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Executives

Bruce L. Connery - Vice President, Investor and Public Relations

Douglas Foshee - President, Director and Chief Executive Officer

Mark Leland - Executive Vice President and Chief Financial Officer

James Yardley - Executive Vice President and Chairman of Pipeline Group

Brent J. Smolik - Executive Vice President of El Paso Exploration and Production

Analysts

Mark Afrasiabi - PIMCO

Tom Nowak - Merrill Lynch

Maura Shaughnessy - MFS Investment Management

Faisel Khan - Citigroup

Sam Brothwell - Wachovia Securities

Gary Stromberg – Lehman Brothers

El Paso Corporation (EP) Q4 2007 Earnings Call February 26, 2008 9:00 AM ET

Operator

I would like to welcome everyone to the El Paso Corporation fourth quarter 2007 earnings call. (Operator Instructions) I would now like to turn the conference over to Mr. Bruce Connery.

Bruce L. Connery

Thank you and good morning. We appreciate your joining our call. In just a moment, I’ll turn the call over to Douglas Foshee, our President and Chief Executive Officer. Others with us this morning who will participate in the call are Mark Leland, our CFO; Jim Yardley, who is President of our Pipeline Group; and Brent Smolik, who is President of El Paso Exploration & Production Company.

Throughout this call, we will be referring to slides that are available on our website at elpaso.com. This morning we issued a press release and filed it with the SEC as an 8-K, and it is also on our website.

During the call, we will include forward-looking statements and projections made in reliance on the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable and complete.

However, a variety of factors could cause actual results to differ materially from the statements and projections expressed in this call. Those factors are identified under a cautionary statement regarding forward-looking statements section of the earnings press release that was filed this morning, as well as in other of our filings with the SEC and you should refer to them.

The company assumes no obligation to publicly update or revise any forward-looking statements made during this conference call or any other forward-looking statements made by the company, whether as a result of new information, future events or otherwise.

Please note that during the call, we will use non-GAAP numbers such as EBIT and EBITDA, and we have included a reconciliation of all non-GAAP numbers in the appendix to our presentation.

I’ll now turn the call over to Doug.

Douglas Foshee

Good morning and thanks for joining us today. 2007 was another year of significant achievement for El Paso. We’ve just concluded our fifth consecutive year of improved earnings and we expect to continue that string in 2008.

Both of our core businesses performed well in 2007. EBIT in the pipes was up 7% over 2006. We put several new projects in service during the year and we continued to add to what we believe is the highest quality backlog in the pipeline business.

With the recent addition to the backlog of the Florida Gas Transmission Phase VIII expansion, our overall backlog is now nearly $4 billion, a record for our company and the underpinning of our ability to forecast 6% to 8% multiyear growth in this business with confidence.

Over in E&P, 2007 was a year of delivering on our commitments. Volumes were up 8%; reserves up 18%; our cost structure improved and we continue to evolve our portfolio to become a more effective competitor in this business.

We also concluded our fifth consecutive year of improving El Paso’s balance sheet. At the beginning of the year we concluded the sale of ANR, permanently repairing the balance sheet and returning our Pipeline business to investment grade status.

Towards the end of the year, we concluded a very successful IPO of El Paso Pipeline Partners, now the lowest yielding MLP giving us another tool in our toolbox to create value both for our shareholders and for the MLP unit holders.

With that as a brief introduction, I’ll turn it over to Mark and Jim and Brent and then come back at the end to wrap up.

Mark Leland

Thank you, Doug, and good morning, everybody. I am starting on slide 7 titled Financial Results. The fourth quarter was another good quarter on pretty much all fronts. On the financial side, we’re reporting earnings this quarter of $151 million or $0.21 per diluted share. Consolidated EBIT was $483 million, up 94% from the same period last year, driven by strong performance by both the Pipeline and E&P Groups.

On a combined basis, EBIT for the two core businesses was up $132 million or 30%. Note that last year’s fourth quarter included a $188 million charge in our marketing segment related to the Alliance capacity pipeline sale.

Interest expense was $252 million, which is down from $287 million in the fourth quarter last year, reflecting a significant debt reduction and liability management efforts completed this year, partially offset by the short term debt increase associated with what is largely a timing difference between the Peoples E&P property acquisition and our announced E&P divestitures.

There were several items impacting earnings this quarter which are highlighted on slide 8. The first is a $34 million pre-tax or $0.03 per share loss from the change in fair value of power contracts in the PJM power pool as a result of increased installed capacity prices. I’ll give more color on this issue later in my comments.

The second item is the $26 million pre-tax or $0.02 per share loss on the puts and calls in the marketing segment we have in place to hedge E&P cash flows against reductions in commodity prices.

The third significant item impacting the quarter’s results is an $8 million or $0.01 per share impairment of our Manaus and Rio Negro power plants in Brazil.

As you recall in 2005 we negotiated a three year extension to the term of the power purchase agreements for these plants which expired in January of 2008, at which time the plants transferred to the off-taker Manaus Energia. This impairment is for additional costs associated with the transfer to Manaus. Adjusting for these items brings adjusted EPS to $0.27 per share.

Slide 9 highlights the business unit contribution. On a combined basis our core Pipeline and E&P businesses generated $892 million of EBITDA versus combined CapEx of $696 million.

Marketing and trading reported EBITDA loss of $63 million which I’ll provide more detail in a minute. Power EBITDA was a loss of $4 million driven almost entirely by the Brazilian power impairment I just discussed.

Corporate EBITDA was a $16 million loss, which includes among other things adjustments to legacy, liabilities and reserves. Accounting for our 50% interest in Citrus on a proportional basis brings Pipeline-adjusted EBITDA at $430 million and total core business adjusted EBITDA at $920 million for the quarter. There is a chart in the appendix that provides the relevant details for adjusted EBITDA calculations.

Slide 10 highlights full-year results. For the 12 months ended December 2007, we reported total diluted EPS of $1.53 per share; $0.96 per share from discontinued operations which was driven by the $674 million after-tax gain on the ANR sale; and $0.57 per share from continuing operations.

EBIT for the year was at $1.652 billion which included strong operating results from both core businesses. E&P was up $269 million or 42% from last year and the Pipeline Group was up 7% or $78 million.

Also included in 2007 EBIT was a debt repurchase charge totaling $291 million. Interest expense associated with continuing operations was down $234 million or 19% as a result of our improved balance sheet, and income tax expense was $222 million which equates to a rate of just under 34% in 2007, versus a $9 million benefit in 2006 as a result of settling several outstanding IRS audits.

Now I’m turning to slide 11, titled Items Impacting 2007 Results. This slide summarizes some of the significant items affecting this year’s earnings. As you recall from our previous quarterly calls, we’ve described several significant items both positive and negative impacting 2007.

These items for the most part are the result of specific actions we took throughout the year to continue to simplify and de-risk our business or are related to non-core legacy operations.

The only new item for the year is the change in fair value of our PJM power contracts which impacted earnings by $0.07 per share this year, and I’ll highlight that in a minute on another slide. So, the total adjustments are $0.43, so when you adjust income we would say our core business, adjusted income per share is about a dollar.

Slide 12 highlights business unit contribution for the full year. On the combined business, our core Pipeline and E&P businesses generated $3.3 billion in EBITDA versus CapEx, including acquisitions of just under $3.7 billion.

Marketing and trading reported an EBIT loss of $199 million, and I’ll highlight that in just a minute. Power EBITDA was a loss of $36 million, driven almost entirely by the Brazilian power impairments and accounting for a 50% interest in Citrus on a proportional basis whereas our Pipeline-adjusted EBITDA to $1.769 billion and total core business adjusted EBITDA to $3.458 billion for the year.

Now, I’m turning to cash flow on slide 13. For the year, cash flow before working capital changes was $2.1 billion, up $498 million or 30%, and cash flow from continuing operations was $1.838 billion.

For the year 2006, cash flow from continuing operations was just over $1.8 billion driven by nearly $900 million return of margin collateral, from the sale of our power book. When you exclude the collateral return from 2006 you can see that we had a much improved cash generation in 2007.

For the year, CapEx excluding acquisitions was $2.5 billion and we closed just under $1.2 billion in acquisitions, and we paid $149 million in common and preferred dividends.

Slide 14 details earnings from the Marketing segment for the quarter and for the year. We’ve segregated these results to highlight the impact of derivatives used to hedge production, cash flows which we view as strategic positions and then other positions which are primarily related to our legacy trading book.

For the quarter and the year we realized EBIT losses of $26 million and $89 million respectively due to the change in fair value of our production-related derivatives compared to gains last year.

The losses were primarily driven by mark-to-market losses on the $7.50 puts we used to hedge natural gas productions. We’ve executed all of our new E&P hedges in the E&P segments so going forward you should expect to see volatility associated with hedging in the Marketing segment continue to decline in 2008.

In the other category of Marketing positions, we realized an EBIT loss of $38 million and $113 million for the fourth quarter and the year respectively versus losses of $197 million and $340 million for the same periods last year. The primary driver of this year’s other marketing EBIT losses are due to the change in fair value of the PJM contracts.

Slide 15 provides more color on the PJM power contract volatility, which impacted non-core earnings this year. As we discussed in the past, the remaining exposure in our power portfolio is related to three contracts: two contracts which require us to simply swap locational differences in energy prices between (inaudible) locations in the Pennsylvania, New Jersey, Maryland eastern region and the PJM west hub through 2013.

And one contract, the UCF contract, which obligates us to deliver physical energy and provide install capacity in the PJM power pool through April 2016.

At year-end, the mark on the three contracts was a liability of $454 million. In 2005, we hedged the power commodity exposure and until last year the primary source of volatility in these power contracts was the change in bases between the eastern (inaudible) locations and west hub.

Beginning in June of 2007, the PJM Independent System Operator implemented a new capacity market and conducted periodic auctions to set prices for providing installed capacity to customers in the PJM pool.

The auction price of the pool-wide installed capacity has increased and it has been the primary driver in the $100 million decrease in the fair value of the contracts this year.

The capacity market is matured over the last year, so we’re in the process of entering into transactions to fix the capacity price for the remainder of the contract term thereby eliminating the mark-to-market exposure of the installed capacity component of these contracts.

So going forward, assuming we’re able to fix the capacity price, remaining exposure is related to basis and discount rates.

Slide 16 summarizes our 2008 hedge program. We been active this last few months and we’ve added to our gas hedge program. In short, our 2008 program includes 188 TBtu with an average floor of $7.94 per MMBtu with an average ceiling price of $10.21 per MMBtu.

On the oil side, we have 3.7 million barrels hedged with an average floor of $80.94 per barrel and the ceiling of $81.44. The combination of these positions hedges approximately 69% of our planned 2008 equivalent production and equates to 76% of our expected 2008 E&P revenues.

2007 continued our string of improving financial flexibility and as slide 17 highlights, this is our fourth consecutive year of debt reduction. In total, we have reduced debt during the period by nearly $9.5 billion or a reduction of 42%.

This year, we finished the year with gross debt of $12.8 billion, down 17% from last year. Interest expense including discontinued operations is down over $300 million compared to last year. And looking to 2008, we have very little capital markets needs due to the work we did in 2007.

So in summary, financial performance was very solid for 2007. We saw good growth in our core businesses. We finished our fifth consecutive year of improved profitability and our balance sheet is in good shape and our hedge program gives us good protection with upside in 2008.

Next, Jim Yardley will put some more color on the Pipeline results.

James Yardley

Thank you, Mark. On slide 18, the Pipeline Group had a very successful year. Financially, we concluded the year with a good quarter and for the year, EBIT was up 7% from 2006.

Operationally, we continued to experience very solid volume growth across our pipes. With respect to new growth, we’ve placed in service a major expansion in The Rockies, the Kanda Lateral that will allow access out of the Uintah Basin.

We also added two new major projects to our backlog of committed growth projects. One, the Gulf LNG terminal to be built in Pascagoula, Mississippi, we completed our acquisition of a 50% interest in this terminal.

Two, we executed a very significant precedent agreement with FP&L in Florida to allow us to go forward with FGT’s $2 billion Phase VIII expansion. So our committed growth backlog now stands at nearly $4 billion, which as Doug said is a record high.

On slide 20, on the financials, our 2007 EBIT was $1.265 billion. This is higher than the high end of our targeted EBIT range for the year. EBIT was up $6 million in Q4 and $78 million for the year.

For the year, essentially all of this 7% EBIT increase was due to higher revenues, mostly from pipeline expansions across the country especially on SNG, TGP and CIG. Revenue also increased due to higher throughput, some pockets of additional capacity sales especially on TGP and higher rates on CIG resulting from a rate case settlement.

We did have higher operating costs in 2007, but this was mostly offset by higher equity and earnings from our investment in Citrus.

Capital expenditures as you can see were essentially flat year-to-year at just over $1 billion. We spent more on growth capital in 2007, nearly $650 million. Significantly up from 2006, but offsetting this, in 2006, we spent over $200 million on hurricane-related capital. Underlying maintenance capital was relatively flat at just over $375 million.

Throughput was up significantly, and this is laid out by pipe on the next slide. So, on slide 21, on throughput, it’s a very nice picture; in total, up 7% from 2006 which in turn was up 6% from 2005.

The increase is broad based coming from both the demand and the supply side. On the demand side, power gen loads especially in the east on both TGP and SNG increased significantly due to warmer summer weather, the drought in the Southeast, and simply an increase in the underlying growth in electricity demand.

On the supply side, we had significantly higher volumes out of The Rockies due both to increased production and the start of our Piceance Lateral in 2006. We also had higher supply area throughput on TGP. All of the gas from the Independence Hub is flowing into TGP nearly 1 Bcf a day. So in sum, the underlying health of our pipelines is excellent.

On the next few slides, we provide an update on our growth projects. This slide 22 is mainly for your reference and updates our committed backlog. And by committed, we mean these are projects for which we have binding long-term precedent agreements with customers that allow us to go forward.

So these projects are now either going through the regulatory review phase or are under construction and will be placed in service over the next several years. Two important points on this slide: first, as we said, our committed backlog is now nearly $4 billion. With this backlog in hand, we’re confident with our 6% to 8% long-term EBIT growth expectation.

Second, this is a high-quality set of projects that comprise our backlog. I say this because concerning capital cost of new infrastructure, our industry is clearly in a very tight and challenging market for pipe and pipeline installation.

But in the box in the lower left corner of this chart, you can see how we’ve managed to reduce this capital cost risk by sharing it with others. On nearly two-thirds of the total capital of these projects we’ve managed to pass on this risk either to contractors, mostly through EPC contracts on the LNG terminal projects, or to customers.

On a portion of the remaining one-third on which El Paso is the primary party bearing the risk, some of this capital is for compression projects that entail lower risk because of the nature of that work relative to laying new pipelines.

So, we like our backlog − a lot. It’s large. It involves primarily straightforward organic expansions of existing infrastructure which tend to be higher return, and we feel good about how we’re managing the capital cost risk.

On slide 23, we closed our acquisition of 50% of the Gulf LNG regas terminal. We also closed on the $870 million non-recourse financing associated with the project at a very attractive interest rate. Construction has now started toward a 2011 in-service date.

The capacity of Gulf is fully contracted long-term with customers. With ENI, the large Italian oil company and with the Angolan LNG consortium comprised of Chevron, BP, ENI, Total, and the Angolan national oil company Sonangol.

Our revenue stream from these terminal use agreements will be substantially reservation charge-based and not subject to the actual use of the terminal or number of LNG ships unloaded.

So, our revenue is highly predictable and stable. Likewise, the capital cost of Gulf is well known because the construction is mostly being done under an EPC contract with Aker-Kvaerner, a large Norwegian contractor with a significant experience in such projects.

So, Gulf is a good one for us. We’ve been able to capitalize on our experience at Elba Island to add value. And, in addition to our ownership interest, we will be responsible for overseeing construction and then we’ll operate it.

On slide 24, on our January earnings guidance call, we discussed three very large projects, each with capital over $2 billion that were in the marketing stage. We did not have customer commitments at that time on any of them, and so they were not yet in our committed backlog.

Now on one of them, this FGT Phase VIII project shown on this slide, we’ve secured a major customer commitment. So, this $2 billion project is a go project and we’ve added it to our backlog. FGT is owned by Citrus, our 50-50 joint venture with Southern Union.

We have a long-term 25-year firm transportation commitment with FP&L, the largest utility in Florida. FP&L will use the increased capacity to fuel a major expansion of power plants in South Florida.

I think you’re aware that a number of proposed coal-fired plants in Florida have been canceled due to environmental concerns, and so Florida and the utilities there are turning to natural gas in a bigger way.

To expand FGT’s system, we’ll loop various segments of the pipeline, about 500 miles of pipeline loop, from the Mobile Bay area across the Panhandle and then south. We’ll also add compression at a number of stations. We’ll file our certificate application with FERC later this year and plan to be in-service April 2011.

Florida has been a growth market for us for a long time. As the name of this project implies, this is our eighth major expansion on FGT over a 20-year period, and during this time, FGT’s capacity will have increased threefold, from less than a Bcf a day to nearly three after completion of this expansion.

On slide 25, these are the other two large projects that we’re marketing. Neither is in the backlog yet. We’ve not committed to go forward on either. But if we’re successful, each individually would have a significant impact on our EBIT in 2011 and beyond.

As we said on our January call, both are grounded in our macro outlook for the changes in gas flows over the next several years; both also utilize our incumbent position and regional markets, The Rockies and the Northeast and finally, on both projects will have equity partners to share the risk. As we’ve been doing, we will keep you apprised of the progress.

So in summary on slide 26, we had an excellent year in 2007, and looking forward, we have a large and very attractive backlog. We fully expect it to yield growth of 6% to 8% and we’re focused on executing to bring these projects in-service over the next several years.

And with that, I’ll turn it over to Brent on E&P.

Brent J. Smolik

Thanks, Jim. Good morning, everyone. My comments will be somewhat brief since we discussed many of our 2007 results on our guidance call last month. E&P had a strong 2007 and some of the story merits repeating. So I will run through that with you.

We also have some additional news this morning primarily regarding reserves which were not final at the time of our January call and regarding our non-proven inventory.

So turning then to slide 28, we successfully delivered on our 2007 commitments with production, capital and operating cost results all well within our guidance. We also had a strong year on our reserves, growing our oil and gas reserve base, and as Doug said, proved reserves grew about 18% and that’s with significant contributions from both our exploration and development programs, as well as the Peoples and the South Texas Laredo acquisitions.

In total, we replaced more than 250% of production and we grew reserves about 130% if you exclude the additions from the acquisitions. We also realized year-over-year improvement on our reserve cost adding reserves at an average of about 3.55 per Mcfe equivalent.

And remember our international capital programs are still early phase, and when you remove that impact from the equation, our domestic U.S. replacement cost came in at about 3.26 per Mcf equivalent and that’s very much in line with our expectations and from what we’ve seen so far competitive with our peer companies that have comparable reserve lives.

In Brazil, we were successful with both our exploration projects, Pinaúna and Bia. And while we didn’t book any proved reserves in 2007 for those discoveries, there are a material resource addition that points to the potential of our international program.

And then lastly, from a strategic perspective, we made good progress high-grading our portfolio which improves both our near-term performance and then it better positions us to achieve a 8% to 12% multi-year production growth and then longer-term improve our cost structure.

So moving then to slide 29, the E&P segment reported EBIT for the quarter of $263 million and $909 million for the full year, that’s 92% and 42% increases respectively over the 2006 results. And the increase was primarily due to, as Mark said, higher production, higher realized commodity prices and continued focus on our cost structure.

Our hedging program provided strong price support and added about $177 million to the full-year earnings numbers. CapEx for the quarter excluding acquisitions was $347 million, which was in line with our expectations.

Then for the full year, we invested about $1.4 billion in our exploration and development programs which was roughly about $200 million increase over 2006, and that increase is largely due to the successful exploration projects we had in Brazil, and two additional exploration and development capital following our South Texas acquisition areas.

For the full year, we spent $1.2 billion on acquisitions which included about $880 million for Peoples and about $250 million for our South Texas acquisition. Total production averaged 924 for the quarter and 862 for the full year, that’s an 11% full year increase and an 8%, as Doug said, increase over the same prior period.

Included in the fourth quarter growth is the contribution from our Peoples acquisition, and I’ll give you a little more detail in a few slides on production. Cash costs averaged $1.83 for the quarter and $1.88 for the full year, again very much on target and for the full year up only slightly about a percent year-over-year.

If you turn to slide 30, there is further cash cost details. It summarizes our cash cost for the quarter and for the full year and for the comparable periods in 2006. We made solid improvement for the quarter and for the year.

The 7% drop in unit lifting cost is as a result of really tremendous effort by our operations group, and I want to thank them again for their 2007 contributions. As we noted in January, we believed we are a top quartile performer in regards to the lifting cost metric and we intend to hold that position.

Production taxes are a little less controllable and they’re really largely a function of higher prices and higher revenues. Unit G&A was up for the quarter and for the year and there are several reasons for the increase. We increased overall head count by about 10% which we’re happy about, and we also moved some of the marketing organization into the E&P business since they’re now directly managing the marketing of our oil and gas production.

Part of the $0.75 per Mcfe improvement that we got from hedging gains is due to their contribution. So, I hope you’d agree that this is a great trade-off to add them into our G&A.

Given our high-grading efforts, we expect further improvements in 2008 and we’ve previously announced, we expect cash costs to average somewhere between $1.75 and $1.90 per M implying about a midpoint improvement of about $0.07.

Slide 31 shows our drilling results by risk category and by our operating divisions. For the full year, we drilled 603 gross wells and experienced a 97% success rate. That activity level was largely on track with our 600 plus wells outlined for our 2007 plan.

We did have higher than expected capital cost in some of our Gulf of Mexico and Brazil projects, and we did several bolt-on acquisitions which caused us to scale back a few of our programs, but it was only slightly and only on the margin.

In the Texas Gulf Coast division, we drilled 84 gross wells with a 92% all-in success rate. And given last year’s acquisitions, South Texas will continue to be a growth area for us.

Our Gulf of Mexico program had six successful wells out of 13 attempts. And while the 46% success rate is a bit below our expectations, if you look at the two-year average, we’re closer to 67% which is in line with our predicted success for Gulf of Mexico.

The Onshore capital is targeted at our most repeatable programs in 2007 and we performed just about as expected. We drilled about 502 wells with a 99% success rate which compares very favorably to 2006.

If you look inside that it included in that performance our 160 wells that we drilled in our Raton program. And as you know, we were successful in all four of our exploration wells that we drilled in Brazil last year.

Turning to slide 32, you can see the resulting equivalent production profiles. We’ve broken out here the Peoples volumes for the quarter and for the year so that you can see the performance of our base business.

You’ll remember that in our third quarter call, I said that our fourth quarter production will come in about 840 per day plus about 70 per day for Peoples and we came in ahead of that target at 924. So both the Onshore and the TGC regions had solid organic growth without the Peoples acquisition.

Onshore was up about 5% from a year ago and TGC had a really good quarter and was up about 23% versus the prior year. In fact, they had a good enough quarter in TGC where we may see some of that come off in the first quarter, as some of that new well production rolls over.

As expected also in the Gulf of Mexico, we saw a rollover from the declines in the new production we had there that came on in the second and third quarters. So Gulf was down just a little bit, but right in line with what we expected for the quarter.

The full-year story is also very good. All the domestic regions showed solid growth. When we look at full year, TGC grew 10% which is the first full year, year-over-year production growth that the division’s had since 2002.

Onshore continued its steady predictable growth, growing 5% essentially all organic, and they really grind it out there; remember 500 wells with a 99% success rate. So it’s a high activity count but very predictable performance. This continues a good string of very solid performance for the Onshore group.

Gulf of Mexico had a successful year averaging 191 million a day or about 10% higher than 2006. Remember, we had a target there of averaging about 175 to 200 a day, so our results were right in line with our expectations.

As we noted on our guidance call in January, we expect full year 2008 volumes to be somewhere in the 870 to 930 a day range. And that assumes remember that we have a full first quarter production from all of the divestiture packages. And I’ll update you in a minute on where we’re at on the divestiture process.

Turning to slide 33, as I mentioned earlier, we had a solid year growing our reserve base from 2.6 Tcf equivalent, and that includes our proportionate share of Four Star to about 3.1 Tcf. And that 18% growth rate is important as we continue to high-grade the portfolio, we’ll have the divestitures that follow.

Remember the acquisition portion of this growth improves our geographic concentration in the core areas that we have our repeatable capital programs and repeatable drilling programs, namely the Ark-La-Tex and the South Texas areas.

When you look at the division breakout, you can see that over two thirds of our reserve base is concentrated in those areas with those low-risk repeatable programs, largely Onshore, largely in the unconventional plays like the coal-bed methane in Raton and Black Warrior Basin, and in the tight gas plays in Ark-La-Tex and South Texas.

The Gulf of Mexico and South Louisiana division makes up less than 10% of our reserve base, and that size reduces our volatility of our total company performance, but still provides us some exposure to the higher impact medium and higher risk opportunities.

The TGC, Texas Gulf Coast reserve base grew about 26% and was one of our biggest growth areas as a percentage year-over-year growth. That was largely because of the additions of the South Texas Laredo and the Peoples acquisitions, but again it highlights the importance of that area for us going forward.

International reserves are approximately 250 B’s, that’s essentially flat year-over-year. It’s important to note that that number does not include incremental resources that we discovered in the four exploration wells last year in Brazil.

So, again I’m pleased with the E&P performance in 2008 and particularly with the growth in our oil and gas reserves.

As you know, we’ve released our non-proved resource potential this morning. Slide 34 shows our future drilling inventory and we start with our PUDs. We have almost 900 Bcf of proven undeveloped reserves, plus about 2.8 Tcf of net risked resource potential.

That risk resource increased about 12% from what we had at the end of 2006, beginning of 2007 and that ending balance doesn’t include the domestic properties that we’re now working to divest.

Our growth reflects the inventory that we acquired through our acquisitions and it also reflects that we identified there are ongoing petrotechnical studies in the work of our petrotechnical teams.

At our Analyst Day in April, we plan to provide you with more detail and further characterize the inventory, but in the interim, I’d like to give you at least a high level summary of the inventory.

Our unconventional inventory represents almost 500 B’s − 495 Bcf of net risked resource potential and is primarily comprised of the company’s coal seam operations in the Raton, Black Warrior and the Arkoma Basins and it also includes our New Albany shale project.

Our conventional low-risk inventory is comprised of all the categories that have a geologic risk of greater than 40% or in that window of 40% to 100%. Currently, we have line in sight to almost 1.5 T’s – 1,460 B’s of net resource potential in those low-risk conventional opportunities.

That total includes resources in the Ark-La-Tex region, where we have a significant tight gas position, includes The Rockies, includes South Texas and it includes the international regions, including the step out drilling from our discovered resources.

Our identified higher risk conventional inventory has a net resource potential of over 800 B’s and that category includes exploration in the Gulf of Mexico, exploration in Texas Gulf Coast, and in both Egypt and Brazil.

I should note that we also include about 250 to 300 B’s of inventory in this category that’s on open acreage that’s either in Gulf of Mexico or South Louisiana and we plan to pursue that inventory in upcoming lease sales and we included in our accounts because it’s part of our ongoing business model there and our ongoing leasing activities.

Then, our total unconventional and conventional lower risk inventory typically consumes about 80% to 85% of our drilling capital. And going forward, we don’t anticipate that changing, but our conventional higher risk inventory will always provide a bit of upside to the portfolio.

Turning now to slide 35, as you know, we’re in the process of selling down of up to half of our Pinaúna development project in Brazil. We’re proceeding with the project in the meantime and will decide in the first half of this year if we take on a partner or if we proceed on our own.

As you know, oil prices have helped that project significantly and we still expect production somewhere in that 15,000 to 20,000 barrels a day range beginning some time second half of 2009. So, either way, Pinaúna is going to be a valuable project.

As we announced last month, we’re continuing to make progress on our domestic asset sales. We’ve got three agreements signed for the Onshore properties. We’re going through the normal closing processes and we expect to have all those assets closed by the end of the first quarter.

Then, we’re also continuing to make progress on the Gulf of Mexico sales process, and we plan to have some news for you soon. So, watch this space for updates for Gulf of Mexico.

And then finally on slide 36, overall I’m quite proud of our E&P accomplishments for 2007. We delivered on our commitments, and at the same time, we high-graded our assets. We’ve increased our internal capabilities, and we’ve improved our overall performance.

We grew our proven reserves and we’ve added to our unproven inventory. As I hope you can see, we are entering 2008 with positive momentum. Our 2008 CapEx program of $1.7 billion is off to a good start. Again, it’s going to be a relatively low-risk drilling program that’s focused primarily on developing the acquisitions and the exploration success that we had last year.

We’ll continue to look for ways to improve our cash cost and we expect improved long-term production growth of about 8% to 12% through 2010 when you compare that to the divest-adjusted 2007 base.

So thanks and I’ll turn back to Doug to wrap up before Q&A.

Douglas Foshee

Thanks, Brent. We expect the momentum we built in 2007 in our two core businesses to carry over into 2008, giving us our sixth consecutive year of improved earnings. This is underpinned as Mark showed by significant downside commodity price protection and significant commodity price upside for the year should natural gas prices exceed $8 dollars.

In addition to that, we now have two core businesses that we believe have the capacity to generate attractive returns and growth beyond 2008. 6% to 8% plus EBIT growth in the pipes and 8 to 12% volume growth in E&P beyond 2008 give us a great deal of optimism about the future.

The addition of El Paso Pipeline Partners, our MLP give us another option for growth with a very competitive cost of capital available for project development, for third-party acquisitions and for so-called drop-downs.

Finally, let me use the speaker’s prerogative to thank all of our employees who we call Team El Paso for their hard work during 2007. We moved a lot of freight last year and we have a lot more to do in 2008.

As much as anything else, our challenge this year is execution on what we already have. If we bring in that $4 billion worth of projects in our backlog on-time and on-budget, while not taking our eye off our existing business; if we develop our E&P inventory at competitive costs vis-à-vis our peers; if we do all of this safely and if we continue to focus on attracting and then retaining and motivating our fellow Team El Paso members, this is going to be a great year for El Paso. Now that’s no small order, but we feel like we’re more than up to the task.

So with that, we’re happy to open it up to your questions this morning.

Question-and-Answer Session

Operator

Your first question comes from the line of Gary Stromberg – Lehman Brothers.

Gary Stromberg – Lehman Brothers

Mark, couple of questions for you on the asset sales. I think last month, you talked about doing $1.1 billion to $1.3 billion, is that still the target and what exactly does that consist of?

Mark Leland

That’s still the target. That’s primarily the E&P divestiture assets that we talked about and the balance of our power assets, primarily the Brazilian power plants.

Gary Stromberg – Lehman Brothers

And, do you think that’s front-end loaded first half of the year?

Mark Leland

Yes.

Gary Stromberg – Lehman Brothers

Okay. And then with regard to the Brazilian E&P sale, if for some reason that doesn’t go through, how much do you think you have to increase 2008 CapEx volume, if at all to complete development on your own?

Brent Smolik

It’s really a function of how fast we go in the interim until we take on a partner, but the outside number we’re looking at would be $60-$70 million that would impact this year. If we keep 100% of the project versus 50%, but it’s all timing. So how fast we identify a partner, how much they take and then how soon we get it done.

Gary Stromberg – Lehman Brothers

That’s helpful. The final question back to Mark on debt levels. Can you just refresh us on what’s drawn on your revolvers? And secondly, how you plan to finance the maturing debt both this year, and I think a little over $1 billion in 2009, if you’ve given that some thought?

Mark Leland

We have about $1 billion of liquidity in the form of both cash and undrawn revolver positions. We have maturities of around $330 million this year, some of which we will just refinance. Others, we’ll pay down. And then in 2009, most of that will be refinanced. And I think given our financial flexibility, we’ll, we won’t have any trouble there. We also have the MLP that gives us a lot more financial flexibility to deal with all of those issues and our CapEx load.

Operator

Your next question comes from the line of Sam Brothwell - Wachovia Securities.

Sam Brothwell - Wachovia Securities

Just to clarify on the impact on CapEx, you said $60 to $70 million if you didn’t take on a partner. Is that just specific to Brazil or is that across the E&P program?

Brent Smolik

That specific response was to Brazil. We don’t have any other issues like that. The others are moving along, and we’re going to get those done and they’re not going to affect CapEx.

Sam Brothwell - Wachovia Securities

Right. But if you didn’t end up selling down 50%, we would have to back-fill the proceeds that we’re assuming that would offset the other CapEx in the program? Is that correct?

Brent Smolik

Yes.

Douglas Foshee

Yes.

Sam Brothwell - Wachovia Securities

That clarifies that. And then Jim, on the Ruby pipeline, you’re estimating I think somewhere in the neighborhood of $2 billion gross CapEx. And my question is, there was a competing project similar route by one of your competitors and their cost estimate was, as I recall, considerably higher than what you’re estimating for the Ruby project.

I just wondered if you can comment on that, and especially in light of all the steady cost escalations we’re seeing in infrastructure across the board.

James Yardley

The capital cost pressure is clearly a reality. All projects are a little bit different. The $2 billion is specific to the route from Opal over to Malin. And in order to get to Opal from different Rockies basins, there will be additional capital spent by somebody. It could be either on WIC or CIG, if it’s moved by El Paso pipe to Opal or it could be on alternative means.

I am not sure that there is an apples-and-apples comparison here, but if for example all of the 1 Bcf a day came from the Piceance, Uinta and Powder River and/or transported on El Paso, our capital to beef up both WIC and CIG would be a lot more, but we’re comfortable with the capital specific in today’s market from Opal to Malin.

Operator

Your next question comes from the line of Faisel Khan - Citigroup.

Faisel Khan - Citigroup

On the Texas Gulf Coast growth, year-over-year, can you describe a little bit more what transpired there? I know you talked about some new wells coming on line; was it large wells or was it one large portfolio of production that came on line?

Brent Smolik

Now, and you’re specifically talking about fourth quarter to fourth quarter, Faisel?

Faisel Khan - Citigroup

Yes.

Brent Smolik

We had a good run on new wells coming on. So, it was a number of new wells, but it wasn’t any specific single large wells that drove that. We had good success in the Dry Hollow area near Victoria, and we had good success in the (inaudible) area in South Texas and then we had a few Vicksburg wells further down the river. So, it really was the timing effect of getting them all on in the fourth quarter and the portfolio of them all working out.

Faisel Khan - Citigroup

Do you think the volumes on TGC might flatten out here over the next 12 months?

Brent Smolik

Yes, we may get some of that flush production fall off in the first quarter, I don’t think for the next 12 months, but since we had such a good fourth quarter, we may see it roll over a little bit in the first quarter, that’s flush coming off those number of new wells.

Faisel Khan - Citigroup

Okay, and looking at your risked and non-risked resource potential, when I equate your risked resource potential to a probable and possible number, is that how I would look at it?

Mark Leland

We try to give you the risking categories so you can look at that however you want. I like to separate out obviously first the PUDs, but then beyond that, the stuff that looks like true unconventional really low geologic risk things, and we separate those, and in that next tranche, if you look at it from a risk perspective it’s, 40% to 100% chance of geologic success so fairly high risk. It’s only that last piece of it that looks like, most like possibles...

Douglas Foshee

Fairly low risk.

Mark Leland

Low risk, sorry, it’s only that last tranche that’s less than 40% that looks riskiest, or looks most like possibles.

Faisel Khan - Citigroup

Okay. I understand. In terms of your domestic replacement cost going forward, are you comfortable with that number or do you think there is room to improve that number going forward?

Brent Smolik

You’re referring to the 3.26?

Faisel Khan - Citigroup

That’s right yes.

Brent Smolik

We’re always striving to improve it. We may get some relief this year on the cost side versus the- vis-à-vis the expectations we set at the budget for 2008 versus 2007. Otherwise, the program looks fairly similar in terms of the portfolio of the kind of things we’re going to drill.

It’s got a little less Gulf of Mexico exposure because of the divestiture there as a percent of the total. So, on the margin, it might be a little more predictable, little less risky, but the program looks similar. So, if we save a little cost that will be the improvement.

Faisel Khan - Citigroup

Okay. And, in terms of the Pinaúna project, what’s the timeline that you’re comfortable and think that you will bring initial production volumes on line? Is it still the fourth quarter?

Brent Smolik

We’re probably into 2009 now just because of the delays we’ve had in trying to integrate all the well data from the discoveries last year and trying to decide if we are going to change the concept. We’ve slipped a little on the time line. And then as we work through partner/no partner decision, we’re probably into 2009.

Faisel Khan - Citigroup

Have you’ve ordered some of the heavy equipment in order to start doing that?

Brent Smolik

The parts of it, that have been procured are mostly around the well heads, the well protectors and the facilities it will set the production facilities on, the two jack-ups, we haven’t yet procured the FSO.

Faisel Khan - Citigroup

Going to the Pipeline side for second, I see the revenues up quarter-over-quarter pretty substantially on the new projects you’ve brought on line, but O&M seems to be up pretty significantly over last year.

I know you talked about a little bit of that in your press release, but can you go into that a little more detail? Should we consider that this O&M level the sustainable level going forward or were there some significant items that we should be probably thinking about as one time?

Mark Leland

No, the increase is primarily the result on the O&M side of some hydrostatic testing that we’ve had to do as the result of a regulatory change. So, as the result of that interpretation of that regulation we’ll have a run rate closer to what you see in the fourth quarter going forward.

Faisel Khan - Citigroup

Okay, so the 246 in O&M that we saw in the fourth quarter is the right run rate, is that what you’re saying?

Mark Leland

I can’t speak specifically to the 246, but generally, there was nothing out of the norm in the fourth quarter.

Faisel Khan - Citigroup

Okay. And then, can you remind us how much capital you have coming on line on the Pipeline business in 2008?

Mark Leland

Growth capital, we’re going to be spending a lot of money. We’re going to be over $1 billion. We’ll be putting in-service about $500 million of projects and we will be spending a lot of money on projects to be coming in-service later. And on top of that, our run rate on maintenance capital has been about $375 million. You ought to expect that to continue.

Faisel Khan - Citigroup

What about development expenses for new pipeline? Isn’t that a large cost that goes into your O&M line?

Mark Leland

We spend development dollars all the time. We capitalize them in that if we’re unsuccessful, we’ll write them off, but in terms of being large, for example to-date on the FGT Phase VIII expansion, we’ve probably spent $2 million or so.

Faisel Khan - Citigroup

Okay, I got you. And then a couple of more questions on the proceeds from the partnership in the fourth quarter, what were the total proceeds from that IPO or the partnership to the C-Corp?

Mark Leland

New proceeds, $540 million net of fees.

Faisel Khan - Citigroup

That was the proceeds that come to the C-Corp both from debt end equity?

Mark Leland

The debt was another $450 million of which we’re using to repay other debt primarily at the Pipeline; $425 actually coming back up.

Faisel Khan - Citigroup

Got you. And then, can you also remind us what are the hard assets that are left in the power segment?

Mark Leland

There’s, the only material assets are the Porto Velho plant in Brazil. And that’s the bulk of it. There is the B2B pipeline we own an interest in, and there is a few smaller plants that we’re in the process of divesting, but that’s the big plant.

Operator

Your next question comes from the line of Maura Shaughnessy - MFS Investment Management.

Maura Shaughnessy - MFS Investment Management

Two questions. The first, can you just talk a little bit more about the MLP drop-down strategy and perhaps even quantify that at the minimum number for the year or how do you think about that?

Mark Leland

Basically, what we’re talking about from a drop-down strategy is, we definitely want to grow the MLP. We want it be a premium yielding MLP. We think that requires a certain growth target, and I’m not sure if we’ve been public as to what we think that is, but we definitely think we need to be a premium to achieve the objectives that we have for the MLP it needs to be a premium MLP.

So, we will grow the MLP either through acquisitions, drop-downs or capital projects to achieve those growth targets. We haven’t specifically set out targeted drop-downs for 2008 or beyond other than saying that we’re mindful of the growth objectives. And we have all the tools to make that happen.

Maura Shaughnessy - MFS Investment Management

Okay. The second question is maybe a bit bizarre, but I’m going to throw it out there anyway. So, I’ve been an observer of your company a long time. And so, when I think about what’s happened over the last 12-18 months or so, huge improvement in the balance sheet that speaks for itself.

The pipeline has always been good. It was capital-starved there for a while, now it’s growing materially and already was a very good asset. And the MLP went well when many folks haven’t even been able to get their deals off the ground. And then the E&P business has improved a lot, now actually has prospects, the diversity of assets make a lot of sense. And some of the costs are actually showing some improvements here.

Yet, when I look at your stock relative to certainly your E&P peers, it’s unbelievably underperformed. And even when I look at your E&P/Pipeline the gas integrated names, it’s also clearly underperformed by a fair amount.

I was just wondering if you could speak to the frustration level perhaps from the Board, from management, what would that necessitate in terms of, there’s always been discussion of splitting the company up if the two pieces aren’t valued appropriately, because frankly, when I see congratulations to all the things that have happened, and yet I see an underperforming stock, and so I’m trying to understand that better.

Douglas Foshee

I think a couple things. Of course, we are all long-term shareholders. So I can’t say I’m pleased with our share price performance for 2007 though we were in the 75th percentile of our peer group in 2006. So, long term, we actually are pretty pleased.

If you look at the bulk of our integrated peers, almost without exception, those that significantly outperformed in 2007 were the beneficiaries of the fact that they are in the gas manufacturing business at a time when that is a very attractive place to be, with very long reserve lives and low decline rates and all those kinds of things.

So, it’s not exactly, I would say, an apples-to-apples comparison. In terms of, I wouldn’t describe it as frustration as much as I would say we’re constantly mindful of whether or not we’re creating long-term value for our shareholders.

We are all both at the management team and at the Board aligned with what we think is the right thing to do for our shareholders long term. And frankly, as a management team, we’re incented in a way that directs us to make the right decisions for our shareholders long term.

So, I think that’s something that we continue to watch. We’ve taken a lot of specific actions over the last four years to put us in a position to be able to make the right decisions and we’ll continue to do that.

By the way I don’t think there is any question no matter how you slice the numbers of whether we have created value since 2004 in both core businesses, but particularly in the rehabilitation of the E&P business, obviously helped by the fact that we’ve had a big commodity price upswing since then but also we positioned that company and now it’ll be a much more effective competitor on its own versus its E&P peers.

Maura Shaughnessy - MFS Investment Management

But Doug, if you look at the company-owned asset value basis and your pipeline clearly warrants a premium multiple as it always has, but the reserves in the ground relative to whether it’s the gas integrators or the other E&Ps or maybe some of today’s information might help some of that, and you haven’t had the growth dynamics or the cost dynamics of some of the peers there, but as I said before, it has improved a fair amount.

On an asset value basis, there is still a very wide gap there. And I’m just trying to understand where are we on the discussion if some of that gap doesn’t close, what are the options that management faces?

Douglas Foshee

The options are no different than the ones that we have pretty consistently talked about. We had in 2007 I would say the first full year at least since I’ve been here where first of all we were down to our two core businesses. And second of all, we had a really good operational year for both core businesses.

So, I would say we are very proud of having done that, but with respect to how the market views that and with respect to how we close what we agree is a gap between the intrinsic value of the company and where we trade, I think the fact that this year we were able to come out with guidance that was multiyear guidance, not just for one business unit, but for both, and I think that guidance for both business units puts us in a very competitive position, and as we deliver on that, in 2008, our expectation is that you will continue to see that valuation gap close, if in the end it doesn’t, we know what to do.

Maura Shaughnessy - MFS Investment Management

Okay, thank you very much and congratulations on all the good work.

Operator

Your next question comes from the line of Tom Nowak - Merrill Lynch.

Tom Nowak - Merrill Lynch

In the EPB offering documents, the numbers put out there for debt reduction at CIG and SNG were $225 million and $289 million, just wanted to confirm those are still the expectations, I think total debt repurchase of CIG so far has been $125 and SNG has been $66?

Mark Leland

Yes, those are still the targets, and we’ll just be opportunistic as we go.

Tom Nowak - Merrill Lynch

Okay. And do you have a cash balance for end of the year?

Mark Leland

$285 million.

Tom Nowak - Merrill Lynch

Thank you. And just to double check the EPB results are fully consolidated, is that correct?

Mark Leland

Yes.

Bruce Connery

Thanks. Time for one more question.

Operator

Your final question comes from the line of Mark Afrasiabi - PIMCO.

Mark Afrasiabi - PIMCO

I was just going to ask you about cash. So you said $285 was the year end?

Mark Leland

Yes.

Mark Afrasiabi - PIMCO

Can you just give me the bridge again on your pro forma debt number you’re put in there at (12814?) where you think that will be at the end of the first quarter roughly?

Mark Leland

We haven’t been providing quarterly debt guidance. And we really didn’t even give guidance for the full year 2008 on what our debt balances are. We’re pretty comfortable with where our balance sheet is. It will move up and down a little bit with the asset sales and the CapEx level and then activity at the MLP, but Mark we haven’t really provided that publicly.

Mark Afrasiabi - PIMCO

Okay. And would you maybe just talk about the cost creep in Pipeline? You mentioned the O&M expense, but is there any sort of lumpy non-recurring cost creep in the quarter, just trying to reconcile the year-over-year growth of what looks like about 2% with your 6% to 8% secular guidance.

Mark Leland

I think you ought to look at the year-to-year comparison on O&M. The timing of actual spending within the year varies from year-to-year. But if you look at the year-to-year increase, there is nothing particularly unusual in that it’s up by 5% or so and that’s about on the mark.

Mark Afrasiabi - PIMCO

Okay. So, I mean the quarterly 2% year-over-year growth, is that something just anomalous, temporary that you see then resuming at 6% to 8% or mid single-digit growth?

Mark Leland

I think on O&M, we’ll be up a little bit more with inflation in 2008.

Bruce L. Connery

That completes our call, and we appreciate your joining us this morning and please call if you have further questions. Thank you.

Operator

Ladies and gentlemen, this concludes today’s conference. You may now disconnect.

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Source: El Paso Corporation Q4 2007 Earnings Call Transcript
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