El Paso 10-K 2008
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2007
For the transition period from to .
Commission File Number 1-14365
El Paso Corporation
(Exact Name of Registrant as Specified in Its Charter)
Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ.
State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant.
Aggregate market value of the voting stock (which consists solely of shares of common stock) held by non-affiliates of the registrant as of June 29, 2007 computed by reference to the closing sale price of the registrants common stock on the New York Stock Exchange on such date: $12,068,373,398.
Indicate the number of shares outstanding of each of the registrants classes of common stock, as of the latest practicable date.
Common Stock, par value $3 per share. Shares outstanding on February 22, 2008: 700,784,034
Documents Incorporated by Reference
List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Portions of our definitive proxy statement for the 2008 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. These will be filed no later than April 30, 2008.
EL PASO CORPORATION
TABLE OF CONTENTS
Below is a list of terms that are common to our industry and used throughout this document:
When we refer to natural gas and oil in equivalents, we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
When we refer to us, we, our, ours, the Company, or El Paso, we are describing El Paso Corporation and/or our subsidiaries.
ITEM 1. BUSINESS
Business and Strategy
We are an energy company, originally founded in 1928 in El Paso, Texas that primarily operates in the natural gas transmission and exploration and production sectors of the energy industry. Our purpose is to provide natural gas and related energy products in a safe, efficient and dependable manner.
Natural Gas Transmission. We own or have interests in North Americas largest interstate pipeline system with approximately 42,000 miles of pipe that connect North Americas major natural gas producing basins to its major consuming markets. We also provide approximately 230 Bcf of storage capacity and have an LNG receiving terminal and related facilities in Elba Island, Georgia with 806 MMcf of daily base load sendout capacity. The size, connectivity and diversity of our U.S. pipeline system provides growth opportunities through infrastructure development or large scale expansion projects and gives us the capability to adapt to the dynamics of shifting supply and demand. Our focus is to enhance the value of our transmission business by successfully executing on our backlog of committed expansion projects in the United States and Mexico and developing new growth projects in our market and supply areas.
Exploration and Production. Our exploration and production business is currently focused on the exploration for and the acquisition, development and production of natural gas, oil and NGL in the United States, Brazil and Egypt. As of December 31, 2007, we held an estimated 2.9 Tcfe of proved natural gas and oil reserves, not including our equity share in the proved reserves of an unconsolidated affiliate of 0.2 Tcfe. In this business, we are focused on growing our reserve base through disciplined capital allocation and portfolio management, cost control and marketing our natural gas and oil production at optimal prices while managing associated price risks.
Our operations are conducted through two core segments, Pipelines and Exploration and Production. We also have Marketing and Power segments. Our business segments provide a variety of energy products and services and are managed separately as each segment requires different technology and marketing strategies. For a further discussion of our business segments, see Part II, Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data, Note 16.
Our Pipelines segment includes our interstate natural gas transmission systems and related operations conducted through four separate, wholly owned pipeline systems, three majority-owned systems and three partially owned systems. These systems connect the nations principal natural gas supply regions to the five largest consuming regions in the United States: the Gulf Coast, California, the northeast, the southwest and the southeast. We also have access to systems in Canada and assets in Mexico. Our Pipelines segment also includes our ownership of storage capacity through our transmission systems, two underground storage facilities and our LNG terminal and related facilities.
Each of our U.S. pipeline systems and storage facilities operate under Federal Energy Regulatory Commission (FERC) approved tariffs that establish rates, cost recovery mechanisms, and other terms and conditions of service to our customers. The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.
Our strategy is to enhance the value of our transmission and storage business by:
In November 2007, we formed El Paso Pipeline Partners, L.P., our master limited partnership (MLP). We contributed our Wyoming Interstate system and 10 percent general partner interests in each of Southern Natural Gas and Colorado Interstate Gas to the MLP. Our ownership interest in the MLP at December 31, 2007 consists of a two percent general partner interest and a 64.8 percent limited partner interest.
The tables below provide more information on our pipeline systems:
In December 2007, we placed the LPG Burgos pipeline in service. This 117 mile pipeline, in which we own 50%, transports liquified petroleum gas and extends from Pemexs Burgos complex to the Monterrey market in the state of Nuevo Leoń, Mexico. The system has a design capacity of 30 million barrels/day and in 2007 we transported an average of 30 million barrels/day.
As of December 31, 2007, we had the following FERC approved pipeline expansion projects on our systems. For a further discussion of other backlog expansion projects, see Item 7 Managements Discussion and Analysis of Financial Condition and Results of Operations.
Intrastate Transmission Systems
CIG has a 50 percent interest in WYCO Development, L.L.C. (WYCO). WYCO owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to Public Service Company of Colorados (PSCo) Fort St. Vrain electric generation plant. WYCO also owns a compressor station on our WIC systems Medicine Bow lateral in Wyoming and leases these pipeline and compression facilities to PSCo and WIC, respectively, under long-term leases. WYCO currently has two expansion projects underway, the High Plains pipeline and Totem storage expansion projects, expected to be completed in 2008 and 2009. CIG will lease these facilities and will be the operator of these projects.
Underground Natural Gas Storage Facilities
In addition to the storage along our pipeline systems, we own or have interests in the following natural gas storage facilities:
We own an LNG receiving terminal located on Elba Island, near Savannah, Georgia with a peak sendout capacity of 1.2 Bcf/d and a base load sendout capacity of 0.8 Bcf/d. The capacity at the terminal is contracted with subsidiaries of British Gas Group and Royal Dutch Shell PLC.
In September 2007, we received FERC approval to expand the Elba Island LNG receiving terminal and construct the Elba Express Pipeline. The expansion is anticipated to increase the peak sendout capacity of the terminal from 1.2 Bcf/d to 2.1 Bcf/d. The Elba Express Pipeline will consist of approximately 190 miles of pipeline with a total capacity of 1.2 Bcf/d, which will transport natural gas from the Elba Island LNG terminal to markets in the southeastern and eastern United States. In February 2008, we completed our acquisition of a 50 percent interest in the Gulf LNG Clean Energy Project, which is constructing a FERC approved liquefied natural gas terminal in Pascagoula, Mississippi that is expected to be placed in service in late 2011.
Markets and Competition
Our Pipelines segment provides natural gas services to a variety of customers, including natural gas producers, marketers, end-users and other natural gas transmission, distribution and electric generation companies. In performing these services, we compete with other pipeline service providers as well as alternative energy sources such as coal, nuclear energy, wind, hydroelectric power and fuel oil.
Imported LNG is one of the fastest growing supply sectors of the natural gas market. LNG terminals and other regasification facilities can serve as important sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems may also compete with our pipelines for transportation of gas into the market areas we serve.
Electric power generation is the fastest growing demand sector of the natural gas market. The growth of the electric power industry potentially benefits the natural gas industry by creating more demand for natural gas turbine generated electric power. This potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity, increased natural gas prices and the use and availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm transportation contracts with natural gas pipelines.
Our existing contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or remarket expiring capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs although, at times, we discount these rates to remain competitive. The level of discount varies for each of our pipeline systems. The table below shows our firm transportation contracts as of December 31, 2007 for our wholly and majority owned systems that expire by year over the next five years and thereafter.
The following table details information related to our pipeline systems, including the customers, contracts, markets served and the competition faced by each as of December 31, 2007. Firm customers reserve capacity on our pipeline system, storage facilities or LNG terminalling facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they request to transport, store, inject or withdraw.
Regulatory Environment. Our interstate natural gas transmission systems and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Each of our interstate pipeline systems and storage facilities operates under tariffs approved by the FERC that establish rates, cost recovery mechanisms, and terms and conditions for services to our customers. Generally, the FERCs authority extends to:
Our interstate pipeline systems are also subject to federal, state and local pipeline and LNG plant safety and environmental statutes and regulations of the U.S. Department of Transportation, the U.S. Department of Interior and the U.S. Coast Guard. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements, and we believe that our systems are in material compliance with the applicable regulations.
Exploration and Production Segment
Our Exploration and Production segments business strategy focuses on the exploration for and the acquisition, development and production of natural gas, oil and NGL in the United States, Brazil and Egypt. As of December 31, 2007, we controlled over four million net leasehold acres and our proved natural gas and oil reserves at December 31, 2007, were approximately 2.9 Tcfe, which does not include 0.2 Tcfe related to our unconsolidated investment in Four Star Oil and Gas Company (Four Star). During 2007, daily equivalent natural gas production averaged approximately 792 MMcfe/d, not including 70 MMcfe/d from our equity investment in Four Star.
We completed the acquisition of Peoples Energy Production Company (Peoples) in September 2007 for $887 million. This acquisition upgraded our portfolio of assets across a number of our operating regions, primarily the Onshore and Texas Gulf Coast regions. We are also further upgrading our portfolio by selling selected non-core properties that no longer meet our strategic objectives. In January 2008, we entered into agreements to sell $517 million of certain non-core properties in our Onshore and Texas Gulf Coast regions with estimated proved reserves of 191 Bcfe at December 31, 2007. While we do not anticipate exiting any region, our divestitures will be weighted towards the Gulf of Mexico and south Texas areas. We have a balanced portfolio of development and exploration projects, including long-lived and shorter-lived properties divided into the following regions discussed below:
Onshore. The Onshore region includes operations that are primarily focused on unconventional tight gas sands, coal bed methane and lower risk conventional producing areas, which are generally characterized by lower development costs, higher drilling success rates and longer reserve lives. We have a large inventory of drilling prospects in this region. During 2007, we invested $543 million on capital projects, not including acquisitions, and production averaged 374 MMcfe/d. The principal operating areas are listed below:
Included in our Mid-Continent operating area are our interests in 127,000 net acres in West Virginia and 122,000 net acres in the Illinois Basin, primarily in the New Albany Shale area in southwestern Indiana. We are the operator of these properties and maintain a 50 percent working interest in this large emerging area which is still under evaluation. We have drilled 34 gross wells in this basin through the end of 2007.
Texas Gulf Coast. The Texas Gulf Coast region focuses on developing and exploring for tight gas sands in south Texas and the upper Gulf Coast of Texas. In this area, we have an inventory of over 10,000 square miles of three dimensional (3D) seismic data. During 2007, we acquired producing properties and undeveloped acreage in Zapata County, Texas for $254 million. During 2007, we also invested $327 million on capital projects and production averaged 213 MMcfe/d. The principal operating areas are listed below:
Gulf of Mexico and south Louisiana. Our Gulf of Mexico and south Louisiana operations are generally characterized by relatively high initial production rates, resulting in near-term cash flows, and high decline rates. During 2007, we invested $309 million on drilling, workover and facilities projects and production averaged 191 MMcfe/d. The principal operating areas are listed below:
Unconsolidated Investment in Four Star. During the third quarter of 2007, we increased our ownership interest in Four Star from 43 percent to 49 percent. Four Star operates onshore in the San Juan, Permian, Hugoton and South Alabama Basins and the Gulf of Mexico. During 2007, our proportionate share of Four Stars daily equivalent natural gas production averaged approximately 70 MMcfe/d and at December 31, 2007, proved natural gas and oil reserves, net to our interest, were 0.2 Tcfe.
Brazil. Our Brazilian operations cover approximately 361,000 net acres. During 2007, we invested $220 million on capital projects in Brazil. Our operations include interests in 13 concessions located in the Espirito Santo, Potiguar and Camamu Basins, including our 35 percent working interest in the Pescada-Arabaiana Fields in the Potiguar Basin. We currently own 100 percent of the BM-CAL-4 concession which includes the Pinauna project. During 2007, we completed drilling two successful exploratory wells that extended the southern limits of the Pinauna project. We are currently assessing development options and have a process underway to potentially market up to a 50 percent non-operating interest in this concession. In addition, we completed drilling and testing two exploratory wells with Petrobras in the ES-5 Block in the Espirito Basin. These wells confirmed the extension of an earlier discovery by Petrobras on a block to the south. Our production in Brazil, primarily attributable to the Pescada-Arabaiana Fields, averaged approximately 14 MMcfe/d in 2007.
Egypt. Our Egyptian operations include a 20 percent non-operated working interest in approximately 13,000 net acres in the South Feiran concession located in the Gulf of Suez. We are currently in the seismic, exploratory drilling and evaluation phases of the project. Our total funding commitment to the South Feiran concession is $3 million. In 2007, we received formal government approval and signed the concession agreement for the South Mariut Block. The block is approximately 1.2 million acres and is located onshore in the western part of the Nile Delta. We paid $3 million for the concession and agreed to a $22 million firm working commitment over three years. We are currently performing seismic evaluations on the block and expect to drill our first exploratory well in late 2008.
Natural Gas and Oil Properties
Natural Gas, Oil and Condensate and NGL Reserves and Production
The table below presents our estimated proved reserves by region and classification as of December 31, 2007 based on an internal reserve report as well as our 2007 production by region. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
Our consolidated reserves in the table above are consistent with estimates of reserves filed with other federal agencies except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.
Ryder Scott Company, L.P. (Ryder Scott), an independent reservoir engineering firm that reports to the Audit Committee of our Board of Directors, conducted an audit of the estimates of 84 percent of our consolidated proved natural gas and oil reserves as of December 31, 2007. The scope of the audit performed by Ryder Scott included the preparation of an independent estimate of proved natural gas and oil reserves estimates for fields comprising greater than 80 percent of our total worldwide present value of future cash flows (pretax). The specific fields included in Ryder Scotts audit represented the largest fields based on value. Ryder Scott also conducted an audit of the estimates of 75 percent of the proved natural gas and oil reserves of Four Star, our unconsolidated affiliate. Our estimates of Four Stars proved natural gas and oil reserves are prepared by our internal reservoir engineers and do not reflect
those prepared by the engineers of Four Star. Based on the amount of proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable. Ryder Scotts reports are included as exhibits to this Annual Report on Form 10-K.
There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production costs, and projecting the timing of development expenditures, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The reserve data represents only estimates which are often different from the quantities of natural gas and oil that are ultimately recovered. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based, and on engineering and geological interpretations and judgment.
All estimates of proved reserves are determined according to the rules currently prescribed by the Securities and Exchange Commission (SEC). These rules indicate that the standard of reasonable certainty be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive or upward revision is more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate.
In general, the volume of production from natural gas and oil properties declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties with proved reserves, or both, our proved reserves will decline as reserves are produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of proved undeveloped reserves and proved non-producing reserves are subject to greater uncertainties than estimates of proved producing reserves. For further discussion of our reserves, see Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.
Acreage and Wells
The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2007, (ii) our interest in natural gas and oil wells at December 31, 2007 and (iii) our exploratory and development wells drilled during the years 2005 through 2007. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.
In the United States, our net developed acreage is concentrated primarily in the Gulf of Mexico (33 percent), Texas (13 percent), Utah (11 percent), New Mexico (10 percent), Alabama (8 percent), Oklahoma (8 percent) and Louisiana (7 percent). Our net undeveloped acreage is concentrated primarily in New Mexico (34 percent), the Gulf of Mexico (14 percent), Wyoming (10 percent), West Virginia (10 percent), Indiana (8 percent), Alabama (6 percent) and Texas (6 percent). Approximately 14 percent, 8 percent and 5 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2008, 2009 and 2010. Approximately 17 percent, 14 percent and 17 percent of our total Brazilian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2008, 2009 and 2010. Approximately 30 percent of our total Egyptian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2010. We employ various techniques to manage the expiration of leases, including extending lease terms, drilling the acreage ourselves, or through farm-out agreements with other operators.
The drilling performance above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of natural gas and oil that may ultimately be recovered.
Net Production, Sales Prices, Transportation and Production Costs
The following table details our net production volumes, average sales prices received, average transportation costs and average production costs (including production taxes) associated with the sale of natural gas and oil for each of the three years ended December 31:
Acquisition, Development and Exploration Expenditures
The following table details information regarding the costs incurred in our acquisition, development and exploration activities for each of the three years ended December 31:
We spent approximately $200 million in 2007, $192 million in 2006 and $247 million in 2005 to develop proved undeveloped reserves that were included in our reserve report as of January 1 of each year.
Markets and Competition
We primarily sell our domestic natural gas and oil to third parties through our Marketing segment at spot market prices, subject to customary adjustments. We sell our NGL at market prices under monthly or long-term contracts, subject to customary adjustments. In Brazil, we sell the majority of our natural gas and oil to Petrobras, Brazils state-owned energy company. We also enter into derivative contracts on our natural gas and oil production to stabilize our cash flows, reduce the risk and financial impact of downward commodity price movements and to protect the economic assumptions associated with our capital investment programs. As of December 31, 2007, our Exploration and Production segment had entered into derivative swap and option contracts on approximately 141 TBtu of our anticipated 2008 natural gas production, 16 TBtu of our total anticipated 2009-2012 natural gas production, basis swaps on 97 TBtu of our anticipated 2008 production and 15 TBtu of our total anticipated 2009-2012 natural gas production and fixed price swaps on 2,498 MBbls of our anticipated 2008 oil production. For a further discussion of these contracts, see Part II, Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations. Our Marketing segment has also entered into additional production related derivative contracts as further described below.
The exploration and production business is highly competitive in the search for and acquisition of additional natural gas and oil reserves and in the sale of natural gas, oil and NGL. Our competitors include major and intermediate sized natural gas and oil companies, independent natural gas and oil operators and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include price and contract terms, our ability to access drilling and other equipment and our ability to hire and retain skilled personnel on a timely and cost effective basis. Ultimately, our future success in the exploration and production business will be dependent on our ability to find or acquire additional reserves at costs that yield acceptable returns on the capital invested.
Regulatory Environment. Our natural gas and oil exploration and production activities are regulated at the federal, state and local levels, in the United States, Brazil and Egypt. These regulations include, but are not limited to, those governing the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners. We are also subject to governmental safety regulations in the jurisdictions in which we operate.
Our domestic operations under federal natural gas and oil leases are regulated by the statutes and regulations of the U.S. Department of the Interior that currently impose liability upon lessees for the cost of environmental impacts resulting from their operations. Royalty obligations on all federal leases are regulated by the Minerals Management Service, which has promulgated valuation guidelines for the payment of royalties by producers. Our exploration and production operations in Brazil and Egypt are subject to environmental regulations administered by those governments, which include political subdivisions in those countries. These domestic and international laws and regulations affect the construction and operation of facilities, water disposal rights, drilling operations, production or the delay or prevention of future offshore lease sales. In addition, we maintain insurance to limit exposure to sudden and accidental pollution liability exposures.
Our Marketing segments primary focus is to market our Exploration and Production segments natural gas and oil production and to manage the Companys overall price risk, primarily through the use of natural gas and oil derivative contracts. In addition, we continue to manage and liquidate various natural gas supply, transportation, power and other natural gas related contracts remaining from our legacy trading activities, which were primarily entered into prior to the deterioration of the energy trading environment in 2002. As of December 31, 2007, we managed the following types of contracts:
Production-Related Natural Gas and Oil Derivative Contracts
Our natural gas and oil contracts include options designed to provide price protection to El Paso from fluctuations in natural gas and oil prices. These contracts are in addition to contracts entered into by our Exploration and Production segment described in that segment. For a further discussion of the entirety of El Pasos production-related price risk management activities, refer to Item 7, Managements Discussion and Analysis of Financial Condition, Results of Operations and Liquidity and Capital Resources. As of December 31, 2007, our Marketing segments contracts provided El Paso with price protection on the following quantities of future natural gas and oil production:
Contracts Related to Legacy Trading Operations
Natural gas transportation-related contracts. Our transportation contracts give us the right to transport natural gas using pipeline capacity for a fixed reservation charge plus variable transportation costs. Our ability to utilize our transportation capacity under these contracts is dependent on several factors, including the difference in natural gas prices at receipt and delivery locations along the pipeline system, the amount of working capital needed to use this capacity and the capacity required to meet our other long-term obligations. The following table details our transportation contracts as of December 31, 2007:
Other natural gas contracts. As of December 31, 2007, we had eight significant physical natural gas contracts with power plants associated with our legacy trading activities, including MCV. We sold our equity investment in the MCV power facility in 2006. These contracts obligate us to sell gas to these plants and have various expiration dates ranging from 2008 to 2028, with expected obligations under individual contracts with third parties ranging from 12,550 MMBtu/d to 130,000 MMBtu/d.
Power contracts. As of December 31, 2007, we had four derivative contracts that require us to swap locational differences in power prices between four power plants in the PJM eastern region with the PJM west hub. In total, these contracts require us annually to swap locational differences in power prices on approximately 4,000 GWh of power through 2008; 3,700 GWh from 2009 to 2012; 2,400 GWh for 2013 and 1,700 GWh from 2014 to 2016. Additionally, these contracts require us to provide installed capacity of approximately 71 GWh per year in the PJM power pool through 2016. While we have basis and capacity risk associated with the contracts, we do not have commodity risk associated with these contracts due to positions we put in place prior to 2007.
Markets, Competition and Regulatory Environment
Our Marketing segment operates in a highly competitive environment, competing on the basis of price, operating efficiency, technological advances, experience in the marketplace and counterparty credit. Each market served is influenced directly or indirectly by energy market economics. Our primary competitors include major oil and natural gas producers and their affiliates, large domestic and foreign utility companies, large local distribution companies and their affiliates, other interstate and intrastate pipelines and their affiliates, and independent energy marketers and financial institutions. Our marketing activities are subject to the regulations of among others, the FERC and the Commodity Futures Trading Commission.
As of December 31, 2007, our Power segment primarily included the ownership and operation of our remaining investments in international power generation facilities listed below. These facilities primarily sell power under long-term power purchase agreements with power transmission and distribution companies owned by local governments. As a result, we are subject to certain political risks related to these facilities. We continue to pursue the sale of our remaining power investments.
In addition to the international power plants above, we also have investments in two operating pipelines in South America with a total design capacity and average 2007 throughput of 1,197 MMcf/d and 1,162 BBtu/d, unadjusted for our ownership interest.
Regulatory Environment. Our remaining international power generation activities are regulated by governmental agencies in the countries in which these projects are located. Many of these countries have developed or are developing new regulatory and legal structures for private and foreign-owned businesses. These regulatory and legal structures are subject to change over time.
A description of our environmental activities is included in Part II, Item 8 Financial Statements and Supplementary Data, Note 12.
As of February 22, 2008, we had approximately 4,992 full-time employees, of which 204 employees are subject to collective bargaining arrangements.
Executive Officers of the Registrant
Our executive officers as of February , 2008, are listed below.
Douglas L. Foshee has been President, Chief Executive Officer and a director of El Paso since September 2003. He became Executive Vice President and Chief Operating Officer of Halliburton Company in 2003, having joined that company in 2001 as Executive Vice President and Chief Financial Officer. Several subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root, commenced prepackaged Chapter 11 proceedings to discharge current and future asbestos and silica personal injury claims in December 2003 and an order confirming a plan of reorganization became final effective December 31, 2004. Under the plan of reorganization, all current and future asbestos and silica personal injury claims were channeled into trusts established for the benefit of asbestos and silica claimants. Prior to assuming his position at Halliburton, Mr. Foshee was President, Chief Executive Officer and Chairman of the Board of Nuevo Energy Company from 1997 to 2001. From 1993 to 1997, Mr. Foshee served Torch Energy Advisors Inc. in various capacities, including Chief Executive Officer and Chief Operating Officer. Mr. Foshee serves on the Federal Reserve Bank of Dallas, Houston Branch as a director. Mr. Foshee serves on the Board of Trustees of Rice University, where he chairs the Building and Grounds Committee in addition to serving as a member of the Council of Overseers for the Jesse H. Jones Graduate School of Management at Rice University. He is a member of the Greater Houston Partnership Board and Executive Committee and serves as Chair of the Environment Advisory Committee. In addition, Mr. Foshee serves on the Boards of Central Houston, Inc., Childrens Museum of Houston, Goodwill Industries, Small Steps Nurturing Center and the Texas Business Hall of Fame Foundation. Mr. Foshee serves on the board of directors of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.
D. Mark Leland has been Executive Vice President and Chief Financial Officer of El Paso since August 2005. Mr. Leland served as Executive Vice President of El Paso Exploration & Production Company (formerly known as El Paso Production Holding Company) from January 2004 to August 2005, and as Chief Financial Officer and a Director from April 2004 to August 2005. He served in various capacities for GulfTerra Energy Partners, L.P. and its general partner, including as Senior Vice President and Chief Operating Officer from January 2003 to December 2003, as Senior Vice President and Controller from July 2000 to January 2003, and as Vice President from August 1998 to July 2000. Mr. Leland has also worked in various capacities for El Paso Field Services and El Paso Natural Gas Company since 1986. Mr. Leland serves on the board of directors of El Paso Pipeline GP Company, L.L.C.
Robert W. Baker has been Executive Vice President and General Counsel of El Paso since January 2004. From February 2003 to December 2003, he served as Executive Vice President of El Paso and President of El Paso Merchant Energy. He was Senior Vice President and Deputy General Counsel of El Paso from January 2002 to February 2003. Prior to that time he worked in various capacities in the legal department of Tenneco Energy and El Paso since 1983. Mr. Baker serves as Executive Vice President and General Counsel of El Paso Pipeline GP Company, L.L.C.
Brent J. Smolik has been Executive Vice President of El Paso and President of El Paso Exploration & Production Company since November 2006. Mr. Smolik was President of ConocoPhillips Canada from April 2006 to October 2006. Prior to the Burlington Resources merger with ConocoPhillips, he was President of Burlington Resources Canada from September 2004 to March 2006. From 1990 to 2004, Mr. Smolik worked in various engineering management and executive capacities for Burlington Resources Inc.
Susan B. Ortenstone has been Senior Vice President of El Paso since October 2003. Ms. Ortenstone was Chief Executive Officer for Epic Energy Pty Ltd. from January 2001 to June 2003. She served as Vice President of El Paso Gas Services Company and President of El Paso Energy Communications from December 1997 to December 2000. Prior to that time Ms. Ortenstone worked in various strategy, marketing, business development, engineering and operations capacities since 1979. Ms. Ortenstone serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C.
James C. Yardley has been Executive Vice President of El Paso with responsibility for the regulated pipeline business unit since August 2006. He has also served as President of Southern Natural Gas Company since May 1998 and President and Chairman of the Board of Tennessee Gas Pipeline Company since August 2006. Mr. Yardley has also been Chairman of the Board of El Paso Natural Gas Company since August 2006. He has been a member of the Management Committees of both Colorado Interstate Gas Company and Southern Natural Gas Company since their conversion to general partnerships in November 2007. Mr. Yardley served as Vice President, Marketing and Business Development for Southern Natural Gas Company from April 1994 to April 1998. Prior to that time, he worked in various capacities with Southern Natural Gas and Sonat Inc. beginning in 1978. Mr. Yardley serves as Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C.
James J. Cleary has been President of El Paso Natural Gas Company and Colorado Interstate Gas Company since January 2004. He also served as Chairman of the Board of El Paso Natural Gas Company and Colorado Interstate Gas Company from May 2005 to August 2006. From January 2001 to December 2003, he served as President of ANR Pipeline Company. Prior to that time, Mr. Cleary served as Executive Vice President of Southern Natural Gas Company from May 1998 to January 2001. He also worked for Southern Natural Gas Company and its affiliates in various capacities beginning in 1979. Mr. Cleary serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C
Daniel B. Martin has been Director of Colorado Interstate Gas Company, El Paso Natural Gas Company, Southern Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. He was Director of ANR prior to its sale in February 2007. He has been Senior Vice President of El Paso Natural Gas Company since February 2000, Senior Vice President of Southern Natural Gas Company and Tennessee Gas Pipeline Company since June 2000 and Senior Vice President Colorado Interstate Gas Company since January 2001. He was Senior Vice President of ANR Pipeline prior to its sale in February 2007. Prior to 2001, Mr. Martin worked in various capacities with Tennessee Gas Pipeline Company since 1978. Mr. Martin serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C.
Our website is http://www.elpaso.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the SEC. Information about each of our Board members, as well as each of our Boards standing committee charters, our Corporate Governance Guidelines and our Code of Business Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.
ITEM 1A. RISK FACTORS
CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however assumed facts almost always vary from the actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, 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 stated expectation or belief will occur, be achieved or accomplished. The words believe, expect, estimate, anticipate and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking 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 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 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, adverse weather conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses.
While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles and self-insurance levels, as well as limits on our maximum recovery, and do not cover all risks. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.
The success of our pipeline business depends, in part, on factors beyond our control.
Most of the natural gas we transport and store is owned by third parties. The results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume of natural gas we are able to transport and store 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 throughput, or to remarket unsubscribed capacity on our pipeline systems:
Certain of our systems transportation services are subject to long-term, fixed-price negotiated rate contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a negotiated rate which may be above or below the FERC regulated recourse rate for that service, and that contract must be filed and accepted by FERC. These negotiated rate contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between recourse rates (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.
The revenues of our pipeline businesses are generated under contracts that must be renegotiated periodically.
Substantially all of our pipeline subsidiaries revenues are generated under contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:
Fluctuations in energy commodity prices could adversely affect our pipeline businesses.
Revenues generated by our transportation, storage and LNG contracts depend on volumes and rates, both of which can be affected by the prices of natural gas and LNG. Increased prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies loss of customer base. The success of our transmission, storage and LNG operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our systems, which requires the development of additional oil and natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our systems. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of
reserves available for transmission, storage and processing through our systems. Pricing volatility may impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:
The expansion of our pipeline systems by constructing new facilities subjects us to construction and other risks that may adversely affect the financial results of our pipeline businesses.
We may expand the capacity of our existing pipeline, storage or LNG facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.
Natural gas and oil prices are volatile. A substantial decrease in natural gas and oil prices could adversely affect the financial results of our exploration and production business.
Our future financial condition, revenues, results of operations, cash flows and future rate of growth depend primarily upon the prices we receive for our natural gas and oil production. Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current world geopolitical conditions. The prices for natural gas and oil are subject to a variety of additional factors that are beyond our control. These factors include:
Further, because the majority of our proved reserves at December 31, 2007 were natural gas reserves, we are substantially more sensitive to changes in natural gas prices than we are to changes in oil prices. Declines in natural gas and oil prices would not only reduce revenue, but could reduce the amount of natural gas and oil that we can produce economically and, as a result, could adversely affect the financial results of our exploration and production business. A decline in natural gas and oil prices could result in a downward revision of our reserves and a full cost ceiling test write-down of the carrying value of our natural gas and oil properties, which could be substantial, and would negatively impact our net income and stockholders equity.
The success of our exploration and production business is dependent, in part, on the following factors.
The performance of our exploration and production business is dependent upon a number of factors that we cannot control, including:
Our natural gas and oil drilling and producing operations involve many risks and may not be profitable.
Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties and the drilling of natural gas and oil wells, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of natural gas, oil, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks. Additionally, our offshore operations may encounter usual marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, governmental regulations and interruption or termination of drilling rights by governmental authorities based on environmental and other considerations. Each of these risks could result in damage to property, injuries to people or the shut in of existing production as damaged energy infrastructure is repaired or replaced.
We maintain insurance coverage to reduce exposure to potential losses resulting from these operating hazards. The nature of the risks is such that some liabilities could exceed our insurance policy limits, or, as in the case of environmental fines and penalties, cannot be insured which could adversely affect our future results of operations, cash flows or financial condition.
Our drilling operations are also subject to the risk that we will not encounter commercially productive reservoirs. New wells drilled by us may not be productive, or we may not recover all or any portion of our investment in those wells. Drilling for natural gas and oil can be unprofitable, not only because of dry holes but wells that are productive may not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs.
Estimating our reserves, production and future net cash flow is inherently imprecise.
Estimating quantities of proved natural gas and oil reserves is a complex process that involves significant interpretations and assumptions. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical, and engineering data. It also requires making estimates based upon economic factors, such as natural gas and oil prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effect of governmental regulation. Due to a lack of substantial, if any, production data, there are greater uncertainties in estimating proved undeveloped reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise. We also use a ten percent discount factor for estimating the value of our future net cash flows from reserves and a one-day spot price (typically the last day of the year), each as prescribed by the SEC. This discount factor may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our exploration and production business or the natural gas and oil industry, in general, are subject. Additionally, this one day spot price will not generally represent the market prices for natural gas and oil over time. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially.
Our reserve data represents an estimate. You should not assume that the present values referred to in this report represent the current market value of our estimated natural gas and oil reserves. The timing of the production and the expenses related to the development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. Changes in the present value of these reserves could cause a write-down in the carrying value of our natural gas and oil properties, which could be substantial, and would negatively affect our net income and stockholders equity.
A portion of our estimated proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change.
The success of our exploration and production business depends upon our ability to replace reserves that we produce.
Unless we successfully replace the reserves that we produce, our reserves will decline which will eventually result in a decrease in natural gas and oil production and lower revenues and cash flows from operations. We historically have replaced reserves through both drilling and acquisitions. The business of exploring for, developing or acquiring reserves requires substantial capital expenditures. Our operations require continued access to sufficient capital to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics. If we do not continue to make significant capital expenditures, if our capital resources become limited, or if our exploration, development and acquisition activities are unsuccessful, we may not be able to replace the reserves that we produce, which would negatively affect our future revenues, cash flows and results of operations.
We face competition from third parties to acquire and develop natural gas and oil reserves.
The natural gas and oil business is highly competitive in the search for and acquisition of reserves. Our competitors include the major and independent natural gas and oil companies, individual producers, gas marketers and major pipeline companies some of which have financial and other resources that are substantially greater than those available to us, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. In order to expand our leased land positions in intensively competitive and desirable areas, we must identify and precisely locate prospective geologic structures, identify and review any potential risks and uncertainties in these areas, and drill and successfully complete wells in a timely manner. Our future success and profitability in the production business may be negatively impacted if we are unable to identify these risks or uncertainties and find or acquire additional reserves at costs that allow us to remain competitive.
Our use of derivative financial instruments could result in financial losses.
Some of our subsidiaries use futures, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions. To the extent we have positions that are not designated as hedges or do not qualify as hedges, changes in commodity prices, interest rates, volatility, correlation factors and the liquidity of the market could cause our revenues and net income to be volatile.
We could incur financial losses in the future as a result of volatility in the market values of the energy commodities we trade, or if one of our counterparties fails to perform under a contract. The valuation of these financial instruments involves estimates. Changes in the assumptions underlying these estimates can occur, changing our valuation of these instruments and potentially resulting in financial losses. To the extent we hedge our commodity price exposure and interest rate exposure, we forego the benefits we could otherwise experience if commodity prices or interest rates were to change favorably. The use of derivatives, to the extent they require collateral posting with our counterparties, could impact our working capital (current assets less current liabilities) and liquidity when commodity prices or interest rates change. For additional information concerning our derivative financial instruments, see Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Part II, Item 8, Financial Statements and Supplementary Data, Note 7.
Our foreign operations and investments involve special risks.
Our activities in areas outside the United States, including power, pipeline and exploration and production projects in Brazil, exploration and production projects in Egypt and pipeline projects in Mexico, are subject to the risks inherent in foreign operations. As a general rule, we have elected not to carry political risk insurance against these sorts of risks including:
Retained liabilities associated with businesses that we have sold could exceed our estimates and we could experience difficulties in managing these liabilities.
We have sold a significant number of assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold, including breaches of warranties, environmental expenditures, asset maintenance, tax, litigation, personal injury claims and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these businesses, including a reduction in historical knowledge of the assets and businesses and in managing the liabilities retained after closing or defending any associated litigation.
Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plans.
Our pipeline and exploration and production businesses require the retention and recruitment of a skilled workforce. If we are unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.
Risks Related to Legal and Regulatory Matters
The outcome of pending governmental investigations could be materially adverse to us.
We are subject to various governmental investigations by one or more of the following governmental agencies: the SEC, FERC and the U.S. Department of Transportation Office of Pipeline Safety. Although we are cooperating with the governmental agency or agencies in these investigations, the outcome of each of these investigations and the costs to the Company of responding and participating in these investigations is uncertain. The ultimate costs and sanctions, if any, that may be imposed upon us could have a material adverse effect on our business, financial condition or results of operation.
The agencies that regulate our pipeline businesses and their customers could affect our profitability.
Our pipeline businesses are regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. In particular, the FERC regulates the rates our pipelines are permitted to charge their customers for their services and sets authorized rates of return. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC had been using a proxy group of companies that included local distribution companies that are not faced with as much competition or risk as interstate pipelines. The inclusion of these lower risk companies could have created downward pressure on tariff rates when subjected to review by the FERC in future rate proceedings. Recently, the U.S. Court of Appeals for the DC Circuit issued a decision that would require the FERC, if it utilizes lower risk companies in the proxy group, to make upward adjustments to the return on equity to compensate for their lower level of risk. Pursuant to the FERCs jurisdiction over rates, existing rates may be challenged by complaint and proposed
rate increases may be challenged by protest. A successful complaint or protest against our pipelines rates could have an adverse impact on our revenues. In addition, in July 2007, the FERC issued a proposed policy statement addressing the issue of the proxy groups it will use to decide the return on equity of natural gas pipelines. The proposed policy statement describes the FERCs intention to allow the use of master limited partnerships in proxy groups, which we and other pipelines have advocated. However, the FERC also proposed certain restrictions that would reduce the overall benefit that pipelines would receive by use of master limited partnerships in the proxy group. Through our trade association, we have filed comments on the policy and participated in a public conference on this subject.
Additionally, we formed El Paso Pipeline Partners, L.P., a master limited partnership, in 2007. The FERC currently allows publicly traded partnerships to include in their cost-of-service an income tax allowance. Any changes to FERCs treatment of income tax allowances in cost of service and to potential adjustment in a future rate case of our pipelines respective equity rates of return that underlie their recourse rates may cause their recourse rates to be set at a level that is different, and in some instances lower than the level otherwise in effect, could negatively impact our investment in El Paso Pipeline Partners, L.P.
Also, increased regulatory requirements relating to the integrity of our pipelines requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our pipelines local distribution company customers could impose requirements that could impact demand for our pipelines services.
Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.
Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation or clean up of contaminated properties (some of which have been designated as Superfund sites by the Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results of operations, cash flows or financial position. See Part I, Item 3, Legal Proceedings and Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
In estimating our environmental liabilities, we face uncertainties that include:
Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions, including carbon dioxide and methane, are in various phases of discussion or implementation. These include the Kyoto Protocol which has been ratified by some of the international countries in which we have operations such as Mexico, Brazil, and Egypt. In the United States, various federal legislative proposals have been made over the last several years. It is difficult to predict the timing of enactment of any federal legislation, as well as the ultimate legislation that will be enacted. However, components of the legislation that have been proposed in the past could negatively impact our operations and financial results, including whether any of our facilities are designated as the point of regulation for GHG emissions, whether the federal legislation will expressly preempt the potentially conflicting state GHG legislation and how inter-fuel issues will be handled, including how allowances are granted and whether caps will be imposed on GHG charges.
Legislation and regulation are also in various stages of proposal, enactment, and implementation in many of the states in which we operate. This includes various initiatives of individual states and coalition of states in the northeastern portion of the United States that are members of the Regional Greenhouse Gas Initiative and seven western states that are members of the Western Climate Initiative.
Additionally, various governmental entities and environmental groups have filed lawsuits seeking to force the federal government to regulate GHG emissions and individual companies to reduce the GHG emissions from their operations. These and other suits may also result in decisions by federal agencies and state courts and other agencies that impact our operations and ability to obtain certifications and permits to construct future projects.
These legislative, regulatory, and judicial actions could result in changes to our operations and to the consumption and demand for natural gas and oil. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG emissions program.
While we may be able to include some or all of any costs in our rates charged by our pipelines and in the prices at which we sell natural gas and oil, such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.
Costs of litigation matters and other contingencies could exceed our estimates.
We are involved in various lawsuits in which we or our subsidiaries have been sued (see Part II, Item 8, Financial Statements and Supplementary Data, Note 12). We also have other contingent liabilities and exposures. Although we believe we have established appropriate reserves for these liabilities, we could be required to set aside additional amounts in the future and these amounts could be material.
Risks Related to Our Liquidity
We have significant debt and below investment grade credit ratings, which have impacted and will continue to impact our financial condition, results of operations and liquidity.
We have significant debt, debt service and debt maturity obligations. The ratings assigned to El Pasos senior unsecured indebtedness are below investment grade, currently rated Ba3 with a positive outlook by Moodys Investor Service (Moodys) and BB- with a positive outlook by Standard & Poors. These ratings have increased our cost of capital and our operating costs, particularly in our marketing operations, and could impede our access to capital markets. Although we must retain greater liquidity levels to operate our business than if we had investment grade credit ratings, the simplification of our capital structure and business has reduced the amount of liquidity we maintain in the ordinary course of business. If there is significant volatility in energy commodity prices or interest rates, then these lower liquidity levels might not be adequate. In such an event, if our ability to generate or access capital becomes significantly restrained, then our financial condition and future results of operations could be significantly adversely affected. See Part II, Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of our debt.
A breach of the covenants applicable to our debt and other financing obligations could affect our ability to borrow funds and could accelerate our debt and other financing obligations and those of our subsidiaries.
Our debt and other financing obligations contain restrictive covenants, which become more restrictive over time, and contain cross default provisions. A breach of any of these covenants could preclude us or our subsidiaries from issuing letters of credit, from borrowing under our credit agreements and could accelerate our debt and other financing obligations and those of our subsidiaries. If this were to occur, we might not be able to repay such debt and other financing obligations.
Additionally, some of our credit agreements are collateralized by our equity interests in EPNG and TGP as well as certain natural gas and oil reserves. A breach of the covenants under these agreements could permit the lenders to exercise their rights to foreclose on these collateral interests.
Adverse changes in general domestic economic conditions could adversely affect our operating results, financial condition, or liquidity.
We are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. Recently, the direction and relative strength of the U.S. economy has been increasingly uncertain due to softness in the housing markets, rising oil prices, and difficulties in the financial services sector. If economic growth in the United States is slowed, demand growth from consumers for natural gas and oil produced and transported by us on our natural gas transportation systems may decrease which could impact our planned growth capital. Additionally, our access to capital could be impeded. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.
We are subject to financing and interest rate risks.
Our future success, financial condition and liquidity could be adversely affected based on our ability to access capital markets and obtain financing at cost effective rates. This is dependent on a number of factors, many of which we cannot control, including changes in:
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
A description of our properties is included in Part I, 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. LEGAL PROCEEDINGS
Details of the cases listed below, as well as a description of our other legal proceedings are included in Part II, Item 8, Financial Statements and Supplementary Data, Note 12, and are incorporated herein by reference.
Fort Morgan Storage Field. CIG owns and operates an underground natural gas storage field in the vicinity of Fort Morgan, Colorado. In October 2006, the production casing in one of the fields injection and withdrawal wells failed resulting in the emergence of natural gas from the storage reservoir at the ground surface. In June 2007, CIG received a proposed Administrative Order of Consent (AOC) from the Colorado Oil and Gas Conservation Commission (Commission). In January 2008, the Commission approved the AOC with a settlement of all alleged violations with a penalty of $374,000.
Rawlins Plant Notice of Probable Violation. CIG owns and operates the Rawlins Gas Plant and Compressor Station which produces butane, propane, and natural gas liquids. Recently, CIG discovered that emissions from the loading process were emitted into the atmosphere and reported the discovery to the Wyoming Department of Environmental Quality (Department) which issued a Notice of Violation. CIG has reached an agreement with the Department to pay a total of $83,000 and to conduct a supplemental environmental program to install additional equipment which will reduce future emissions.
Natural Buttes. On May 19, 2004, the Federal Environmental Protection Agency (EPA) issued a Compliance Order (Order) to CIG related to alleged violations of a Title V air permit in effect at CIGs Natural Buttes Compressor Station. On July 7, 2004, the EPA issued a confidential Pre-filing Settlement Offer which contained a proposed fine of $350,000. In September 2005 the matter was referred to the U.S Department of Justice (DOJ). We have entered into a tolling agreement with the United States and have concluded settlement discussions in principle with the DOJ and the EPA, setting a penalty of $470,000, which includes $50,000 in incremental costs for a Supplemental Environmental Project. We have established a reserve for this penalty amount, and we anticipate a documented settlement in the first half of 2008.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Our common stock is traded on the New York Stock Exchange under the symbol EP. As of February 22, 2008, we had 33,757 stockholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.
Quarterly Stock Prices. The following table reflects the quarterly high and low sales prices for our common stock based on the daily composite listing of stock transactions for the New York Stock Exchange and the cash dividends per share we declared in each quarter:
Stock Performance Graph. This graph reflects the comparative changes in the value of $100 invested since December 31, 2002 as invested in (i) El Pasos common stock, (ii) the Standard & Poors 500 Stock Index, (iii) the Standard & Poors 500 Oil & Gas Storage & Transportation Index and (iv) our peer group identified below. The Peer Group we used for this comparison is the same group we use to compare total shareholder return relative to our performance for compensation purposes. Our peer group for 2007 included the following companies: Anadarko Petroleum Corp., Apache Corp., CenterPoint Energy Inc., Devon Energy Corp., Dominion Resources, Inc., Enbridge, Inc., Equitable Resources, Inc., NiSource, Inc., ONEOK, Inc., PG&E Corp., PPL Corp., Questar Corp., Sempra Energy, Southern Union Co., Spectra Energy Corp., Transcanada Corp. and Williams Companies, Inc. Our peer group for 2006 included the companies listed above as well as Western Gas Resources, Inc. and Kinder Morgan, Inc., but did not include Spectra Energy Corp.
COMPARISON OF ANNUAL CUMULATIVE TOTAL RETURNS
Dividends Declared. On February 7, 2008, we declared a quarterly dividend of $0.04 per share of our common stock, payable on April 1, 2008, to shareholders of record as of March 7, 2008. Future dividends will depend on business conditions, earnings, our cash requirements and other relevant factors.
Other. The terms of our 750,000 outstanding shares of 4.99% convertible preferred stock prohibit the payment of dividends on our common stock unless we have paid or set apart for payment all accumulated and unpaid dividends on such preferred stock for all preceding dividend periods. In addition, although our credit facilities do not contain any direct restrictions on the payment of dividends, dividends are included as a fixed charge in the calculation of our fixed charge coverage ratio under our credit facilities. If our fixed charge ratio were to exceed the permitted maximum level, our ability to pay additional dividends would be restricted.
Odd-lot Sales Program. We have an odd-lot stock sales program available to stockholders who own fewer than 100 shares of our common stock. This voluntary program offers these stockholders a convenient method to sell all of their odd-lot shares at one time without incurring any brokerage costs. We also have a dividend reinvestment and common stock purchase plan available to all of our common stockholders of record. This voluntary plan provides our stockholders a convenient and economical means of increasing their holdings in our common stock. Neither the odd-lot program nor the dividend reinvestment and common stock purchase plan have a termination date; however, we may suspend either at any time. You should direct your inquiries to Computershare Trust Company, N.A., our stock transfer agent at 1-877-453-1503.
ITEM 6: SELECTED FINANCIAL DATA
The following selected historical financial data as of and for the years ended December 31, 2004 to 2007 is derived from our audited consolidated financial statements for El Paso and its subsidiaries and is not necessarily indicative of results to be expected in the future. The amounts as of and for the year ended December 31, 2003, are derived from unaudited consolidated financial statements. Such amounts were adjusted to reflect the reclassification of ANR, our Michigan storage assets and our 50% interest in Great Lakes Gas Transmission as discontinued operations. The selected financial data should be read together with Part II, Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K.
Factors Affecting Trends. Prior to 2006, our financial position and operating results were substantially affected by the restructuring and realignment of our business around our core pipeline and exploration and production operations. Accordingly, we sold a substantial amount of non-core assets to reduce our long-term financing obligations resulting in a significant reduction of our revenues and net income during the years ended December 31, 2003, 2004, and 2005. We recorded net pretax charges of approximately $0.1 billion in 2005, $1.1 billion in 2004 and $1.3 billion in 2003, primarily as a result of losses and impairments of assets and equity investments, restructuring charges, and settling litigation. In 2007, we sold our ANR pipeline system and related assets and also completed the offering of common units in El Paso Pipeline Partners, L.P., our master limited partnership.
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Our Managements Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further beginning on page 27. Listed below is a general outline of our MD&A:
Our Business includes a summary of our business purpose and description, factors influencing profitability, a summary of our 2007 performance, an outlook for 2008 and an update of our credit profile;
Results of Operations includes a year-over-year analysis beginning on page 44 of the results of our business segments, our corporate activities and other income statement items, including trends that may impact our business in the future;
Liquidity and Capital Resources includes a general discussion beginning on page 65 of our debt obligations, available liquidity, expected 2008 cash flows, and significant factors that could impact our liquidity, as well as an overview of cash flow activity during 2007;
Off Balance Sheet Arrangements, Contractual Obligations, and Commodity-Based Derivative Contracts includes a discussion beginning on page 68 of our (i) off balance sheet arrangements, including guarantees and letters of credit, (ii) other contractual obligations, and (iii) derivative contracts used to manage the price risks associated with our natural gas and oil production and;
Critical Accounting Estimates includes a discussion beginning on page 71 of accounting estimates that involve the use of significant assumptions and/or judgments in the preparation of our financial statements.
Our business purpose is to provide natural gas and related energy products in a safe, efficient and dependable manner. We own or have interests in North Americas largest interstate natural gas pipeline systems and are a large independent natural gas and oil producer focused on growing our reserve base through disciplined capital investment and portfolio management, cost control and marketing and selling our natural gas and oil production at optimal prices while managing associated price risks.
Factors Influencing Our Profitability. Our pipeline operations are rate-regulated and accordingly we generate profit based on our ability to earn a return in excess of our costs through the rates we charge our customers. Our exploration and production operations generate profits dependent on the prices for natural gas and oil and the volumes we are able to produce, among other factors. Our future profitability in each of our operating segments will be primarily influenced by the following factors:
Exploration and Production
In addition to these factors, our future profitability will also continue to be impacted by our debt level and related interest costs, the successful resolution of our historical contingencies and completing the orderly exit of our remaining power assets, historical derivative contracts and other remaining non-core assets.
Summary of Overall Performance in 2007. The year ended December 31, 2007 marked our fifth consecutive year of improved profitability, driven primarily by a strong base of earnings and cash flow in our pipeline and exploration and production businesses as well as an interest expense reduction of approximately 20 percent. Across our pipeline system, we made progress on our backlog of committed expansion projects and created El Paso Pipeline Partners, L.P., our master limited partnership. In our exploration and production business, we experienced continued success in our worldwide exploration and drilling programs. These successes allowed us to replace our worldwide natural gas and oil reserves and move forward in high grading our portfolio to improve our cost structure. The following provides additional details of these items and other significant highlights in our core businesses in 2007:
In addition, our 2007 performance was impacted by our Marketing and Power segments where we continued to reduce the size and volatility of these operations and by corporate costs incurred in conjunction with simplifying and strengthening our balance sheet. Specifically, we incurred (i) mark-to-market losses in our Marketing segment on production-related option contracts and legacy positions, including our Pennsylvania-New Jersey-Maryland (PJM) power contracts and (ii) incremental losses in our Power segment on Brazilian power investments. Additionally, in 2007, we (i) incurred debt extinguishment costs of approximately $291 million in conjunction with repurchasing or refinancing more than $5 billion of debt to strengthen our balance sheet and (ii) resolved certain legal and contractual disputes (see, Item 8, Financial Statements and Supplementary Data, Note 12).
Outlook. For 2008, we expect the current operating trends in our core pipeline and exploration and production businesses to continue with a focus on growing these businesses. For each business, we expect the following:
Pipelines We anticipate that our pipeline operations will continue to provide strong operating results based on its expansion plans, the current levels of contracted capacity, and the status of its rate and regulatory actions. In the pipeline industry, a favorable macroeconomic environment supports continued industry growth. We expect to spend significant pipeline growth capital in 2008. These expenditures should lay the foundation for future growth and the advancement of our significant backlog of committed expansion projects in our market and supply areas and in the development of significant new infrastructure opportunities. Additionally, we will continue to pursue proposed joint venture development projects that would use our incumbent pipeline infrastructure to connect supply areas to areas of high demand in the West, Northeast and Southeast. Finally, we expect to grow our MLP through organic growth opportunities, potential acquisitions, or through future asset contributions. Currently we have in excess of $2 billion in net operating losses available to us to offset any potential tax gains on future asset contributions to the MLP.
Exploration and Production We expect to continue with the momentum established in 2007 and seek to create value through a disciplined and balanced capital investment program. Our drilling programs will focus on growing reserves at reasonable finding and development costs, and growing production efficiently through active cost management. In 2008, our domestic programs will constitute approximately 80 percent of our planned capital and substantially all of our expected production. Performance of these programs will require successful integration and execution of our 2007 acquisitions and our 2008 planned divestitures. In 2008, our International capital is expected to increase approximately 50 percent over our 2007 program. Successful execution of these programs, primarily in Brazil, will require effective project management, partner relations and successful negotiations with regulatory agencies. Our future financial results will be primarily dependent on the continued successful execution of these drilling programs and favorable commodity prices to the extent our anticipated natural gas and oil production is unhedged. Based on our current derivative positions, we anticipate our 2008 hedging program will provide protection from price exposure on a substantial portion of our anticipated natural gas and oil production as previously described.
Credit Profile. Our outstanding debt was $12.8 billion at December 31, 2007. In 2007, we strengthened our credit profile as a result of several actions taken during the year including:
Results of Operations
As of December 31, 2007, our core operating business segments were Pipelines and Exploration and Production. We also have a Marketing segment that markets our natural gas and oil production and manages our legacy trading activities and a Power segment that has interests in several international power plants. Our segments are managed separately, provide a variety of energy products and services, and require different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses, contracts and assets all of which are immaterial.
Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business segments, which consist of both consolidated businesses and investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income or loss from continuing operations, such as discontinued operations and the impact of accounting changes, (ii) income taxes and (iii) interest and debt expense. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods or capital structure. 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 flows.
Below is a reconciliation of our EBIT (by segment) to our consolidated net income (loss) for each of the three years ended December 31:
The discussions that follow provide additional analysis of the year over year results of each of our business segments, our corporate activities and other income statement items.
Our Pipelines segment operates primarily in the United States and consists of interstate natural gas transmission, storage and LNG terminalling related services. We face varying degrees of competition in this segment from other existing and proposed pipelines and proposed LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. Our revenues from transportation, storage, LNG terminalling and related services consist of two types:
The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, market conditions, regulatory actions, competition, weather and declines in the creditworthiness of our customers. We also experience earnings volatility at certain pipelines when the amount of natural gas used in operations differs from the amounts we receive for that purpose.
Historically, much of our business was conducted through long-term contracts with customers. However, many of our customers have shifted from a traditional dependence on long-term contracts to a portfolio approach, which balances short-term opportunities with long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new supply sources, volatility in natural gas prices, demand for short-term capacity and new power plant markets.
We continue to manage our recontracting process to limit the risk of significant impacts on our revenues from expiring contracts. Our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs, although we discount these rates at various levels for each of our pipeline systems to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for active contracts is approximately five years as of December 31, 2007. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts on our wholly and majority owned systems as of December 31, 2007, including those with terms beginning in 2008 or later:
In November 2007, we completed an offering of common units in an MLP. We contributed 100 percent of WIC (our wholly owned interstate pipeline transportation business located primarily in Wyoming and Colorado) and 10 percent equity interests in CIG and SNG to the MLP. We have both a 2 percent general partner interest and a 64.8 percent limited partner interest in the MLP.
Summary of Operational and Financial Performance
In 2007, we continued to deliver strong financial performance across all pipelines. We placed several expansion projects in service including Phase I of the SNG Cypress project, TGP Louisiana Deepwater Link project, TGP Triple-T Extension project, TGP Northeast Connexion-New England project and Mexico LPG Burgos project and continued to make significant progress on our backlog of expansion projects. We also successfully resolved our EPNG and Mojave rate cases and restructured and renewed certain customer contracts. During 2007, we benefited from (i) higher realized rates on certain of our systems, (ii) increased throughput, and (iii) increased activity under other various interruptible services.
The level of throughput on our systems can provide evidence of the underlying long-term value of our system capacity. In 2007, increased throughput across our system was a result of broad based increases in power demand from Mexico, California, the Northeast and the Southeast based on underlying growth in electricity demand, colder weather and lower availability of hydroelectric power in the Northwest. We have also experienced higher supply related throughput as a result of our Rockiesrelated expansions.
During 2008, we currently plan on spending $1.6 billion in capital, of which $1.2 billion will be targeted towards our backlog of expansion projects. We intend to build on the growth achieved in 2007 and currently have almost $4 billion in committed expansion projects that comprise our backlog as follows:
Other Large Projects in Development. We also have two development projects underway, the recently announced Ruby Pipeline project and the Northeast Passage project. Combined, these projects are estimated to cost over $4 billion (over $2 billion net to our interests) with estimated in-service dates in 2011. These projects are in various phases of development, including obtaining necessary customer commitments and holding ownership discussions.
The table below and discussion that follows detail the impact on EBIT of significant events in 2007 compared with 2006 and 2006 as compared with 2005. We have also provided an outlook on events that may affect our operations in the future.
Reservation and Usage Revenues. During the year ended December 31, 2007, our EBIT was favorably impacted by:
Partially offsetting these favorable impacts in 2007 was the expiration of certain firm transportation contracts on our EPNG, MPC and SNG systems.
The increase in our reservation and usage revenues in 2006 compared with 2005 was primarily due to:
Expansions. During 2007 and 2006, our reservation revenues and throughput volumes increased due to projects placed in service. Below is a discussion of our expansion projects placed in service.
Projects Placed in Service in 2007 and 2006. During 2007, we placed several expansion projects in service including Phase I of the Cypress project, the Louisiana Deepwater Link project, the Triple-T Extension project, the Northeast Connexion-New England project and the Mexico LPG Burgos project. In 2006, we placed several expansion projects in service including the Cheyenne Plains Yuma Lateral project, the Elba Island LNG expansion and the Piceance Basin project on our WIC system.
Projects Placed in Service in 2008. In January 2008, we completed the WIC Kanda Lateral project which should increase annual revenues by approximately $25 million.
Gas Not Used in Operations, Revaluations, Processing Revenues and Other Natural Gas Sales. During the year ended December 31, 2007, our EBIT was unfavorably impacted by the (i) revaluation of net gas imbalances and other gas owed to our customers in our CIG and WIC systems as a result of increasing natural gas prices in 2007 versus decreasing natural gas prices in 2006 (ii) lower processing revenues and operational gas costs on our CIG system due to a decrease in processing volumes and natural gas liquids. Partially offsetting these unfavorable impacts in 2007 were higher volumes of gas not used in TGPs operations.
During 2006, higher realized prices on sales of gas not used in operations resulted in favorable impacts to our operating revenues, partially offset by lower sales volumes of natural gas not used in operations during 2006 compared to 2005. We also experienced favorable impacts to our operating expenses in 2006 due to decreases in the index prices used to value the net imbalance position on several of our pipeline systems. In 2005, higher gas prices caused an increase in our obligation to replace system gas and settle gas imbalances in the future, resulting in an unfavorable impact on our 2005 operating results. In addition, our pipelines also retained lower volumes of gas not used in operations during 2005. We anticipate that the overall activity in this area will continue to vary based on factors such as volatility in natural gas prices, the efficiency of our pipeline operations, regulatory actions and other factors.
Hurricanes Katrina and Rita. During 2007, we incurred lower operation and maintenance expenses to repair damage caused by Hurricanes Katrina and Rita as compared to 2006. In 2006, we recorded higher operation and maintenance expenses compared with 2005 as a result of unreimbursed amounts expended to repair hurricane damage. We do not anticipate that expenditures related to these hurricanes, net of related reimbursements, will materially impact our future financial results.
Asset Impairments. During 2007, we recorded a $10 million impairment of certain pipeline assets originally purchased to repair certain offshore hurricane damage following a decision not to use these assets. In addition, we recorded a loss of approximately $9 million pursuant to a FERC determination on the accounting treatment for the pending sale of certain transmission facilities. During 2006 and 2005, we impaired various pipeline development projects based on changing market conditions. In 2006, these impairments included $13 million and $3 million due to discontinuing our Continental Connector Pipeline
project and the remainder of our Seafarer Project. In 2005, we recorded impairments of $18 million and $28 million due to discontinuing a portion of our Seafarer project and the entirety of our Blue Atlantic development project.
General and Administrative Expenses. During the year ended December 31, 2007, our general and administrative expenses were higher than in 2006 primarily due to increased insurance costs for wind damage on our pipeline assets located primarily in the Gulf of Mexico region. Our general and administrative costs were lower in 2006 than 2005, primarily due to a decrease in accrued benefit costs and lower allocated costs from El Paso based on the estimated level of resources devoted to the pipeline segment and the relative size of its EBIT, gross property and payroll as compared to the consolidated totals.
Depreciation Expense. Depreciation expense was higher for 2006 compared to 2005 primarily due to higher depreciation rates applied to EPNGs property, plant and equipment following its 2006 rate case.
Operating Costs (Including Pipeline Integrity). During 2007, we incurred higher operating costs than in 2006 primarily due to increased repair and maintenance costs, allowances for non-trade accounts receivable and environmental reserves. During 2006, we incurred higher costs than in 2005 primarily for repairs and maintenance and $19 million of pipeline integrity costs which we began expensing in 2006 as a result of the adoption of an accounting release issued by the FERC.
Bankruptcy Settlements. In 2007, we received $10 million to settle our bankruptcy claim against USGen New England, Inc. During 2007 and 2006, we recorded income of approximately $5 million and $18 million, net of amounts potentially owed to certain customers, related to amounts recovered from the Enron bankruptcy settlement. In February 2008, we received a portion of the bankruptcy settlement under Calpine Corporations approved plan of reorganization. In connection with this plan, we received Calpine common stock with a market value of approximately $29 million, on which we will recognize a gain in the first quarter of 2008.
Equity Earnings from Citrus. During the year ended December 31, 2007, equity earnings on our Citrus investment increased primarily due to (i) a favorable settlement of approximately $8 million for litigation brought against Spectra LNG Sales (formerly Duke Energy LNG Sales, Inc.) for the wrongful termination of a gas supply contract; (ii) Citrus sale of a receivable for approximately $3 million related to the bankruptcy of Enron North America and (iii) favorable operating results of approximately $8 million from Florida Gas Transmission Company, a pipeline owned 100 percent by Citrus, due to higher system usage and lower operating costs.
Regulatory Matters/Rate Cases. Our pipeline systems periodically file for changes in their rates, which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Currently, certain of our pipelines have no requirements to file new rate cases in 2008 and expect to continue operating under their existing rates. Certain other pipelines have recently completed, or are in rate proceedings or have upcoming rate actions including the following:
Exploration and Production Segment
Overview and Strategy
Our Exploration and Production segment conducts our natural gas and oil exploration and production activities. The profitability and performance of this segment are driven by the ability to locate and develop economic natural gas and oil reserves and extract those reserves with the lowest possible production and administrative costs. Accordingly, we manage this business with the goal of creating value through disciplined capital allocation, cost control and portfolio management.
Our domestic natural gas and oil reserve portfolio blends slower decline rate, typically longer lived assets in our Onshore region with steeper decline rate and shorter lived assets in our Texas Gulf Coast, Gulf of Mexico and south Louisiana regions. We believe the combination of our assets in these domestic regions provides significant near-term cash flow while providing consistent opportunities for competitive investment returns. In addition, our international activities in Brazil and Egypt provide opportunity for additional future reserve additions and longer term cash flows.
As part of our business strategy, we attempt to create value through a balance of drilling activities, exploration, and through acquisitions of assets and companies. For 2008, we expect our growth to occur principally through drilling activities and we will continue to evaluate acquisition and growth opportunities that are tightly focused around our core competencies and areas of competitive advantage. We believe strategic acquisitions can support our corporate objectives by:
In September 2007, we acquired Peoples, which provided an upgrade to our portfolio of assets. We are also further upgrading our portfolio by selling selected properties. In January 2008, we entered into agreements to sell $517 million of certain non-core properties in our Onshore and Texas Gulf Coast regions with estimated proved reserves of 191 Bcfe at December 31, 2007. These sales are expected to close in the first quarter of 2008. We expect upgrading our portfolio will extend the reserve life of our assets, reduce unit operation and maintenance costs, increase predictability, improve capital efficiency and expand the depth of our inventory.
In addition to executing on our strategy, the profitability and performance of our exploration and production operations can be substantially impacted by (i) changes in commodity prices, (ii) industry-wide increases in drilling and oilfield service costs, and (iii) the effect of hurricanes and other weather impacts on our daily production, operating and capital costs. To the extent possible, we attempt to mitigate these factors. As part of our risk management activities, we have entered into derivative contracts on a significant portion of our anticipated 2008 natural gas and oil production to reduce the financial impact of downward commodity price movements.
Significant Operational Factors Affecting the Year Ended December 31, 2007
Production. Our average daily production for the year was 792 MMcfe/d (not including 70 MMcfe/d from our share of production from our equity investment in Four Star). Our production levels grew in every quarter of 2007. Below is a further analysis of our 2007 production by region (MMcfe/d):
Onshore region Our 2007 production continued to increase through capital projects where we maintained or increased production in most of our major operating areas, with the majority of growth coming from the Rockies and Arklatex areas. Our Peoples acquisition in September 2007 also contributed to production volume increases during the year.
Texas Gulf Coast region The acquisition of properties in Zapata County during the first quarter of 2007 and the success of our drilling program more than offset natural production declines and the sale of certain non-strategic south Texas properties in 2006. Our Peoples acquisition in September 2007 also contributed to production volume increases during the year.
Gulf of Mexico and south Louisiana region We began producing from development wells in the western Gulf and south Louisiana and several exploratory discoveries occurring prior to 2007. We also recovered volumes previously shut-in by hurricane damage which, when coupled with these new production sources, helped to offset natural production declines.
Brazil Production volumes decreased in 2007 due to natural production declines and a contractual reduction of our ownership interest in the Pescada-Arabaiana Fields in early 2006.
Four Star Our original ownership interest in Four Star was obtained in the Medicine Bow acquisition in August 2005. In January 2007, Four Star acquired properties that added production of approximately 5 MMcfe/d, net of our interest on the acquisition date. In the third quarter of 2007, we spent $27 million to increase our ownership interest in Four Star from 43 percent to 49 percent.
2007 Drilling Results
Onshore. We realized a 99 percent success rate on 502 gross wells drilled.
Texas Gulf Coast. We experienced a 92 percent success rate on 84 gross wells drilled.
Gulf of Mexico and south Louisiana. We drilled six successful wells and seven unsuccessful wells.
Brazil. We currently own 100 percent of the BM-CAL-4 concession in the Camamu Basin. In 2007, we completed drilling two successful exploratory wells south of the Pinauna Field in this concession that extends the southern limits of the Pinauna project. We are currently assessing development options and have a process underway to potentially market up to a 50 percent non-operating interest in this concession. In addition, we completed drilling and testing two exploratory wells with Petrobras in the ES-5 Block in the Espirito Basin. These wells confirmed the extension of an earlier discovery by Petrobras on a block to the south. We are currently in negotiations with Petrobras on a unitization agreement for the development of this discovery.
Egypt. In 2007, we received formal government approval and signed the concession agreement for the South Mariut Block. The block is approximately 1.2 million acres and is located onshore in the western part of the Nile Delta. We paid $3 million for the concession and agreed to a $22 million firm working commitment over three years. We are currently performing seismic evaluations on the block and expect to drill our first exploratory well in late 2008.
Cash Operating Costs. We monitor cash operating costs required to produce our natural gas and oil volumes. These costs are calculated on a per Mcfe basis and include total operating expenses less depreciation, depletion and amortization expense, other non-cash expense items and the cost of products and services on our income statement. In 2007, cash operating costs per unit increased to $1.88/Mcfe as compared to $1.86/Mcfe in 2006. Our operating costs increased primarily as a result of higher production taxes which increased due to higher natural gas and oil reserves, lower severance tax credits, higher marketing and other costs and higher corporate overhead allocations.
Reserve Replacement Costs/Reserve Replacement Ratio. We calculate two primary metrics, (i) a reserve replacement ratio and (ii) reserve replacement costs, to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. The reserve replacement ratio is an indicator of our ability to replenish annual production volumes and grow our reserves. It is important for us to economically find and develop new reserves that will more than offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of adding reserves which is ultimately included in depreciation, depletion and amortization expense. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core asset areas at a lower cost than our competition. We calculate these metrics as follows:
Both the reserve replacement ratio and reserve replacement costs per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio is limited because it typically varies widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. In addition, since the reserve replacement ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
The exploration for and the acquisition and development of natural gas and oil reserves is inherently uncertain as further discussed in Part I, Item 1A, Risk Factors, Risks Related to our Business. One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped. At December 31, 2007, proved developed reserves represent approximately 71 percent of total proved reserves. Proved developed reserves will generally begin producing within the year they are added whereas proved undeveloped reserves generally require a major future expenditure.
The table below shows our reserve replacement costs and reserve replacement ratio for our domestic and worldwide operations for each of the years ended December 31:
In 2007, our domestic reserve replacement costs decreased primarily due to favorable acquisitions and finding and development costs and upward revisions in previous estimates of reserves due to higher commodity prices at December 31, 2007. We typically cite reserve replacement costs in the context of a multi-year trend, in recognition of its limitation as a single year measure, but also to demonstrate consistency and stability, which are essential to our business model. For the three year period ending December 31, 2007, our average reserve replacement costs for our domestic and worldwide operations were $3.31/Mcfe and $3.40/Mcfe, including acquisitions, and $3.64/Mcfe and $3.75/Mcfe excluding acquisitions.
Capital Expenditures. Our capital expenditures were as follows for the three years ended December 31:
Outlook for 2008
For 2008, we anticipate the following on a worldwide basis:
Price Risk Management Activities
As part of our strategy, we enter into derivative contracts on our natural gas and oil production to stabilize cash flows, to reduce the risk and financial impact of downward commodity price movements on commodity sales and to protect the economic assumptions associated with our capital investment programs. Because this strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. Adjustments to our hedging strategy and the decision to enter into new positions or to alter existing positions are made at the corporate level based on the goals of the overall company.
The following table and discussion that follows shows, as of December 31, 2007, the contracted volumes and the minimum, maximum and average prices we will receive under these contracts when combined with the sale of the underlying hedged production:
All of our oil fixed price swaps and 86 percent of our natural gas fixed price swaps and option contracts are designated as accounting hedges. Gains and losses associated with these natural gas contracts are deferred in accumulated other comprehensive income and will be recognized in earnings upon the sale of the related production at market prices, resulting in a realized price that is approximately equal to the hedged price. With regard to our natural gas positions, approximately 7 TBtu of our fixed price swaps, 15 TBtu of our option contracts and all of our basis swaps are not designated as accounting hedges. Accordingly, changes in the fair value of these derivatives are recognized in earnings each period.
During January and February 2008, we entered into (i) 47 TBtu of options on our anticipated 2008 natural gas production with a floor price of $8.00 per MMBtu and an average ceiling price of $10.64 per MMBtu; (ii) 7 TBtu of options on our anticipated 2009 natural gas production with a floor price of $8.00 per MMBtu and a ceiling price of $11.05 per MMBtu; and (iii) 292 MBbls of fixed price swaps on our anticipated 2008 oil production at a price of $99.00 per barrel. All of these contracts were designated as accounting hedges, except for 19 TBtu of the 2008 natural gas option contracts. The total of all our positions provides price protection on approximately two-thirds of our planned 2008 equivalent production.
Additionally, the table above does not include contracts entered into by our Marketing segment as further described in that segment. For the consolidated impact of the entirety of El Pasos production-related price risk management activities on our overall liquidity, see the discussion of factors that could impact our liquidity in Liquidity and Capital Resources.
Operating Results and Variance Analysis
The tables below and the discussion that follows provide the operating results and analysis of significant variances in these results during the periods ended December 31:
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Our EBIT for 2007 increased $269 million as compared to 2006. The table below lists the significant variances in our operating results in 2007 as compared to 2006:
Operating revenues. During 2007, revenues increased compared with 2006 due to higher realized natural gas and oil prices, including the effects of our hedging program. Realized gains on hedging transactions were $177 million during 2007, as compared to losses of $58 million in 2006. During 2007, we also benefited from an increase in production volumes in all domestic regions over 2006.
Other revenue. During 2007, we recognized mark-to-market gains of $7 million compared to losses of $40 million in 2006 related to the change in fair value of derivatives not designated as hedges, including a portion of our oil and natural gas fixed price swaps, option contracts and basis swaps.
Depreciation, depletion and amortization expense. During 2007, our depletion rate increased as compared to the same periods in 2006 as a result of the Peoples and Zapata County, Texas property acquisitions and higher finding and development costs.
Production costs. Our production taxes increased during 2007 as compared to 2006 primarily due to higher natural gas and oil revenues and lower severance tax credits in 2007.
General and administrative expenses. Our general and administrative expenses increased during 2007 as compared to 2006 primarily due to higher marketing and other costs previously included in our Marketing segment and higher corporate overhead allocations.
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Our EBIT for 2006 decreased $56 million as compared to 2005. The table below lists the significant variances in our operating results in 2006 as compared to 2005:
Operating revenues. Natural gas revenues decreased by approximately $197 million as natural gas prices were not as strong in 2006 as compared to 2005. However, we experienced lower hedging program losses for 2006 of $58 million compared to losses of $260 million for 2005. Realized oil, condensate and NGL prices increased in 2006 when compared to 2005.
Our production volumes benefited in 2006 from our acquisitions in 2005. However, overall production volumes decreased in our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions due to natural declines, and the sale of certain non-strategic south Texas properties with average production of 5 MMcfe/d in 2006. Also, our Gulf of Mexico and south Louisiana region production continued to be impacted in 2006 by Hurricanes Katrina and Rita, which occurred in late 2005. Our production volumes in Brazil decreased due to the contractual reduction of our ownership interest in the Pescada-Arabaiana Fields in 2006.
Depreciation, depletion and amortization expense. During 2006, we experienced higher depletion rates as compared to 2005 primarily as a result of higher finding and development costs and the cost of acquired reserves. However, lower production volumes in 2006 partially offset the impact of these higher depletion rates.
Production costs. In 2006, our lease operating costs increased as compared to 2005 in all regions as a result of inflation in fuel costs, power and other services. In our Onshore region, additional increases were due to increased subsurface maintenance and our acquisition of Medicine Bow. In the Gulf of Mexico region, additional increases were due to hurricane repairs not recoverable through insurance. Additionally, production taxes increased as a result of lower tax credits in Texas taken in 2006 compared to 2005.
General and administrative expenses. Our general and administrative expenses decreased during 2006 as compared to the same period in 2005, primarily due to lower corporate overhead allocations.
Other. During 2006, we recorded a loss of approximately $40 million of the fair value of our derivatives not designated as hedges as compared to a $9 million loss in 2005. In 2006, our EBIT was also unfavorably impacted by earnings from Four Star due to lower natural gas prices. Our EBIT was favorably impacted by operations at our processing plants and insurance recoveries resulting from Hurricane Ivan, among other items.
Our Marketing segments primary focus is to market our Exploration and Production segments natural gas and oil production and to manage the Companys overall price risks, primarily through the use of natural gas and oil derivative contracts. In addition, we continue to manage and liquidate remaining legacy natural gas supply, transportation, power and other natural gas contracts entered into prior to the deterioration of the energy trading environment in 2002. Any future liquidations may impact our cash flows and financial results. However, we may not liquidate certain of these remaining legacy contracts before their expiration if (i) they are uneconomical to sell or terminate in the current environment due to their terms, credit concerns of the counterparty or lack of liquidity in the market or (ii) a sale would require an acceleration of cash demands. The table that follows provides a description of our remaining contracts and our remaining exposure on these contracts. All mark-to-market contracts are subject to interest rate exposure as the interest rates used in determining the fair market values are subject to change from period to period.
Overview. Over the past three years, our operating results and year-to-year comparability have been impacted by significant commodity and other market fluctuations, changes in the composition of our portfolio (and related effort to manage our portfolio) based on actions taken to reduce exposure and exit our legacy trading activities. The tables below and discussions that follow provide further information about these events, our overall operating results and analysis by significant contract type for our Marketing segment during each of the three years ended December 31:
Our 2007 results were primarily driven by mark-to-market losses on our production-related option contracts and legacy natural gas and power positions (including our PJM contracts). These losses were partially offset by $23 million of other income recognized upon the sale of our investment in the NYMEX and $28 million of EBIT ($23 million of revenues and $5 million of other income) related to the settlement of outstanding California power price disputes.
Our 2006 and 2005 financial results were significantly impacted by:
Production-related Natural Gas and Oil Derivative Contracts
Options contracts. Our production-related natural gas and oil derivative contracts are designed to provide protection to El Paso against changes in natural gas and oil prices. These are in addition to those derivative contracts entered into by our Exploration and Production segment which are further described in the discussion of that segment above. For the consolidated impact of all of El Pasos production-related price risk management activities, refer to our Liquidity and Capital Resources discussion. The fair value of our derivative contracts is impacted by changes in commodity prices from period-to-period and is marked-to-market in our results. Listed below are the volumes and average prices associated with our production-related derivative contracts as of December 31, 2007:
We experience volatility in our financial results based on changes in the fair value of our option contracts which generally move in the opposite direction from changes in forward commodity prices. During 2007 and 2005, increases in forward commodity prices reduced the fair value of our option contracts resulting in a loss. During 2006, decreases in forward commodity prices increased the fair value of our option contracts resulting in a gain. We received approximately $45 million and $59 million in 2007 and 2006 and paid $40 million in 2005 on contracts that settled during those periods.
Contracts Related to Legacy Trading Operations
Natural gas transportation-related contracts. As of December 31, 2007, our transportation contracts provide us with approximately 0.6 Bcf/d of pipeline capacity. The recovery of demand charges related to our transportation contracts and therefore the profitability of these contracts, is dependent upon our ability to use or remarket the contracted pipeline capacity, which is impacted by a number of factors including differences in natural gas prices at contractual receipt and delivery locations, the working capital needed to use this capacity and the capacity required to meet our other long term obligations. In November, 2007, our future earnings exposure relating to our transportation contracts was reduced with the transfer of our Alliance capacity to a third party. As of December 31, 2007, our contracts require us to pay demand charges of approximately $41 million in 2008 and an average of $24 million between 2009 and 2012. Our transportation contracts are accounted for on an accrual basis and impact our revenues as delivery or service under the contracts occurs. The following table is a summary of demand charges (in millions) and percentage of recovery of these charges for each of the three years ended December 31:
Other natural gas derivative contracts. In 2006 we divested or entered into transactions to divest of a substantial portion of these natural gas contracts, which substantially reduced our exposure to price movements on these contracts. However, we maintain contracts with third parties that require us to purchase or deliver natural gas primarily at market prices including a gas supply contract with the MCV power facility. Additionally, we recognized a $49 million gain in 2006 associated with the assignment of certain natural gas derivative contracts to supply natural gas in the southeastern U.S. In 2006 in conjunction with sale of the MCV facility in our Power segment, we recorded a cumulative mark to market loss of approximately $133 million which had not been previously recognized due to our affiliated ownership interest.
Power Contracts. By the end of 2005, we had substantially eliminated exposure to power price movements on our legacy power contracts. Prior to eliminating this price risk, we experienced significant net decreases in the fair value of these contracts based primarily on changes in natural gas and power prices as well as differences in locational power prices.
The remaining exposure in our power portfolio is related to several contracts that require us to swap locational differences in power prices between power plants in the Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub, and provide installed capacity in the PJM power pool through 2016. The fair value of these contracts decreased by approximately $100 million in 2007 and increased by approximately $70 million in 2006. The losses in 2007 were primarily the result of increasing installed capacity prices in the PJM region, while the gains in 2006 primarily related to locational price differences in these regions. By the end of 2006, we had eliminated the commodity price risk associated with these contracts. In 2007, the PJM Independent System Operator began conducting periodic auctions to set prices for providing installed capacity to customers in the PJM power pool. The fair value of our power contracts is impacted by changes in installed capacity prices, which are based in part on the result of these auctions. The results of future auctions, and other potential developments with our contracts and the PJM marketplace may result in future volatility in our operating results. We estimate that a ten percent change in auction prices from the most recent capacity price of $174/MW-day would change the fair value of our contracts by approximately $5 million.
Other. During 2005, a bankruptcy court entered an order allowing Mohawk River Funding IIIs, our subsidiarys, bankruptcy claims with USGen New England. We received payment on these claims and recognized a gain of $17 million in 2005 in other income related to this settlement.
Overview. Our Power segment consists of assets in Brazil, Asia and Central America. We continue to pursue the sales of these remaining power investments. As of December 31, 2007, our remaining investment, guarantees and letters of credit related to projects in this segment totaled approximately $548 million, which consisted of approximately $514 million in equity investments and notes receivable and approximately $34 million in financial guarantees and letters of credit as follows:
Operating Results. In 2007, our results were primarily negatively impacted by impairment losses in Brazil related to the Porto Velho, Manaus and Rio Negro projects. Prior to 2006, our financial results in this segment were significantly impacted by impairments, net of gains and losses on sale, on both domestic and other international power facilities. A further discussion of these events and other factors impacting our results in this segment for the three years ended December 31 are listed below:
Brazil. In 2007, our Porto Velho project, Manaus and Rio Negro projects and our other Brazilian operations (including our interests in the Bolivia-to-Brazil and Argentina-to-Chile pipelines) generated EBIT losses of $27 million, EBIT losses of $6 million and EBIT of $12 million, respectively. Our 2007 results included charges of $57 million for Porto Velho and $15 million for Manaus and Rio Negro based on adverse developments at these projects. In 2006 and 2005, EBIT was $41 million and $23 million for Porto Velho, $17 million and $19 million for Manaus and Rio Negro and $6 million and $13 million for our other Brazilian operations. For a further discussion of matters that have impacted or could impact our Brazilian investments, see Item 8, Financial Statements, Note 17.
Other International Power. During 2005, we recorded impairments of $176 million which were significantly offset by gains on sales of assets of $131 million based on the value received or expected to be received upon closing the sales of our assets in Asia and Central America. Our results were also impacted by our decision to not recognize earnings from assets we planned to sell based on our inability to realize those earnings through their expected selling price. We did not recognize earnings of approximately $10 million, $26 million and $30 million for the years ended 2007, 2006 and 2005. We continue to pursue the sale of our remaining investments in Asia and Central America and until these sales are completed, any changes in regional political and economic conditions could negatively impact the anticipated proceeds we may receive, which could result in additional impairments of our investments.
Domestic Power. In 2006, we completed the disposition of our domestic power business. We recorded a gain in this segment of approximately $10 million, primarily related to the sale of our investment in MCV. The disposition of our investment in MCV in 2006 also impacted certain contracts and the financial results in our Marketing segment. Prior to 2006 we sold our interests in several domestic power facilities and restructured power contracts, resulting in significant impairments and substantially lower earnings from these operations. In addition, we recorded our proportionate share of MCVs losses based on their impairment of the plant assets in 2005.
Prior to January 1, 2006, we had a Field Services segment. During 2005, we generated EBIT of $285 million which, among other items, was primarily due to a gain of $183 million on the sale of our general partner and limited partner interests in Enterprise Products Partners, L.P. and a gain of $111 million on the sale of our Javelina processing operations.
Corporate and Other Expenses, Net
Our corporate activities include our general and administrative functions as well as a number of miscellaneous businesses, which do not qualify as operating segments and are not material to our current year results. The following is a summary of significant items impacting the EBIT in our corporate activities for each of the three years ended December 31:
Extinguishment of Debt. During 2007, we incurred losses of $291 million in conjunction with repurchasing or refinancing more than $5 billion of debt. This amount included $86 million related to repurchasing EPEPs $1.2 billion notes. For further information on our debt, see Item 8, Financial Statements, Note 11.
Litigation, Insurance, and Other Reserves. During 2007, we recorded a gain of approximately $77 million on the reversal of a liability related to The Coastal Corporations legacy crude oil marketing and trading business. For a further discussion of this matter, see Item 8, Financial Statements, Note 12. We also have a number of pending litigation matters against us. In all of these matters, we evaluate each lawsuit and claim as to its merits and our defenses. Adverse rulings and unfavorable settlements against us related to these matters impacted our results in 2007 and 2006 and may further impact our future results. In 2005, we recorded significant charges in operation and maintenance expense to increase our litigation, insurance and other reserves based on ongoing assessments, developments and evaluations of the possible outcomes of these matters. In 2005, the most significant item was a charge in connection with a ruling by an appellate court that we indemnify a former subsidiary for certain payments being made under a retiree benefit plan. Additionally, in 2005 we incurred charges of $72 million primarily related to the final prepayment of the Western Energy Settlement and additional charges related to increased premiums from a mutual insurance company in which we participate, based primarily on the impact of several hurricanes in 2005.
Interest and Debt Expense
Our interest and debt expense was approximately $1.0 billion, $1.2 billion and $1.3 billion during the years ended December 31, 2007, 2006 and 2005.
Our total interest and debt expense has decreased over the past three years primarily due to the retirements of debt and other financing obligations, net of issuances. See Part II, Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion.
In 2007, our overall effective tax rate on continuing operations for each period differed from the statutory rate due primarily to earnings from unconsolidated affiliates where we anticipate receiving dividends that qualify for the dividend received deduction. In 2006 and 2005, we recorded $159 million and $58 million of tax benefits based primarily on the conclusion of IRS audits. In 2006, the audits of The Coastal Corporations 1998-2000 tax years and El Pasos 2001 and 2002 tax years were concluded which resulted in the reduction of tax contingencies and the reinstatement of certain tax credits. In 2005, we finalized The Coastal Corporations IRS tax audits for years prior to 1998.
For a discussion of our effective tax rates and other tax matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 4.
Our discontinued operations in the years presented primarily include our ANR pipeline and related assets, our gathering and processing operations in south Louisiana and certain international power operations. For the year ended December 31, 2007, income from discontinued operations was $674 million primarily a result of the gain on the sale of ANR and related operations of $648 million, net of income taxes of $354 million. For the years ended December 31, 2006 and 2005, we had losses from our discontinued operations of $56 million and $96 million. Our 2006 loss of $56 million was primarily a result of recording approximately $188 million of deferred taxes upon agreeing to sell the stock of ANR, our Michigan storage assets and our 50 percent interest in Great Lakes Gas Transmission. Prior to our decision to sell, we were only required to record deferred taxes on individual assets and liabilities and a portion of our investment in the stock of one of these companies. Our 2005 loss of $96 million was primarily a result of impairments of our discontinued international power operations partially offset by income from ANR and related assets and a gain on the sale of our south Louisiana operations. All of these items are further discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 2.
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
Liquidity and Capital Resources
Sources and Uses of Cash. Our primary sources of cash are cash flow from operations and amounts available to us under revolving credit facilities. On occasion and as conditions warrant, we may also generate funds through capital market activities and proceeds from asset sales. Our primary uses of cash are funding the capital expenditure programs of our pipeline and exploration and production operations, meeting operating needs, and repaying debt when due or repurchasing certain debt obligations when conditions warrant.
Overview of Cash Flow Activities. During 2007, we generated positive operating cash flow of approximately $1.8 billion, primarily as a result of cash provided by our pipeline and exploration and production operations. We also sold our ANR pipeline and related assets which generated $3.7 billion of net proceeds. We utilized our operating cash flow and cash from the sale of ANR to fund maintenance and growth projects in our pipeline and exploration and production operations and to reduce our debt obligations (see Item 8, Financial Statements, Note 11). In November 2007, we issued units in a master limited partnership generating gross proceeds of $575 million from the initial public offering. For the year ended December 31, 2007 and 2006, our cash flows from continuing operations are summarized as follows:
The contribution of cash generated from our discontinued operations reflected above consists of the following for the year ended December 31, 2007:
Credit Profile. The substantial repayment of debt obligations during 2007 improved our credit profile and our credit ratings. In March 2007, Moodys Investor Services upgraded our pipeline subsidiaries senior unsecured debt rating to an investment grade rating of Baa3 and upgraded El Pasos senior unsecured debt rating to Ba3 while maintaining a positive outlook. Additionally, in March 2007, (i) Standard and Poors upgraded our pipeline subsidiaries senior unsecured debt rating to BB and upgraded El Pasos senior unsecured debt rating to BB- maintaining a positive outlook and (ii) Fitch Ratings initiated coverage on El Paso assigning a rating of BB+ on our senior unsecured debt and an investment grade rating of BBB- to our pipeline subsidiaries senior unsecured debt. This improvement should provide us a lower cost of capital on our planned expansion projects in our pipeline business.
In addition, during 2007 we restructured our El Paso and El Paso Exploration & Production revolving credit agreements with improved terms and pricing and refinanced approximately $2.0 billion of EPEP, SNG and EPNG debt providing us with a lower cost of debt with less restrictive covenants. We also established a pipeline MLP which provides us a lower cost of capital and allows us to better compete for expansion projects of our pipeline business. We expect to grow our MLP through organic growth and accretive acquisitions from third parties, El Paso or both.
Liquidity/Cash Flow Outlook. For 2008, we expect to continue to generate positive operating cash flows. We also anticipate generating over $1 billion upon the completion of asset divestitures in conjunction with high grading our exploration and production asset portfolio and completing remaining international power asset sales. We anticipate using cash proceeds from our exploration and production divestitures to repay debt in the first quarter of 2008. We expect to use our cash from operations and remaining sales proceeds primarily for working capital requirements and for expected capital expenditures. We have approximately $0.3 billion of debt that matures through December 31, 2008 that we currently intend on refinancing. Additionally, we previously announced our intention to repurchase debt of approximately $0.5 billion of CIG and SNG. In December 2007, we repurchased approximately $0.2 billion and anticipate completing the remaining $0.3 billion of repurchases in the first half of 2008.
Our planned cash capital expenditures for 2008 are as follows:
Factors That Could Impact Our Future Liquidity. Based on the simplification of our capital structure and our businesses, we have reduced the amount of liquidity needed in the normal course of business. However, our liquidity needs could increase or decrease based on certain factors described below and others listed in Part 1, Item 1A, Risk Factors. These factors include, but are not limited to, the completion of planned asset sales, the effect that our debt level, and below investment grade credit ratings could have on our cost of capital, our ability to access capital markets, and operating costs (primarily margining requirements related to our derivative positions) and adverse changes in domestic economic conditions, including recession or economic slowdown, which could also impact the demand for our natural gas transportation services and ultimately impact our planned growth capital.
Price Risk Management Activities and Cash Margining Requirements. Our Exploration and Production and Marketing segments have derivative contracts that provide price protection on a portion of our anticipated natural gas and oil production. The following table shows the contracted volumes and the minimum, maximum and average cash prices that we will receive under our derivative contracts when combined with the sale of the underlying production as of December 31, 2007. These cash prices may differ from the income impacts of our derivative contracts, depending on whether the contracts are designated as hedges for accounting purposes or not. The individual segment discussions provide additional information on the income impacts of our derivative contracts.
During January and February 2008, we entered into (i) 47 TBtu of options on our anticipated 2008 natural gas production with a floor price of $8.00 per MMBtu and an average ceiling price of $10.64 per MMBtu; (ii) 7 TBtu of options on anticipated 2009 natural gas production with a floor price of $8.00 per MMBtu and a ceiling price of $11.05 per MMBtu; and (iii) 292 MBbls of fixed price swaps on our anticipated 2008 oil production at a price of $99.00 per barrel.
We currently post letters of credit for the required margin on most of our derivative contracts. Historically, we were required to post cash margin deposits for these amounts. During 2007, approximately $90 million of posted cash margin deposits were returned to us resulting from settlement of the related contracts and changes in commodity prices. In 2008, based on current prices, we expect approximately $0.2 billion of the total of $1.0 billion in collateral outstanding at December 31, 2007 to be returned to us, primarily in the form of letters of credit.
Depending on changes in commodity prices, we could be required to post additional margin or may recover margin earlier than anticipated. Based on our derivative positions at December 31, 2007, a $0.10/MMBtu increase in the price of natural gas would result in an increase in our margin requirements of approximately $14 million which consists of $5 million for transactions that settle in 2008, $3 million for transactions that settle in 2009 and $6 million for transactions that settle in 2010 and thereafter. We have a $250 million unsecured contingent letter of credit facility available to us if the average NYMEX gas price strip for the remaining calendar months through March 2008 reaches $11.75 per MMBtu, which is further described in Item 8, Financial Statements, Note 11.
Off-Balance Sheet Arrangements
We enter into a variety of financing arrangements and contractual obligations, some of which are referred to as off-balance sheet arrangements. These include guarantees, letters of credit and other interests in variable interest entities.
We are involved in joint ventures and other ownership arrangements that sometimes require additional financial support in the form of financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. For example, if the guaranteed party is required to purchase services from a third party and then fails to do so, we would be required to either purchase these services or make payments to the third party to compensate them for any losses they incurred because of this non-performance. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental matters and necessary expenditures to ensure the safety and integrity of the assets sold.
Our potential exposure under guarantee and indemnification agreements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. For those arrangements with a specified dollar amount, we have a maximum stated value of approximately $785 million, for which we are indemnified by third parties for $15 million. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 11. Included in the above maximum stated value is approximately $438 million related to indemnification arrangements associated with the sale of ANR and related operations and approximately $119 million related to tax matters, related interest and other indemnifications and guarantees arising out of the sale of our Macae power facility. As of December 31, 2007, we have recorded obligations of $51 million related to our guarantees and indemnification arrangements, of which $8 million is related to ANR and related assets and Macae. We are unable to estimate a maximum exposure for our guarantee and indemnification agr