Summary of EL PASO CORP/DE

Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in our 2008 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.
Overview and Outlook During the quarter ended March 31, 2009, our pipeline operations continued to provide a strong base of earnings and operating cash flow. 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. We remain focused on implementing the nearly $8 billion backlog of committed pipeline growth projects, with several of those projects expected to commence service in 2009.
In our exploration and production business, we continued to generate significant positive operating cash flow during the quarter despite a low commodity price environment, principally as a result of derivatives we have in place related to our 2009 production. As of March 31, 2009, we had 120 TBtu of natural gas hedges with an average floor price of $9.02 per MMBtu and an average ceiling price of $14.35 per MMBtu and 1,348 MBbls of crude oil swaps at $45 per barrel on our remaining anticipated 2009 production. However, lower natural gas prices at the end of the first quarter of 2009 resulted in approximately $2.1 billion of non-cash ceiling test charges, primarily in our domestic full cost pool, which significantly impacted our overall first quarter 2009 results. The ceiling test charges did not consider the value of our financial derivative contracts which was $573 million as of March 31, 2009. If commodity prices decrease further and we do not experience anticipated further reductions in oilfield service costs, we may be required to record additional non-cash ceiling test charges in the future.
In both of our core businesses, we have implemented various cost saving measures to reduce our capital, operating, and general and administrative costs. These measures include reducing drilling activity in our exploration and production business until we experience further expected reductions in oilfield service costs, realizing cost reductions in our capital and maintenance programs by renegotiating contracts with contractors, suppliers and service providers, and deferring and eliminating various discretionary costs.
The volatility in the financial markets, the energy industry and the global economy is expected to continue for the remainder of 2009 and possibly beyond. 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. Additionally, commodity prices for natural gas and oil have been and are expected to remain volatile, and although we have attempted to mitigate the effects of these reductions in commodity prices by entering into derivative contracts on our natural gas and oil production, we still have a portion of our production subject to the current lower commodity price environment as further described below. Finally, while the impacts are difficult to quantify, a continued downward trend in the global economy could have adverse impacts on natural gas consumption and demand over time. All of these factors may impact our outlook for the remainder of 2009 and beyond.
As of March 31, 2009, we had approximately $3.3 billion of available liquidity (see Liquidity and Capital Resources) and have designed our 2009 plans to address the impacts of current volatility in the global financial markets. Based on our activities to date, we do not anticipate a need to further access the capital markets to meet our 2009 debt maturities or fund our 2009 capital program, regardless of whether we are successful in obtaining equity partners on any of our capital projects. When prudent, however, we will continue to be opportunistic in building liquidity to meet our long-term capital needs. There are no assurances, however, that we will be able to access the financial markets to fund our long-term capital needs. Our 2009 plans are also 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 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.

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Currently, these plans include:
• Capital Expenditures. Planned 2009 capital expenditures between approximately $2.7 billion to $3.0 billion, with $1.7 billion of capital being spent in our pipeline business and $0.9 billion to $1.2 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. In our exploration and production business, although it will also impact our near-term growth profile in this business, the objective of reductions in our capital program is to retain substantially all of our existing natural gas and oil resource positions for future exploration and production when commodity prices and oilfield service costs return to more favorable levels.

• 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.

• Other Liquidity Sources. We will continue to be opportunistic in generating additional liquidity, which may include additional asset sales or partnering opportunities on expansion projects. To the extent these opportunities 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, further reductions in operating and general and administrative expenses, additional secured financing arrangements, seeking additional partners for one or more of our other growth projects or selling additional non-core assets.

Our plans were determined based on a number of factors, the most significant of which are described below and in further detail in our 2008 Annual Report on Form 10-K:
• Debt Capital Structure. Our debt capital structure is 82 percent fixed interest rates and 18 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. As previously discussed, we have mitigated our sensitivity to commodity prices with approximately three-fourths of our pipeline revenues collected in the form of demand or reservation charges and derivative contracts in our exploration and production business. As noted above, we have significant derivative contracts in place for our 2009 natural gas and oil production. We have also entered into derivative contracts on a substantial portion of our anticipated 2010 natural gas production and a portion of our 2011 natural gas production to mitigate exposure to low commodity prices; however, we continue to have some commodity price exposure in 2010 and beyond. Finally, 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 continue to monitor the financial situation of our major lenders, derivative counterparties, customers, joint interest partners, vendors and suppliers, and enforce our contractual rights with regard to obtaining collateral or providing credit.

• Lending Institutions. As of March 31, 2009, we have determined the potential exposure to a loss of available capacity under our credit agreements, due to our assessment of our lenders' ability to fund, to be approximately $30 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.

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Segment Results We have two core operating business segments, 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 power and pipeline 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 our 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 items such as (i) interest and debt expense,
(ii) income taxes and (iii) net income attributable to noncontrolling interests so that our 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 (loss), income (loss) before income taxes 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 the quarters ended March 31:

                                                               2009        2008
                                                                (In millions)
     Segment
     Pipelines                                               $    396     $  381
     Exploration and Production                                (1,685 )      242
     Marketing                                                     52        (60 )
     Power                                                          4         (2 )

     Segment EBIT                                              (1,233 )      561
     Corporate and other                                           (7 )       39

     Consolidated EBIT                                         (1,240 )      600
     Interest and debt expense                                   (255 )     (233 )
     Income taxes                                                 526       (148 )

     Net income (loss) attributable to El Paso Corporation       (969 )      219
     Net income attributable to noncontrolling interests           12          9

     Net income (loss)                                       $   (957 )   $  228

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Pipelines Segment
Overview and Operating Results. During the first quarter of 2009, we continued to deliver strong operational and financial performance across all pipelines. Our first quarter 2009 EBIT increased four percent from the first quarter 2008 or eight percent when excluding the impact of the Calpine settlement and asset impairments in 2008. In the first quarter of 2009, we benefited from several expansion projects placed in service in 2008. Below are the operating results for our Pipelines segment as well as a discussion of factors impacting EBIT for the quarters ended March 31, 2009 and 2008, or that could potentially impact EBIT in future periods.

                                                             2009           2008
                                                               (In millions,
                                                            except for volumes)
    Operating revenues                                    $       733     $    720
    Operating expenses                                           (366 )       (363 )

    Operating income                                              367          357
    Other income, net                                              41           33

    EBIT before adjustment for noncontrolling interests           408          390
    Net income attributable to noncontrolling interests           (12 )         (9 )

    EBIT                                                  $       396     $    381

    Throughput volumes (BBtu/d)(1)                             19,704       19,321

(1) Throughput volumes include our proportionate share of unconsolidated affiliates and exclude intrasegment activities.

                                                                        Variance
                                               Operating         Operating                          EBIT
                                                Revenue           Expense           Other          Impact
                                                                Favorable/(Unfavorable)
                                                                     (In millions)
Expansions                                    $        19        $       (5 )      $     8        $     22
Reservation and usage revenues                         27                 -              -              27
Gas not used in operations and
revaluations                                            1                (6 )            -              (5 )
Calpine bankruptcy settlement                         (29 )               -              -             (29 )
Loss on long-lived assets                               -                16              -              16
Hurricanes                                              -                (4 )            -              (4 )
Net income attributable to
noncontrolling interests                                -                 -             (3 )            (3 )
Other(1)                                               (5 )              (4 )            -              (9 )

Total impact on EBIT                          $        13        $       (3 )      $     5        $     15

(1) Consists of individually insignificant items on several of our pipeline systems.

Expansions. During the first quarter of 2009, we benefited from increased reservation revenues and throughput volumes due to projects placed in service throughout 2008 including the Kanda lateral project, Phase I of the Southeast Supply Header project, the Medicine Bow expansion and the High Plains Pipeline.
We continue to make progress on our nearly $8 billion backlog of expansion projects, spending $0.2 billion during the quarter ended March 31, 2009 and approximately $1.5 billion inception-to-date on these projects. These projects are substantially fully contracted with customers and will be placed in service over the next five years. In addition, financings have been completed to fund our $1.3 billion expansion capital plan in 2009 and a substantial portion of the capital needs for the Gulf LNG and FGT Phase VIII projects. Over the next twelve months,we expect six projects to be placed in-service representing $1.1 billion of the expansion backlog.
During the first quarter of 2009, we agreed with our customer to defer the anticipated in-service date for our Raton 2010 project from June 2010 to December 2010. For a further discussion of our expansion projects, see our 2008 Annual Report on Form 10-K.

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Reservation and Usage Revenues. During the quarter ended March 31, 2009, our EBIT was favorably impacted by (i) increased reservation and other service revenues on our EPNG system primarily due to higher contracted capacity to California customers and an increase in EPNG's tariff rates effective January 1, 2009, subject to refund, (ii) increased revenues for the off-system and mainline capacity on our Rocky Mountain region systems primarily due to renegotiated contract terms and new contracts and (iii) higher realized rates in the northern region and additional capacity sales in the southern region of our TGP system. For a further discussion of our EPNG rate case, see Other Regulatory Matters below.
Gas Not Used in Operations and Revaluations. During 2008, CIG and WIC implemented FERC-approved fuel and related gas cost recovery mechanisms designed to reduce earnings volatility resulting from these items over time which favorably impacted our EBIT in the first quarter of 2008. Partially offsetting this impact were higher average prices realized on operational sales of gas not used in our TGP system during the quarter ended March 31, 2009.
Calpine Bankruptcy Settlement. During the first quarter of 2008, we received a partial distribution under Calpine's approved plan of reorganization and recorded revenue of $29 million.
Loss on Long-Lived Assets. During the first quarter of 2008, we recorded impairments of $16 million primarily related to our decision not to proceed with the Essex-Middlesex Lateral project due to its prolonged permitting process and changing market conditions.
Hurricanes. We continue to repair damages to sections of our Gulf Coast and offshore pipeline facilities due to Hurricanes Ike and Gustav which occurred in 2008. For the quarter ended March 31, 2009, our EBIT was unfavorably impacted by repair costs that will not be recoverable from insurance due to losses not exceeding self-retention levels. See Liquidity and Capital Resourcesfor a further discussion of these hurricanes.
Noncontrolling Interests. During the quarter ended March 31, 2009, our net income attributable to noncontrolling interests increased as compared to the same period in 2008 due to the additional contribution of interests in CIG and SNG to our majority-owned master limited partnership during September 2008.
Other Regulatory Matters. 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, while certain of our pipelines are expected to continue operating under their existing rates, other pipelines have projected upcoming rate actions with anticipated effective dates in late 2009 through 2011.
In June 2008, EPNG filed a rate case with the FERC as required under the settlement of its previous rate case. The filing proposed an increase in its base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of EPNG's proposals in the technical conference proceeding.
In March 2009, SNG filed a rate case with the FERC as permitted under the settlement of its previous rate case. The filing proposed an increase in SNG's base tariff rates. In April 2009, the FERC issued an order accepting the proposed rates effective September 1, 2009, subject to refund and the outcome of a hearing and a technical conference on certain tariff proposals. The FERC appointed an administrative law judge who will decide the rate case issues should SNG be unable to reach a settlement with its customers.

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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 at 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 strategy focuses on building and applying competencies in assets with repeatable programs, executing to improve capital and expense efficiency, and maximizing returns by adding assets and inventory that match our competencies and divesting assets that do not. For a further discussion of our business strategy in our production business, see our 2008 Annual Report on Form 10-K.
Our domestic natural gas and oil reserve portfolio blends lower decline rate, typically longer lived assets in our Central and Western regions, with steeper decline rate, shorter lived assets in our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions. In April 2009, we made a decision to reorganize our domestic exploration and production operations by combining our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions which was effective May 1, 2009.
During the first quarter of 2009, we sold domestic non-core natural gas producing properties in our Western and Central regions for approximately $93 million.
Internationally, our portfolio consists of producing fields along with projects in several exploration and development areas of interest in offshore Brazil and exploration projects in Egypt. Success of our international programs in Brazil and Egypt will require effective project management, strong partner relations and obtaining approvals from regulatory agencies, although current economic conditions may dictate the timing of our spending. In Egypt, in the first quarter of 2009 we exchanged a 40 percent working interest in our South Mariut block for an equal working interest in the Tanta block. In addition, we successfully bid to farm-in a 50 percent working interest in the South Alamein block located in the Western Desert and are awaiting final government approval. CEPSA Egypt S.A. B.V., the operator of the block, spud the first exploratory well on the block in February 2009. These transactions expand our acreage position and diversify our portfolio in Egypt.
During the first quarter of 2009, the industry experienced continued reductions in the market price of natural gas from already reduced levels at December 31, 2008. Furthermore, while service and equipment costs have declined, they have not declined commensurate with the reduction in commodity prices. Accordingly, we recorded non-cash ceiling test charges of approximately $2.1 billion in the first quarter of 2009 as described further in Operating Results and Variance Analysis below. Low commodity prices and high service, equipment and material costs have continued to challenge our economic assumptions on development and exploration in 2009. Coupled with unprecedented challenges in the credit markets, these events resulted in us reducing capital spending in late 2008 and our anticipated capital program in 2009 as previously disclosed in our 2008 Annual Report on Form 10-K. Based on these lower spending levels, we expect our 2009 production volumes to be down from two percent to ten percent compared to 2008.
Significant Operational Factors Affecting the Quarter Ended March 31, 2009 Production. Our average daily production for the three months ended March 31, 2009 was 731 MMcfe/d (which does not include 72 MMcfe/d from our share of production from our equity investment in Four Star). Below is an analysis of our production volumes by region for the quarters ended March 31:

                                                      2009      2008
                                                          MMcfe/d
                 United States
                 Central                                245       241
                 Western                                164       149
                 Texas Gulf Coast                       203       236
                 Gulf of Mexico and south Louisiana     110       173
                 International
                 Brazil                                   9        12

                 Total Consolidated                     731       811

                 Four Star                               72        75

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In the first quarter of 2009, production volumes increased in our Central and Western regions. Central region production volumes increased as a result of our successful Arklatex drilling programs including the Haynesville Shale, while our Western region production volumes increased in both the Rockies and the Raton Basin. In our Texas Gulf Coast region, production volumes decreased primarily due to sales of assets in 2008 and 2009, while Gulf of Mexico and south Louisiana region production volumes decreased due to the impacts of asset sales and ongoing impacts of Hurricanes Ike and Gustav. In Brazil, our production volumes decreased primarily due to natural production declines.
2009 Drilling Results
Our drilling results for the quarter ended March 31, 2009 by region are as follows:
Central. We achieved a 100 percent success rate on 46 gross wells drilled. Western. We achieved a 100 percent success rate on two gross wells drilled. Texas Gulf Coast. We achieved a 100 percent success rate on 13 gross wells drilled.
Gulf of Mexico and south Louisiana. We achieved a 50 percent success rate on two gross wells drilled.
Brazil. Our drilling operations in Brazil are primarily in the Camamu and Espirito Santo Basins.
• Camamu Basin. During the first quarter of 2009, we continued the process of obtaining regulatory and environmental approvals that are required to enter the next phase of development in the Pinauna Field. The timing of the Pinauna Field development will be dependent on the receipt of these approvals and either the recovery of commodity prices or cost reductions that reflect the current low commodity price environment.

In the BM-CAL-6 block, following the drilling of an unsuccessful exploratory well in 2008 and further evaluation, we have decided to relinquish our interest in this block. In the BM-CAL-5 block, we continue to evaluate the results and appraisal options on a well where hydrocarbons were discovered in 2008 and plan to participate in drilling a second exploratory well to evaluate another prospect in the block during the second quarter of 2009.

• Espirito Santo Basin. We continue to execute the plan of development for the Camarupim Field which includes drilling four horizontal natural gas wells. As of March 31, 2009, one well has been drilled and tested and three additional wells have been spud and are nearing completion. Petrobras, the operator, estimates it will complete all drilling operations and begin production from the field in late June or early July 2009.

In 2008, we also participated with Petrobras in drilling an exploratory well in the ES-5 block in the Espirito Santo Basin in which we own a 35 percent working interest. Hydrocarbons were found in the well and we are now evaluating the results. During the second quarter of 2009, we plan to participate with Petrobras in drilling another exploratory well to evaluate an additional prospect in the ES-5 block.

During the first quarter of 2009, we added approximately 58 Bcfe of . . .