ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview Our Management's Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Item 1A, Risk Factors. 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 2008 performance and an outlook for 2009;
Results of Operations - includes a year-over-year analysis 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 of our sources and uses of cash, available liquidity, our liquidity outlook for 2009, an overview of cash flow activity during 2008, and additional factors that could impact our liquidity;
Off Balance Sheet Arrangements, Contractual Obligations, and Commodity-Based Derivative Contracts - includes a discussion 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 of accounting estimates that involve the use of significant assumptions and/or judgments in the preparation of our financial statements.
Our Business 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 America's largest interstate natural gas pipeline systems that provides a stable base of earnings and cash flow with a significant backlog of committed expansion projects. We are also a large independent natural gas and oil producer focused on generating competitive financial returns through disciplined capital allocation 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, our costs to explore, develop, and produce natural gas and oil, and the volumes we are able to produce, among other factors. While current volatility in the financial markets described further below could influence our near-term profitability, our long-term profitability in each of our operating segments will be primarily influenced by the following factors:
Pipelines
• Continuing to successfully execute on our backlog of committed expansion projects and develop new growth projects in our market and supply areas;

• Contracting and recontracting pipeline capacity with our customers;

• Maintaining or obtaining approval by FERC of acceptable rates, terms of service, and expansion projects; and

• Improving operating efficiency.

---

Table of Contents

Exploration and Production
• Long-term growth of our natural gas and oil proved reserve base and production volumes through successful drilling programs and/or acquisitions;

• Finding and producing natural gas and oil at a reasonable cost; and

• Managing price risks to optimize realized prices on our natural gas and oil production.

In addition to these factors, our future profitability will also be affected by any impacts of the volatility in the current financial and commodity markets, 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 2008 Financial and Operational Performance During 2008, our pipeline operations continued to provide a strong base of earnings and cash flow and in the first half of 2008 while, our exploration and production business benefited from a favorable commodity price environment. However, during the second half of 2008, earnings in our exploration and production business were negatively affected by the adverse impacts on production volumes of Hurricanes Ike and Gustav and a decline in commodity prices. In the fourth quarter of 2008, we recorded non-cash full cost ceiling test charges of $2.7 billion in our domestic and Brazilian full cost pools as a result of this decline in commodity prices.
Our 2008 financial performance was also impacted by favorable resolution of certain litigation and other matters which was largely offset by losses in our Marketing segment from changes in natural gas and oil prices and a decline in interest rates.
The following table provides significant operational highlights of our core businesses in 2008:

Area of Operations Significant Highlights Pipelines Completed several pipeline projects and entered into new expansion projects including our Ruby pipeline project, TGP 300 Line project and FGT phase VIII Project resulting in a current backlog of committed growth projects of approximately $8 billion Placed several expansion projects in service including the WIC Kanda lateral, Phase II of the Cypress pipeline project, Cheyenne Plains compression expansion, Southeast Supply Header Phase I expansion, Medicine Bow expansion, High Plains Pipeline, and Bluewater reconfiguration project Exploration and Achieved an overall drilling success rate of 98 percent Production Advanced growth opportunities domestically in the Niobrara Shale in the Raton Basin, the Haynesville Shale in Arklatex and the Altamont field in the Rockies and internationally through our exploration programs in Brazil and Egypt. In 2008 and early 2009, we executed a unitization agreement and gas and condensate sales agreements with Petrobras to develop the Camarupim Field in Brazil High graded our asset portfolio through the sale of certain non-core properties (primarily in our Texas Gulf Coast and Gulf of Mexico regions) and acquired interests in domestic natural gas and oil properties in the Western region that complement our existing asset portfolio Managed price risk through derivative contracts which, when combined with our other positions, provided higher realized commodity prices in 2008 and gives us price protection on a significant portion of our planned 2009 equivalent production

In our non-core Power segment we sold or transferred several international power investments. In February 2009, we completed the sale of our interest in the Porto Velho power generation facility to our partner. See Item 8, Financial Statements and Supplementary Data, Note 18 for a further discussion of the sale of this investment.

---

Table of Contents

Outlook for 2009 We expect that our pipeline operations will continue to provide a strong base of earnings and operating cash flow in 2009 and anticipate spending approximately $1.7 billion in capital expenditures in this business. In our pipeline business, approximately three-fourths of the revenues are collected in the form of demand or reservation charges which are not dependent upon commodity prices or throughput levels. Also, we expect to have relatively stable rates within our pipeline group, with the majority of our pipelines not having any outstanding rate cases pending before the FERC. We expect two of our pipelines, EPNG and SNG, will be involved in major rate cases in 2009 and we expect those rate cases to result in increased revenues. Finally, we will remain focused on implementing the approximate $8 billion backlog of new committed pipeline growth projects, with several of those projects expected to commence service in 2009.
In our exploration and production business, we expect to generate significant operating cash flow and earnings, although additional non-cash ceiling test charges could impact our earnings in the future as a result of declines in natural gas and oil prices, as they have since December 31, 2008. Reductions in oilfield service costs could partially mitigate the impacts of the commodity price declines. In this business, we have reduced our capital expenditure program for 2009 to a range of $0.9 billion to $1.3 billion from $1.7 billion in 2008. Additionally, current commodity prices remain volatile and at lower levels than we have experienced over the last several years; however, we have financial derivative contracts in place for 2009 providing an average floor price of $9.02 per MMBtu for 176 TBtu of natural gas that will greatly mitigate our natural gas price risk for 2009. We also expect reductions in oilfield service costs in 2009 to the extent that commodity prices and drilling activities remain at lower levels. Although it will also impact our near-term growth profile, the objective of our capital program is to retain substantially all of our existing inventory for future exploration and production when commodity prices return to more favorable levels.
In response to our anticipated 2009 capital requirements and debt maturities, since November 2008 we have successfully generated additional liquidity of approximately $1.9 billion. During this time we completed various debt offerings including $1.2 billion raised through three separate capital market transactions, entered into new credit facilities, and completed non-core asset sales as further described in Liquidity and Capital Resources. As a result, we have available liquidity as of February 27, 2009 of $3.3 billion to carry us into 2010. See Liquidity and Capital Resources below for additional detail. Based on the completion of these activities, we do not expect to have to further access the capital markets for the remainder of 2009, regardless of whether we are successful in obtaining equity partners on any of our capital projects. However, we will continue to be opportunistic in building liquidity when prudent to meet our long-term capital needs.
We have also implemented various cost saving measures to reduce our capital, operating, as well as general and administrative costs. These measures include reducing drilling activity in our exploration and production business in the first half of 2009 until we expect to obtain further reductions in oilfield service costs later in 2009. These measures also include obtaining supply chain management savings with regard to our capital and maintenance programs, renegotiating contracts with contractors, suppliers and service providers, as well as deferring and eliminating various discretionary costs.
The extreme volatility in the financial markets, the energy industry and the global economy will likely continue to impact our outlook for 2009. First, the global financial markets continue to remain extremely volatile and it is uncertain whether recent U.S. and foreign government actions will successfully restore confidence and liquidity in the global financial markets. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital, and may require us to further adjust our current financing and business plans. Second, commodity prices for natural gas and oil remain volatile and at levels substantially below those experienced prior to the fourth quarter of 2008. We may be required to record additional ceiling test charges in the future unless commodity prices significantly increase or oilfield service costs significantly decrease from their current levels. Approximately three-fourths of our domestic natural gas production in 2009 is hedged and is therefore not subject to commodity price exposure. However, we do not currently have substantial hedges in place for 2010 and beyond. Third, while the impacts are difficult to quantify at this point, a downward trend in the global economy could have adverse impacts on natural gas consumption and demand. Although all sectors could be impacted, it is likely industrial demand for energy would be impacted first in any prolonged downturn in the economy. Based on these conditions, our plans for 2009 include:
• Capital Expenditures. Planned 2009 capital expenditures between approximately $2.6 billion to $3.1 billion, with $1.7 billion of capital being spent in our pipeline business and $0.9 billion to $1.3 billion in our exploration and production business. Our $1.7 billion of planned pipeline capital reflects equity partnering on one or more of our expansion projects.

• Asset Sales. We have sold or are evaluating the sale of several non-core assets generating cash proceeds of approximately $0.4 billion in 2009, of which approximately $0.2 billion have already been completed.

---

Table of Contents

• Other Liquidity Sources. We will continue to be opportunistic in generating additional liquidity. In February 2009, we settled our 2009 crude oil production hedges generating $186 million of cash. Additionally, to the extent any of the asset sales or partnering opportunities on expansion projects are delayed or cannot be completed, there is a further decline in commodity prices or we experience other major disruptions in the financial markets, we could also pursue other alternatives, including additional reductions in our discretionary capital program, additional secured financing arrangements, seeking additional partners for one or more of our other growth projects or selling additional non-core assets.

Our 2009 plans were determined based on a number of factors, the most significant of which are noted below:
• Debt Capital Structure. Our debt capital structure is 80 percent fixed interest rates and 20 percent floating interest rates. Accordingly, we believe we have lessened exposure to market changes in interest rates on our existing debt which impact our interest costs.

• Revenue and Price Sensitivities. In our pipeline business, approximately three-fourths of our pipeline revenues are collected in the form of demand or reservation charges. As a result, near-term declines in demand for natural gas due to recessionary pressures or declines in natural gas prices do not significantly impact pipeline revenues. Our exploration and production business, however, is impacted by fluctuations in commodity prices, although this is mitigated somewhat by derivative contracts in place in 2009 representing approximately 75 percent of our domestic natural gas production. Additionally, in the event of lower oil or natural gas prices, we currently have unencumbered exploration and production properties and reserves that we could pledge as collateral to maintain our current available borrowing base under the revolving credit facilities at our exploration and production subsidiary.

• Counterparty Risk. We continually monitor the financial situation of our major lenders, trading counterparties, customers, joint interest partners, vendors and suppliers, and enforce our contractual rights with regard to providing collateral or credit. Certain of our contractual arrangements with such parties include requirements to provide letters of credit, performance bonds or other assurances of performance to mitigate, in part, the risk of non-performance by such parties. However, our natural gas and oil hedges executed in our exploration and production business do not contractually require the posting of margin.

• Lending Institutions. As part of our determination of available capacity under our credit agreements, we completed an assessment of our available lenders under these facilities, which is a diverse group. Based on our assessment, we have determined the potential exposure to a loss of available capacity to be approximately $28 million from El Paso's $1.5 billion revolving credit facility, approximately $2 million from EPEP's $1.0 billion revolving credit facility, and approximately $15 million under EPB's $750 million credit facility. This assessment was based upon the fact that one of our lenders has failed to fund previous requests under these facilities and has filed for bankruptcy.

Our 2009 plans are designed to address the impacts of the current volatility in the global financial markets and to maintain sufficient liquidity to meet 2009 debt maturities and fund our 2009 capital program. Additionally, they are designed to retain our long-term growth potential, including our committed pipeline project backlog and our core domestic and international drilling programs, as well as our natural gas and oil resource inventory positions. In light of the current volatility of the financial markets, the energy industry and the global economy, it is possible additional adjustments to our plan and outlook will be required which could impact our financial and operating performance.

---

Table of Contents

Results of Operations Overview
As of December 31, 2008, 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 assets in South America and Asia. 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) as a measure 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 investors because it allows them to evaluate more effectively 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, (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:

2008 2007 2006 (In millions) Segment Pipelines $ 1,273 $ 1,265 $ 1,187 Exploration and Production (1,448 ) 909 640 Marketing (104 ) (202 ) (71 ) Power 1 (37 ) 82 Segment EBIT (278 ) 1,935 1,838 Corporate and other 124 (283 ) (88 ) Consolidated EBIT (154 ) 1,652 1,750 Interest and debt expense (914 ) (994 ) (1,228 ) Income taxes 245 (222 ) 9 Income (loss) from continuing operations (823 ) 436 531 Discontinued operations, net of income taxes - 674 (56 ) Net income (loss) $ (823 ) $ 1,110 $ 475

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.

---

Table of Contents

Pipelines Segment Overview 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: Percent of Total Type Description Revenues Reservation Reservation revenues are from customers (referred to as firm 76 customers) that reserve capacity on our pipeline systems, storage facilities or LNG terminalling facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Usage and Other Usage revenues are from both firm customers and 24 interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenues from the processing and sale of natural gas liquids and other miscellaneous sources.

The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, 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 maximum allowable rates allowed under our tariffs, although at times, we enter into contracts at less than these maximum allowable rates to remain competitive. We refer to the difference between the maximum rates allowed under our tariff and the contractual rate we charge as "discounts". 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 six years as of December 31, 2008. 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, 2008, including those with terms beginning in 2009 or later:

Percent of Total Percent of Total BBtu/d Contracted Capacity Reservation Revenue Reservation Revenue (In millions) 2009 2,600 10 $ 151 7 2010 3,497 13 287 14 2011 3,104 12 294 15 2012 3,928 15 241 12 2013 3,278 13 248 12 2014 and beyond 9,613 37 819 40 Total 26,020 100 $ 2,040 100

---

Table of Contents

Summary of Operational and Financial Performance In 2008, we continued to deliver strong operational and financial performance across all pipelines. We placed several expansion projects in service including the WIC Kanda lateral project in January, Phase II of the Cypress project in May, the Cheyenne Plains compression expansion project in August, Phase I of the Southeast Supply Header project in September, the Medicine Bow expansion in October and the High Plains Pipeline in November, and continued to make significant progress on our backlog of expansion projects. In September 2008, we contributed additional interests in CIG and SNG to El Paso Pipeline Partners, L.P. (EPB), our master limited partnership, as further discussed in Part I, . . .