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 nine months of 2009, both our pipeline and exploration and production operations continued to provide a strong base of earnings and significant operating cash flow. In late 2008, we outlined our plan to respond to the volatility in the financial markets, energy industry and the global economy while retaining our long-term growth potential comprised of our committed pipeline project backlog and our core domestic and international drilling programs, as well as our natural gas and oil resource positions. Since that time we have executed on that plan by securing significant financing for our pipeline backlog, entering into a partnering agreement on our Ruby pipeline project, and managing our exposure to a volatile commodity price environment through an expanded hedging program, among other actions. We believe that the stability of our pipeline earnings coupled with the hedging program in our exploration and production business, will continue to protect our earnings base and operating cash flow despite economic conditions and the current commodity price environment.
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 continue to grow our pipeline business through expansions of our existing pipeline systems, as well as greenfield projects. During 2009, we have placed four growth projects in-service. In addition, our backlog of growth projects at September 30, 2009, is approximately $6 billion (net to our ownership interest) of which we have spent approximately $2 billion inception-to-date on these projects. We expect to place these projects in-service over the next several years. We have significantly mitigated the risk associated with our remaining backlog by
(i) entering into an agreement with several infrastructure funds managed by GIP, whereby it will invest up to $700 million in our Ruby pipeline project
(ii) subscribing approximately 90 percent of the capacity of our aggregate backlog under contract terms of 10-30 years primarily with investment-grade customers and (iii) purchasing or committing to purchase steel at fixed prices for all of our largest projects as well as contracting for a significant portion of the construction costs. Finally, we remain focused on growing our MLP. In our exploration and production business, we continued to generate significant positive operating cash flow during the quarter despite a lower level of drilling activity, lower commodity prices and a reduction in capital spending in 2009. Although it impacts our near-term growth profile, the reductions in our 2009 capital program have been managed to retain substantially all of our existing natural gas and oil resource positions for future exploration and production when commodity prices return to more favorable levels. The derivatives we have in place related to our 2009-2011 production provide significant downside protection to sustain us through the current commodity price environment while still allowing upside potential should prices recover. As of September 30, 2009, we had 40 TBtu of natural gas hedges with an average floor price of $9.02 per MMBtu, 32 TBtu of natural gas hedges with an average ceiling price of $14.35 per MMBtu and 727 MBbls of crude oil swaps at $56.48 per barrel on our remaining anticipated 2009 production. During the first nine months of 2009, we settled all of our $110.00 per barrel 2009 fixed price oil swaps, receiving approximately $186 million in cash. Due to lower natural gas prices at the end of the first quarter of 2009, we recorded approximately $2.1 billion of non-cash ceiling test charges, primarily in our domestic full cost pool, which significantly impacted our earnings for 2009. If commodity prices decrease from the September 30, 2009 levels, we may be required to record additional ceiling test charges in the future. Throughout 2009 we have also implemented numerous cost saving measures including additional cost reductions in our capital and maintenance programs by renegotiating contracts with contractors, suppliers, and service providers, and deferring or eliminating various discretionary costs. As of September 30, 2009, we had approximately $2.4 billion of available liquidity (see additional discussion in Liquidity and Capital Resources). Our 2009 capital program is estimated to total approximately $3.1 billion, $2 billion of which relates to our pipeline business and approximately $1 billion relates to our exploration and production business. We expect to invest approximately $1 billion of capital during the last quarter of 2009. Our remaining debt maturities in 2009 are not material and in 2010 we have approximately $250 million of debt (excluding Ruby debt which we anticipate will convert into Ruby preferred equity) that will mature.

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Although the financial and commodity markets have shown signs of improvement, they remain volatile. We currently expect that the volatility in the financial markets and commodity markets will continue for the fourth quarter of 2009 and beyond. In light of this continued volatility, we recently announced additional steps we are taking to further improve our financial flexibility to fund our core businesses. These steps include:
• A reduction of $150 million in annual operating and administrative expenses achieved primarily by reducing internal costs and improving efficiencies from leveraging a consolidated supply chain organization. We expect to achieve a portion of our overall projected savings associated with these measures beginning in 2009. In conjunction with the efforts, we also estimate that we will incur approximately $25 million to $30 million in one-time reorganization costs primarily in 2009;

• The sale of $300 million to $500 million of assets during 2010; and

• A reduction in our quarterly dividend from $0.05 per share to $0.01 per share, which will result in annual cash savings of approximately $112 million.

The additional steps we are taking to further improve our financial flexibility to fund our core businesses are designed to (i) provide incremental funding for our 2010 capital programs focused on our pipeline backlog of growth opportunities and unconventional natural gas drilling inventory in our exploration and production business, (ii) improve our overall cost structure,
(iii) protect our credit profile and (iv) enhance our returns. We currently expect that the 2010 capital budget for our exploration and production business will be comparable with our 2009 total spending level, with approximately one-half of the capital program targeted for our Haynesville, Altamont and Eagle Ford areas. In our pipeline business, we currently estimate that the 2010 capital budget will increase from our 2009 capital program, primarily due to the anticipated construction of our Ruby pipeline project. For reporting purposes, during the construction phase, Ruby is consolidated; however after the pipeline is placed in-service, Ruby will be reported as an equity investment. In October 2009, we announced our re-entry into the midstream business where we believe that the movement to more unconventional supply basins will present future opportunities. In addition, we believe that we may have unique organic growth opportunities where we can leverage our existing competencies and the existing footprints of our pipeline and exploration and production businesses. We intend to re-enter the business at a measured pace, consistent with our overall liquidity and capital constraints. We will continue to have additional funding requirements for our capital program in 2010 and will be opportunistic in accessing the capital markets. We will also continue to assess and take further actions where warranted to meet our objectives, as well as to address further changes in the financial and commodity markets which may include limited access to the capital markets during certain periods and commodity prices lower than current forecasts.

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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 remaining 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 September 30:

                                                  Quarters Ended                Nine Months Ended
                                                  September 30,                   September 30,
                                                2009           2008            2009            2008
                                                                   (In millions)
Segment
Pipelines                                     $    326        $  278        $    1,049        $   954
Exploration and Production                          88           532            (1,536 )        1,078
Marketing                                          (28 )          82                34           (131 )
Power                                               (8 )          (6 )             (25 )            4

Segment EBIT                                       378           886              (478 )        1,905
Corporate and other                                (20 )          (5 )               4             75

Consolidated EBIT                                  358           881              (474 )        1,980
Interest and debt expense                         (256 )        (221 )            (764 )         (675 )
Income tax benefit (expense)                       (35 )        (215 )             425           (450 )

Net income (loss) attributable to El
Paso Corporation                                    67           445              (813 )          855
Net income attributable to
noncontrolling interests                            15             7                38             23

Net income (loss)                             $     82        $  452        $     (775 )      $   878

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Pipelines Segment
Overview and Operating Results. During the first nine months of 2009, we continued to deliver strong operational and financial performance in our Pipelines segment. Our EBIT for the quarter and nine months ended September 30, 2009 increased 17 percent and 10 percent from the same periods for 2008. In the first nine months of 2009, we benefited from several expansion projects placed in service in 2008 and 2009, stronger revenues due to increased re-contracting and marketing efforts, higher volumes of gas not used in operations and effective cost control. Below are the operating results for our Pipelines segment as well as a discussion of factors impacting EBIT for the periods ended September 30, 2009 and 2008, or that could potentially impact EBIT in future periods.

                                                   Quarters Ended                 Nine Months Ended
                                                   September 30,                    September 30,
                                                2009            2008            2009             2008
                                                          (In millions, except for volumes)
Operating revenues                            $    667        $    628        $   2,050        $  1,994
Operating expenses                                (373 )          (387 )         (1,104 )        (1,133 )

Operating income                                   294             241              946             861
Other income, net                                   47              44              141             117

EBIT before adjustment for
noncontrolling interests                           341             285            1,087             978
Net income attributable to
noncontrolling interests                           (15 )            (7 )            (38 )           (24 )

EBIT                                          $    326        $    278        $   1,049        $    954

Throughput volumes (BBtu/d)(1)                  17,757          18,905           18,460          18,736

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

                                         Quarter Ended September 30, 2009                                    Nine Months Ended September 30, 2009
                                                     Variance                                                              Variance
                          Operating         Operating                           EBIT             Operating          Operating                           EBIT
                           Revenue           Expense           Other           Impact             Revenue            Expense           Other           Impact
                                                                                Favorable/(Unfavorable)
                                                                                     (In millions)
Expansions                $       30        $       (6 )      $      9       $        33        $        73        $       (16 )      $     30        $     87
Reservation and usage
revenues                          (4 )               -               -                (4 )               22                  -               -              22
Gas not used in
operations and
revaluations                       8                13               -                21                  6                 23               -              29
Bankruptcy proceeds               (1 )              (1 )             -                (2 )              (45 )               (2 )             -             (47 )
Loss on long-lived
assets                             -                (2 )             -                (2 )                -                 22               -              22
Operating and general
and administrative
expenses                           -                13               -                13                  -                 15               -              15
Hurricanes                         7                 4               -                11                  7                 (1 )             -               6
Net income
attributable to
noncontrolling
interests                          -                 -              (8 )              (8 )                -                  -             (14 )           (14 )
Other(1)                          (1 )              (7 )            (6 )             (14 )               (7 )              (12 )            (6 )           (25 )

Total impact on EBIT      $       39        $       14        $     (5 )     $        48        $        56        $        29        $     10        $     95

(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 and 2009 including the Medicine Bow expansion, the High Plains Pipeline, the Carthage Expansion and the Totem Gas Storage project.
We continue to make progress on our backlog of expansion projects, spending approximately $1 billion during the nine months ended September 30, 2009 and approximately $2 billion inception-to-date on these projects. The capacity of our backlog of expansion projects is approximately 90 percent subscribed with contract terms of 10-30 years and will be placed in-service over the next several years. In addition, financings have been completed to fund our $1.6 billion expansion capital plan in 2009 and a substantial portion of the capital needs for the Gulf LNG, Florida Gas Transmission (FGT) Phase VIII and Ruby projects. During 2009, we have placed four growth projects in-service and expect three additional projects, representing $1.0 billion of our expansion backlog, to be placed in-service by the end of 2010.

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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 10-K.
• WIC Piceance Lateral Expansion. In September 2009, our WIC Piceance Lateral Expansion project was placed in-service.

• WIC Systems Expansion. In July and November 2009, WIC filed applications with the FERC for certificate authorization to construct the WIC expansion project.

• CIG Raton 2010 Expansion. During the first quarter of 2009, we agreed with our customers to defer the targeted in-service date for our Raton 2010 project from June 2010 to December 2010. In September 2009, CIG filed an application with the FERC for certificate authorization for this project.

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

• Concord Lateral Expansion. In October 2009, our Concord Lateral Expansion project was placed in-service.

• TGP 300 Line Expansion. In July 2009, TGP filed an application with the FERC for certificate authorization for its 300 Line Expansion project to add firm transportation capacity to its existing pipeline system in the northeast U.S. market area. All of the firm transportation capacity resulting from this project is fully subscribed with one shipper based on a precedent agreement which was executed in the third quarter of 2009. In October 2009, we entered into a pipeline installation contract for approximately $194 million.

• Ruby Pipeline Project. We expect that the Ruby pipeline project will consist of approximately 680 miles of 42" pipeline and multiple compressor stations with total horsepower of approximately 157,000; however, final sizing will be based on market support. In June 2009, the FERC issued a draft Environmental Impact Statement (EIS) related to our Ruby pipeline project, which is expected to be issued in final form in January 2010. In September 2009, we received a Preliminary Determination from the FERC on non-environmental issues related to this project. Subject to FERC approval, the project is anticipated to be placed in-service during the first quarter of 2011.

As discussed further in Liquidity and Capital Resources below, in August 2009, we entered into an agreement with GIP, whereby it will invest up to $700 million in the Ruby pipeline project. We have also selected a financial advisor and in conjunction with our partner, we have begun working through a financing plan.

• FGT Phase VIII Project. In September 2009, the FERC issued a final EIS. We also received the Pipeline and Hazardous Materials Safety Administration special permit from the Department of Transportation in order to operate the pipeline at higher operating pressures.

• South System III and Southeast Supply Header Phase II. In August 2009, we received certificates of authorization from the FERC on the South System III and the Southeast Supply Header Phase II projects.

• Elba Expansion III/ Elba Express/ Cypress Phase III. During the second quarter of 2009, BG LNG Services LLC (BG) and SNG, Elba Express 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 December 31, 2014, or, in the event certain conditions are unable to be met by BG, to terminate the Elba III Phase B expansion. In exchange for this delay/termination option, BG has committed to subscribe to certain firm Phase B capacity on El Paso's Elba Express pipeline and to 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.

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In addition to our backlog of contracted organic growth projects, we have other projects that are in various phases of commercial development. 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. In early 2009, SNG executed a non-binding letter of intent (LOI) with Florida Power & Light Company (FPL) to expand SNG's pipeline system by approximately 600 MMcf/d by constructing approximately 375 miles of 36-inch pipeline from western Alabama to northern Florida. This expansion project was subject to the Florida Public Service Commission's (PSC) approval for FPL to build an intrastate pipeline which would connect to our SNG system. The PSC rejected FPL's proposal and SNG's LOI with FPL has expired. The future of this project is uncertain.

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.
Reservation and Usage Revenues. During the quarter ended September 30, 2009, our reservation and usage revenues decreased slightly as compared to the same period in 2008 primarily due to lower volumes delivered and lower average system rates in our TGP system. During the nine months ended September 30, 2009, our overall EBIT was favorably impacted by (i) increased reservation and other services revenues on our EPNG system during the first nine 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 from the Marcellus Basin in the northeast market area of our TGP system.
For the nine months ended September 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 northeast and southwest. 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 on certain of our pipelines with the FERC to recover our prudently incurred costs.

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Gas Not Used in Operations and Revaluations. During the quarter and nine months ended September 30, 2009, our overall EBIT was favorably impacted by $13 million and $32 million primarily due to retained fuel volumes in excess of fuel used in operations, higher realized prices on operational sales and lower electric compression utilization in one of our pipelines. In addition, during the quarter ended September 30, 2009, our overall EBIT was favorably impacted by $5 million primarily due to favorable revaluation of retained volumes on our SNG system. Effective September 1, 2009, a volume tracker was implemented as part of SNG's rate case settlement as further discussed below, therefore our SNG system no longer shares retained gas not used in operations.
In addition, during the quarter and nine months ended September 30, 2008, CIG and WIC recorded cost and revenue tracker adjustments associated with the implementation of fuel and related gas cost recovery mechanisms, which the FERC approved subject to the outcome of technical conferences. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009, and October 1, 2009, the FERC issued orders to CIG and WIC, respectively, directing us to remove the cost and revenue components from their fuel recovery mechanisms. Due to these orders, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to fuel imbalance revaluations, their settlement, and other gas balance related items. We continue to explore options to minimize the price volatility associated with these operational pipeline activities.
On October 1, 2009, EPNG received an order from the FERC directing EPNG to modify the cost and revenue component of its fuel recovery mechanism. EPNG is . . .