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Executives

Bruce Connery - VP of Investor and Media Relations

Doug Foshee - Chairman and CEO

Mark Leland - CFO

Jim Yardley - President, Pipeline Group

Brent Smolik - President of El Paso Exploration & Production Company

Analysts

Carl Kirst - BMO Capital Markets

Faisel Khan - Citigroup

Rebecca Followill - Tudor Pickering

Jonathan Lefebvre - Wells Fargo

Lasan Johong - RBC Capital Markets

Kevin Smith - Raymond James

El Paso Corp. (EP) Q3 2009 Earnings Call November 4, 2009 10:00 AM ET

Operator

Good morning. My name is Cynthia and I will be your conference operator. At this time I would like to welcome everyone to the El Paso Corporation Third Quarter 2009 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions) Thank you. I would now like to turn today's call over to Bruce Connery, Vice President of Investor and Media Relations. Please go ahead, sir.

Bruce Connery

Good morning and thank you for joining our call. In just a moment I'll turn the call over to Doug Foshee, Chairman and Chief Executive Officer of El Paso. Others with us this morning who will be participating in the call are Mark Leland, Chief Financial Officer, Jim Yardley, President of our Pipeline Group and Brent Smolik, President of El Paso Exploration, Production Company.

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

During this call we will include certain forward-looking statements and projections. 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 cautionary statements regarding forward-looking statement section of our earnings press release as well as in other of our SEC filings 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, nor 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'll 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 will now turn the call over to Doug.

Doug Foshee

Thanks, Bruce, and good morning. I want to begin my comments this morning by revisiting a slide that we presented at the beginning of the year as our goals for each business unit and for the company as a whole and provide you with my assessment of where we are against those goals as we close out the year.

For the overall company, our primary goal was to build financial strength by maximizing liquidity and maintaining the investment grade ratings for our pipes. By doing these things, we hope to improve our credit metrics. As we sit here in November we're ahead of our expectations for these measures in every respect.

We ended the quarter with $2.4 billion in liquidity. We got there by using many of the corporate finance tools available to us. $1.3 billion in financings, $200 million in drops into the MLP and $300 million in asset sales. These actions combined with outstanding operating performance at the business units give us lots of flexibility as we enter 2010.

We're adding to that flexibility with the announcements we made yesterday regarding our own cost reduction exercises as well as a reduction in the dividend and I will talk more about the rationale for those actions in a minute.

But the outcome of these efforts helps us achieve another key objective and that's to increase our long-term return on capital and our profitability. The combination of these measures as well as lower DD&A rate has given us the ability to increase guidance for 2009 to the $1.15 to $1.20 a share on an adjusted basis.

We also increased both the volumes and duration of our hedge portfolio this year giving us much greater downside protection through 2010 and 2011, in addition to providing greater certainty around our ability to fund maintenance an growth capital in what are now free business units.

Our goals for the pipelines aren't overly complex. Construct our backlog and bring it in on time and on budget creating significant incremental EBITDA in the process. Continue to look for the right opportunities to leverage the strength of our existing franchise to meet the ongoing needs of our customers for new infrastructure and finish our industry leading pipeline integrity program.

So far so good on all fronts. Our execution story remains intact with four more projects this year put in service on time and on budget. Three more projects will come on stream by the end of 2010 and we expect them to be on time and on budget. And our current view is that the remainder of our backlog is in great shape.

We believe our execution capability is a key differentiator for El Paso overall. We continue to put resources, training, and management attention into ensuring that we continuously improve in this area. And he we look forward to reporting continued progress to you. By the end of this year we expect to have completed 86% of our efforts to make every on shore pipeline six inches in diameter or larger, in-line inspect able or pick able.

You may recall that this has been a multiyear effort requiring about $75 million in capital spending a year and we're on track to complete this within our originally stated deadline of 2012. We entered into an exciting partnership with GIP on Ruby, another key objective. As you will hear from Jim in a few minutes, our financial performance was ahead of plan. And we continue to see opportunities for growth in the emerging unconventional gas fairways by virtue of our incumbent positions. Our goals for E&P at the beginning of the year were much more defensive in nature. We wanted to limit capital spending to those areas that worked in a very low commodity price environment and avoid spending capital as much as possible until costs came down in line with the drop in commodity prices.

And we wanted to allocate resources not being used for drilling as we took rigs down from a peak of close to 30, to five at the low point, to high grading, preserving and then growing our inventory.

So far our E&P team is having the best year since I've been with the company. Domestic production is ahead of plan despite spending less capital. Our performance in the Haynesville is top quartile and we have many years of drilling ahead of us. We're growing our Altamonte activity at a measured pace given our position there at a relative health of oil prices and the team has done a great job of bringing costs down in all areas.

An outcome of all this is a continuing shift in our capital spending, our production, our proved reserves, our inventory and to lower risk more repeatable prospects that generate better returns at lower natural gas prices.

Another outcome of the reduction in activity, continued focus on cost, great domestic production performance in our price risk management activities is that in 2009 E&P has been a significant cash flow contributor to the company overall.

The E&P team has also continued to build inventory and in places that are strategically important to El Paso overall. With continued delineation in the Haynesville, we've added significantly to our proved and unproved inventory this year. We now have over 5300 total and 270 Haynesville locations to drill the deepest multiyear inventory we've ever had and that total doesn't yet have any Eagle Ford wells in it.

In Egypt, early success in our South Alamein block bodes well for our over 1.5 million net acres in the western desert. Our second well on that block tested 1700 barrels a day un-stimulated, so we're very encouraged about our drilling program there and our ability to add quality oil oriented projects to our inventory.

And finally we've accumulated over 112,000 acres in the emerging Eagle Ford shale play from a dead start a year ago. While it's still very early days there we're encouraged by the results so far of our first well.

We announced yesterday that the well was producing over $6 million a day at over 5000 psi and still cleaning up. Today the well is up to 7 million a day and this well has only been on a few days so we expect it to continue to improve. In combination, our inventory in the Haynesville, the Eagle Ford and Egypt, all new over the last year, have changed the face of our E&P business in a dramatic way.

Finally, on the international development front, though it came on much later in the year than we had hoped, Camarupim is now producing over 90 million a day from one well and we look forward to the balance of the producing wells coming on in the coming months.

One thing that wasn't in our publicly stated goals at the beginning of the year was our re-entry into the midstream business but this should come at no surprise as we've talked many times over the last several years about looking for opportunities in what we've referred to as the white space between our E&P and pipeline business.

We think now is the right time to begin to leverage the existing footprints of our E&P and pipeline business. On the slide, you will see the existing skill sets that give us the confidence to take this step. We've been in this business before and we were successful. It's a natural adjunct to what we already do and in some circumstances we think there are enough synergies to have a combined outcome that's better than the sum of the parts.

But in simple terms, we intend to leverage our existing physical footprint and leverage an existing set of competencies to generate projects that we believe will produce very attractive risk-adjusted returns to our investors. But while we do intend to leverage those things, what we don't intend to do is increase leverage on our balance sheet to do it.

And we intend to walk into this business, not run. We have a strategy, we have focus areas and we have a talented team of professionals that we've put on the task, led by Mark Leland. This is a long-term strategy driven by the items I've just alluded to. I expect that most of the capital committed to this business overtime will be for organic growth.

That's certainly our primary focus. But acquisitions are a possibility to the extent they fit strategically with our existing footprint and fit with our balance sheet constraints. Now I would like to spend a few minutes talking about the actions that were announced yesterday. We kicked off a project in early spring designed to improve our cost structure, improve our execution capability, further consolidate and standardize shared service functions, improve our organizational health and improve our overall returns and therefore our performance for our investors and we think we've done just that.

We asked a committed group of employees divided into 12 opportunity teams to come up with a plan to accomplish these goals. Project insight, as its known internally, will result in $150 million in annual savings, net of the cost of implementation. The savings come from a myriad of places within and outside the organization.

Workforce reductions in certain areas, contractor reductions, and leveraging the total company spend covered by our supply-chain management professionals, to name just a few.

In addition, we expect to sell $300 million to $500 million in assets in 2010 as we continue to optimize the overall portfolio. This is in line with actions we've taken over the last several years as a result of continually reviewing the strategic fit of each of our assets under changing circumstances. And we announced a reduction on the dividend payable on EP common stock resulting in a $112 million in annual savings.

We have, today, the best set of organic growth opportunities that we've ever had had. And we're confident in our ability to execute on them to produce risk adjusted returns that yield significant benefits to our shareholders. We think these opportunities offer greater long-term rewards to our investors at the margin than the after-tax returns on a larger dividend. We didn't make this choice easily or without considerable discussion and debate at the management team and the board level. And the reduction in our own internal costs are meant to show that we're willing to take out internal costs that far exceed what we're asking our shareholders to allow us to retain. The combination of these actions will yield improved long-term performance across the board.

Our goal wasn't just to lower costs, though. Our goal was to position ourselves to win. To that end, we've realigned the organization to more effectively respond to the opportunities we see in front of us. Some of these changes are public, like Mark taking on the responsibility of building our new midstream business and giving J.R. Sult and Dane Whitehead new and important leadership positions.

Most of them, though, aren't public, but they're equally as important. We've put people in leadership positions and new organizational structures in each business unit and in every shared services area. This is a continuation of a management development and succession planning process that we began building several years ago. It's an area that doesn't show up in quarterly earnings releases, but it's what we believe will separate the winners from the (Inaudible) over the long-term, and we intend to win the war on talent.

So we think this combination of actions will lead to long-term out performance by improving our cost structure, improving our execution capabilities and improving the long-term organizational health of the company.

With that I will turn it over to Mark and come back at the end to wrap up.

Mark Leland

Thank you, Doug, and good mornings everybody. I'm starting on slide 14. As both business units are performing as well as I can remember, and it's showing in their financial and in operating results. We're reporting adjusted earnings per share of $0.23 compared to adjusted earnings per share of 0.35 for the third quarter of last year.

I'll cover the adjustments in the next slide. Reported earnings per share for the quarter was $0.08. Key drivers affecting the third quarter earnings were lower commodity prices offset by lower costs in the E&P segment and higher pipeline EBIT. Compared to the same period last year natural gas prices on our physical sales were down 65%. And even after factoring in our strong hedge position gas prices are down 15%. Offsetting the lower commodity prices was pipeline EBIT which was up 17%. Jim and Brent will provide more color on business unit performance.

The items impacting the earnings this quarter are fairly small individually and are highlighted on slide 15. The first adjusted item is the ceiling test charge in Egypt on the South Mariut portion of our acreage. This totaled $5 million or $0.01 per share. The second item is a $6 million pre-tax or $0.01 per share, non-cash mark-to-market loss on the legacy power book primarily due to lower interest rates.

The third item is mark-to-market loss on the legacy natural gas book totaling $14 million pre-tax or $0.01 per share, also due to lower interest rates. The fourth item is a $16 million pre-tax loss primarily associated with an obligation related to environmental remediation of a non-operating legacy chemical plant.

Finally, we're adjusting for the impact of the hedging in the E&P segment. This totaled $118 million pre-tax or $0.11 per share. The adjustment consists of the exclusion of $87 million mark-to-market gain of financial derivatives and the add-back of $205 million of cash settlements in the quarter.

Making these adjustments brings adjusted EPS to $0.23. Not included in the $0.23 is a $0.04 benefit associated with the early settlement of our well hedges, which we realized in the first quarter. Adjusting for this benefit would bring adjusted EPS to $0.27. The $0.04 represents the amount that would have been recognized this quarter if those hedges would have remained in place.

Slide 16 highlights our business unit contribution. On a combined basis our pipeline and E&P business generated $616 million in EBITDA, and adjusted EBITDA of $799 million, both before ceiling test charges. Marketing recorded an EBIT loss of $28 million. And I'll provide more detail of that in a minute. Power EBITDA was a loss of $8 million due to foreign exchange currency losses and the tax continues to be at the Bolivia to Brazil pipeline, which we own about 8%. Corporate EBITDA was a loss of $17 million due primarily to the environmental remediation charge I noted on the previous slide. There's a chart in the appendix that provides all the relevant details for the adjusted EBITDA calculation.

Marketing segment results are summarized on slide 17, and you can see the book continues to strengthen its contracts roll off, which means a smaller and less volatile impact on this segment. As I mentioned last quarter we'll likely move this slide to appendix again next year. The primary driver of the marketing EBIT this quarter was mark-to-market losses due to lower discount rates and credit adjustments due to tightened credit spreads.

I'll now turn in to cash flow on slide 18. Our cash flow from operations for the first nine months was just under $1.8 billion compared to a little over $2 billion last year in a much stronger price environment. Year-to-date CapEx including smaller acquisitions was $2.1 billion. We generated $303 million in divestiture proceeds and dividends were $133 million. So year-to-date we're about $170 million free cash flow negative despite large pipeline growth CapEx. Key drivers in our cash flow position so far this year has been our flexibility around E&P CapEx and our hedge positions.

As you'll see in the next slide, year-to-date E&P generated $1.26 billion of adjusted EBITDA and $95 million of divestiture proceeds while spending only $740 million on CapEx and acquisitions or total contribution to free cash flow of $616 million. We're making progress on the Ruby financing, which is highlighted on slide 19. We've asked all three rating agencies to rate the Ruby debt. We're cautiously optimistic that Ruby will be related investment grade during the construction phase. We're confident Ruby will be related investment grade once it begins operations. We anticipate Ruby will be capitalized about 50% debt, 50% equity and expect debt to be about $1.4 billion.

Given the current state of the bank financing market we believe a significant portion of the financing will be traditional bank, construction, project financing debt with the remainder coming from project bonds and private debt. Interest from potential lenders is high as we would expect given the quality of the review projects. One benefit of a partner like GIP is how well their group of relationship augments what we consider our traditional group of relationship things. The result of a combined effort for financing will be more efficiently priced and effectively executed financing. We expect to syndicate and close the financing in the first half of 2010 concurrent with the start of construction.

Our natural gas hedge position through 2011 is summarized on slide 20. They are about 70% of our remaining 2009 domestic gas or just over $9 per MMBtu. In addition, if we produce the same volume in 2010 as in 2011 as we will in 2009, we'd be approximately 75% hedged with a floor of $6.41, with a ceiling of $7.24 in 2010. And in 2011 we'd be approximately 60% collared with a floor of $6 and a ceiling of $8.66. These positions haven't changed since last quarter.

On the oil side, we have 85% of our remaining 2009 oil hedged at [$56.84] per barrel. Remember we sold our $110 oil swaps in the first quarter for $187 million. In the third quarter we added oil hedges at a floor of $74.63 for about 60% of our 2010 production assuming its flat in 2009. All of these positions look pretty good in relationship to today's board strip. If we're wrong on the price we have plenty of up side with our ceilings and unhedged production but more importantly the significant downside prediction in the event belong to lowered natural gas prices.

On liquidity which is highlighted on slide 21 remains strong. We closed the quarter with $2.4 billion in liquidity compared to $2.3 billion at the end of last quarter. We expect to end the year with liquidity at $1.6 to $1.7 billion range, which should be sufficient to carry us well into 2010.

To wrap up, we continue to generate strong earnings and cash flow from our core business. And liquidity is strong. We made progress advancing the Ruby financing. In addition, our hedge program coupled with our stable pipeline earnings gives us a nice base of earnings and cash flow for the next several years, even at a low gas price environment. All in all, we're in excellent position to deliver the growth associated with our pipeline backlog and take advantage of a growing opportunity set in the E&P business.

So with that I'll turn it over to Jim for a pipeline update.

Jim Yardley

Thanks Mark. Our Pipeline Group continues to deliver. Financially, we had another strong quarter. We also settled a major rate case at SNG. As Doug said we continue to execute on our backlog of growth projects. We placed two more projects in service on time and on budget since last quarter's call. And we're on track to do the same on another $1 billion of projects to go in service next year. And we're continuing to see very real opportunities to add significant new projects to the backlog.

Slide 24 reviews our financials for the quarter. Our third quarter EBIT of $326 million is an increase of $48 million. 17% over third quarter 2008. The EBIT increase was driven primarily by higher revenues from several expansions. These include the Medicine Bow expansion in the Rockies, CIG's High Plains and Totem Storage projects, and TGPs Carthage expansion. Also importantly operating costs were lower year-to-year both in the field and in the office.

Third quarter EBITDA and adjusted EBITDA for our 50% interest in citrus are both are both up by similar amounts. CapEx of over $1.2 billion year-to-date is comprised of nearly $1 billion spent on our growth projects with the remainder devoted to maintenance capital. The increase from 2008 is due primarily to higher backlog spending mostly on Elba Express and Ruby.

So very strong third quarter and year-to-date results for the Pipeline Group. On slide 25, we show our year-to-date throughput on the pipelines. Overall we've seen a 2% decrease in throughput, lower demand, primarily related to the economic slowdown has more than offset expansions, mostly in the Rockies. On TGP, throughput declined primarily due to the very mild weather in the northeast and to a lesser extent declines in supply area volumes in Texas and Louisiana.

On SNG, industrial demand is down, but we see signs of it stabilizing and perhaps increasing a little bit more recently. Power gen loads on SNG have been quite strong due to the warmer summer in the southeast, but also displacement of coal use, particularly early in the year.

EP&G throughput has declined in both Arizona and California due to the economy, the start-up of a competitor's lateral into Phoenix and low injection rates in the storage in California after a weak winter withdrawal season.

In the Rockies the expansions that increase throughput or the high plains expansion into Denver that went in service last November, also the wick Medicine Bow expansion out of Powder River. On slide 26, we achieved a major milestone with the settlement of the SNG rate case.

This is a very good outcome for us and for our customers. We maintained solid regulated returns and get contracts extensions through mid 2013 and our customers have rate certainty through at least September 2012. The settlement is uncontested. It's been filed with FERC by the ALJ and we expect FERC approval in early 20 10.

We have an obvious preference for settling rate cases across our pipes to avoid the cost, time and uncertainty of litigation. Settlements allow us to quickly get back to the business of providing our customers the very best service, also growing our business with them. On slide 27, we update this last slide quarterly for your reference. It shows the size and plant and service date for each project.

The backlog is a diverse set of projects that provides us with substantial and known growth for our pipes. In total, the backlog is approximately 90% subscribed with long-term contracts with mostly investment grade customers. And these projects will provide solid regulated-like returns.

So this continues to be a very nice picture. And on slide 28, we're executing very well to bring the backlog projects in service on time and on budget. Here's our recent record. Since January of 2008, we've placed in service now nine projects totaling $400 million net to El Paso and done so within 3% of budget.

Two of these went on service. The Piceance Expansion, on the Rockies and our expansion on TGPs line into New Hampshire, which entered service last week for KeySpan on time for the winter heating season.

We'll place in service another billion dollars of projects throughout 2010 and these projects shown here are far enough along that we can say with some confidence that we fully expect them to be on-time and on budget. And so we're executing very well.

Slide 29, shows steady progress in advancing our large projects that go in service in 2011. On Ruby, we received a favorable preliminary determination from FERC on certain commercial terms. This helps advance the financing of Ruby.

We expect to receive the final environmental impact statement before year end, which will be a major mile stone, and the FERC certificate is expected in the first quarter. We'll then start construction next spring. FTT phase 8 is on a similar schedule. We just received the final EIS and we expect the FERC certificate this month.

And we just received the FERC certificate on SNGs next south system expansion. We also ordered pipe for it at a favorable price and we'll start construction early next year. At Gulf LNG, our new terminal in Pascagoula, the roofs have now been raised on both storage tanks and construction is on schedule.

Finally on TGP Line 300, we just executed a unit price contract for that pipeline installation. Unit price contracts have substantially more cost certainty than traditional time and materials contracts. So across the board while the projects shown here have ways to go we continue to make good progress. Progress on the regulatory front, progress in contracting for pipe and installation to de-risk the projects and in the case of Gulf LNG, progress on its construction.

Finally, on slide 30, we continue to see additional growth opportunities. This slide shows what's going on in the northeast on TGP? You're aware of the Line 300 expansion for equitable. We'll expand the 300 line by 340 a day, all for equitable under a 15 year agreement, primarily to move their Appalachian gas in Kentucky and West Virginia to northeast markets.

In addition, as we mentioned on last quarter's call, we're benefiting from a substantial ramp-up in Marcellus activity in northeast Pennsylvania. 200 a day is now flowing into TGP there, that steadily increased from essentially nothing at the beginning of the year. We've also executed back haul agreements with producers. This FT ramps up over time such that by 2012, will provide with us $40 to $50 million in annual revenues.

This back haul business has required no new capital. And we are clearly well placed for forward haul expansion out of Marcellus as production continues to ramp up. This is an example of future growth opportunities on our existing pipeline network, a network, which is well positioned in many of the best markets, and supply basins and with deep connectivity into these markets.

So, in summary, the pipes are delivering. Our financial performance is strong. We're executing on our backlog of growth projects and see the probability for more. And now I will turn it over to Brent.

Brent Smolik

Thanks, Jim and good morning, everyone. I'm going to start this morning on slide 33, we had another very good quarter executing on our capital programs and our domestic operations. During the quarter we continued to focus our capital on the most economic programs by adding two rigs to our Haynesville shale program and one to the Altamonte oil program.

We operated between six and ten rigs in Q3 with the Haynesville activity the highlight of our results. The cost side of our business looks good. Domestic cost per unit continue to come down even though our production was lower in the third quarter than the second and we continue to drive down our drilling and completion costs across the programs. We still expect to come in at about a billion dollars of capital, which is several hundred million dollars below where we expected to be for the year at the beginning of this year.

As you know, the Petrobras operated Camarupim project in Brazil has experienced numerous delays this year, but the first well is now producing at over 90 million day and that impact, the delay that will cost us about a $40 to 45 million day gap in our 2009 annual average production.

The good news is that our domestic drilling program has performed extremely well and we've been able to essentially offset the Camarupim shortfall. We're on track to deliver our annual production target in spite of the Camarupim delays and in spite of spending less domestic CapEx than we had planned. On page 34, I will review the third quarter financial results. Third quarter EBITDA was well behind a year ago but that was mostly due to price. Our third quarter realized gas price excluding the derivative settlements was $3.32 per m versus $9.58 a year ago and including our derivatives it gets closer at 737 per m versus $8.67 a year ago.

Third quarter volumes including our interest in four star averaged $732 million a day which reflects our lower level of drilling activity, especially in the Gulf Coast parts of our business. As Mark noted E&P is contributing significantly to free cash flow. Adjusted EBITDA plus divestiture proceeds totaled a little over $1.35 billion for the first nine months which is over $600 million more than the $740 million that we've spent on capital and acquisitions so far this year.

On slide 35 we show the last five quarters of production. As you can see from the green and yellow bars, that's our western and central divisions, which comprise most of our resource based programs have held up very well.

On the right side of the page is a blowup of those two divisions going back to 2005 and the trend demonstrates the continuation of the on shoring and de-risking of our capital programs. Volumes from the central and western regions now account for about 63% of our total production and at the current CapEx levels; you will see that trend of growing on shore relative to the Gulf Coast division.

On slide 36, we show the per-unit cash costs, we've changed this chart a little bit because the story on lifting, unit lifting cost is much better than the Q3 numbers indicate stand alone. The total unit LOE went from $0.61 in the second quarter to $0.77 a unit in the third quarter. But $0.19 of that was from the startup and the commissioning costs associated with Camarupim that we expensed when the project came on-line in this quarter. Domestic LOE is the bottom green bars, actually went down by $0.03 per unit even though production was counsel from the second quarter. And that's a cost trend that we're very proud of and one that we expect to maintain going forward.

Slide 37 lists a few key recent third quarter accomplishments. Since our last call we successfully drilled and production tested a well in Egypt in the southernmost South Alamein block. We've ramped up our domestic drilling program to eight to nine rigs. Given the positive results of our Haynesville program, we've taken it from the two rigs to five rigs, and we expect to maintain a five to six rig program going into 2010.

We've completed six Haynesville wells since the second quarter call with an average initial rate of greater than $16 million a day. And given higher oil prices we've added a second rig to our Altamonte program, and we've been running a rig or two recently in south Texas. One of those South Texas rigs drilled our first Eagle Ford well. And in Q3 we've almost doubled our acreage position in the Eagle Ford. And I will expand on all those topics in the next few slides.

On slide 38, 30-day IP rates for the first 11 Haynesville wells. And they're shown in chronological drilling order from left to right. Not included on this slide, we have another four wells that are producing but have been on for less than 30 days. So they're not included here. We've clearly continued to improve the initial producing rates during 2009 as we continue to optimize the completion designs for our Haynesville wells.

On slide 39, we show our Haynesville gross production trend year-to-date and for the rest of the year. Below the charts you can see the progression and the number of rigs that we had operating from one early in the year to five rigs from September through the remainder of the year. The impact of the ramp-up is really apparent in the fourth quarter. Our gross volume should be well north of $100 million day, and our net volumes will be in the 60% to 65% range of that gross total.

Although the shale wells do decline steeply, the cumulative production is significant, and a large part of the reason that our domestic volumes are ahead of plan in spite of us spending less CapEx than we originally budgeted. The next two slides show the significant learning curve improvement of our Haynesville program.

Slide 40 demonstrates the reduction in costs and cycle times that we've achieved in the program through improved drilling and completion designs and reductions in service and supply costs. These savings have come even as we've increased the length of the laterals and we've increased the number of frac stages in the wells.

The next slide highlights the improvements on the rates and reserve per well. The improvement in the reserves reflects those longer laterals and better frac stimulations but also reflects the quality of the Haynesville and the area that we refer to as the Greater Holly area, which is sort of the center of De Soto parish, where the bulk of our acreage is concentrated. And although we're not showing peer data on this slide, we believe that our Greater Holly area well performances best in class for the Haynesville.

Now turning to slide 42. Hopefully you've seen the results of our first Eagle Ford well in La Salle County, Texas. We drilled this well with just over a 4000 for lateral and we completed it with 16 stages. And we're real-time testing the well as we speak. We're not at the point yet of having a 24-hour state test rate but the well is currently producing about $7 million a day of gas, and we're still making frac water and so the well is still cleaning up. So we're very encouraged about the shale potential in this area. The wells in the area that we refer to as dry gas area for the Eagle Ford play. And as you see on the map we also have acreage in the area where we expect to have condensate production as well.

In September, we announced that we had about 60,000 net acres in the play. We've continued to lease and we now hold 112,000 net acres in the trend. Our total resource potential here is comparable to the Haynesville with more than a Tcf of net risked resources. We are going to start slow here with a one-rig program. We still have a lot to learn but it's clear that our Haynesville experience is going to be valuable and we're transferring those learnings to this program just as fast as possible.

Slide 43 is an update on Brazil. As I mentioned earlier, that the first well at Camarupim is producing approximately $90 million a day, which is about $20 million a day net to El Paso. The field produced briefly in September but there were some problems with the dehydration facilities on the FPSO. That problem wasn't corrected until October, and so we've only recently been realizing these volumes in our year-to-date numbers.

As a reminder this is a gas field with the gas price index to oil prices. So as the field production increases, we'll be marginally increasing our exposure to higher oil prices. The current estimate from Petrobas has the second and third wells on line in early next year. Although the start-up was delayed, the first well has been producing at a very high-end of our expectations, both for gas and for condensate rates, which is positive for the overall project returns.

On the E&P operated side, we continue to make progress on permitting of the Pinauna development project. We're nearing a public comment period on the development plan, which we anticipate will go well.

As summarized on slide 44, we've now drilled three wells in our South Alamein Block in Egypt. The first well found oil with pay on logs and we recovered live oil samples. We flow tested the second well at very attractive un-stimulated rate of more than 1700 barrels a day. We then drilled a third well approximately 80 kilometers away at the far west end of our block and tested a separate play which fortunately was not successful. Now we're going to have some dry holes here but it's still a great risk/reward proposition. Remember we're targeting oil. The dry hole costs are relatively load low and the resource sizes can be material based on the discoveries on trend in the western desert. Now we can't even declare our first two well commercial discoveries until we further delineate the area but we're highly encouraged by our results to-date. We'll drill a fourth well in the South Alamein block this year and we will likely continue drilling in the block in 2010.

So I'll wrap up on slide 45 as Doug and Mark both mentioned we're having a really good year in E&P. Our domestic program is performing very well. And we're managing our capital effectively and we're putting it to work in the three programs that have the very best economics in the current gas price environment. We're benefiting from a deflationary environment but a lot of our progress on the capital and the cash cost front is a result of the efforts of our E&P staff. And I really appreciate the creative ways they've found to lower our cost structure in this cycle.

And although we've not shown any details today, we've been focused on cataloging our future drilling locations and we have grown our inventory significantly since the beginning of the year. So I'll look forward to seeing many of you on our December 10 Analyst Day and giving you a more detailed update on our E&P progress. So thanks and I will now turn the call back to Doug.

Doug Foshee

Thanks, Brent. We're getting close to wrapping up 2009 and I'm very proud of the performance by both business units. Given the overall economic backdrop, there has never been a time where execution was more important, and I'm really pleased with how our team has responded. We've asked them to husband resources, cut capital, cut costs, and at the same time keep their eye on the longer term and continue to prosecute our existing growth initiatives as well as continue to identify new opportunities.

And it's not just the Haynesville or the Eagle Ford, which are very public. The opportunities in our pipeline business aren't over, and we continue to see opportunities to serve our customers in new ways as the growth in unconventional gas around the country leads to new midstream and pipeline infrastructure needs for our customers. The steps we announced last night are important in terms of building our financial flexibility, protecting our credit profile and putting us in a better position to deliver on our growth opportunities. I hope that we've convinced you as we've convinced ourselves that we're taking these steps because of positive things that are happening at El Paso.

We look forward to sharing our 2010 plan and the strategies for our businesses at our December 10 Analyst Day meeting in New York. We're still in the process of finalizing that plan but here are a few things will you hear. Not surprisingly our 2010 capital program will be larger in 2009, driven almost exclusively by committed pipeline growth capital and the actions we've taken already give us a great running start at funding that growth. About half our E&P capital or more next year will go to a combination of Haynesville, Eagle Ford and Altamonte.

Overall capital in E&P will be consistent with spending levels this year, so given the mix change, we should see continued improvement in overall capital efficiency. I hope this gives you some sense for how our capital is shaping up for 2010. We look forward to taking a deeper dive with you in December and hope that you will join us in New York or on the webcast.

Before I turn it over to your questions this morning though I'd like to take the speakers' prerogative and publicly acknowledge Mark for the tremendous contribution that he's made to company as our CFO during a particularly eventful and important period in our company's existence. I couldn't be more thrilled that Mark will be leading the charge for our re-entry into the midstream business, a business that he knows so well. I look forward to watching Mark and his team create value for the El Paso shareholders going forward.

And finally, I want to officially welcome J.R. Sult and Dane Whitehead to the executive team. You both have big shoes to fill.

I'd like to open it up and answer your questions. I'm sorry we've gone a little long this morning but we had a lot to say. And I'd like to ask you if you would to limit yourself to two questions. If you have more, jump back in the queue, and we'll take them later, if we have time we'll take them offline.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Carl Kirst with BMO Capital Markets.

Carl Kirst - BMO Capital Markets

First off, just a clarification, as I was writing everything down. At the very end when you were saying about the 2010 capital program on E&P you said half is going to go to Haynesville, Eagle Ford, Altamonte. Did you follow that up by saying, overall, it should be basically the same level as 2009? Did I hear that correct?

Doug Foshee

I said consistent, which means pretty close to the same.

Carl Kirst - BMO Capital Markets

The real question that I wanted to ask also on the CapEx and maybe this is a little bit too much into the 2010 guidance. But as we sort of look at the potential now, we've got perhaps more opportunities coming in midstream, Jim mentioned other opportunities might be coming their way, perhaps some of that in Florida. But as we've now kind of taken these additional moves what do you think is perhaps the CapEx program that if we saw more opportunities coming to you guys? What do you think the CapEx you could support without jeopardizing your ratings? Is that something you can answer?

Doug Foshee

I think we'll be able to support easily the 2010 capital plan that we're going to show you on December 10. I think you should think about as I mentioned that the outset, think about our midstream strategy as a very long-term strategy for us. It is something that we have wanted to do for some time. We think now is the time to begin to do it. But you shouldn't think about that as necessarily causing significant capital needs over and above what we were planning to spend in 2010.

And you ought to think about, while we have lots of, we think, opportunities in front of us, for more infrastructure needs for our customers, I would anticipate most of that capital would be more like 2011, 2012 and beyond and so after we've hit this what we have said previously as our big capital spending year in the pipes in 2010 and then we've said we're going to be relatively consistent year-over-year with capital spending in E&P though because we continue to see a mix shift, meaning more capital in places like Haynesville, we should continue to see improvements in the capital efficiency of that spending.

Operator

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

Faisel Khan - Citigroup

I got a question on the Eagle Ford, talked about risk/resource potential 1.1 TCS at first well looks like it's doing pretty well. What kind of decline rate assumption are you guys taking into that risk resource? Similar to the Haynesville or something else?

Brent Smolik

Faisal this is Brent. Because the completion designs are quite similar, we're getting kind of the similar size and fracs and a similar number, we did a couple more here than we have been. The reservoir is not that different, characteristics, so we're thinking of them as very similar until we know something different, in terms of the profile. These will start at a lower rate probably than our best Haynesville wells but the profile will be very similar.

Faisel Khan - Citigroup

Just from a broader perspective, in terms of priority of capital, operating cash flow and including the potential proceeds from your asset sales, what's the could you prioritize paying down debt, spending capital and E&P pipeline also expanding your midstream operations, how would you guys prioritize that? And the follow-up to that on the dividend side too to be fair to say that the dividend cut is kind of a temporary sort of issue and we'll come back to it later?

Brent Smolik

Well, let me try to start sort of at the beginning of that comment. You will not see, as a result of what you know is a big capital spending year for us in the pipeline business in 2010, combined with plus or minus a billion dollars in capital spending in E&P in 2010, you won't see any debt reduction from us in 2010, right. So our ability to significantly de-lever the balance sheet starts to come into play post 2010.

As we get into that arena where the growth capital is largely been spent, of the current backlog in the pipeline business, then we begin to have new sets of opportunities that could be changing the company long term and decisions to make about the trade-off between debt reductions and dividend increases.

Faisel Khan - Citigroup

Okay. Fair enough. Thanks for the time. I will jump back in line.

Operator

Your next question comes from the line of Rebecca Followill of Tudor Pickering.

Rebecca Followill - Tudor Pickering

Back to the dividend, question in capital discipline investors in part like dividends because they provide a choke on capital discipline. So are you guys maybe in December going to talk some more about what your criteria is for returns, the capital discipline process, the capital allocation process, so that there's some reassurance that as you spend, that it is adding value down the road?

Doug Foshee

Yeah, we don't walk away from December 10, having done that I'll consider that a disappointment.

Rebecca Followill - Tudor Pickering

So we can look for that in December?

Doug Foshee

Yes, again.

Rebecca Followill - Tudor Pickering

Following up on that also, I know you guys walked through liquidity and things look really good, but again, whenever someone cuts the dividend and I know you guys are seeing those opportunities, you want some reassurance that it is for that opportunity. So you guys feel comfortable from your liquidity position, there's not a concern; there's not something else that's kind of in the weeds that we should be worried about?

Doug Foshee

I'm not sure I understand the nature of the question. It should come as no surprise to our investors that 2010 is a year when we will outspend the cash flow generating capabilities of the company. So the question really is what's the most prudent way to fund that? We made some really difficult decisions internally. The outcome of which was project insight, which will give us $150 million head-start on that. We also made the decision that spending the marginal dollar on investing in our business versus a hire dividend made sense. We think that's the right thing to do for our shareholders. We wanted, though, there is some symmetry around the fact that we hope in the eyes of our investors that we made hard decisions about internal ways to generate that cash flow first and in fact, we're going to take more costs out of the business internally, significantly more than we're asking our investors to allow us to keep in the form of a dividend.

Rebecca Followill - Tudor Pickering

So you didn't understand the question, but you answered it anyway, so thank you, Doug.

Operator

Your next question comes from the line of Jonathan Lefebvre with Wells Fargo.

Jonathan Lefebvre - Wells Fargo

On the maintenance CapEx for the E&P program, if I remember correctly, I believe it was about $1 billion in 2009 to hold production flat. Any sense for where that might be next year with services costs coming down and what you think maintenance CapEx might be?

Brent Smolik

Jonathan, the biggest shift we're seeing in the 09 to 10 efficiencies I think will come from the portfolio shifts as much as it will from additional CapEx savings from the supply side. So as we move more capital to Haynesville type wells with hire rates then that will be what most improves our year-over-year efficiencies. So we're going to be kind of in the same neighborhood, slightly improved this year versus next year versus this.

Jonathan Lefebvre - Wells Fargo

So if I heard you correctly, maintenance CapEx is about what it was in 09?

Doug Foshee

It depends on, if you call maintenance CapEx keeping volumes flat and ignore reserve growth, I think the thing that will change that has changed in our business, is our dollars, our capital efficiencies going up. Therefore, you should see the portfolio F&D costs come down, therefore you should see more reserve growth at a given level of spending.

Brent Smolik

And that's a trend we expect to continue.

Jonathan Lefebvre - Wells Fargo

One more, if I may. On the $300 to $500 million of asset sales is that inclusive of potential drop-downs or is that on top of potential drop-downs to the MLP? I just want a point of clarity on that.

Brent Smolik

I think we've clearly identified some assets in our portfolio that make sense to sell. We will also evaluate the opportunity set for drop downs. So the extent we do drop downs you know we clearly read the higher even exceeding that asset sales.

Jonathan Lefebvre - Wells Fargo

So that's on top of.

Doug Foshee

Yeah, it could be.

Operator

Your next question comes from the line of (inaudible) with JP Morgan.

Unidentified Analyst

Can you give us an update for your exploratory activities in Brazil? It looks like Petrobras reported an ore discovery he in the Potiguar block. You have some interest in. Can you give us an update on that?

Brent Smolik

They did announce that, I think it's on A&P website there. There are two blocks up in that area that were pure exploratory blocks that we have relinquished earlier this year one of those was official last month, one will be this month. So we are not in that well even though it's still showing us as a current participant in the concession we are not in that well. And I think what they have announced is a technical discovery. I don't think there's been any announcement about commerciality.

Operator

Your next question comes from the line of (Inaudible).

Unidentified Analyst

Great news on the various cost cutting efforts and the Eagle Ford acreage. I wanted to ask about the SNG rate case settlement. I was just wondering what kind of earnings impact that's expected to have going forward.

Jim Yardley

Our rate base increased as a result of primarily of a lot of hurricane repairs in the Gulf of Mexico, and the earnings power of that is in the range of $10 million to $15 million in EBIT.

Operator

Your next question comes from the line of Lasan Johong of RBC Capital Markets.

Lasan Johong - RBC Capital Markets

Doug, if the dividend cut is somewhat temporary, i.e. a year, maybe two years. Why make the decision to cut it and not sell additional assets or do more drop-downs to balance out the CapEx needs?

Doug Foshee

You bring up a good point. These are all discussions and debates we had internally as a management team and with our board. First of all, I think someone else suggested the word temporary. We haven’t said the word temporary in our press release. We're not saying the word temporary now, which I will say that as we get beyond 2010 and get the bulk of the growth portfolio and the pipeline business put in place, we'll have the ability to make different decisions.

At the end of the day, though when you look at the existing financial levers that exists in our company, when you look at the level of capital that we expect to spend in 2010 and the opportunities we see in front of us. We thought that it was actually the prudent thing to cue to reduce the dividend, because in effect especially in 2010 at the margin, any dividend that we would pay would be debt finance. And that's not a position we wanted in to in.

Lasan Johong - RBC Capital Markets

I understand that. I just didn't think $100 million would make that much of a difference in your CapEx budget.

Doug Foshee

You're right. And that's actually a very good point. I guess my observation would be most of the things that we're doing individually are not needle movers. I think what we tried to do was show people that cumulatively they're really important. Cumulatively, the actions that we've taken are really important to put us in a position to be able to fund existing growth opportunities in both of our core businesses that we know generate attractive rates of return, even at low commodity prices, and be able to go into 2010 with a confidence we can fund that, no matter the circumstance.

Lasan Johong - RBC Capital Markets

Yeah, I understand that. That's a very good point. Let me ask you about midstream business. Can you give us a little more color on kind of what kind of projects you're planning to do, in which basin? Are you talking the about just simply gathering, or are we talking about more complex stuff including fractionation and processing?

Doug Foshee

I think we would like to say we have a strategy. Our view would be that it's fairly competitively sensitive at this point. We want to ask you, as an investor, to some extent to give us the benefit of the doubt that when we come with a project, it will make sense, and it will meet the strategic guidelines that we laid out, meaning it will take advantage of the existing physical footprint of one or more of our existing businesses. And it will take advantage of an existing set of competencies, so that when we go into it, we can have a relatively high degree of confidence, we're going to get the kinds of rates of return out of it. We think we should get. And in the best case, we think it has the chance actually to leverage the returns in one or more of the other two businesses.

Lasan Johong - RBC Capital Markets

You (Inaudible) what you're telling me that this is more infield drilling than it is a exploratory or even a step-out well.

Doug Foshee

Yes.

Operator

Your next question comes from the line of Kevin Smith with Raymond James.

Kevin Smith - Raymond James

As your production has kind of declined a little bit this year. Do you get a feeling that your inherent decline rate has going down?

Brent Smolik

Gone down meaning higher decline, Kevin?

Kevin Smith - Raymond James

Well, lower decline rate. I assume a lot of your Gulf of Mexico and other properties, as they come down, they're stabilizing production. I'm just trying to get a feel for what you really need to spend to maintain production and maybe win current CapEx plans will allow you to flat line production and potentially grow it.

Brent Smolik

The discussion we had at the load areas that we still frac were somewhere around a $1 billion to keep production flat year-over-year from 9 to 10, although that's improving because of lower costs and shifting to some of the higher rate wells. And we will see benefit as we get further out in time of a shallower decline in some of the Gulf Coast properties, but we haven't yet seen it in 9. We've seen those roll off because we haven't spent much capital on them. So you have seen those roll off a little bit but they will shove around a little bit as we into '10.

Kevin Smith - Raymond James

What do you think your decline rate is right now?

Brent Smolik

Mid-30s. Overall average for the full domestic portfolio.

Kevin Smith - Raymond James

Okay. And so you'd expect, then for at least the next several quarters for production still declined at the same rate?

Brent Smolik

That's a trend. I think that trend…

Kevin Smith - Raymond James

Not overall.

Brent Smolik

I think the trend that you can see kind of in the moving more production to your onshore and more of the resource plays is likely to continue. So we'll see slight growth in those areas or growth in those areas, and we'll see some decline in the Gulf Coast part of our business for the next couple quarters. Overall growth, excluding Eagle Ford.

Kevin Smith - Raymond James

Are you growing production in your Altamonte properties?

Brent Smolik

We got down to one rig, and so it's been kind of flattish through the summer but we've ramped recently back up to the second rig so we'd expect to see production start back up again.

Operator

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

Faisel Khan - Citigroup

Couple of follow-up questions. First I guess on the Gulf Coast volume, those seem to sequentially be ramping down over the last several quarters. I guess where do you think that will bottom out in terms of production? I know you guys are focusing your efforts in the Eagle Ford and the Haynesville, but kind of western parts of your portfolio.

Brent Smolik

Faisel, I think it's going to be a function of capital that we spent in the early part of next year, and as Doug points out, we're going to have to parse out Eagle Ford, because right now we count that in South Texas, which is rolled up in to Gulf Coast. It looks to me like sometime middle in next year we'll see that slide for the next two to three-quarters, and then we'll be able to sell it out a bit there.

Faisel Khan - Citigroup

Talk a little bit more about the drilling in Egypt. The first well you say is proved oil. Second well tested 1700 barrels oil per day. Where are the first two discoveries in that block? Is it the Boraq trend or Nawwar trend you guys described in your presentation?

Brent Smolik

Yeah almost right center of the block that T-shaped block, right in the center of it. In the Boraq trend. That's where the two structures are. Two wells, two separate structures, both of them with oil in them, then we're going to have to delineate the two of those and then Nawwar is way west that’s where the third well that was drilled that was the dry hole.

Faisel Khan - Citigroup

How would you compare kind of the fiscal terms in Egypt with you know say that of Brazil or U.S.? How should we look at that?

Brent Smolik

The oil terms are quite good. If we find gas, we have to negotiate that gas contract price and that's why you see us focusing more of the activity on the oilier part of the trend the western part southern and western part of the three block area okay great so based on the well costs and the resource sizes, recoveries per well they are very competitive contracts and returns.

Faisel Khan - Citigroup

Last question, on Ruby, you talked about it being 50-50%, financed with debt and equity. Given the partnership you guys have with your partner, what kind of equity contribution would you guys to have make to the JV over the next year or so?

Brent Smolik

Yeah, I think we'll both be contributing approximately $700 million. We're now trued up and on a pro rata basis, I think by the time we start construction we will have contributed all of our equity.

Faisel Khan - Citigroup

Thanks, I appreciate the time.

Brent Smolik

Operator, we'll take one more call, please.

Operator

Your final question comes from the line of [Stuart Weinman] with Catapult.

Unidentified Analyst

Thanks for taking the call. Just had a quick question on the acquisition breakout on the E&P side of roughly $39 million. Was that all for the Eagle Ford acreage?

Brent Smolik

No that was when we paid in our historical share of the South Alamein block in Egypt. The same block we've been talking about drilling on. We bought into that block that's operated by Cepsa. So the acquisition total is that there is some cost basically cost basically.

Unidentified Analyst

Thanks for the clarification.

Brent Smolik

That concludes our call. We appreciate your time. We appreciate your questions and if you have follow-ups, please let us know. Thank you.

Operator

Ladies and gentlemen, this concludes today's El Paso Corporation Third Quarter 2009 Earnings Conference Call. You may now disconnect.

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Source: El Paso Corp. Q3 2009 Earnings Conference Call
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