El Paso Corp. Q1 2009 Earnings Call Transcript

May. 8.09 | About: Kinder Morgan, (KMI)

El Paso Corp. (EP) Q1 2009 Earnings Call May 8, 2009 10:00 AM ET

Executives

Bruce Connery – Vice President, Investor and Public Relations

Doug Foshee – President and Chief Executive Officer

Mark Leland – Chief Financial Officer

Jim Yardley – President, Pipeline Group

Brent Smolik – President, El Paso E&P Company

Analysts

Shneur Gershuni – UBS

Carl Kirst – BMO Capital

Faisel Khan – Citigroup

Joseph Allman – JP Morgan

Becca Followill – Tudor Pickering

Holly Stewart – Howard Weil Inc.

Mark Caruso - Millennium Partners

Operator

Welcome to the El Paso Corporation's first quarter 2009 earnings conference call. (Operator Instruction) Mr. Bruce Connery, you may begin your call.

Bruce Connery

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 our CFO, Jim Yardley, President of our Pipeline Group and Brent Smolik, President of El Paso Exploration and Production.

Throughout this call we will be referring to slides that are available on our website elpaso.com. This morning 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 made 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 the cautionary statement regarding forward-looking statements 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 call or any other forward-looking statements made by the company whether as a result of new information, future events, or otherwise. Please note that during the call we will be using non-GAAP numbers such EBIT and EBITDA, and we have included a reconciliation of all non-GAAP numbers in the appendix to our presentation.

Now, I'll turn the call over to Doug.

Doug Foshee

I want to start this morning by saying we had a great quarter. Both business units performed ahead of expectations for the quarter, pipeline EBITDA was up 4% over Q1 '08 and adjusting for a one-time gain in last year's first quarter, EBITDA for the pipes was up 8%. Our growth projects continue to come in on time and on budget and we continue to believe we'll be able to say the same thing going forward for the balance of our pipeline backlog.

On the E&P side, EBITDA was up 14% versus Q1 '08 and volumes for the quarter were up a healthy 7% over Q4 '08. The company earned $0.47 a share for the quarter taking out the affects of the price related ceiling test charge, but our view is that the more comparable number is $0.35 a share taking out both the negative affect of the ceiling test charge and the positive affect of the early cash out of our oil hedges for the period from April through December of 2009. That's compared to $0.33 a share in last year's first quarter in a much more robust commodity environment.

For the company as a whole, we were free cash positive for the quarter even before considering the impact of some non-strategic asset sales. Cash flow from operations was up 20% year-over-year. Liquidity remains strong at $3.3 billion at quarter end, meaning that we have no need to access capital markets in 2009 for 2009 under any commodity price scenario. And we expect to exit the year with at least $1.3 billion in liquidity to give us a strong running start on 2010 and beyond.

We made significant progress during the quarter on financing the backlog, as Mark will describe in more detail, highlighted by the recent successful $600 million bond offering for the financing of FGT Phase VIII. And finally, we're in the late innings of our process to select a Ruby partner and expect to have news to report on this key 2009 objective soon.

Before I turn it over to Mark, I'd like to talk more specifically about the two key drivers we see in our business for 2009 and beyond, namely natural gas prices and capital markets availability. Almost every variable that affects future gas prices is currently outside of what would be considered a normal range. The U.S. market is currently oversupplied by 4 plus Bcf a day by our estimation. Activity levels have dropped at an unprecedented rate over a very short period of time, but supply hasn't yet responded.

As much as 9 Bcf a day in new LNG liquefaction capacities coming online between now and the end of 2010 as much as 10,000 megawatts of new efficient coal-fired power is coming online between now and 2011. Industrial demand, which was down 20% or more in the early part of the year, has now recovered somewhat largely due to fertilizer production. And, of course, overlaying all of this is the state of the U.S. economy, and as importantly, the global economy and the pace of their respective recoveries.

We believe that because of our footprint in the U.S., both in pipes and E&P, we have as good a view on real-time gas supply and demand as anyone and better than many. And our conclusion from the data we see is that longer term, meaning beyond 2011, the evidence suggests that the case for natural gas is still really strong, especially in a carbon constrained world when the concept of pricing carbon emissions comes into play.

In this environment, we believe natural gas will be naturally advantaged and, therefore, will increase its market share in the demand for energy in the U.S. But shorter term, our crystal ball is very fuzzy, so while we are predicting low gas prices for a sustained period of time, we do believe that the probability of low gas prices for a sustained period of time has risen over the last six months. So, how have we chosen to respond?

This quarter we've added to our price protection materially for 2010 and 2011. In 2010 that protection's in the form of 175 Bcf of floors at $6.41, and roughly 113 Bcf of ceilings at $7.42. That represents a very substantial proportion of what we would expect to produce in 2010 in a constrained capital spending environment. Similarly, we've added 116 Bcf of 6x9 collars for 2011, again, designed to protect a substantial proportion of our production in that year in a capital constrained environment.

Now, let me turn to capital markets. We know that we need access to capital markets to fund our two businesses. Treasury rates have come down but high yield spreads have widened materially, and we all saw the impact of the events of the fall of last year when those markets were effectively closed. More recently, capital markets relevant to us have improved. Several high yield issuers have issued bonds in addition to El Paso.

The MLP market has shown signs of life. Some equity's been issued since the beginning of the year. All of these so-called green shoots are positive but still seem to us to be fragile and episodic. So in that environment how do we respond? Well, first we have a robust plan that is multiyear and is tested through many cases, including sustained low commodity prices.

Second, we started early last fall and satisfied all of our needs for 2009 effectively by January. Third, we've moved quickly and opportunistically and will continue to do so to satisfy our capital needs for 2010 and beyond. And last, we have or will use every tool in our toolkit, as is evidenced by the myriad of financings in non-strategic asset sales completed so far.

How we deal with these two key drivers, natural gas prices and capital markets availability, is key to making our strategy work. And that strategy is really pretty simple. We have something that very few of our competitors have in this environment, a clear path to long-term growth. And that's by virtue of the highest quality backlog in the pipeline business. We just have to execute on it successfully.

So, to start we don't think that hoping for natural gas prices to be higher is much of a strategy. That means we won't spend incremental drilling dollars today before the cost structure has reset on the hope of receiving $7 in the cash market because lower 48 supply will contract in the second half of this year. There are just too many offsetting variables for us to be willing to take that risk.

We intend to keep our liquidity strong our own diminutive version of Jamie Diamond's fortress balance sheet concept, if you will. By doing that we'll give our investors confidence in our continued ability to fund our businesses. We recently celebrated our 80th anniversary so we've seen lots of cycles. Our plan not only addresses our short-term responses to reduced commodity prices and constrained capital markets, it also preserves our longer term growth opportunities. We intend to stay laser focused on bringing our pipeline backlog in on time and on budget.

We'll flex our EMT CapEx down until some combination of a step function improvement in cost and an improvement in cash prices materializes, while at the same time preserving our inventory and execution skills for the future and will continue to work our own cost structure down.

The result of all this, we think, is a compelling investment opportunity. Low risk growth at our pipeline business supported by a backlog of projects with a combined 93% of capacity sold under 10 plus year contracts. Limited down side as a result of strong liquidity and substantial commodity price protection for three years and great optionality on the recovery in gas prices whether that's in 2009 as some predict or in later years.

And with that, I'll turn it over to Mark and come back and wrap up at the end.

Mark Leland

I'm starting on slide ten. As Doug noted, we really had a good quarter, not just in earnings but progress on items that are important to us over the next several years like maintaining strong liquidity, completing additional financings and putting new hedges on to support much of our cash flow through 2011.

Starting with earnings, we reported adjusted earnings per share of $0.47 compared to adjusted earnings per share of $0.33 for the first quarter last year. I'll cover the adjustments on the next slide. Reported earnings per share for the quarter was a loss of $1.41, which includes a $1.3 billion after-tax non-cash ceiling test charge. The key drivers affecting first quarter earnings were higher pipeline EBIT than the same period last year and strong hedge position coupled with good operating metrics at the E&P segment. Jim and Brent will provide more color on business unit performance.

The items impacting earnings this quarter are highlighted on slide 11. The first adjusting item this quarter is the non-cash ceiling test charge, which impacted earnings $1.92 per share negatively. This charge was driven by sharply lower natural gas prices which fell to $3.63 per Mmbtu from $5.71 per Mmbtu in the fourth quarter of last year.

The second and third adjusting items totaled $55 million pre-tax or $0.05 per share, our mark-to-market gains associated with the change in fair value of legacy power, trading and natural gas contracts in the marketing segment. The fourth item is a $45 million pre-tax or $0.04 per share adjustment related to financial derivatives in the E&P segment, due to lower prices, lower oil and gas prices in the quarter. This adjustment consists of $394 million mark-to-market gain on financial derivatives less $439 million of cash settlements in the quarter.

Included in the cash settlements is $186 million realized with the early settlement of our 2009 $110 per barrel oil swaps, of which $149 million or $0.12 per share is related to contracts hedging April through December production. If you treat the $0.12 as an out of period, then we had a $0.35 per share quarter. However if you do that, you need to add the $0.12 back to the remainder of the year when calculating adjusted EPS at about $0.04 per quarter.

Slide 12 highlights our business unit contributions. Both of our core businesses had great quarters. On a combined basis, pipeline and E&P businesses generated just over $1 billion in EBITDA, and adjusted proportionately EBITDA of about $1.1 billion, both before ceiling test charges. Adjusted EBITDA is calculated with our 50% interest in citrus and 49% interest in four star on a proportional basis. Marketing recorded EBITDA $52 million, which I'll provide more detail on this in a minute.

[Power] EBITDA was $4 million and corporate EBITDA was a loss of $5 million. There's a chart in the appendix that provides relevant details on adjusted EBITDA calculations. The marketing results are summarized on slide 13. This is the third consecutive quarter of improved results for this business. For the quarter we realized an EBIT gain of $52 million compared to a $60 million loss in the same period last year.

The primary driver impacting marketing earnings is a non-cash mark-to-market earnings in the power of natural gas books, which are driven by the application of EITF 085 on our derivative liabilities, which effectively requires us to consider the risk of non-performance in valuing the liability without regard to letters of credit that may be posted against those liabilities.

Now, I'm turning to cash flow on slide 14. Our cash flow from operations was very strong this quarter at $809 million, which is up from $634 million during the same period last year. CapEx in the quarter was $759 million. Dividends and distributions were $44 million, and thus makes us slightly pre-cash flow positive, even before considering the $210 million of non-core asset sales. So in short, we're free cash flow positive for the quarter and cash flow from operations was up 28% year-over-year.

Slide 15 shows liquidity at the end of the quarter and at the end of April which was $3.3 billion and $3.2 billion respectively. Note that at the end of February we had liquidity of $3.3 billion, so for the last three months liquidity has been very stable, which is consistent with our free cash flow position over the quarter. We have more than ample liquidity to meet our main maturities and fund the balance of our 2009 capital program.

Slide 16 rolls liquidity forward from the end of first quarter to the end of the year based on our current expectations of operating cash flow, maturities, dividends and CapEx. As you can see, we expect to end the year with between $1.3 and $1.6 billion liquidity, which gives us plenty of flexibility as we move into 2010. And we will continue to be opportunistic in 2009 to build financial flexibility and strength to finance our growth project backlog and our E&P opportunities over the next several years.

I want to give an update on financing activities since our last call in February, which is summarized on slide 17. In the last several weeks we've added to our new letter of credit facility bringing the total to $150 million, which will take up to $350 million over the next couple of quarters to replace expiring LC facilities. We're also making progress on financing the Ruby project. We're in active negotiations with several potential partners, and while at the same time we've seen a pick up in interest from additional potential investors, as the project continues to mature.

On the financing plan, we interviewed several banks to act as our financial advisor on the project and will select a lead bank by the end of May. As you may have seen, Florida Gas Transmission completed a very successful bond offering last week, which was upsized at $600 million at a rate of 7.9%. So now about half of the Phase VIII expansion has been financed. So the bottom line is that the market for raising capital is getting better, especially for pipeline projects, and we are staying out in front of our capital needs.

The remainder of our hedge position for 2009 is summarized on slide 17. Our 2009 natural gas hedges are consistent with what we've shown you before. We have an average floor just over $9 on 122 TBtu and an average ceiling of a little over $14 or 96 TBtu. We have 1.4 million barrels of our oil production swapped at $45. Approximately 70% of our domestic natural gas production is hedged so we're in great shape for the rest of the year.

We've added substantially to our 2010 hedge program and established a strong floor 2011. These positions are highlighted on slide 19. On the gas side, we now have floors on 175 TBtu of our 2010 production at an average floor price of $6.41. The position is made up of 52 TBtu of swaps at an average price of $6.19 and 123 TBtu of puts averaging floor price of $6.50 per Mmbtu.

In all upside is capped on 113 TBtu at $7.24. We recently established a 2011 hedge program that creates a very attractive floor price to protect our ability to generate solid cash flows while leaving plenty of outside potential should natural gas prices rebound in 2011. We now have floors on 125 TBtu of our 2011 production of an average floor price of about $6 with a ceiling price of about $8.62. To date we don't have any significant oil hedges for 2010 or 2011.

So to wrap it up, we had a very nice quarter from an operating results standpoint. Our liquidity is strong. We continue to make progress in financing our backlog and established a very attractive hedge program for 2010 and 2011. Our businesses are operating well in a tough environment. We feel comfortable achieving our 2009 financial targets we established on our last call.

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

Jim Yardley

The pipelines are off to a solid start in 2009. Financially we continue to deliver consistent results. Throughput increased despite the economic recession, and we're making steady progress to deliver our $8 billion committed backlog. Six more projects will enter service this year or early next and we expect them to go in service at or below our budgeted comps.

On slide 22, a summary of our financial results for the quarter. EBIT was $396 million up $15 million from first quarter 2008, a 4% increase. The EBIT increase was driven by higher revenue from expansions, capacity sales and higher [Park & Loan] revenue. Importantly operating costs were essentially flat year-to-year. And first quarter 2008 included some non-recurring items particularly the settlement of the Calpine bankruptcy, so that after adjusting for the non-recurring items EBIT increased 8% year-to-year.

Capital expenditures of $286 million are comprised primarily of about $200 million spent on the backlog growth projects and the remainder on maintenance capital and hurricane repairs. The increase from first quarter 2008 is due primarily to higher backlog spending, mostly for Elba Express and Ruby, and hurricane repairs. So in summary, a solid start financially.

Slide 23 summarizes our throughput for the quarter relative to last year. In short, higher throughput on our Rockies pipelines offset declines elsewhere, overall a 2% increase. The Rockies increase resulted from year-to-year production increases but also expansions, both out of production basins as well as our High Plains expansion into Denver which went into service last fall. Throughput on our other three pipes was mixed with the most notable trends being some gas for coal substitution on power gen loads offset by declines in industrial demand and the impact of the economy, especially in our markets in Arizona.

Some of these trends will likely persist, though we see some tangible signs of the declines in industrial demand lessening to somewhat, as Doug mentioned, to recovery and demand at fertilizer plants that we serve. And as you know, our revenue stream consists predominately of demand charges so throughput changes have only a minor impact on revenue.

On slide 24, our growth projects for 2009 and early 2010 continue to be on time and on budget. The first one to go in service this year is our Carthage line expansion to serve a new Entergy power plant in northern Louisiana. This project will go in service later this month. Our Totem Storage project for Xcel in Colorado will go in service for working storage injections in July, we're injecting the base gas now. And then on the fourth quarter we'll place in service two compression expansions, one on our Piceance Lateral on the Rockies and the other on TGP in New Hampshire for National Grid.

And these will be followed in early 2010 by our Elba projects, the expansion of the Elba terminal and our Elba Express pipeline. We just kicked off construction on Elba Express. It's our largest construction project this year. It's 190 miles of 42-inch and 36-inch pipe and will connect Elba Island supplies into Transco's main line at the Georgia/South Carolina state line. A 100% of the capacity in all six of these expansions is fully contracted under long-term contracts.

On slide 25, let's talk about Ruby. We've been fielding a number of questions about it. Mark and Doug gave an update on where we are on partnering and financing the project. I'll talk about how we view Ruby as an investment for El Paso. And my message is simple. Ruby is a strategic and valuable long-term investment for El Paso. And let me make four points on this.

First, the foundation for Ruby was, and still is, based on the long-term macro outlook in the west. This macro is grounded in pipeline constraints out of the Rockies, obviously a very prolific and important supply region, and declining Canadian exports to the U.S. on which California and the northwest are particularly dependent. Very simply, Ruby will provide a needed outlet for pipeline constrained Rockies production and connect the supply to the west coast in need of additional supply and supply diversity.

And these long-term fundamentals hold true today. Although Rockies drilling activity has declined and production has flattened, the Rockies have a huge resource base, an estimated 250 Tcf of remaining recoverable reserves, according to the Colorado School of Mines. And Canadian exports are expected to continue to decline by 2 Bcf a day or more through 2014.

Second, there is clear evidence of the market's belief in this macro. We have 1.1 Bcf a day of the 1.3 Bcf to 1.5 Bcf a day of capacity subscribed under long-term contracts. The contracts are with 12 shippers, 11 Rockies producers and PG&E on the market side. We're actively marketing the remaining capacity, and while the decline in Rockies drilling has temporarily slowed, producer's appetite for additional capacity, markets in Nevada and the northwest are in need of capacity particularly for power gen.

Third, we're on schedule for an early 2011 in-service day. We expect FERC to issue its draft EIS in June and last week FERC announced it's schedule to issue a final EIS in October and its order in January 2010. We have strong support at FERC from both the producer shippers and PG&E, as well as the California PUC. We also have support from the governors of Wyoming, Colorado, Nevada and Utah.

And finally we fully expect to complete the project within our $3 billion budget. Over $1 billion of costs are already locked in, our pipe, compression, valves and fittings. Pipe is being rolled today and will be delivered continuously through early next year. We have incentive based installation contracts with four top flight pipeline contractors, and we've been doing extensive construction planning with these contractors for the last 18 months.

We spent considerable time on route selection, environmental analysis and geo-technical analysis. We've had significant consultation with various permitting agencies, and have made adjustments to our route to avoid environmental and archaeologically sensitive areas. And we've reached out to NGOs and landowners. We've received voluntary survey permission from 100% of landowners, which is a significant indication that our outreach effort is working. So all this makes us feel very comfortable with our budgeted capital costs. In short, we expect Ruby to be a solid long-term investment.

Due to the economic recession and drilling downturn, it may or may not be fully subscribed from day one. But even in the event it takes some time to ramp up to full subscription, we still are in a solid regulated return over the long-term. We're moving forward with this very important and strategic investment. It will be an excellent one for El Paso, our partners and customers.

Turn to slide 26, an update on our $8 billion committed backlog. This slide shows the capacity and capital cost for each project, an aggregate to total capacity on all these projects is 93% subscribed under long-term contracts. There's been very little change in the projects capital cost and in-service dates since our last call. The only change being a deferral of the in-service date of our [Attune] 2010 project from the second quarter to fourth quarter 2010 that was requested by our shippers.

The punch line here is that, as we continue to move these projects along, we grow more comfortable that we'll bring them in at or below our budgeted costs. So in summary the pipes are off to a strong start in 2009, financially and operationally, and we're focused on executing on our backlog. You'll see another four of these projects enter service this year.

And with that, I'll turn it over to Brent.

Brent Smolik

E&P started the year strong and we had a quarter operationally. We only included one chart in the E&P section that compares the first quarter of '09 with the first quarter of '08. We're obviously in a totally different environment than we were a year ago, so I'm going to spend most of my time discussing our current thinking about capital, what's going on with costs and how we're advancing our key drilling programs in the current environment.

Turning to slide 29, first quarter production is up 7% from the fourth quarter at 803 million per day. During the quarter most of our Gulf production came back on line and we've benefited from a scaled back but successful Q1 drilling program. That included the benefit of our high initial production rate from our Haynesville wells.

In the quarter, we completed our fifth Shale well and our sixth well came on line in early April. I'll give you a full Haynesville update in a moment, but the short story is that we've rapidly advanced this program and we're drilling and completing these wells as efficiently as any of our industry peers. And while we're always focused on value creation, our current focus is even more intense given the steep drop in natural gas and oil prices. We've seen prices come down a lot faster than cost, so we've continued to reduce our activity levels and our capital spend rate through the quarter.

Our Q1 adjusted EBITDA of $557 million was almost twice our CapEx for the quarter of $321 million. Admittedly, the adjusted EBITDA includes the early settlement of our 2009 oil hedges, but for the quarter our capital program was well within our E&P cash flow. We've actively updating our inventory of future capital projects and our plans as we prioritize our cap allocation options for 2009 and for '10. And as Doug and Mark mentioned, during the quarter we significantly increased our 2010 and 2011 hedge positions.

And finally, we recently completed an E&P reorganization that we expect to drive further efficiencies in our programs. Geographically you'll see us moving from four domestic divisions to three by combining the Gulf of Mexico and Texas Gulf Coast to create the new Gulf Coast division. And we've also created a centralized operations group. It's comprised of drilling, production operations, supply chain management, safety and the environmental teams. These organizational shifts will result in an improved execution going forward and more rapid adjustment to the declining service cost market.

Let's move to slide 30. We've condensed all of our financial and operational metrics into one slide, but there's additional details in the appendix for your review. As Mark described, we had a significant ceiling test charge this quarter. It was driven by the quarter ending natural gas prices being 36% lower than year end and that lower gas price resulted in about 400 Bcf of natural gas reserve revisions.

With out the charge our EBIT was up roughly $140 million from last year. Q1, 2008 included about $102 million a day of production that we subsequently divested, and when you account for those divested volumes, overall production was up approximately 2% year-over-year. So much of the EBIT improvement came from our solid 2009 hedging program.

The first quarter will likely be our peak quarter for capital at $321 million since we've lowered our capital spending significantly and because service costs continue to come down. Overall cash costs were down compared to the first quarter of 2008 by about $8 million.

The unit cost of $2 per M is down $0.09 from the fourth quarter of 2008 and also trending lower as operating expenses trend down, and in the first quarter we also included a one-time severance charge in G&A of approximately $0.04 a unit. As expected, the DD&A rate was substantially lower due to our previous year end ceiling test charge, and then given the impact of the first quarter charge, we now expect our full year DD&A rate to drop to the $1.70 to $1.90 range.

Now turning to slide 31, this chart summarizes our view of the 2009 service cost structure. The middle column summarizes how service costs have shifted on average during Q1 across our domestic portfolio. The third column or right column summarizes how we project them to decline further during the remainder of 2009, and the comparisons versus our 2008 average for our programs and those two columns are meant to be additive by the end of 2009. That's the kinds of reductions we would expect to see by the end of the year.

Slide 32 demonstrates our response to those cost trends. The graph shows our operating rig count at the end of each quarter going back to Q1 of 2008 and our projections for the remainder of the year. As you can see, we swiftly cut capital in the fourth quarter in response to lower commodity prices and the state of the capital markets and then we've continued to reduce our capital spending. We'll have six to eight rigs operating by the end of Q2 primarily in the Arklatex with perhaps one in Utah and the Altamont oil play, and one in South Texas and we also have in those numbers one operated rig working in Egypt.

The path for the remainder of the year remains fluid. We've narrowed our full year range to $900 million to $1.2 billion and correspondingly we've adjusted our production guidance to $730 million to $800 million a day. Now, $300 million is still a fairly wide range for this far into the year for capital, but you should expect this to be near the midpoint of that range unless costs or price trends improve significantly.

As you can see in the bar graph, that could mean going down to five or six rigs for the remainder of the year or ramping back up to as high as about 15. We sold non-core U.S. properties that were producing about $15 million per day in the quarter, which added about $90 million to our liquidity and in spite of those sales our production is very much on track with our original guidance.

So we're very pleased to date with the performance of all of our domestic divisions, and we'll keep you posted about how the project program, the capital program sorts out, but regardless of the size we'll ensure that our capital program is creating value as we go forward through the year.

Let's now go to Haynesville on slide 33. We brought on one more Haynesville well in February, since the February call that's the Gamble11H which IP'd at almost $18 million a day. We held that production back somewhat during the frac cleanup but we view the Gamble 11H well to be similar quality to the Blake well.

We're also completing an additional well now and we currently have two Haynesville wells drilling. On this slide we've also included two graphs that we thought you might find interesting. The top one on the right shows the well performance of the first five wells from time zero. That's where you can see the comparable performance of the Blake and the Gamble 11H wells together.

On the bottom graph you can see our historic total net Haynesville production, and it's not hard to see when a new well comes on line. And we really come up the learning curve quickly, both in terms of our drilling and completing of these wells, and if you go to the next chart on 34, it demonstrates our spud to completion cycle time for the play, and this is for the Louisiana portion of the play where we've been the most focused as a company

We've plotted all the wells that have been drilled and completed and reported to the state, including the five that we've completed. As you can see, our last two wells are among the fastest in the industry. Now, obviously, we paid close attention to the initial production rates, but this cycle time metrics is an important indicator of our relative cost and efficiency in the trend. And while it's still relatively early days, we believe that we've got an inventory now and a program that stacks up well against others in the Haynesville play.

Slide 35 includes an update for our Cotton Valley horizontal program also in the Arklatex. Again we show this because economically it ranks high in our portfolio, and we're well positioned in the trend. As shown on the chart, we've completed three wells since the last call with gross IP rates that average above $6 million a day, and that last well by the way is still cleaning up after the frac treatment.

We've also included the same type of production graphs here that we had for the Haynesville, and you can see the initial rates are not as high as the Haynesville, but the decline rates are not quite as severe and the completed well costs are lower. We're usually in the $6 to $7 million range here.

As the graph on the bottom right shows, the impact on production is also meaningful. That's why we generally kept one to two rigs working in this program. It doesn't have the headline appeal of the Haynesville, but this is one of our core programs and will be for a long time as a result of having over a hundred locations in our inventory.

Let's switch gears and talk about the Altamont oil field for a moment in Utah on slide 36. As we've discussed before, the Altamont Bluebell field is a huge tight oil field where we have a net risk resource estimate of over 70 million barrel equivalents. We were ramping up activity here when oil was almost $150 a barrel, and now we've adjusted to the lower oil prices.

And there's a couple of important updates for the program. First, costs have come down significantly, partly due to deflation of all service costs and partly due to our own efficiency gains, and then second and just as important, is the fact that we're getting much higher initial producing rates out of the wells.

The graph on the right shows our average 2008 well cost and the 30-day IP rates and our last three wells that have been completed in 2009. And you can see that two of the last three wells are near 1,000 barrels a day as we continue to improve our selection criteria and the completion techniques. The bottom line is that this program is now profitable below $50 per barrel, and based on the WTI strip pricing, our Altamont drilling inventory gives us a nice CapEx option.

On slide 37, I'll give you a brief update on our international programs. Petrobras has recently advised us that the Camarupim field will not begin production until late June or until early July. The delays are primarily in the subsea well hook ups and the FPSO commissioning procedures, but all the equipment is basically onsite and being commissioned.

Once online our production expectations are unchanged. It should produce 50 to 60 million cubic feet a day, net to our interest when all four wells are on stream, and the delays will have an impact on our full year production performance by about 20 to25 million a day annual average, but that's going to be largely offset by better than planned domestic production, which is why the midpoint of our 2009 volume range is essentially unchanged.

As you know, we had some successful Brazil exploration wells in the fourth quarter of last year and earlier this year. One was in the same block as the Camarupim, the top well, the second well BM Cal 5 block that's the [Kopieva] prospect, and we continue to evaluate additional appraisal drilling of those two discoveries with Petrobras, as well as the possibility of additional exploration drilling in 2009.

And finally the regulatory process for our [inaudible] oil project continues to move forward and we'll continue to be patient with that project as we update costs, which are coming down, advance the regulatory approval process, and we monitor all prices.

In Egypt, we successfully negotiated and captured a 50% working interest in the [sepsa] operated south Alamein block located onshore in the western desert. And while we are waiting final governmental approval on the farm end, we spud the first exploratory well. It started in February and it's nearing completion.

We did have some disappointing news in Egypt at our operated South Mariut block. Our first well found nice reservoir quality sands on structural highs, but unfortunately it was wet and was declared a dry hole.

Now remember the South Mariut block is a large concession with multiple play types and prospects that we shared with our 40% partner RWE, and we're now preparing to spud our second well to test another one of those prospects in the block. We're optimistic about our Egypt business primarily because we've expanded our footprint and we diversified our interest in some very perspective trends.

Slide 38 demonstrates that our Egypt is located between the western desert and the Nile Delta, and we now have interest in three blocks that total about 1.5 million net acres. As I discussed on the last slide, that South Alamein farm end is currently pending the final approval from the petroleum minister, but we've now diversified our interest across those three blocks. In total, we anticipate spending about $60 million to $80 million dollars on five to seven exploration wells in 2009.

So, I'll conclude on slide 39. We're highly focused, especially in this environment, on managing our capital to create value. Service cost has started to come down, but we need them to come down more before we elect to increase our rig activity later in the year.

We're focused on our core programs and they're performing well, and a lot of this success is due to the efficiency gains that we've created by our own efforts. And I want to thank our team for the improvements to date, and I believe that our new organization structure is going to help us drive those efficiencies every further.

Before I close, I want to remind you that our drilling program is touching just a fraction of our current inventory. We can be flexible with regard to our capital program since much of our lands are either held by production or have a good bit of term remaining, so we're preserving our inventory while we throttle back our drilling program.

I will now turn back to Doug for closing comments.

Doug Foshee

We have a lot of wood to chop in 2009 and we're doing it in a very challenging environment, but we couldn't be more pleased with the start we got in the first quarter. And we're happy to answer your questions this morning.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Ron Barone - UBS Securities.

Shneur Gershuni – UBS

It's actually Shneur Gershuni. Just a couple of quick questions here, I was wondering, you've sort of talked about Ruby at the beginning that you're in the late innings of finding a partner. Just wanted to confirm that whatever portion you get an investor in, whether it's 50% or less, that the percentage ownership would equal the percentage economics. Is that effectively what you are targeting?

Doug Foshee

Yes.

Shneur Gershuni – UBS

So there won't be any surprise in that respect basically.

Doug Foshee

No.

Shneur Gershuni – UBS

Okay. Moving on, just two quick questions, with respect to EPB, you did a dropdown back in September, you took some units on it. EPB has obviously done very well, as well as many of the FERC regulated pipeline MLPs have done well. Is there an option on the table to potentially pursue further dropdowns as a source of potential capital, as well as liquidating some of the position you took on back in September as well?

Mark Leland

Shneur, its Mark Leland. The MLP market has been fairly robust, though it seems fragile like all markets more than we expected in terms of the ability to access the market. So, we definitely like the idea of doing additional transactions at the MLP, but we'll just wait and see and potentially be opportunistic. We do not expect to sell any of our units that we on.

Shneur Gershuni – UBS

Okay. One last question for Brent on the Haynesville commentary, if I heard you correctly, if you can just confirm, is that you believe you have few results right now, that the results are inline, if not better, both a production and on a cycle time basis than some of the other players in the Haynesville. And, I was wondering if you can comment on whether you're participating in some of the data sharing that has been going on with some of the other players in the Haynesville as well?

Brent Smolik

Yes, definitely. We've got [CA's] signed and data sharing arrangement with several other companies, especially on the Louisiana side where the most activity has been and where most of our acreage is. We also had non-op interest in some of those wells, so we actually see AFE.

Operator

Your next question comes from Carl Kirst - BMO Capital.

Carl Kirst – BMO Capital

Just actually a clarifying question, if I could, on Ruby, and Mark I think the statement in the slides was a financial advisor, Bonnie Mae. Is that somehow different than actual joint venture partners or is that just more signaling that this is basically a financial player?

Mark Leland

No.

Brent Smolik

Two things completely different.

Mark Leland

Two things different, what that is, is the lead project financing advisor.

Carl Kirst – BMO Capital

Okay, appreciate the clarification. With respect also on Ruby, Jim, you mentioned Nevada potentially picking up some or I guess needing some load there. Is that where you, if over the next two years we do see incremental contract from Ruby, I mean is that something that you think is going to be picking up the slack, or is that just more sort of a potential what if so to speak?

Jim Yardley

I really think you ought to look at it more globally. We see in the west in northern California, Nevada, the northwest incremental demand for power gen. A lot of that could easily be gas. Separate and distinct from that, there is the driver of supply diversification away from Canadian gas by existing users. So, I wouldn't limit it just to Nevada.

Carl Kirst – BMO Capital

Okay, fair enough. And then just, Brent, on the Haynesville, it sort of seems that the cycle times kind of now appear to be kind of flattening out at least over the last three months or so and the 75 to 80 days. Do you think that, as you guys move up the learning curve, that we could continue to see material pickups in cycle time, or is this is more like 75 sort of ultimately going down to 70, so to speak.

Brent Smolik

Yes, you can see it flattening a little, but don't rule out technology shifts and operational design shifts. For example, the current well we're completing we're working 24 hour a day on the completion, which saves money for us and the suppliers shortened cycle time. So we'll continue to look for new ideas, if they're cost effective for both us and the suppliers to take days off.

Operator

Your next question comes from Faisel Khan - Citigroup.

Faisel Khan – Citigroup

If I am looking at the Haynesville slide on page 33, it seems that if I'm going from Miller Land all the way to GR Gamble, obviously IP rates are also going up. I'm also looking at the sequence of those wells, that when you started drilling and when they came online, it seems like your higher IP rate came later on in the game. Is that a function of where you chose to drill or is that a function of how you chose to drill?

Brent Smolik

I think it is where and how we chose to complete. And so as we moved a little further east in the thicker part of the Haynesville, we're getting higher rates, but we've also lengthened the lateral length and we've added frac stages. And so, as we optimize the cost and benefit of longer lateral length and more frac stages, we'll find the right numbers and get the right rate frac cost combination.

Faisel Khan – Citigroup

Okay. So it's fair to say that if you had known what you know now after drilling GR Gamble, your Miller Land well would have done just as well.

Brent Smolik

Maybe not just as well, but better because we would have drilled it longer and we'd have fraced it with several more stages, maybe three or four more stages.

Faisel Kahn - Citigroup

And then earlier in the conference I think you said, you had drilled a discovery in Brazil on one of the other blocks. Is that still? I missed some commentary.

Brent Smolik

Yes, I was referencing. We had talked about it previously and I just referenced back because it's part of our capital uncertainty if we appraise those wells this year with Petrobras. But, the two of them were, a well called Todd, that's in the [EIS-5 Block], that's the same block that Camarupim development project is located in, and the second one was called [Cobyeba]. That was a discovery that flowed a couple thousand barrels a day on test that we drilled jointly with Petrobras in a block called BM Cal-5 and so those were both discoveries. Our debate for 2009 CapEx is do we appraise it this year.

Faisel Kahn - Citigroup

In the Texas Gulf Coast, the sequential drop in volume is about 20 million cubic feet a day for the fourth quarter to first quarter, what was that a function of?

Brent Smolik

Yes, I think that's, you see in the capital pull back in South Texas, primarily in some of the natural decline, what we'll get from that.

Faisel Kahn - Citigroup

Then in Altamont, what's the oil price that you guys realized on that basis?

Brent Smolik

We've been averaging about $12 to maybe $13 back of WTI.

Faisel Kahn - Citigroup

Okay, and then, on the pipeline side, with your long lead time projects to 2011. What are your customers saying about those projects? Are they very much, they've already committed to those projects, but could they ask you, to slow things down if the economy continues at the current pace or are those projects, they're still very much wanting them to come online at that time?

Mark Leland

Yes, I think the answer to that is that we're always talking to our customers, both on the market side as well as the producer side. But, I wouldn't expect any significant change in service timing of those projects. If there are things around the edges that make sense, we're glad to do it and, likewise, if there's a way to maintain our current profitability. But, I wouldn't expect any big changes.

Faisel Kahn - Citigroup

Last question, I guess, I think you have a large customer that's coming up for resigning on one of your western pipelines towards the end of this year. Any expectations on, there's a demand for that capacity?

Mark Leland

I think, with respect to re-contracting across our pipes, whether it be in the west or east or northeast, I think we feel very good about things. If, in particularly, in the west, I think there are signs that California, in particular, likes the fact that their big LDCs there have a relatively low cost insurance policy as the result of the amount of FT that they have.

Operator

Your next question comes from Joe Allman - JP Morgan.

Joseph Allman – JP Morgan

Brent, could you comment on the recent costs of the recent Haynesville wells and what kind of lateral length are you looking at these days and how many frac stages?

Brent Smolik

Yes, there's some, so I'll go back. Frac stages, we're in the kind of 10 to 12 range leaning towards more. It looks like is better economically. Probably, it's a lateral length limited by spacing most of the time, so 4,000 to 5,000 feet if we can fit it in based on surface and lease constraints. And costs are kind of just above $10 million, $10 million to $11 million, at late last year, first quarter of this year, costs structure and when we quote those, that's a full, completed tied in, going down the flow line kind of costs.

Joseph Allman – JP Morgan

Okay, any comment on the direction of those? I mean I would assume you're thinking that they're going to go down, but could you give us what the target might be, say, by year end 2009?

Brent Smolik

Yes, I think if you look back to that service costs table is why we put that in there, but those are some of the biggest percentage spend items between the rig and stem primarily. And so, if we can get to a point to see 30% to 50% cost reductions, then those are going to translate not fully, but largely to the total well costs.

Joseph Allman – JP Morgan

Okay, that's helpful and, then, EURs, what kind of EURs are you looking at for the wells you've drilled so far?

Brent Smolik

Again, there's a lot of variation that you can see on that chart, but on the better wells that you see on the chart, we're probably eight to ten B's per well is what those are working out. I don't know that we can yet say that for the full average, but we can say it for the better wells.

Joseph Allman – JP Morgan

Okay, that's helpful and, then, in terms of your new E&P budget, does that reflect the costs that you show, the cost decline that you showed in that table?

Brent Smolik

It's attempting too. We're trying and letting on a lot of things there, international activity, Petrobras activity, there are costs structures in the domestic U.S. and how fast it adjusts, and then activity levels. So, we've got a lot moving parts in there. But, we've tried to factor in our best view of where costs are headed.

Joseph Allman – JP Morgan

Okay, lastly, could you just talk about rigs? How many rigs you've got running right now and where are they operating and in your timeline, you showed that you think that you might be increasing the rigs? Could you talk about that a little bit too?

Brent Smolik

Yes, that currently, by the end of Q2 or the next little bit here, we'll be down to mostly Arklatex rigs. We may have one running in South Texas, one running in Utah in the Altamont oil play, and one in Egypt that's operated. We'll have a few non-operated rigs as well.

But I'm giving you the operated activity and the Arklatex will probably be in that three to four range and so, somewhere around six to eight is what we're looking at by the end of the quarter and it could stay that low or even lower by the end of the year if costs don't improve. If it gets better, we show on the one chart in the deck that we could maybe get up to as high as 15 and live within that capital range.

Joseph Allman – JP Morgan

Where would you add the next rigs if prices improve here?

Brent Smolik

Today, the way where we sit here today, would be Haynesville and, perhaps, Cotton Valley Horizontal, maybe in Altamont, a second rig if oil prices continue to strengthen.

Operator

Your next question comes from Becca Followill - Tudor, Pickering & Holt.

Becca Followill – Tudor Pickering

Mark, can you talk about your revolver discussions and where that stands and what your expectations are once that finalizes?

Mark Leland

Yes, we're in the final stages of finalizing the borrowing base re-determination and we have no indication that there'll be changes to our borrowing base. So we think we're nearly done and no changes to the reserve base supporting the revolver.

Becca Followill – Tudor Pickering

Great, and then, this is probably and unfair question, but I've got to try anyway, in light of the CapEx reductions for 2009, and just the band that you have for there, any thoughts on 2010 production?

Brent Smolik

No, and we're just not and it's for a couple of reasons, Becca. We still have a relatively wide of CapEx for this year. But, 2010, as we've said before, because most of our E&P CapEx is discretionary, that could be a very wide band and we're just not prepared to guide today on what that might look like.

Operator

Your next question comes from Holly Stewart - Howard Weil.

Holly Stewart – Howard Weil Inc.

I have two quick ones, one on the guidance and one on Ruby. First, on the guidance, the $0.85 to $1.05, are you still comfortable after taking into account the better than expected 1Q, the lower DD&A and the lower service costs?

Mark Leland

Yes, Holly, this is Mark. I think that we definitely will have lower DD&A. Remember that our guidance was based on $5 gas, so we expect that we'll see lower, even though we're very well hedged, we're still 70% hedged, so we expect to see a little lower earnings there. So, at the end of the day, we have an adjusted guidance, but I think we're trending towards the higher end of the EPS guidance.

Holly Stewart – Howard Weil Inc.

Okay, perfect, and secondly, just kind of following up on Shenur's question on Ruby. Assuming a 50/50 partner, is it safe to say that the sunk costs on Ruby are not necessarily going to be reimbursed at that 50% or 50/50 rate?

Brent Smolik

No, that's not safe to say.

Operator

Your next question comes from Stuart Wyman – Catapult.

Shneur Gershuni – UBS

Hi, yes, this is actually Shneur Gershuni, a quick question on the Haynesville slide. The two wells that came at 15 million and 20 million IP, what is your best projection at the EURs on those wells at this point?

Brent Smolik

Yes, I'd rather not get down to the well level projection. We talked about that a little bit ago. I think those higher rate wells for the trend look like they're pending kind of in the 8 to 10 Bcf range per well and I think, for now, as early as it is in the trend, that's about as good as we can do.

Shneur Gershuni – UBS

And that's over period is that 8 Bcf produced?

Brent Smolik

Oh, those are going to be very long lived, so 30, 40-year lives.

Shneur Gershuni – UBS

Okay. Just another quick question on a different topic, what's the total CapEx spend to date on Ruby?

Mark Leland

It's about $120 million or so.

Brent Smolik

On that question, just to clarify the long lived on the Haynesville Wells but because of those steep initial declines, we'll get about a quarter of the production in the first year.

Shneur Gershuni – UBS

Thank you.

Brent Smolik

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

Operator

Your last question comes from Mark Caruso - Millennium Partners.

Mark Caruso - Millennium Partners

I had just had a follow up that Shneur had touched on it a little bit, but as we look at your 2010 financing needs, and Mark and you guys had said you guys are going to be opportunistic to get ahead of that, but does the 2010 guideline cap ex assume 100% El Paso ownership of Ruby or 50%?

Brent Smolik

Well, we haven't given guidance for 2010.

Mark Caruso - Millennium Partners

But, yes, I think you guys gave us a three-year CapEx number?

Brent Smolik

But we have said that one of our primary goals for 2009 is to have a partner on Ruby.

Mark Caruso - Millennium Partners

Sort of just from a high level, then if Ruby's at $1 billion of CapEx then if you get a partner, that's $500 million less you'd have to get financing for next year and, then if you guys do a drop down let's say $200 million to $300 million, that would be further or less that you'd have to do in 2010 for financing? I just want to make sure I'm thinking about it the right way.

Brent Smolik

Yes, generally, that's correct.

Operator

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

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