklahoma and subsequently consolidated by the court. Plaintiffs contend that defendants underpaid royalties from 1983 to the present on natural gas produced from specified wells in Oklahoma through the use of below-market prices, improper deductions and transactions with affiliated companies and in other instances failed to pay or delayed in the payment of royalties on certain gas sold from these wells. The plaintiffs seek an accounting and damages for alleged royalty underpayments, plus interest from the time such amounts were allegedly due, as well as punitive damages. The plaintiffs have filed expert reports alleging damages in excess of $1 billion. While Burlington accepted our tender of defense in 1997, and had been defending the matter since that time, it has recently asserted contractual claims for indemnity against us. We believe we have substantial defenses to the plaintiffs' claims as well as to the claims for indemnity. The court has certified the plaintiff classes of royalty and overriding royalty interest owners, and the parties are proceeding with discovery.
It is anticipated that this matter will be scheduled for trial during 2004. A third action, styled Bank of America, et al v. El Paso Natural Gas and Burlington Resources Oil & Gas Company, was filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting similar claims as to specified shallow wells in Oklahoma, Texas and New Mexico. A class has not been certified. We believe we have substantial defenses to the plaintiffs' claims as well as to the claims for indemnity. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.
In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.
For each of our outstanding legal matters, we evaluate the merits of the case, our exposure in 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. 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 current reserves are adequate. As of December 31, 2003, we had accrued approximately $541 million for all outstanding legal matters, which is reflected in the Western Energy Settlement liability and other current liabilities on our balance sheet.
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 on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2003, we had accrued approximately $28 million for expected remediation costs at current and former sites and associated onsite, offsite and groundwater technical studies and for related environmental legal costs, which we anticipate incurring through 2027. Our accrual at December 31, 2003, was based on the probability of the most likely outcome that can be reasonably estimated; however, our exposure could be as high as $54 million. Below is a reconciliation of our accrued liability as of December 31, 2003 (in millions).
For 2004, we estimate that our total remediation expenditures will be approximately $4 million, which primarily will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $2 million in the aggregate for the years 2004 through 2008. These expenditures primarily relate to compliance with clean air regulations.
CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to four active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2003, we have estimated our share of the remediation costs at these sites to be between $12 million and $17 million. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Reserves for these matters are included in the environmental reserve discussed above.
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 and regulations and claims for damages to property, employees, other persons and the environment 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 relating 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
CPUC Complaint Proceeding. This matter will be settled by the Western Energy Settlement. In April 2000, the CPUC filed a complaint under Section 5 of the Natural Gas Act (NGA) with the FERC alleging that our sale of approximately 1.2 Bcf/d of capacity to our affiliate, EPME, raised issues of market power and violation of the FERC's marketing affiliate regulations and asked that the contracts be voided. In the spring and summer of 2001, two hearings were held before an ALJ to address the market power issue and the affiliate issue. On November 19, 2003, in approving the JSA, FERC also vacated both of the ALJ's Initial Decisions. As discussed under the Western Energy Settlement, a request for rehearing of this order is pending.
Systemwide Capacity Allocation Proceeding. In July 2001, several of our customers filed complaints against us at the FERC claiming that we had failed to provide appropriate service on our pipeline. As a result of the FERC's many orders in these proceedings; (i) FR shippers were required to convert from full requirements to contract demand service on September 1, 2003; (ii) firm customers were assigned specific receipt point rights in lieu of systemwide receipt point rights; (iii) reservation charges will be credited to all firm customers if we fail to schedule confirmed volumes except in cases of force majeure; in such force majeure cases, the reservation charge credits will be limited to the return and associated tax portion of our reservation rate; (iv) no new firm contract can be executed unless we can demonstrate there is adequate capacity on the system available to provide the service; (v) capacity turned-back to us from contracts that terminated or expired from May 31, 2002 and May 1, 2003, could not be remarketed because it was included in the volumes allocated to the FR shippers; and (vi) a backhaul service was established from our California delivery points for existing and new shippers. We also received certificate authority to add compression to our Line 2000 to increase our system by 320 MMcf/d without receiving cost coverage for the expansion until our next rate case (in January 2006).
On July 9, 2003, the FERC found that we had not violated our certificates, our contractual obligations, including our obligations under the 1996 Rate Settlement (discussed below), or our tariff provisions as a result of the capacity allocations that have occurred on the system since the 1996 Rate Settlement. In addition, the FERC found we had correctly stated the capacity that is available on a firm basis for allocation among our shippers and that we had properly allocated that capacity. On a prospective basis, the FERC ordered us to set aside a pool of 110 MMcf/d of capacity for use by the converting FR shippers until the first phase of the Line 2000 Power-up expansion (discussed below) went into service (as of February 27, 2004, after which the pool of capacity has been reduced to 50 MMcf/d until the second phase of the Power-up is placed in service in mid-2004).
On July 18, 2003, the FR shippers filed an appeal of the July 9 order with the D.C. Circuit (Arizona Corporation Comm'n, et al. v. FERC, No. 03-1206) and subsequently sought a stay of the FERC's orders. The stay was denied by the court. Other parties have filed appeals of the FERC's orders and all such appeals have been consolidated. The final outcome of these appeals cannot be predicted with certainty.
Rate Settlement. Our current rate settlement establishes our base rates through December 31, 2005. The settlement has certain requirements applicable to the Post-Settlement Period. These requirements include a provision which limits the rates to be charged to a portion of our contracted portfolio to a level equal to the inflation-escalated rate from the 1996 rate settlement. We are currently reviewing the definition and applicability of this future capped-rate requirement given, among other things, the customer and contract changes required by the capacity allocation proceeding discussed above. We have the right to increase or
decrease our base rates if changes in laws or regulations result in increased or decreased costs in excess of $10 million a year. In addition, all of our settling customers participated in risk sharing provisions. Under these provisions, we received cash payments in total of $295 million for a portion of the risk we assumed from capacity relinquishments by our customers (primarily capacity turned back to us by Southern California Gas Company and Pacific Gas & Electric Company which represented approximately one-third of the capacity of our system) during 1996 and 1997. The cash we received was deferred, and was recognized in revenues ratably over the risk sharing period which ended December 31, 2003. As of December 31, 2003 all risk sharing revenues had been collected from customers under this provision. Amounts received for relinquished capacity sold to customers, above certain dollar levels specified in our rate settlement, obligated us to refund a portion of the excess to customers. Under this provision, we refunded a total of $46 million of 2002 revenues to customers during 2002 and the first quarter of 2003. During 2003, we established an additional refund obligation of $40 million of which $28 million has been refunded to customers as of December 31, 2003. Both the risk and revenue sharing provisions of the rate settlement expired at the end of 2003.
Line 2000 Project. In July 2000, we applied with the FERC for a certificate of public convenience and necessity for our Line 2000 project, which was designed to replace old compression on the system with a converted oil pipeline, resulting in no increase in system capacity. In response to demand conditions on our system, however, we filed in March 2001 to amend our application to convert the project to an expansion project of 230 MMcf/d. In May 2001, the FERC authorized the amended Line 2000 project. We placed the line in service in November 2002 at a capital cost of $189 million. The cost of the Line 2000 conversion will not be included in our rates until our next rate case, which will be effective on January 1, 2006.
In October 2002, pursuant to the FERC's orders in the systemwide capacity allocation proceeding, we filed with the FERC for a certificate of public convenience and necessity to add compression to our Line 2000 project to increase the capacity of that line by an additional 320 MMcf/d at an estimated capital cost of approximately $173 million for all phases of the Power-up. On June 4, 2003, the FERC issued an order approving our certificate application. On November 14, 2003, FERC denied pending requests for rehearing on its June 4 order approving the power-up. The project is currently under construction and Phase I was placed in service on February 27, 2004, adding 120 MMcf/d of compression to our system.
There are other regulatory rules and orders in various stages of adoption, review and/or implementation, none of which we believe will have a material impact on us.
While the outcome of our outstanding rates and regulatory matters cannot be predicted with certainty, based on current information and our existing accruals, 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. However, it is possible that new information or future developments could require us to reassess our potential exposure and accruals related to these matters.
Other Matters
Enron Bankruptcy. In December 2001, Enron Corp. and a number of its subsidiaries, including Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of New York. Enron North America had transportation contracts on our system. The transportation contracts have now been rejected and we have filed a proof of claim in the amount of approximately $128 million, which included $18 million for amounts due for services provided through the date the contracts were rejected and $110 million for damage claims arising from the rejection of its transportation contracts. We anticipate that Enron will vigorously oppose these claims. Given the uncertainties of Bankruptcy Court, we have fully reserved for all amounts due from Enron through the date the contracts were rejected, and we have not recognized any amounts under these contracts since the rejection date.
While the outcome of this matter cannot be predicted with certainty, based on current information and our existing accrual, we do not expect the ultimate resolution to have a material adverse effect on our financial position, operating results or cash flows. However, it is possible that new information or future developments could require us to reassess our potential exposure related to this matter, and adjust our accrual accordingly.
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.
Capital Commitments
At December 31, 2003, we had capital and investment commitments of $43 million primarily relating to ongoing capital projects. Our other planned capital and investment projects are discretionary in nature, with no substantial capital commitments made in advance of the actual expenditures.
Operating Leases
We lease property, facilities and equipment under various operating leases. Minimum annual rental commitments on operating leases as of December 31, 2003, were as follows:
Aggregate minimum commitments have not been reduced by minimum sublease rentals of approximately $6 million due in the future under noncancelable subleases. In addition, as part of our relocation from El Paso to Colorado Springs, we accrued these minimum lease commitments as merger-related charges. These accruals were reduced by our estimated minimum sublease rentals.
Rental expense for operating leases for each of the years ended December 31, 2003, 2002 and 2001 was $3 million.
11. RETIREMENT BENEFITS
Pension and Retirement Benefits
Prior to January 1, 1997, El Paso maintained a defined benefit pension plan covering substantially all of our employees. Pension benefits were based on years of credited service and final five year average compensation, subject to maximum limitations as defined in the pension plan. Effective January 1, 1997, the plan was amended to provide benefits determined by a cash balance formula. Employees who were pension plan participants on December 31, 1996, receive the greater of cash balance benefits or prior plan benefits accrued through December 31, 2001.
In addition, El Paso maintains a defined contribution plan covering its U.S. employees, including our employees. Prior to May 1, 2002, El Paso matched 75 percent of participant basic contributions up to 6 percent, with the matching contributions being made to the plan's stock fund, which participants could diversify at any time. After May 1, 2002, the plan was amended to allow for matching contributions to be invested in the same manner as that of participant contributions. In March 2003, El Paso suspended the matching contribution. Effective July 1, 2003, El Paso began making matching contributions again at a rate of 50 percent of participant basic contributions up to 6 percent. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates. See Note 13 for a summary of transactions with affiliates.
Other Postretirement Benefits
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 (OPEB) is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. The medical plan is pre-funded to the extent employer contributions are recoverable through rates. To the extent actual OPEB costs differ from amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $11 million to our other postretirement benefit plan in 2004.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. The benefit obligations and costs reported below, which include prescription drug coverage, do not reflect the impact of this legislation. Current accounting standards that are not yet effective may require changes to previously reported benefit information once they are finalized.
The following table presents the change in benefit obligation, change in plan assets, reconciliation of funded status, and components of net periodic benefit cost for other postretirement benefits as of and for the twelve months ended September 30 (the plan reporting date):
Benefit costs include the following components for the year ended December 31,:
Benefit obligations are based on actuarial estimates and assumptions. The following table details the weighted average assumptions we used for our other postretirement plan for 2003, 2002 and 2001:
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(1) The expected return on plan assets is a pre-tax rate (before a tax rate ranging from 15% to 17% on postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with our debt and equity securities. These expected returns were then weighted based on the target asset allocations of our investment portfolio.
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 10.0 percent in 2003, gradually decreasing to 5.5 percent by the year 2008. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change in assumed health care cost trends would have the following effects:
Other Postretirement Plan Assets. The following table provides the actual asset allocations in our postretirement plan as of September 30:
The target allocation for the invested assets is 65% equity/35% fixed income. In late 2003, we modified our target asset allocations for our postretirement plan to increase our equity allocation to 65 percent of total plan assets. As of September 30, 2003, we had not yet adjusted our portfolio's investments to reflect this change in strategy. Other assets are held in cash for payment of benefits upon presentment. Any El Paso stock held by the plan is held indirectly through investments in mutual funds.
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 support the benefit obligation to participants, retirees and beneficiaries. In meeting this objective, the plan seeks to achieve a high level of investment return consistent with a prudent level of portfolio risk. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall in investment performance compared to investment objectives is the result of general economic and capital market conditions.
12. PREFERRED STOCK
On April 3, 2003, El Paso contributed its 500,000 shares of our 8% preferred stock to us, including accrued dividends of $9 million. The total contribution was approximately $359 million and is reflected as
additional paid in capital in our stockholder's equity. During each of the years ended December 31, 2002 and 2001, we paid $28 million in dividends on our preferred stock.
13. TRANSACTIONS WITH AFFILIATES
We participate in El Paso's cash management program which matches short-term cash surpluses and need requirements of its participating affiliates, thus minimizing total borrowing from outside sources. As of December 31, 2003 and 2002, we had advanced to El Paso $779 million and $990 million. The rate of interest at December 31, 2003 and 2002, was 2.8% and 1.5%. These receivables are due upon demand; however, we do not anticipate settlement within the next twelve months. As of December 31, 2003 and 2002, we have classified $779 million and $565 million as non-current note receivables from affiliates. See Note 2 for a discussion of issues regarding our ongoing participation in and the collectibility of these receivables.
At December 31, 2003 and 2002, we had other accounts receivable from affiliates of $4 million and $7 million. In addition, we had accounts payable to affiliates of $13 million at December 31, 2003, and $33 million at December 31, 2002. These balances arose in the normal course of business. As a result of El Paso's credit rating downgrades, we maintained $6 million and $5 million as of December 31, 2003 and 2002 in contractual deposits related to an affiliate's transportation contract on our EPNG system.
During 2002, we distributed assets with net book values of $19 million to our parent through a dividend.
We provided El Paso Merchant Energy L.P. transportation services for the years ended 2003, 2002 and 2001. We recognized revenues of $18 million, $46 million and $72 million for these periods. We entered into these transactions in the ordinary course of business and the services were based on the same terms as non-affiliates.
El Paso allocated a portion of its general and administrative expenses to us. The allocation is based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll. For the years ended December 31, 2003, 2002 and 2001, the annual charges were $52 million, $49 million and $43 million. TGP allocates payroll to us and other expenses associated with our shared pipeline services. The allocated expenses are based on the estimated level of staff and their expenses to provide the services. For the years ended 2003, 2002 and 2001, the annual charges were $8 million, $7 million and $6 million. El Paso Field Services allocated payroll and other expenses to us. During 2003, 2002 and 2001 those amounts were $9 million, $8 million and $7 million. In addition, we performed operational, financial, accounting and administrative services for, an affiliate, CIG. The amounts received for these services are recorded as reimbursement of operating expenses and for 2003, 2002 and 2001 were $13 million, $12 million and $7 million. We believe all the allocation methods are reasonable.
The following table shows revenues and charges from our affiliates:
14. TRANSACTIONS WITH MAJOR CUSTOMER
The following table shows revenues from our major customer for the years ended December 31:
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(1) Our contracts with Southern California Gas Company include 1,215 BBtu/d which expires in 2006 and 93 BBtu/d which expires 2004 through 2007.
15. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the years ended December 31:
16. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below:
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholder of El Paso Natural Gas Company:
In our opinion, the consolidated financial statements listed in the Index appearing under Item 15(a)(1) present fairly, in all material respects, the consolidated financial position of El Paso Natural Gas Company and its subsidiaries (the "Company") at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.
As discussed in Note 2 to the consolidated financial statements, the Company's indirect parent, El Paso Corporation, may be in default of covenants contained in its revolving credit facility and other financing transactions. Such an event of default could have a material impact on the Company's liquidity. Certain waivers have been obtained by El Paso Corporation, however, additional waivers must be obtained and certain conditions must be satisfied to continue the effectiveness of the waivers.
/s/ PricewaterhouseCoopers LLP
Houston, Texas March 15, 2004
SCHEDULE II
EL PASO NATURAL GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN MILLIONS)
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(1) Reflects charges for the Western Energy Settlement.
(2) Includes a $412 million charge for the Western Energy Settlement.
(3) Relates to payments made pursuant to the Western Energy Settlement.
(4) Relates to amounts collected and paid for our risk sharing provisions with customers.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Controls and Procedures. Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures (Disclosure Controls) and internal controls over financial reporting (Internal Controls) as of the end of the period covered by this Annual Report pursuant to Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934 (Exchange Act).
Definition of Disclosure Controls and Internal Controls. Disclosure Controls are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified under the Exchange Act. Disclosure Controls include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Internal Controls are procedures which are designed with the objective of providing reasonable assurance that (1) our transactions are properly authorized; (2) our assets are safeguarded against unauthorized or improper use; and (3) our transactions are properly recorded and reported, all to permit the preparation of our financial statements in conformity with generally accepted accounting principles.
Limitations on the Effectiveness of Controls. El Paso Natural Gas Company's management, including the principal executive officer and principal financial officer, does not expect that our Disclosure Controls and Internal Controls will prevent all errors and all fraud. 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 the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, 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. Our Disclosure Controls and Internal Controls are designed to provide such reasonable assurances of achieving our desired control objectives, and our principal executive officer and principal financial officer have concluded that our Disclosure Controls and Internal Controls are effective in achieving that level of reasonable assurance.
No Significant Changes in Internal Controls. We have sought to determine whether there were any "significant deficiencies" or "material weaknesses" in El Paso Natural Gas Company's Internal Controls, or whether the company had identified any acts of fraud involving personnel who have a significant role in El Paso Natural Gas Company's Internal Controls. This information was important both for the controls evaluation generally and because the principal executive officer and principal financial officer are required to disclose that information to our Board's Audit Committee and our independent auditors and to report on related matters in this section of the Annual Report. The principal executive officer and principal financial officer note that there has not been any change in Internal Controls that occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Internal Controls.
Effectiveness of Disclosure Controls. Based on the controls evaluation, our principal executive officer and principal financial officer have concluded that the Disclosure Controls are effective to ensure that material information relating to El Paso Natural Gas Company and its consolidated subsidiaries is made known to management, including the principal executive officer and principal financial officer, on a timely basis.
Officer Certifications. The certifications from the principal executive officer and principal financial officer required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as Exhibits to this Annual Report.
PART III
Item 10, "Directors and Executive Officers of the Registrant;" 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," have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit Fees for the years ended December 31, 2003 and 2002 of $588,500 and $490,000 were for professional services rendered by PricewaterhouseCoopers LLP for the audits of the consolidated financial statements of El Paso Natural Gas Company, the review of documents filed with the Securities and Exchange Commission, consents, and the issuance of comfort letters. No other audit-related, tax or other services were provided by our auditors for the years ended December 31, 2003 and 2002.
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.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(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:
(b) REPORTS ON FORM 8-K:
None.
EL PASO NATURAL GAS COMPANY
EXHIBIT LIST DECEMBER 31, 2003
Exhibits not incorporated by reference to a prior filing are designated by an asterisk. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
UNDERTAKING
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and our 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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 15th day of March 2004.
EL PASO NATURAL GAS COMPANY
By /s/ JOHN W. SOMERHALDER II ------------------------------------ John W. Somerhalder II Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
EL PASO NATURAL GAS COMPANY
EXHIBIT INDEX DECEMBER 31, 2003
Exhibits not incorporated by reference to a prior filing are designated by an asterisk. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.