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Executives

Bruce Connery – VP, Investor and Public Relations

Doug Foshee – President and CEO

Mark Leland – EVP and CFO

Jim Yardley – President, Pipeline Group

Brent Smolik – President, El Paso E&P Company

Analysts

Shneur Gershuni – UBS

Carl Kirst – BMO Capital

Faisel Khan – Citigroup

Becca Followill – Tudor, Pickering

Rick [ph] – Barclays Capital

Sam Brothwell – Wachovia

El Paso Corporation (EP) Q4 2008 Earnings Call Transcript February 26, 2009 10:00 AM ET

Operator

Good morning. My name is Abigail and I will be your conference operator today. At this time, I would like to welcome everyone to the El Paso Corporation fourth quarter 2008 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. Mr. Connery, you may begin your conference.

Bruce Connery

Good morning. And thanks for joining our call. In just a moment I’ll turn the call over to Doug Foshee, our President and Chief Executive Officer. Others with us this morning who will be participating on the call are Mark Leland, our CFO; Jim Yardley, President of our Pipeline group; and Brent Smolik, President of El Paso E&P Company.

Throughout this call we will be referring to slides that are available on our Web site 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 Web site. 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 statement regarding forward-looking statements section of earnings press release 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 call or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise.

And please note that during the call, we will be using non-GAAP terms such 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.

Doug Foshee

Thanks, Bruce, and good morning. I’d like to kick off this morning by hitting the highlights for 2008 and setting out our plans for leading the company through the current environment. And then before I turn it over to Mark, I want to spend a few minutes describing to you our key priorities.

In spite of the challenges in 2008 from the hurricane season and then the subsequent meltdown of the economy, we had some significant accomplishments for the year. Though I know we can’t ignore the price related ceiling test charge here at the end of the year, it’s a fact that but for that charge caused by the precipitous drop in commodity prices in the fourth quarter, we would have posted our sixth consecutive year of improved earnings. And both of our business units contributed significantly to that success.

In the pipes, we placed seven growth projects in service. We see in the outcomes here, with the projects overall in service at seven times their run rate EBITDA, the positive effects of all of the investments we’ve made over the last two years with Jim and his team in improving our commercial skills, our supply chain skills, and our project execution skills. These investments will continue to pay dividends as we move forward on the other signature achievement for the year, securing a committed backlog of $8 billion in new growth projects, which we expect to generate an incremental $1.2 billion of EBITDA a year when fully in service. And all of this was accomplished while achieving the best safety performance in our history.

Over in E&P, we grew our non-crude inventory by almost 30% year-over-year. And the gross growth was an area that had all the attributes we looked for, significant acreage largely held by production, lots of relatively low risk repeatability so we can benefit from continued – continuous improvement, and longevity. Also, again before considering the effects of the price revision at year-end, we achieved reserve replacement ratio of almost 200%. This increase was done at a cost per unit domestically at $2.87, a 12% reduction over 2007 in a year where costs were an all time high. This is a direct result of our high-grade process over the past few years; the investments we’ve made to upgrade our supply chain management skills; and, a focus by Brent and his team on larger scale, more repeatable programs.

In Brazil, we had success with the drill bit. And in Egypt we kicked off a very exciting drilling campaign. And Brent’s going to describe these in more detail during his comments.

We put in place during 2008 a significant amount of price protection for 2009 that today have a value of over $650 million. That gives us significantly more flexibility in how we manage through this year. In addition, we’ve been able to leg in into some 2010 price protection at attractive levels. Our cash flow from operations for 2008 was up over 30% from 2007. Finally, and maybe most importantly, we reacted quickly to changes in the markets and built liquidity significantly.

Under very difficult market conditions, the teams executed on several asset sales. And Mark and his finance team accessed both public and private debt markets. The combination of which has us today holding $3 billion – $3.3 billion of liquidity, eliminating our need to access capital markets this year under any commodity price scenario.

Now let me get – move on to 2009 and beyond. We find ourselves as a leader in uncharted waters. Commodity prices are low and have descended at a rate much faster than cost. Demand for our products is down. We’re all trying to forecast when the effects of a dramatic drop off in drilling activity will result in a rebalancing of the supply-demand equation, especially for natural gas.

The global recession means some new realities in capital markets today and a great deal of uncertainty as to the future. The monetary and fiscal stimulus that’s been both provided and proposed by Congress, Treasury, and the Federal Reserve means that all of the normal macroeconomic drivers will suffer distortion maybe for a long time. Any one of these would be a real leadership challenge, but the combination leaves us faced with an unprecedented need to manage in real-time; to constantly reassess our assumptions under various scenarios; to maintain maximum flexibility to respond to near term events; and, to communicate regularly with our primary constituencies, our investors, our customers, our employees, and our Board.

So in that environment what have we done so far? First, we acted swiftly to address our liquidity needs in 2009. Second, we cut capital. But we made the cuts with some principles in mind. We want to protect our ability to execute on the backlog of committed projects we have in the pipes at all cost. But even here we’ve worked to reduce capital by working our supply chain early and often.

At E&P, we knew that it was appropriate to cut capital. But we wanted to do it in a way that preserves as much of our future inventory as possible. In addition, we need real-time mechanisms and lots of communication to ensure that we’re staying focused on generating adequate returns on the capital we do spend given the fluidity of commodity prices, basis differentials, and oil field services cost.

And in this environment we want to shorten up the duration of our supply chain as much as possible to give us as much flexibility as possible and oil field services market that, at least in the near term, has excess capacity. We’ve been diligent in communicating with the rest of the 5,000 members of team El Paso, exactly what our challenges are and how we intend to respond. Finally, we’ve set up much more frequent reviews of our plan not only among the leadership team, but also with our Board.

Now, if you would turn to slide seven, titled “Key Priorities”, in an environment like the one we find ourselves in today, the tactical priorities take precedence over many things. But we’re trying hard to make all of these near term decisions in a way that preserves our longer term strategic objectives. So on time and on budget for $8 billion worth of growth projects is absolutely front and center for Jim and his team. At the same time, we need to continue to listen to our customers and their needs and be ready to respond while being selective about new opportunities. And finally, our commitment to our industry leading pipeline integrity program and its completion is sacrosanct.

As a reminder, we’re spending about $75 million a year to make all of our onshore pipes six inches and greater, in-line inspectable or (inaudible) by 2012, going well beyond Federal safety requirements.

In E&P, our team knows that we need to be prepared to flex their program up and down more than is ideal. And we need to do this without sacrificing our ability to capture opportunities down the road. The team needs to live within its means. And finally, we continue to look for opportunities to high-grade our portfolio even in a down market as we did just recently with the sale of some mature assets.

With regard to our balance sheet, we’ll continue to maximize liquidity and use the full suite of funding tools available to us. We don’t know where gas prices will be for the next few years so we’re taking actions to ensure that we can withstand a prolonged period of low commodity prices. But we’ll preserve the investment grade ratings in our pipes. And as the growth projects come on stream and begin producing that incremental $1.2 billion in cash annually, we’ll look to significantly improve our credit metrics.

Finally, we’ll continue to work on continuously improving our return on total capital. With that as pretext, I’ll turn it over to Mark and come back at the end to wrap up. Mark?

Mark Leland

Thank you, Doug. And good morning, everybody. I’m starting on slide nine. As Doug mentioned, despite the challenging environment in which we included the financial market’s turmoil, falling commodity prices, plus residual impact of Hurricane Ike, this quarter, the company generated good earnings and cash flow. We’re reporting adjusted earnings per share of $0.21 compared to adjusted earnings per share of $0.27 for the fourth quarter of last year. I’ll cover the adjustments on the next slide.

Reported earnings per share was a loss of $2.43, which includes a $2.8 billion non-cash ceiling test charge and impairment of our investment in Four Star. Adjusted or proportional EBITDA was $1 billion, up 15% from the same period last year. Adjusted EBITDA for the quarter includes over $225 million of mark-to-market gains and other special items. Excluding those items in mark-to-market gains, adjusted EBITDA was 11% lower than the same period last year. The key drivers affecting the fourth quarter earnings were lower oil and natural gas prices and residual impacts on both business units from Hurricane Ike. Jim and Brent will provide more color on business unit performance.

For the full year, we’re reporting adjusted diluted earnings per share of $1.31, compared to $1 last year. Adjusted or proportional EBITDA was just under $4.1 billion, compared to just under $3.1 billion last year. And cash flow from operations was $2,370 million, up 31% from last year. So for the full year we saw significant improvement in cash flow and adjusted earnings.

The items impacting earnings this quarter are highlighted on slide 10. This quarter we’re adjusting for the ceiling test charges and Four Star impairment as well as normal adjustments we’ve made throughout 2008, which are only for significant mark-to-market items and legacy matters in our non-core discontinued businesses.

The non-cash ceiling test charges for Four Star’s – and Four Star’s impairment totaled just under $2.8 billion on a pre-tax basis or $2.90 per share. Year-end prices used for the ceiling test calculation were $5.71 per MMbtu for gas and $44.60 per barrel of oil. The second adjusting item is a $37 million pre-tax or $0.03 per share mark-to-market gain from the change in fair value of legacy power trading contracts in the marketing segment. The third significant item impacting the quarter’s results is a $16 million or $0.01 per share gain associated with a legacy indemnification related to the sale of an ammonia facility. The fourth item is a $40 million or $0.06 per share tax benefit associated with restructuring several of our foreign legacy legal entities. The fifth item is a $9 million or $0.01 per share gain associated with a change in fair value of production puts in call in the marketing segment used to hedge E&P cash flows. These positions have now expired and won’t impact the marketing segment any longer. The final adjusting item is $164 million or $0.15 per share mark-to-market gain on derivatives in the E&P segment due to low – lower oil and natural gas prices at quarter end. These amounts are net of $37 million of current quarter settlements. So accounting for these items brings adjusted EPS to $0.21 per share.

During the quarter, we elected to de-designate derivatives treated as accounting hedges in the E&P segment. That means all derivatives used to hedge E&P production will be accounted for on a mark-to-market basis through earnings which will – which we will highlight and adjust for each quarter going forward. We think this will reduce complexity associated with our hedging activities by treating all of our derivatives on a consistent basis opposed to where we were with a portion of positions receiving hedge accounting treatment and a portion’s being marked through earnings.

Slide 11, business unit contribution. On a combined basis, our core pipeline and E&P businesses generated $877 million EBITDA and adjusted our proportional EBITDA of $924 million, both before ceiling test charges and Four Star impairment. Adjusted EBITDA is calculated with our four – with our 50% interest in Citrus and 49% interest in Four Star on a proportional basis.

Marketing reported EBIT at $27 million, and I’ll provide more detail on this in a minute. Power EBITDA was a $3 million loss and corporate EBITDA was $49 million due primarily to mark-to-market gains and a change in the fair value of legacy indemnification on the sale of the ammonia facility, and a gain on a sale of a legacy property in the Northeast. There’s a chart in the appendix that provides the relevant details on the adjusted EBITDA calculations.

The marketing segment results are summarized on slide 12. For the quarter, we realized an EBIT gain of $27 million compared to a $64 million loss. The key items point out – the key items to point out for the quarter are a $9 billion gain due to production related derivatives which are now completely rolled off. We also had a $37 million gain on the Power book mostly due to interest rate changes.

For the year, we realized mark-to-market loss totaling $104 million compared to $202 million loss last year. The primary drivers of this loss were $50 million loss on production related derivatives, which include mark-to-market losses due to price movements and cost associated with terminating some of these positions. The other big driver was a $46 million loss in Power – in the Power book, which is primarily driven by changes in interest rates.

The slide we’ve shown in the past couple of quarters showing PJM basis movements in related cash settlements is updated for the fourth quarter and included in the appendix. The slide demonstrates cash settlements on a – on basis positions continue to be (inaudible).

And now turning to cash flow on slide 13, for the year, cash flow before working capital changes was just under $3.1 billion, up $924 million or 43% from cash flow – from continuing operations – and cash flow from continuing operations was $2,370 million compared with $1,838 million for the same period last year.

CapEx for the quarter was $2,757 million. And we spent $362 million primarily for the acquisition of a 50% interest in Gulf LNG and some producing properties in the Rockies. We completed the E&P properties sales as well as two small international power plants in a legacy real estate and received $682 million in cash proceeds. So the key take away from this slide is cash flow from operations was strong and up 31% year-over-year.

I want to give an update on financing activities and liquidity. Slide 14 chronicles the significant financing activities completed since our third quarter call. We completed six transactions with notional value of $1.785 billion, which after fees and discounts, added approximately $1.7 billion in incremental liquidity. We’ve employed many of our corporate finance tools in doing so. We opened a high-yield market in early December with an expense of five-year corporate bond. We used unencumbered E&P reserves to secure $300 million revolver. We then used excess capacity at one of our investment grade pipelines to issue $250 million high grade bond. Then we went back to the high-yield market for another $500 million corporate bond at a much more attractive rate.

In addition, throughout the period we added $100 million of LC credit – LC capacity through a CDS backed bank facility, which we plan to increase to $350 million to replace the maturing LC facilities later this year. And earlier this week we closed a $135 million private placement at the Elba LNG facility to finance part of its current expansion. These financings appear expenses and they certainly higher than they would have been a year ago. But the company’s weighted average cost of debt is still a respectable 7.1%. We’re also well in the way in completing a project financing of the Elba Express Pipeline, which we expect to close in the next month or so.

Slide 15 shows the resulting improved liquidity provided by the financing activity and pulled back capital spending we described in the third quarter. In short we’ve build liquidity from $1.9 billion to what we estimate to be about $3.3 billion at the end of this month. In spite of spending over $900 million of CapEx during the same time and repaying debt. As a note, February liquidity is net of a $112 million of maturities that came due earlier this month.

Our aggressive approach to building liquidity reflects a couple of things. First, we’re not good prognosticators and thus don’t have a unique insight into when the financial markets will improve. So we will air on the side of caution. And second, we believe that as a result of the turmoil and uncertainty in the economy and credit markets, a high value is placed on certainty and financial flexibility.

Slide 15 highlights how the bond market has reacted to our efforts to build liquidity. You can see yield on the El Paso 7% bond due 2017, peaked just before we did the first bond deal in December. Since then you can see the dramatic improvement in trading levels, down to the BBB index level where these bonds are traditionally traded. In the equity markets, we've seen similar results since the day before our bond deal transaction, our bond transaction, our equity has materially outperformed our proxy peer group as well as the S&P energy index.

We have a very nice hedge position for 2009, which is summarized on slide 17. Our 2009 gas hedges are consistent with what we've shown before. We have an average floor of just over $9 per MMbtu and 176 Tbtu. We have 1.5 million barrels of our oil production swapped at $45 per barrel. Approximately 75% of our domestic natural gas production is hedged, and those positions have year-end value of about $730 million.

We've made some changes to our oil positions. Recently, we monetized our 3.1 million barrels of $110 swap for $186 million in cash. We replaced those hedges with the 1.5 million barrels of $45 swaps I’ve mentioned – just mentioned. This monetization allowed us to build liquidity and reduce exposure to one large financial institution at a very low discount. These hedge positions will contribute significantly to our cash flow stability and liquidity for 2009.

We began establishing our 2010 hedge program. We don’t have any oil hedges for 2010 yet. On the gas side, we have about 47 Tbtu hedged and an average floor of $6.79. The position is made up of 22 Tbtu of $7 puts and 25 Tbtu of fixed price swaps averaging $6.61. We look to continue to opportunistically add more floors as the year progresses.

Beginning on slide 19, I'll provide more color to yesterday’s release on the outlook for 2009. Like most companies in our sector, we've been running numerous planning scenarios in response to and in preparation for an uncertain economic environment.

Our current outlook assumes $5 per MMbtu NYMEX gas for the year, and $40 per barrel of WTI oil prices.

We expect to spend between $2.7 billion and $ 3.1 billion of capital, with $1.7 billion being spent on pipelines, just under $1.3 billion of that for expansions. In the E&P group we expect to spend between $900 million and $1.3 billion with about $250 million being allocated internationally. Based on those capital plans, we expect the E&P group to produce between 725 and 815 million cubic feet a day, including our share of four star. E&P plans – as Doug mentioned, E&P plans are very fluid given uncertainties around natural gas and oil prices as well as service costs.

Our emphasis is on maximizing return on capital. We will adjust allocation and timing the E&P capital based on market conditions. And we've already planned to delay 2Q spending in anticipation of lower service costs, and Brent will expand on this. We're monitoring and adjusting our capital program continuously, which may result in a wide range of outcomes given market conditions.

Slide 20 highlights our current financial targets for 2009. Based on our ‘09 outlook assumptions, we expect adjusted EPS to be between $0.85 to $1.05. EBIT will range between $2 billion and $ 2.3 billion, the pipeline group at about $1.4 billion, and the E&P between $800 million and $900 million. EBITDA is expected to be between $ 3.1 and $3.3 billion, with the pipeline at $1.8 billion, that by the way is up 10% from 2008.And the E&P group will be between $1.4 billion and $1.6 billion.

Resulting cash flow from operations is expected to be between $1.7 billion and $2 billion. And given our strong hedge positions, we have fairly limited exposure in commodity prices, which you can see here $1 change in gas or $10 change in oil prices generates about a $0.04 change in EPS or $40 million change in EBITDA.

Slide 21 is a liquidity roll forward for 2009, starting with year-end liquidity of $2.2 billion, and then adding the financing activity and assets sale close through February brings current liquidity to about $3.3 billion. That liquidity plus cash from operations and proceeds from new – for a few non-core assets sale should give us ample liquidity from maturities and CapEx for the year without access in capital markets.

We do assume we're going to renew the new $ 300 million EPEP revolver in December, and we’ll complete – the completion of our LC facility. So under our plan, we should have between $1.2 billion and $1.6 billion of liquidity at the end of the year. This will provide us plenty of cushion and flexibility to the extent we experienced changing commodity prices or the extent we haven’t completed pipeline partnering opportunities by year-end.

We'll continue to be opportunistic using all of our tools. We have to raise liquidity to finance our pipeline backlog, such as project financing, pipeline financing, corporate debt parenting, partnering additional pipeline projects, and MLP dropouts.

So just to wrap up on slide 22, we've made substantial progress on building liquidity, which has been reflected in both our bond spreads and our equity performance, reducing pressure on future cost of capital. Our 2009 capital program balances our objectives as funding pipeline expansion backlog while continue to focus on value creation on our E&P programs and maximizing liquidity. And as we demonstrated in the recent past, we'll be opportunistic in the capital markets.

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

Jim Yardley

Thanks, Mark. The pipeline has had an excellent year in 2008. We continued to deliver consistent financial reports, throughput grew for the fifth consecutive year, and we made very meaningful progress in advancing our growth projects. We placed in service seven expansions totaling about $700 million, including three more in the fourth quarter. And we signed customer commitments to allow us to move forward with three new large projects so that our committed backlog at year-end was nearly $8 billion.

Finally, something we don’t speak with you often enough, our safety performance. We had our best ever safety performance in 2008, as Doug mentioned, and this is a tribute to our 3,400 pipeline employees across the country to keep the gas flowing 24/7 safely and reliably.

On slide 25, the summary of our financial results. EBIT and EBITDA for the year are right on plan. Before minority interests attributable to the MLP, EBIT increased 6% for the quarter and 3% for the year. For both the fourth quarter and the year, revenue increased from expansions and capacity sales, and was somewhat offset by increased, costs including hurricane related costs of $18 million and $ 31 million for the quarter and year, respectively.

Our EBITDA adjusted for our 50% interest in Citrus is now approximately $1.8 billion, and meaningful growth and EBITDA is kicking in. Before the hurricane impact, our fourth quarter EBITDA grew 9% from fourth quarter 2007.

Capital expenditures for the year were approximately $1.2 billion, not including our acquisition of 50% of Gulf LNG and a small acquisition on TGP. Of the $1.2 billion, approximately $420 million was for maintenance capital, and the remainder was on our growth projects.

On slide 26, slide 26 summarizes our throughput for the year. Throughput was flat on our eastern pipes and increased on our western pipes, overall, a 4% increase year-to-year. In the east on TGP, throughput increased from the deepwater independent sub, but was negatively impacted by the hurricanes.

Today, total volume out of the Gulf of Mexico and TGP is still down by about 300 a day relative to pre-hurricane flows. SNG benefited from a full year of the Cyprus pipeline from Elba down to Northern Florida, but power gen loads on SNG fell due to the milder summer in the Southeast. In the West, lines to California increased primarily due to lower prices in the Permian, resulting in increase flows west on EPNG, essentially displayed Canadian deliveries into Northern California. On the Rockies, volumes on CIG, WIC, and Cheyenne plains all benefited from various expansions and increased Rockies production.

While throughput increased year-to-year, more recently, we see signs of weakening gas demand, especially in the industrial sector. Late on the fourth quarter and to date this year, throughput has declined significantly to directly serve industrials on SNG. SNG’s industrial customer mix generally mirrors that of the country. As a reminder, our revenue stream on the pipes is predominantly driven by demand charges, so there's little middle term financial impact of lower throughput if that occurs.

Turn to slide 27, the next three slides talk about our very good progress in executing on our growth backlog. On slide 27, here are the seven growth projects we placed in service and are now earning revenue. They've been built on approximately seven times EBITDA on a run rate basis.

During the fourth quarter, we completed and put into service two more projects in the west, the WIC Medicine Bow expansion, to increase capacity out of the (inaudible) basin, and our High Plains project that expands CIG system by 900 day, primarily into the Denver area.

Turning to slide 28, we update the slide portally for your reference. It shows our committed backlog. I’’ remind you that the capacity of these projects is either fully contracted or substantially contracted under long term contracts with customers, so both we and our customers are committed.

The backlog will have attractive profitability. Like the recently completed projects, we expect the CapEx to EBITDA ratio for the backlog to average approximately seven times on a run rate basis. And we continue to manage the CapEx risk and de-risk the projects as I'll discuss in the next slide.

Since our last quarterly call, we see no change in our CapEx forecast to complete these projects. Concerning timing, most of the backlog, approximately $ 6 billion, will not go into service until 2011 or beyond. Only four smallish projects totaling $200 million will be placed in service this year. And then early next year the first phase of the Elba expansion and Elba express pipeline go in service. Elba express is our largest construction project this year. It’s a 190 miles of 36 and 42 inch pipe. All the pipe has now been delivered from overseas and construction will kick off next month.

Of the nearly $8 billion backlog, about $ 1.3 billion were spent through 2008, and another $1 billion has been financed in Gulf LNG and FGT. Our spend in 2009 will be about $1.3 billion, leaving a balance post 2009 of just over $4 billion.

The largest piece of that is Ruby. And as we said, we intend to bring in a partner on Ruby and project finance it.

Turning to slide 29, this speaks to how we’ve mitigated the capital cost risk on the backlog. These five projects represent nearly $7 billion of the total of $8 billion. First, on our LNG project, both the Elba extension and the new Gulf LNG terminal are being built under fixed price EPC contracts.

CBI, that built the prior Elba expansion, is doing this expansion as well. At Elba, the outer tank of – the other wall of the new tank is nearly complete, and the roof raising will be done in late March. Aker Kvaerner is doing the Gulf LNG facility in Pascagoula. And there, the concrete tank base slabs have been completed and the seawall is taking shape.

On the pipeline project shown here, remember that, typically, the cost for the pipe and the construction is represented by two-thirds of the total CapEx of the project. So you can see like the LNG projects, our pipeline projects capital costs also have been substantially de-risked. Specifically with respect to the steel and pipe, all the pipes for these projects have been contracted for on a fixed price basis. Our strategy was to lock in the pipe cost, at the same time, receive customer commitments for the expanding capacity, which we did. And we are happy with the resulting profitability and reduced risk.

In addition, we continue to work with our pipe suppliers to look for opportunities to benefit from the now falling prices of steel and pipe. For example we recently negotiated a significant price reduction on the price for the line 300 project from our overseas supplier.

Concerning construction installation, as you can see, we've secured contracts with installers on either unit priced basis, or in the case of Ruby, an incentive priced arrangement. So again, we have a high degree of price protection and incentives for contractors to perform. We've not yet concluded negotiations on line 300 for installation but the market is now working in our favor and we haven’t decided yet whether to use a unit priced or time and materials arrangement on this one.

Finally, an update on recent activity on our Ruby pipeline. We have binding long term commitments from 12 shippers for 1.1 a day out of Ruby's total capacity of 1.3 to 1.5 a day. Last quarter, PGNE, our largest shipper received approval from a California PDC [ph] concerning their contract with Ruby. And last month, we submitted to FERC certificate application. These were both major milestones. We expect FERC to process the application over the next year and look forward to FERC certification in early 2010.

So in summary, on slide 30, our pipes continue to demonstrate earnings stability that’s inherent in our demand based revenue string. We also have clear multiyear growth in hand and are executing to place these backlog projects in service.

And with that I'll turn you over to Brent.

Brent Smolik

Thanks, Jim. Good morning, everyone. I've got a lot of materials that covers – so I’m going to move quickly this morning. Note there are some charts in the appendix, so not going to review, and the materials are included there for your reference.

Turning in to slide 32, as Mark said, E&P ended the year with adjusted EBITDA of about $2.3 billion. Annual production came in consistent with our November guidance of $316 million, a day, which is up about 2% on a pro forma basis from 2007.

On the reserve side, we released our end of year results a couple of weeks ago, and our numbers prior to price revisions were solid. We replaced 195% of domestic reserves. And our domestic reserves replacement cost dropped to 287 per Mcfe versus roughly 325 in 2007.

In the year where service costs were all time highs for the year, we’re very proud of this improvement in our F&B . Our non-proved inventory also grew by 27%, and most of that growth was in the unconventional and conventional low risk categories, which is where you would expect to see it based on our focus in our 2009 capital program.

Our Camarupim project is moving closer to first sales and Petrobras has informed us that they now expect first production to be early in the second quarter. Camarupim is a gas project which is priced relative to an oil basket of fuel oils. And with low year-end pricing, we didn’t book any reserves in that project in 2008. So those reserves will positively impact our 2009 results.

And then way back in 2001 we closed the sale of the E&P assets that generated about $640 million of proceeds and completed a hydrating process, and through those sales, we also released about $90 million of P&A liabilities. We sold about 300 (inaudible) of approved reserves, mostly in the Gulf of Mexico and the Texas Gulf Coast.

Turning now to slide 33, Mark has covered most of the financial information. So I'll just add that excluding the ceiling test and impairment charges we took in 2008, EBIT was roughly flat with the fourth quarter of 2007. Unrealized gas prices were flat, while oil prices were substantially higher. Production for the quarter was lower than 2007 due to the hurricane interruptions in 2008, along with the fact that 2007 included a full period of the volumes from the properties that we then sold in the first quarter of 2008.

On the capital side, we came in below $1.7 billion for the year. And you may recall that we were trending closer to $1.9 billion prior to our CapEx reductions that we initiated in the fourth quarter. Cash costs for the quarter in the year were higher than last year, which is better displayed on slide 34. So let's turn there.

The direct lifting costs were up about $0.15 per Mcfe quarter-to-quarter . This reflects about $9 million of hurricane related costs and a loss of $53 million a day of fourth quarter production from hurricane interruptions. The year to date picture is the same story with the hurricane volumes impacted on the full year basis by about $25 million a day.

G&A was up for the quarter at about $0.14 a unit, primarily due to the lower volumes and slightly higher staffing levels, while the full year unit rate was down about $0.05 a unit. So the key takeaway for the year is our controllable cash costs were down about $0.04 per Mcfe despite the repair costs and the loss of hurricane volumes as we continue to find ways to manage our lifting costs and our G&A in what was a pretty inflationary environment last year.

I'm now turning to full year production on slide 35. There's also a quarterly production chart in the appendix. On a reported basis, our volumes were down 5% from 2007, but there are a number of moving parts here. Again, we bought Peoples in late 2007 – September of 2007, and we completed our divestitures in the first quarter of 2008, plus we had the hurricane interruptions in late 2008. When you adjust for all that, on a pro forma basis, we are up about 2% for the year. Again, hurricane’s impact to the full year by about $25 million a day, and without that adjustment the pro forma full year production would have been roughly flat to ’07 and about $790 million a day.

So turn to the next page, the waterfall on slide 36 shows the changes that took our proved reserves from 3.1 Tcf down to 2.5 trillion cubic feet. As I noted earlier, we are pleased with almost 600 of reserved additions. It’s a dramatic year-over-year improvement for us. And it reflects the understanding – our improved understanding of our – of our asset base across the domestic US.

We’ve produced almost 300 Bcf equivalent, sold about 285 of these net of purchases. And we had about 560 Bcf of negative revisions, again mostly due to price. As shown in the table on the bottom left, both oil and natural gas prices were down from end of year ’07, but oil was down far more than natural gas. And most of our negative revisions were in our more early asset areas, including the Altamont oil field in Utah and in offshore Brazil.

On the right side of the chart, we note that assuming $7 price for natural gas and $70 for oil as a year-end spot price, the year-end reserves would have been roughly 3 trillion cubic feet. And if we drop that down to $6 and $60, it’s about 2.9 trillion cubic feet equivalent. So hopefully, you’ll see that we – that we’ll see some of these reserves added back to the ledger as we go forward in the future.

On slide 37, we show reserve replacement costs before price related revisions, and reserve replacement rates for 2006, 2007, and 2008. The green colored bars reflect drill bit only metrics without the impact of acquisitions, and the trends reflect the fundamental improvements that we’ve made in our portfolio and in our operating capabilities. Again, we’re proud of these trends over the last three years, but especially so considering the relatively high cost of steel and services in 2008.

Our unproven inventory is essentially our net risk 2P and 3P resources. The 2008 additions include almost 500 Bcf of the proved reserves. They were revised off at year-end due to low year in commodity prices, which then became part of our non-proved inventory. However, we drilled up about the same amount of the inventory from last year during the years. So these two things essentially offset each other, which means that we experienced real inventory growth of about 700 Bcf equivalent.

We’ve increased our unconventional opportunities in that growth significantly, including the Raton Basin CBM and the Haynesville Shale. And we’ve not yet included anything in this summary for the Niabera [ph] Shale and the Raton Basin. As a reminder, we’ve got about 300,000 net acres in the Raton Basin that are perspective for Niabera. And we own the minerals, but we’re still very early stages in that program so we haven’t included them in the inventory yet.

The conventional low risk resources have also grown substantially, and that includes our Cotton Valley type gas series and the Arklatex where we seldom drill a dry hole and where our Cotton Valley horizontal program has been performing very well. And I’ll show a little more about that in a moment.

And then finally, the exploration of highest risk wedge is down year-over-year. So I hope what you’ll take a look at in our current inventory is that we’ve improved both the amount of future resources and the quality of our future capital programs.

So that closes out 2008. Let’s look forward at 2009. On page 39, we show the elements of our capital program. And as Mark and Doug have both mentioned, we’ve designed it to be a flexible program for 2009. With the rapidly changing service costs, basis movements, and declining commodity prices, we’re literally constantly evaluating the portfolio to make sure we’re not only adding value, but we’re making the most efficient use of our capital.

On the right side, we’re showing you the $1.3 billion dollar case as it exists today versus our 2008 actual spend. And despite a sharp year-over-year reduction in total capital, you can see our current plan is to increase our spending in our central division, which includes the Arklatex. Our Haynesville and our Cotton Valley horizontal programs are both progressing well, and we’ll also likely drill some of our best vertical programs in the Arklatex this year.

We currently have one rig running in the Altamont field in Utah as we continue to reduce the drilling and the completion cost of that program. And the Black Warrior coal-bed methane program still generates good returns, even at relatively low pricing due to its higher net-backs and the efficiencies we’ve created in that basin over time.

As you can see from the two bars, we’ll spend considerably less in the Texas Gulf Coast in 2009. We still have a healthy inventory there, but we’re going to dial that program down to a smaller, lower risk program for the year. The same holds true for the Gulf of Mexico. The Gulf of Mexico team had a good year in 2008, but the inventory there is barely secure, and the risk, the uncertainties, and the longer cycle times are less consistent with our objectives for this year.

International program will be up slightly from last year at about $250 million. Back in November, I mentioned that we’ve slowed the pace of spending at our (inaudible) project so that we can hopefully capture lower future development costs and hopefully higher oil prices. So very little CapEx is going to go to that project this year.

We started our first well in Egypt at the end of January, and we hope to have it tested by – hopefully, by our first quarter conference call. We’ll probably wind up drilling three or four wells there this year. And we’ll spend somewhere in the $70 million to $80 million range. So the plan – I’m showing you the plan as it stands today. And as we said, we’ll continue to update our cost estimates and optimize our capital program accordingly as we go through the year.

Now, slide 40 shows our operated rig count at the end of each quarter. As you can see, we cut our capital in the fourth quarter pretty dramatically in response to the lower prices and the state of the capital markets. We’ve gone from a peak of about 27 to 28 rigs to today about 13 currently running. We’ll be down to eight rigs at the end of March and we’ll be down to five to six by the end of the second quarter. The cost of services are coming down rapidly, but not rapidly enough in some areas. So we plan to defer our capital spending until later in the year until we’re – we clearly get better pricing. And naturally, we’ll keep you updated as we adjust our program as we go.

Since the biggest piece of our domestic spending is in the Arklatex, I’d like to give you a brief update on our Haynesville and Cotton Valley horizontal drilling programs. All of our Cotton Valley activities have been in Louisiana on the eastern half of the play. We’ve been coming up the learning curve quickly in terms of well design and cost. And on slide 41, we’ve included a couple of learning curve examples, the time the drilling complete our first four wells and the total cost per foot – per foot of lateral drilled. And we’re quite pleased with the reductions in time and cost, and we’re also quite pleased with the progressive improvement in the producing rate for oil as shown on the left side of that chart.

We started out below 10 million a day per well. And our most recent well, the Blake 10H produced over 20 million a day, after 10 stages of fracs in the lateral. We’ll probably keep two to four rigs running in the Arklatex that are capable of drilling these kind of wells, and we can drill somewhere in the neighborhood of 15 to as many as 25 Haynesville wells this year.

Slide 42 provides a summary of our Cotton Valley horizontal program in the Arklatex area. That program’s gotten a lot less attention lately, but the returns on those wells are attractive because the cost is about 45% less than Haynesville wells cost to drilling complete. We’ve got six of those wells producing, and three of them with high keys in the 9 to 9 million a day range. And we expect to drill somewhere around six to ten of those wells in the program this year.

Leaving domestic US and turning quickly to Egypt, on slide 43, we’ve been working for a while on an acreage swap with RWE, and we recently received ministerial approval for that trade. Their Tanta block is immediately east of our South Mariut block. And it’s comparable in size and prospectivity [ph] to South Mariut. Both parties went on this deal because of the – the trade’s going to spread capital and risk over a large area and from the technology sharing that we’ll have between our two Egyptian teams.

Our first well in South Mariut is drilling, as Doug said. And as a result of the agreement with RWE, we’ll now have a 60% interest in the well. We continue to refine our 3D seismic interpretations in the South Mariut block, and we currently have one additional drill site prepared and four additional stake and ready for construction. RWE plans to shoot 3D seismic on the Tanta block later this year. And so in aggregate, our Egyptian program’s off to a great start, and I’m pleased that we’ve been able to expand our footprint in the western desert. Going forward, we plan to even grow that position further as we continue to evolve this Egyptian business.

And then turning to Brazil on slide 44, there’s a quick update there for the Camarupim project. Petrobras is the operator, and we have a 24% interest in the project. As I’ve mentioned, they advised us now – they now expect to have first gas production on the second quarter. The first available wells have been drilled and tested, and it’s ready to be tied back to the FS – FPSO facility. The second and third wells have been drilled and are currently being completed, and the fourth well will start in March. In addition, the FPSO is now right in Brazil on February 17th. It’s clearing customs and inspections, and then we hope that vessel’s going to be on location right near the end of February.

So once all the – all four wells are on line, we expect to produce somewhere in the 50 to 60 million barrel-a-day range net El Paso. Also, on the ES-5 block, about 15 kilometers to the northeast, we and Petrobras have drilled the Tot exploration well, which have found – which found apparent gas pay in two intervals. And we’re currently in the process of testing the lower of those two zones.

So in summary, on page 45, following our solid 2008 E&P performance, we’re highly focused in 2009 on ensuring that our capital programs creates value in the current – the current environment that we’re faced with. Today, that means slowing our capital programs and getting the benefit of further reduction service cost, and it means that we’ll continue to review our inventory to make sure that we’re drilling our most economic programs.

Consequently, as Mark said, we’ve laid out a fairly wide range of capital spend and result from production volumes. This is by far the most fluid environment that we’ve seen in our industry. So we’re going to remain disciplined and – and again, make best use of our capital and do the best we can to hang on to our improving inventory projects. And because our program is going to be influx, we’ll keep you posted on our activity levels and on the progress of our programs as we go through the year.

So then, I’ll turn back to Doug for closing comments.

Doug Foshee

Thanks, Brent. This is as challenging a time in our industry as I’ve experienced in my 27 years in it. We’ve tried to outline for you today what we’re doing to manage through the near term tactical issues that face us as well as what we’re doing to preserve our ability to deliver value to our shareholders longer term. We look forward to your questions around these issues this morning. But let me just close our formal comments by saying that if we could leave you with one impression today, it’s that as a leadership team, as a Board, and as a group of 5,000 members of team El Paso, we’re battle tested for just this kind of environment, we’re focused, we’re engaged, and we’re on top of our business. And with that, we’ll open it up to your questions.

Question-and-Answer Session

Operator

(Operator instructions) We’ll pause for just a moment to compile the Q&A roster. Your first question comes from Shneur Gershuni with UBS, your line is open.

Shneur Gershuni – UBS

Thank you, good morning. I guess my first question is, with respect to liquidity on – thank you very much for putting up the slides with respect to how your liquidity’s going to look throughout the year and so forth. In the scenario where gas prices, oil prices continue at these levels and, let’s say, they continue into 2010, how comfortable are you with $1.2 billion of year-end liquidity to fund 2010? And is there any more flexibility within the E&P program and also the pipeline CapEx program to be able to move out of 2010?

Mark Leland

Shunir, this is Mark. We feel pretty comfortable with our liquidity at year-end, though, certainly given a low price environment, we’re always going to want to add to liquidity. And we’ll be working on building liquidity throughout the rest of this year to prepare for 2010. We’ve got some flexibility on the E&P side as you’ve seen, the – the range in CapEx this year, we have probably similar range that we’re looking at next year and beyond. But generally, we feel pretty good about where we are today. Our hedges give us a lot of time and cushion to deal with liquidity and what happens in 2010.

Doug Foshee

Yes. This is Doug. I think from our perspective, the good news is, we’re sitting here in February already focusing on 2010. And that’s because we stacked up $3.3 billion worth of liquidity to put us in a position to be – to really be responsive to things early. So we are planning for what we would do in the event that we had a very protracted low price, low commodity price scenario.

And I think you’ll see us respond to that, just like we responded last year to what happened in the fourth quarter. And I have a lot of faith in Mark and his finance team to do that. A couple of things I’d point out, one in particular is we do retain a great deal of flexibility with regard to our capital spending levels and E&P. We’re going to spend $250 million this year internationally. But to a large degree, as we look at 2010, that’s discretionary spending on our part.

Similarly, we have a lot of discretion in the spending levels in our domestic portfolios. We think we’re in – actually in a really good position to deal with that particular issue, recognizing that we’re preserving our – number one, we’re going to preserve the investment grade rating of the pipes, and secondly, we’re preserving the ability to show the kind of growth we know we get longer term out of the pipeline growth projects that are 10, 20, 30-year contracts with investment grade customers.

Shneur Gershuni – UBS

In addition to that, do you still feel that you still have some room at the operating companies to raise capital also if necessary?

Mark Leland

Yes. Yes, Shunir. We have about $4.5 billion or maybe $4.7 billion of debt on the pipeline. They’re going to generate something like $1.8 billion on EBITDA next year so there’s quite a bit of capacity there. I think it’s probably $2.5 billion or so that we could raise and still retain our ratings at the pipeline levels.

Shneur Gershuni – UBS

That’s great. I just wanted to turn to one of Jim’s comments, you talked about a price reduction from an overseas supplier, and so forth. I just want to confirm, did you negotiate a reduction in your steel costs?

Jim Yardley

Well, let’s see, I think the one you’re talking about is one where – in that particular case, the pipe supplier had not yet committed to his steel. So as the result of – as the result of the fall in the steel market, he was able to go back to his steel supplier and pass that along to us.

Shneur Gershuni – UBS

And are you able to do that with some of the other contracts that you have in place, giving in mind that a lot of steel companies have been pushing the envelope with their input suppliers as well – to as well – they’ve also renegotiated delivery dates as well. Are you able to retain some of those benefits on some of your existing price contracts?

Jim Yardley

Yes. I think the answer to that is not always, but we have good long term relationships that we built up with pipeline suppliers around the world as the result of being the size that we are, so that we are talking to them. We’re talking to – to them today, and there ought to be further opportunities.

Doug Foshee

Let me say this, there’s nothing in our forecast of capital spending on the pipeline side that assumes we get any cost reductions in steel beyond those that we’ve already got.

Shneur Gershuni – UBS

Okay. Great. And just one last question for Brent, we’ve seen oil production come off. Is that a trend that we should continue to see on a go-forward basis? And also if you can also compare and contrast your Haynesville results with some of the other operators, do you feel you’re in a sweet spot? Or do you feel you’ve figured out where you need to be there, or is it still a little bit of a size project for you?

Brent Smolik

No. I think we’ve moved past the size project. Let me take them in reverse order. Because of our legacy land position in the Arklatex, we find ourselves partnered with some of the other operators. So we get to see direct costs from their AUPs [ph] that they’ve proposed to us and we get to see actual results. And we’re as – we’re as competitive as anyone, and you could see that cost coming down dramatically, just like it’s coming down for everyone. We think we’ve got the frac technology more in line as you can see from the results of the last well. The acreage itself is located what I think is right in the heart of the Louisiana side of the fairway. At least 30,000 acres of it is right in what I think industry thinks is the prime sweet spot. So that part of it is going to be – we’ll have a large inventory of those to drill for a long time.

Our oil production is going largely be a function of how much drilling we do in Altamont in Utah. Today, we’re down to just one rig running in that program, and we’re sort of taken that as a well by well decision. So you may see our oil tail off a little bit in gas replacement.

Shneur Gershuni – UBS

Great. Thank you very much.

Brent Smolik

Thank you.

Operator

Our next question comes from Carl Kirst with BMO Capital, your line is open.

Carl Kirst – BMO Capital

Hey, good morning, everyone, and certainly a nice way to meet the current challenges. Doug, let me ask on Ruby, you had started your comments talking about being responsive to customers. Have you gotten any sense that would slow down in the Rockies at any of the Producer team that she’s asking you to delay that line?

Dough Foshee

No, none. And in fact, I would say, with the growth out of the Shale place, most of which is headed east. Our view would be that there’s more need now for a western exit to Rockies production than there was when we started the project.

Mark Leland

Just to add to that, just – I think you’re aware right now Carl that the basis from the Rockies is, cheaper prices out there are probably 250 or so, with the Cheyenne hub so if Ruby were in – a lot of people like to see Ruby in service today, so I think, quite the contrary, I think that people want Ruby in service today. So I think – quite the contrary, I think that people want Ruby to be built.

Carl Kirst – BMO Capital Markets

Jim, just a micro question on Ruby. I think at the time of the actual FERC filing, there was still – one of the shippers – that had to be around 200 million a day of contracted capacity that had gotten Board approval. Is that all done? Is the full 1.1 now locked and loaded?

Jim Yardley

The 1.1 is locked and loaded. The one that you’re referring to would be an addition to that. And, no. We had not received Board approval. Or that customer has not received Board approval yet.

Carl Kirst – BMO Capital Markets

Okay. So it would be on top of the 1.1.

Jim Yardley

Yes.

Carl Kirst – BMO Capital Markets

Great. And then just moving quickly on the E&P side, Brent, I know looking at broad, top down unit cash costs can be somewhat of an over simplification. But certainly, I can understand why fourth quarter cash cost was up sequentially and over last year given the hurricane impact; lower production.

But looking out into 2009 of the guidance of cash cost relative to where it was in the fourth quarter seems to be continued upward – upward pressure when obviously, we’re looking around at the service community and wondering how low it’s going to go. Can you help me reconcile that? Is this just a matter of being conservative or is there something else going on here?

Brent Smolik

No. There’s no other messages in there. That’s largely keeping G&A about where it is. And managing LOE on a total dollar basis. But because we’re year-over-year down on total production you’re seeing that unit cost increase. But we’re not signaling anything incremental there and that there’s higher cost in the…

Carl Kirst – BMO Capital Markets

Okay. So even though fourth quarter production was roughly in the 750 million range and that’s the midpoint of the ’09 guidance, we still might be seeing some upward cost structure? That’s conservatively how you’re positioning it right now?

Brent Smolik

No. The inside – the domestic should be fairly close to flat on an absolute dollar basis. And then we’ve got to layer in the Brazil piece because we picked up the expense of that BM [ph] project. But structurally nothing much changes between 2007 – 2008 and 2009.

Carl Kirst – BMO Capital Markets

Great. Thanks, guys.

Operator

Your next question comes from Faisel Khan of Citigroup. Your line is open.

Faisel Khan – Citigroup

Good morning.

Doug Foshee

Good morning, Faisel.

Faisel Khan – Citigroup

How are you doing?

Doug Foshee

Good.

Faisel Khan – Citigroup

On the construction cost for the pipeline I just want to understand the mechanics of how the steel pricing works. Is it – do you contract for a certain amount of volume of pipe from your suppliers and you physically hedged the steel? Or is it – is it all done at the same time with the steel company?

Jim Yardley

Our contracts Faisel, are with the pipe – the pipe mills. And so what we did on the big projects we negotiated fixed price arrangements on the pipe with them. They in turn were dealing with the steel mills. What I referred to was – so those are – those are in place and they’re done. And we feel comfortable with that. Especially since we have for the most part, negotiated rates with our customers that match up well with that cost of the pipe.

What has happened is the result of the fall off in steel. And now market prices of pipe is that some of those – some of those pipe mills had ordered their steel and some haven’t. In the case of – where they hadn’t yet gone to their steel suppliers at the time they locked in to us there was an opportunity to do something there. And we and the pipe mills capitalized.

Brent Smolik

But just to – I want to make sure we’re clear too. We don’t hedge steel. You used the word hedge. I just want to make sure that you know we don’t do that.

Faisel Khan – Citigroup

Okay. Understood. And then in terms of the current construction cost of the backlog you guys have, that looks like to be the same construction cost that you gave us last year when you were developing your plans for this backlog. If the current cost structure continues to decline and construction would there be some room to improve the project cost of those pipelines in the backlog?

Jim Yardley

Yes. I think the answer to that is possibly yes. I think another way to say it is we feel a lot more confident in our current prices today and there ought to be opportunities to maybe improve that down the road.

Faisel Khan – Citigroup

Okay. Understood. And just on the E&P side of the equation. Looking at your capital spending plans of, I believe, $1.3 billion for ’09 and your current rig count which you guys gave us of roughly six rigs in February, assuming that you continue that rig count there seems to be a little of a disconnect between that rig count and your capital spending plans being – it looks like it should be much lower if you were continuing at that rate. So can you help me bridge the gap there?

Brent Smolik

Today we’re closer to 13 rigs. And we’re essentially into February now. And we’ll be down to that five to six rig level by the end of Q2.

Faisel Khan – Citigroup

Okay.

Brent Smolik

So we went through that quickly. And then the reason there’s a range of $.9 billion to $1.3 billion for the full year is that how much do we ramp back up for the full year. So in a low case as we grow back up it would total .9. And then as we – if we get to the higher case which would probably mean more Haynesville or Arklatex activity, on the margin we would get closer to 1.3. And all of those rig counts were domestic. We just have the one rig running in Egypt.

Faisel Khan – Citigroup

Okay. And that would also translate to your production guidance too?

Brent Smolik

Yes.

Faisel Khan – Citigroup

7.25 to 8/15th. So $900 million would give you the $7.25 and–

Brent Smolik

Yes.

Faisel Khan – Citigroup

Okay. Got you.

Brent Smolik. Right.

Faisel Khan – Citigroup

Understood. Thanks, guys.

Doug Foshee

Yes.

Operator

Your next question comes from Becca Followill with Tudor, Pickering. Your line is open.

Becca Followill – Tudor, Pickering

Good morning.

Doug Foshee

Good morning, Becca.

Becca Followill – Tudor, Pickering

Following up on that same question on the trajectory of the production profile across the year, fourth quarter we’re 752 million a day. The midpoint or guidance is 770. So do we see a decline in the first part of the year and then ramp up in the second half? As Brazil comes online, without giving its exact numbers, can you give us some structure on how it shakes out across the year?

Doug Foshee

Becca, I’ll let Brent talk about how the capital programs are shaped and how that might affect volumes. But just to level set you we’re at about 800 million a day now. Today.

Becca Followill – Tudor, Pickering

Okay.

Doug Foshee

And we have 35 to 50 million a day coming on in Brazil in the second quarter. And then Brent, if you want to go through the regions.

Brent Smolik

Yes. So those are the two biggest pieces of uncertainty we have in there, Becca. Then you think about the total capital, so $.9 billion to $1.3 billion. And then we think about the shape of that capital spend. So we’re going to have a fairly low second quarter capital spend. And then how aggressive will we ramp back out of it will affect our total full year average and our exit rate.

And then in that calculus it was wider ranges and more uncertainty than we’ve had in our guidance ranges. But it also has in there uncertainty around the service cost reductions. And therefore the numbers of activities that we’re able to get done. We tried to stew all of that in looking at the low capital-high capital case, Brazil timing, Haynesville results, and service cost structures to get to that range of outcomes that we’re guiding to. That’s the big moving parts for us though.

Becca Followill – Tudor, Pickering

Great. So the difference between the fourth quarter and today is hurricane related?

Doug Foshee

Most of that’s recovering in the Gulf of Mexico. We had a – we had the knock on us – the finishing up of our 2008 capital program. So south Texas is actually up a little bit over the fourth quarter. Arklatex and Haynesville is up a little bit over the fourth quarter. And then we recovered for the hurricane in the Gulf of Mexico.

Becca Followill – Tudor, Pickering

Great.

Doug Foshee

It is today’s 800 issue.

Becca Followill – Tudor, Pickering

Okay. And then a second question is on service costs. What have you assumed in your E&P budget? What kind of delta?

Doug Foshee

What we’re currently looking at, the full year average versus last year’s full year actual is something like 10% to 12% in the current capital plans at the – that’s in the plan that you – that results in our number you saw.

Brent Smolik

Right. That’s what we’ve got built into that set of assumptions. And in there there’s a lot of variance by services actual – obviously. And there’s also, taking into account those places where we have contracts. But the rigs for example, we’re down to only one rig by end of this year that we’ll have on contract. And we’ll only have long term contract and will only have three on by the end of the second quarter. But we factored all that in by service, by commodity to get to that average of 10 to 12.

Becca Followill – Tudor, Pickering

Great. Thank you, guys.

Doug Foshee

Yes.

Operator

Our next question comes from Jim Harmon with Barclays Capital. Your line is open.

Rick – Barclays Capital

Hey, there. This is Rick [ph] and Jim.

Doug Foshee

Hi, guys.

Rick – Barclays Capital

Hi. I want to go back at the flexibility in the budget from the $1,300 million to the $900 million and how production holds up because just superficially you averaged about 25 rigs per quarter. And you’ve got the first half here averaging seven. And I’m trying to figure out – there’s $400 million – the gap – the drop in spending is much bigger than the range that you have in the production. I understand that you’ve got Brazil coming on, but I’m trying to figure out where you would be dialing down that what appears to be incredibly less productive than what you’re keeping?

Brent Smolik

So the biggest chunks of that Rick, are going to be last year in fairly active Raton Basin Program. You remember how those CBM wells produced (inaudible) that dewatering phase? And then we also had a fairly large Black Warrior Basin Program that we still have some this year but smaller than last year. And some of those are – you’ve hit it, are fairly inefficient the first year of capital spend. So those will be in holding patterns in dewatering. Especially the Raton Basin this year.

The other places that’s affecting your math there is, I’d like to say the TGC program at the end of last year. We’re still completing those wells. But we’ll get that rolled off effect through the course of this year. And so some of it’s carry on effect from last year. Some of it is we’re moving away from those things that were good long term economics but relatively inefficient for the first year of production. Like the Raton.

Rick – Barclays Capital

Okay. Good. You’ve provided a Haynesville snapshot, the Cotton Valley horizontal snapshot with volumes. Are those currently producing volumes gross or net?

Doug Foshee

Everything we’ve put on that slide is gross as if it comes out of the well.

Rick- Barclays Capital

Okay. Great.

Doug Foshee

There’s a lot of confusion out there about – when we’re talking about net volumes or HH [ph] volumes or IP. So we try to put what’s coming out of the well.

Rick – Barclays Capital

Okay. Order of magnitude; what’s your average net revenue interest in all this?

Doug Foshee

Relatively high. In the Haynesville it’s going to be 70% to 80% and mostly on the high end of that. There will be some wells that give unitized – where we’ll get unitized end. But the bulk of our acreage is near 100% working interest and close to 80% is net.

Rick – Barclays Capital

Okay. Great. Pipeline side real quick. If we get a partner for – when we get a partner, let’s put a positive spin on it. When we get a partner for Ruby, how is that partnership going to work? Are they going to say, “Okay. You spent so much to date and therefore this partner will spend until they catch up with you.” Will they get a cash infusion? Can you give us a little idea of how you would expect to have this partner come in and true up their exposure relative to yours?

Mark Leland

Rick, this is Mark. It’s a little early to say. We’re right in the middle of working through all of that with several different parties. But needless to say, we expect that partnership to be on a 50-50 basis. And so by the time the construction starts, we’ll be all trued up.

Rick – Barclays Capital

Okay. So it sounds like in that context you would be receiving money for your pipe expenditures and all the types of things you’ve done as precursors to starting to put in the ground.

Doug Foshee

We’re not going to get too far into what we’re going to try to negotiate on the deal.

Rick – Barclays Capital

Okay.

Doug Foshee

I appreciate the question. But–

Rick – Barclays Capital

But fine, it’s okay. The other issue is you’ve gone from trying to do Ruby and you mentioned one or more. Is this philosophically something you want to do with several of the other projects? Or is this just as a function of if the financial backdrop, et cetera continues to remain difficult? We would possibly do that. How do I put that into context?

Doug Foshee

I think the way to think about that is we are, right now in the business of creating maximum flexibility.

Rick – Barclays Capital

Okay.

Doug Foshee

So we’re going to look at every option that we think is a viable option. That doesn’t mean we’re going to action everything that we consider. But we think it’s appropriate to let people know that that – that’s the mode we’re in.

Rick – Barclays Capital

Okay. Great. Thank you very much.

Operator

Your last question comes from Jonathan Lafave [ph] with Wachovia. Your line is open.

Sam Brothwell – Wachovia

Hi. It’s Sam Brothwell. I think you hit most of them. But just a clarification. Did I hear you correctly Brent, saying that the Cotton Valley horizontals were costing roughly about 40% of a Haynesville – a typical Haynesville well?

Brent Smolik

That’s about where we’ve been running on average. No. 40% less

Sam Brothwell – Wachovia

40% less. Okay. I got you.

Brent Smolik

40% less. And that’s mostly a function of just measured – total measured depth and lower cost completions because we have less fracs and not so high pressure as the Haynesville. But the economics are working out quite nicely on the Cotton Valley Program.

Sam Brothwell – Wachovia

It looks that way. Thank you very much.

Doug Foshee

All right. That concludes the call. We very much appreciate your interest. And if you have any further questions, don’t hesitate to call. Thank you.

Operator

This concludes your conference call for today. You may now disconnect.

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