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 first six months of 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 our backlog of committed pipeline growth projects and have placed two projects in-service during 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 June 30, 2009, we had 80 TBtu of natural gas hedges with an average floor price of $9.02 per MMBtu, 64 TBtu of natural gas hedges with an average ceiling price of $14.35 per MMBtu and 902 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 results for that quarter and the first six months of 2009. As a result of improved commodity prices and lower costs at June 30, 2009, we did not have a ceiling test charge in our domestic or Brazilian full cost pools during the second quarter of 2009. Subsequent to June 30, 2009, however, commodity prices have declined, and as such we may be required to record additional 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 oilfield service costs decrease to a level commensurate with commodity prices, 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 June 30, 2009, we had approximately $2.3 billion of available liquidity (see Liquidity and Capital Resources), after repayment of $0.9 billion in outstanding debt obligations that matured in May 2009. We have designed our 2009 plans to address the impacts of current volatility in the global financial markets and based on our activities to date, we do not anticipate a need to further access the capital markets to fund our 2009 capital program. When prudent, we will continue to be opportunistic in building liquidity to meet our long-term capital needs; however, there are no assurances that we will be able to continue 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 of approximately $3.2 billion, with $2.1 billion of capital being spent in our pipeline business and approximately $1.0 billion in our exploration and production business (see Liquidity and Capital Resources).

In our pipeline business, in July 2009, we entered into a binding agreement with several infrastructure funds managed by Global Infrastructure Partners (GIP), whereby they will invest up to $700 million in our Ruby pipeline project in the following three major tranches (i) a loan of $405 million to be advanced as a series of loans on and after the initial closing (which is expected to occur in August 2009), which would be converted into preferred equity in a holding company for the Ruby pipeline project ("Ruby") upon satisfaction of certain conditions, (ii) $145 million contributed in or around October 2009 as a convertible preferred equity interest in Ruby that may be simultaneously exchanged for a convertible preferred equity interest in a holding company of Cheyenne Plains Gas Pipeline ("Cheyenne Plains") and
(iii) up to an additional $150 million contributed at the time of financing closing to the extent required. The convertible preferred equity interest in Ruby will earn a 13 percent yield beginning at final project completion. GIP will have the right to convert its preferred equity to common equity at any time. However, the preferred equity is subject to a mandatory conversion to common equity upon the satisfaction of certain conditions, including Ruby entering into additional firm transportation agreements.

If all conditions to closing are satisfied or waived, then at the time of project completion, GIP would own a 50% equity interest in Ruby and all ownership in Cheyenne Plains would be transferred back to us. We will provide security for GIP's investment until the completion of the Ruby Pipeline project that will include a portion of our approximately 55 million El Paso Pipeline Partners, L.P. common units, our equity interest in Ruby and our equity interest in Cheyenne Plains. If the closings associated with the project financing or the project completion do not occur by certain dates, there are provisions in the agreements to unwind the transactions, including the repayment of the loan and the redemption of GIP's interests in Ruby and Cheyenne Plains with a return on its investment. Additionally, if such closings do not occur, then GIP has the option to retain a 50% common interest in Cheyenne Plains.

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 $0.3 billion in 2009, nearly all of which have already been completed.

• Other Liquidity Sources. We will continue to be opportunistic in generating additional liquidity, which may include additional asset sales or additional 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 financing arrangements, seeking additional partners for 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 84 percent fixed interest rates and 16 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 through 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 and 2011 natural

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gas production to mitigate exposure to low commodity prices; however, we continue to have some commodity price exposure remaining. 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 additional collateral towards the revolving credit facilities at our exploration and production subsidiary should this be necessary based on revaluation of our borrowing base under this facility in November 2009.

• 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 June 30, 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 $31 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 measures 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 periods ended June 30:

                                                  Quarters Ended                 Six Months Ended
                                                     June 30,                        June 30,
                                                2009            2008        2009                2008
                                                                    (In millions)
Segment
Pipelines                                     $    327        $  295        $       723        $   676
Exploration and Production                          61           304             (1,624 )          546
Marketing                                           10          (153 )               62           (213 )
Power                                              (21 )          12                (17 )           10

Segment EBIT                                       377           458               (856 )        1,019
Corporate and other                                 31            41                 24             80

Consolidated EBIT                                  408           499               (832 )        1,099
Interest and debt expense                         (253 )        (221 )             (508 )         (454 )
Income tax benefit (expense)                       (66 )         (87 )              460           (235 )

Net income (loss) attributable to El
Paso Corporation                                    89           191               (880 )          410
Net income attributable to
noncontrolling interests                            11             7                 23             16

Net income (loss)                             $    100        $  198        $      (857 )      $   426

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Pipelines Segment
   Overview and Operating Results. During the first six months of 2009, we
continued to deliver strong operational and financial performance across all
pipelines. Our EBIT for the quarter and six months ended June 30, 2009 increased
11 percent and 7 percent from the same periods for 2008. In the first six months
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 periods ended June 30, 2009 and
2008, or that could potentially impact EBIT in future periods.

                                                   Quarters Ended                 Six Months Ended
                                                      June 30,                        June 30,
                                                2009            2008            2009            2008
                                                         (In millions, except for volumes)
Operating revenues                            $    650        $    646        $  1,383        $  1,366
Operating expenses                                (365 )          (383 )          (731 )          (746 )

Operating income                                   285             263             652             620
Other income, net                                   53              40              94              73

EBIT before adjustment for
noncontrolling interests                           338             303             746             693
Net income attributable to
noncontrolling interests                           (11 )            (8 )           (23 )           (17 )

EBIT                                          $    327        $    295        $    723        $    676

Throughput volumes (BBtu/d)(1)                  17,929          17,981          18,817          18,652

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

                                            Quarter Ended June 30, 2009                                         Six Months Ended June 30, 2009
                                                     Variance                                                              Variance
                           Operating          Operating                          EBIT             Operating          Operating                          EBIT
                            Revenue            Expense          Other           Impact             Revenue            Expense           Other          Impact
                                                                                 Favorable/(Unfavorable)
                                                                                      (In millions)
Expansions                $        20        $        (5 )     $     13       $        28        $        39        $       (11 )      $     21       $     49
Reservation and usage
revenues                            3                  -              -                 3                 30                  -               -             30
Gas not used in
operations and
revaluations                       (7 )               17              -                10                 (7 )               11               -              4
Bankruptcy
settlements                       (12 )               (2 )            -               (14 )              (41 )               (2 )             -            (43 )
Loss on long-lived
assets                              -                  8              -                 8                  -                 24               -             24
Hurricanes                          -                 (2 )            -                (2 )                -                 (5 )             -             (5 )
Net income
attributable to
noncontrolling
interests                           -                  -             (3 )              (3 )                -                  -              (6 )           (6 )
Other(1)                            -                  2              -                 2                 (4 )               (2 )             -             (6 )

Total impact on EBIT      $         4        $        18       $     10       $        32        $        17        $        15        $     15       $     47

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

Expansions. During 2009, we benefited from increased reservation revenues and throughput volumes due to projects placed in-service throughout 2008 including the Kanda lateral project, the Medicine Bow expansion and the High Plains Pipeline.
We continue to make progress on our backlog of expansion projects and have placed two projects in-service during the second quarter of 2009. We have spent $0.6 billion during the six months ended June 30, 2009. Our backlog of expansion 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 $1.7 billion expansion capital plan in 2009 and a substantial portion of the capital needs for the Gulf LNG and Florida Gas Transmission Phase VIII projects. Over the next twelve months, we expect several projects to be placed in-service representing $0.9 billion of the expansion backlog.

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Additionally, listed below are significant updates to our December 31, 2008 backlog of projects originally discussed in our 2008 Annual Report on Form 10K.
• Colorado Interstate Gas Company (CIG) Raton 2010 Expansion. During the first quarter of 2009, we agreed with our customers to defer the in-service date for our Raton 2010 project from June 2010 to December 2010.

• Totem Gas Storage. In June 2009, our Totem Gas Storage project was placed in-service.

• TGP 300 Line Expansion. In July 2009, we filed an application with the FERC for certificate authorization for our 300 Line Expansion project.

• Ruby Pipeline Project. In June 2009, the FERC issued a draft Environmental Impact Study. A final environmental impact statement is scheduled to be issued in October 2009. Final sizing of the project will be based on market support. In July 2009, we entered into a binding agreement with GIP, whereby they will invest up to $700 million in the Ruby pipeline project as further discussed in Overview and Outlook above.

• Elba Expansion III/ Elba Express/ Cypress Phase III. On June 25, 2009, BG LNG Services LLC (BG) and SNG, Elba Express (EEC) and Southern LNG, Inc. entered into agreements to delay the in-service date of the Elba III Phase B expansion project. The modified agreements give BG the option to delay the in-service date of the Elba III Phase B expansion to as late as the end of 2015, or, in the event certain conditions are unable to be met by BG, to terminate the Elba III Phase B expansion. In exchange for allowing this delay/termination option, BG has committed to subscribe to certain firm Phase B capacity on El Paso's Elba Express pipeline and to potentially provide certain rate considerations on an existing transportation contract on El Paso's SNG Pipeline. In addition, BG has given up its right to proceed with Phase III of the Cypress Expansion Project on SNG.

In addition to our backlog of contracted organic growth projects, we have other projects that are in various phases of commercial development, two of which are noted below. Many of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads, as well as new supply projects.
• Potential Power Plant Loads. SNG has executed a non-binding letter of intent with Florida Power & Light (FPL) to expand SNG's system by approximately 600 MMcf/d by constructing approximately 375 miles of 36-inch pipeline from western Alabama to northern Florida. The expansion is currently estimated to cost approximately $1.4 billion to $1.6 billion and would serve, in part, two oil-fired power plants that FPL plans to convert to natural gas usage. However, Southern Union (a 50% owner of Florida Gas Transmission along with us) has alleged that SNG does not have the right to participate in the project.

Along the Front Range of CIG's system, utilities have various projects under development that involve constructing new natural gas-fired generation in part to provide backup capacity required when renewable generation is not available during certain daily or seasonal periods.
• Potential Supply Projects. TGP's system is located over a significant portion of the Marcellus Basin that is under various phases of development by producers. TGP has executed firm transportation contracts with shippers from the basin utilizing its existing capacity. In addition, TGP has been in discussions with producers to expand its system to provide additional transportation capacity from the Marcellus Basin.

Most of our potential expansion projects would have in-service dates for 2014 and beyond. If we are successful in contracting for these new projects, the capital requirements could be substantial and would be incremental to our backlog of contracted organic growth projects. Although we pursue the development of these potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects to be included in our backlog of contracted organic growth projects.

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Reservation and Usage Revenues. During the quarter and six months ended June 30, 2009, our overall EBIT was favorably impacted by (i) increased reservation and other services revenues on our EPNG system during the first six months of 2009 primarily resulting from higher contracted capacity to primary delivery points in California and an increase in EPNG's tariff rates effective January 1, 2009, subject to refund, which was partially offset by decreased usage revenues primarily due to reduced throughput in 2009, (ii) increased revenues for the mainline and lateral capacity on our Rocky Mountain region systems primarily due to new contracts and restructured contract terms and
(iii) additional capacity sales in the southern, central, and northern regions of our TGP system. For the six months ended June 30, 2009, our throughput volumes on our TGP and EPNG systems decreased compared with the same period in 2008. This was due, in part, to general weakness in natural gas demand in the United States, including in the southwest and northeast. Although fluctuations in throughput on our pipeline systems have a limited effect on our short-term results since a material portion of our revenues are derived from firm reservation charges, it can be an indication of the risks we may face when seeking to recontract or renew any of our existing firm transportation contracts. Continuing negative economic impacts on demand, as well as adverse shifting of sources of supply, could negatively impact basis differentials and our ability to renew firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates. If we determine there is a significant change in our costs or billing determinants on any of our pipeline systems, we will have the option to file rate cases with the FERC to recover our prudently incurred costs. Gas Not Used in Operations and Revaluations. During the six months ended June 30, 2009, our revenue was favorably impacted by approximately $15 million primarily due to higher average prices realized on operational sales of gas not used in our TGP system, partially offset by $5 million related to replacement of depleted storage volumes in our SNG system, among other items. In addition, during the six months ended June 30, 2008, we recorded fuel cost and revenue tracker adjustments associated with the implementation of FERC-approved fuel and related gas cost recovery mechanisms by CIG and Wyoming Interstate Company during 2008. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009, the FERC issued an order on rehearing that effectively unwound the non-volumetric provisions of CIG's fuel and gas cost recovery mechanism, which we believe could expose us to both positive and negative fluctuations in gas prices in the future. This price volatility may impact our earnings through the periodic non-cash revaluation of our fuel imbalances and their eventual cash settlement, along with other impacts to related gas balance items. We are currently evaluating the impact of this order on our fuel recovery mechanism, and have not yet determined if we will file for a judicial appeal of the FERC rehearing order. Bankruptcy Settlements. During the quarter and six months ended June 30, 2008, we recognized revenue of $6 million and $35 million related to distributions received under Calpine Corporation's approved plan of reorganization. This settlement was related to Calpine's rejection of its transportation contracts with us. During the second quarter of 2008, we recorded income of approximately $8 million as a result of settlements received from the Enron Corporation bankruptcy. Loss on Long-Lived Assets. During the quarter and six months ended June 30, 2008, we recorded impairments of $8 million and $24 million, primarily related to our Essex-Middlesex Lateral project due to a prolonged permitting process. Hurricanes. We continue to repair damages to sections of our Gulf Coast and . . .