El Paso Corporation Q1 2010 Earnings Call Transcript

| About: Kinder Morgan, (KMI)

El Paso Corporation (EP) Q1 2010 Earnings Conference Call May 6, 2010 10:00 AM ET


Bruce Connery – VP, Investor and Public Relations

Doug Foshee – Chairman, President and CEO

J.R. Sult – SVP and CFO

Jim Yardley – EVP and President, Pipeline Group

Brent Smolik – EVP and President, El Paso E&P Company


Carl Kirst – BMO Capital

Craig Scherer – Tuohy Brothers Investment Research

Rick Gross – Barclays Capital

Ted Durban – Goldman Sachs

Becca Followill – Tudor Pickering and Holt

Jonathan Lefebvre – Wells Fargo


Good morning. My name is Tina, and I will be your conference operator today. At this time I would like to welcome everyone to the El Paso Corporation first quarter 2010 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)

At this time I would like to turn the conference over to Mr. Connery, Vice President of Investor and Media Relations. Mr. Connery, you may begin your conference.

Bruce Connery

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

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

Please note that we have a financial and operating reporting package in the supporting materials of the webcast details located in the investor section on our website that includes GAAP financial statements and non-GAAP reconciliations.

If you have not done so, please download this package so that you have all relevant financial information available.

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 statement section of our earnings press release as well as in other filings with the SEC and you should refer to them.

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

And now I will turn the call over to Doug.

Doug Foshee

Thanks, Bruce and good morning. Back in December at our Analyst Day we laid out a multiyear view of El Paso along with metrics and milestones which in many ways the investment thesis for our stock. We have assembled what we believe is an enviable portfolio of growth projects; in the pipes those projects helped build on the nation’s premier interstate natural gas pipeline system providing long term and very visible future earnings growth. At E&P, we have repositioned our asset base to have a much deeper inventory of predominantly onshore opportunities that are competitive at much lower commodity prices. And across the company we have cut cost and improved our processes, thereby improving our returns in a way that we think is sustainable.

The keys to our plan are execution, funding growth capital, particularly in 2010, and continuing to improve balance sheet.

In the execution bucket, we intend to bring our industry leading pipeline backlog in on time and on budget. We also need to demonstrate that last year’s performance in E&P was no fluke and that we can sustain first quartile operating performance and returns. In particular in this area, we need to continue to show progress in the Haynesville and Altamont and begin to move our Eagle Ford position into full development to prove up the value of this early entry position in one of the best North American unconventional plays and we need to continue to prudently build our opportunity set in the pipes and E&P and then our nascent midstream business.

In the funding growth capital bucket, we intend to ensure that we can successfully fund over $4 billion in CapEx in 2010 as spending on the pipeline backlog peaks and maintain strong liquidity during this period of historically high CapEx. In the improving the balance sheet bucket, we plan to get to free cash positives certainly by 2012 as CapEx peaks this year and then declines in the 2011 and the full impact of that growth capital begins to show in earnings and cash flow moving into 2012.

This morning we will show you that we have gotten a lot done on all of these fronts during the first quarter. First, on balance, we had a great quarter. Earnings was $0.51 a share reported or $0.33 a share on an adjusted basis puts us off to a great start on our 2010 goals. On the execution front, we moved a big step closer to starting construction on Ruby with the receipt of our FERC certificate. Jim will update you further on this important project later.

We put two projects in service in the quarter, Elba Island and the Elba Express pipeline. Total capital on the two was $900 million and they were both on time and on budget. We also started construction on two new expansions and expect to start construction a third soon. In all cases, those projects remain on and on budget. And finally in the pipes, we now have a billion dollars in growth projects in the Marcellus with line 300 and the northeast upgrade both on TGP. So we continue to take advantage of our incumbent position in key areas.

Still on the execution front but in E&P, we had a great kickoff in 2010. Production was up $40 million a day from the fourth quarter and cash costs were down 6% versus Q1 ‘09 at $1.88. The Haynesville paced our activity for the quarter with gross volumes hitting a 180 million a day and made continued progress in the Eagle Ford adding our first successful well in the liquids rich portion of the play and adding to our acreage position during the quarter.

Finally on the execution front, we remain on track to achieve our overall cost reduction goal baked into our guidance for the year of $150 million.

On the funding and balance sheet fronts, we completed three key objectives during the quarter. The Mexican asset sale, which we highlighted earlier, closed adding $300 million to the (inaudible) and achieving our goal for 2010 for asset sales. Second and more importantly, we closed the project financing for Ruby yesterday ensuring the funding of this key project at very favorable rates and on very favorable terms, a testament to the strength of the project as well as the strength of our finance and pipeline teams.

And finally we completed our largest dropdown to El Paso Pipeline Partners, our MLP during the quarter with the sale of 51% interest in the Elba Island LNG terminal and the Elba Express pipeline. This transaction generated roughly $660 million in cash to El Paso and was a real win-win for the EPB unit holders and the EP shareholders. With these three key objectives reached, we have essentially assured our funding for 2010 as J.R. will explain in more detail later, improving our balance sheet and keeping liquidity very strong at $2.7 billion.

This strong performance across the board means that we are trending towards the high-end of our guidance range in virtually every category, earnings, cash flow, costs and E&P volumes. All in all, a great start to the year and now I will turn it over to J.R., Jim, and Brent and I will come back at the end to wrap up. J.R.?

J.R. Sult

Thanks, Doug and good morning. Since our last call in early March, we have continued to make significant progress on our 2010 financing plan and I am extremely pleased to report that we have essentially met our funding requirements for all of 2010 in the first four months of the year. I will spend most of my time this morning reviewing our progress with you, but first I want to view our first quarter 2010 financial results, and I am starting on slide five titled 2010 first quarter financial results. As Doug indicated, adjusted diluted earnings per share for the quarter was $0.33 reflecting strong performances in both pipelines and E&P. solid pipeline earnings driven by expansions, strong production volumes and lower cash operating cost at E&P and a lower effective tax rate contributed to our first quarter performance.

Not surprisingly current quarter results are lower than a year ago. First quarter of 2009 benefited from higher average realized commodity prices including the impact of our hedge position. As you will recall, we had a $9.04 of a significant portion of our 2009 natural gas production. In addition, you will recall that we monetized our $110 per barrel oil swaps last year. Adjusted EPS for the prior quarter included $0.12 per share or $149 million attributable to swaps for the second, third, fourth quarters of 2009. So in total last year’s quarter benefited by about $0.25 a share or $300 million from higher realized commodity prices included the oil swaps and other derivate settlements.

Our GAPP reported diluted earnings for the first quarter of 2010 was $0.51 per share. A summary of these adjustments and a reconciliation to our reported earnings are included in our financial and operational reporting package on our website. The items impacting the first quarter included the impact of our (E&P) hedges, certain legacy matters and the tax impact of the healthcare legislation.

Our effective tax rate for the quarter was 31%, which is lower than the statutory rate due primarily to an increase in income attributable to non-taxable, non-controlling interest. This was partially offset by an $18 million deferred tax charge from the healthcare legislation enacted in March of this year, which includes a provision (inaudible) to deductibility of certain retiree prescription drug expenses. With the exception of the impact of the healthcare legislation, the effective rate is consistent with the rate we assumed in our 2010 guidance shared with you back in December.

In the pipeline growth for adjusted EBIT increased 6% to $421 million for the quarter, driven largely by the impact of expansion projects. Adjusted EBITDA for the pipes was just over $525 million. In E&P adjusted EBIT of $189 million declined from year ago due to lower average prices I mentioned earlier but also due to decline in revenues for lower cash operating cost and DD&A. Adjusted EBITDA for E&P was nearly $300 million for the quarter.

We have also included for your reference in the reporting package our adjusted pro rate EBITDA results, including our share of Citrus and Four Star.

Turning to slide six, which shows our cash flow from operations and capital expenditures for the quarter, cash flow from ops for the quarter was $570 million reflecting the support of our hedge program, or a substantial portion of our first quarter domestic natural gas production was hedged at a price north of $6. As expected, operating cash flow in 2010 was below last year’s level again driven primarily by lower average commodity prices including our hedges.

As far as capital is concerned, our 2010 plan remains on target. Pipeline capital was up in ‘10 consistent with the anticipated spending levels for the development of the backlog. As you will recall, 2010 is the peak spending year associated with the construction of the backlog with our Ruby pipeline project accounting for a significant portion of current year activity. E&P capital on the other hand is lower in 2010 reflecting higher rig activity and service cost as we entered 2009. The 2010 capital spend levels reflect some frontend loading of our more traditional programs as Brent will discuss later in the call.

Total liquidity on April 30th stood at $2.7 billion exclusive of cash and credit facility capacity at both EPB and Ruby.

Turning now to slide seven, I am sure most of you have seen the press release that we issued yesterday announcing the closing of the Ruby project financing. The second year $1.5 billion debt facility is supported by the (inaudible) the traditional pipe project financing loan based on LIBOR plus of spread. Ruby’s borrowing rate is LIBOR plus 300 basis points for the first two years, LIBOR plus 325 for the third and fourth years and LIBOR plus 375 for the fifth through to seventh years. The spread beginning in year five assumes that we have refinanced the portion of the debt prior to that day. Earlier today Ruby entered into forward swap agreements to fix at least 75% of the floating LIBOR interest rate beginning in June 2011 and extending through the maturity of the bank facility.

Based on the swap rates and the current six month LIBOR of the unhedged portion, the weighted average rate would be approximately 6.5% excluding debt issue costs. (inaudible) the facility in total required conditions president are satisfied which includes among others receipt of the BLM right-of-way grant and the FERC final notice to proceed and Jim Yardley, will update that review in few minutes.

As I mentioned in our December Analyst meeting that Ruby financing was our single largest transaction in our 2010 financing plan. I’m very pleased with the outcome and happy to have this one in the call. I’m starting on slide eight, which is a summary of a recent dropdown to El Paso Pipeline Partners. In March, we completed the sale of 51% of the entities in Elba Island LNG terminal and Elba Express Pipeline to RTB [ph].

This is our third drop down to the partnership since (inaudible) were getting started. The beauty of our MLP on the drop down strategy is that these transactions are truly win-win for both El Paso and EPB stakeholders. At El Paso we received $660 million in cash making a significant contribution for meeting our financing requirements for 2010. The transaction also further accelerates growth and the value of El Paso’s incentive distribution rights or IDRs since we continue to move higher and higher in the splits.

And finally we have a greater portion of our premium pipeline franchise whose value is directly tied in the market price of EPB which carries a significantly higher and readily apparent valuation. For EPB this is a great transaction as well, to borrow on the Parkship’s assets based by adding interest in two high quality assets that are as good as gifts for MLP. We have incredibly stable cash flows with contracts that are 20 to 30 years long with subsidiaries of Shell and BG.

Unit holders are also benefiting from the recent 6% increase in distribution following the acquisition and the 17% increase over the past year reflecting a success of the growth strategy driven by both organic growth and drop downs from El Paso. On slide nine, is an update of the status of our 2010 financing plans. Back at the analyst meeting we laid out the road map for funding our $4 billion capital budget. We also said at the time that we had excellent line of sight the execution of the components of our plant.

With the close of the Ruby project financing, recent sale of our Mexican pipeline assets and the dropdown of the EPB with essentially met our 2010 funding requirements. Our current year needs have been achieved, we’ll continue to be opportunistic in the financial markets to remain fully committed growing in our MLP for the benefit of both El Paso and El Paso Pipeline Partners and stakeholders.

We can’t predict how many more drops we’ll do in 2010 or the size, that we’re optimistic about the potential of access in the MLP capital markets to advance for the longer term improving in El Paso’s balance sheet.

On slide 10, there is a summary of our 2010 and 2011 hedge position for our natural gas and oil production. With $6.33 more than roughly 70% of our domestic natural gas projection for the remainder of 2010, with those positions waited to the second and third quarter. We’re nearly fully hedged in third quarter and about 30% hedged in the fourth quarter.

In 2011 about 65% of our domestic production tensed with the floor of $6 and then on the oil side we remained substantially hedged in ‘10 with an average floor price of $76. The key change from the last updated March is that we put on more oil hedges in 2011. We now have roughly 70% of our 2011 oil production hedge with an $84 floor. We’ve included our customers detail of all our hedges in the reporting package. That’s my update for you this morning. We’re very pleased with the financial performance for the Company so far this year and we populously made terrific progress on our financing plan.

With that I’ll turn the call over to Jim for an update on the Pipeline Group. Jim?

Jim Yardley

Thanks J.R. The pipes were up to a solid start this year. Adjusted EBIT of $421 million is up 6% from first quarter of 2009 and the four non-controlling interest attributable to El Paso Pipeline Partners EBIT is up 11%. We’re executing very well on our growth projects. In the first quarter we placed and serviced on time and on budget both the Elba Express Pipeline and Elba expansion. As Doug, said these are large projects, total capital of $900 million and now generating revenue and they’re both fully contracted long term.

On our Ruby pipeline, we received the FERC certificate and we expect to start construction in late June or early July. We also kicked up construction on the large FGT Phase VIII expansion. And finally we added a significant new growth projects to our backlog with secured commercial arrangements with shippers to move forward with another major expansion on the Marcellus.

Slide 13 summarizes throughput our major pipes. Changes in throughput versus last year reflects the economy, weather and production threats. In the East, TGP market areas throughput was flat, driven mostly by pretty normal winter weather in the Northeast. While we did a meaningful change in where supplies came from, volumes have went up rapidly out of the Marcellus and also Rex [ph] in Ohio and these new supply sources displays for both Canadian imports to Niagara and some long haul volumes transported out of the Gulf Coast.

Some of the Gulf Coast volumes haven’t instead been transported on short hauls to other pipes serving primarily in the Southeast. In the Southeast on SNG, throughput was very strong primarily for the record breaking cold winter weather, also industrial finance required recovered quite well from depressed levels of early 2009.

On EP&G throughput decreased especially due to the continued slow economy in the Southwest. Also contributing increase of gas from California Storage, startup carters of LNG delivered the (inaudible) and increased Canadian imports in to California. Finally throughput on our Rockies pipelines increased primarily due to Rockies production levels and the start of the (inaudible). And March and April was seeing a slow increase in Rockies production from its low point at the end of 2009.

So there were some swings in throughput year-to-year, but remember the throughput levels have only a small impact on our near term financials because of the nature of our business. Slide 14 summarizes where we are on Ruby. Ruby remains on budget and on schedule. We received FERC approval on April 5. In the order FERC agreed that the proposed route will have the least amount of environmental impact.

We’ve been working with all stakeholders over the past two to three years to come up with the route that has the least impact and we develop the restoration plants that preserve habitats for threatened plants and animals. We now expect BLM’s approval for the right-of-way grant over Federal lands by the end of May.

About 56% of Ruby’s route on Federal land. Once we receive the BLM approval and on the FERC notice of receipt we expect to start construction most lightly in late June or early July. We plan to do some staging in pipe and equipment in advance so that we can get of a fast start. As you know we’ll be utilizing seven different construction spreads from four contractors. Most of that is high desert, it’s about 120 miles and more mountainous terrain. For each spread we devoted a lot of time to detailed construction planning of the contractors.

We still expect all the pipe were being a grant by yearend or shortly thereafter. We’ll then complete pipeline tie ends, do the commissioning of the compression and test the systems. With Ruby’s ongoing and service next spread. Switching gears to the Northeast, the Marcellus continues to be an exciting area for us. Marcellus production in to TGP is now over 500 a day. We affirm transportation backhaul business with Marcellus producers that will provide approximately $60 million of annual revenue by 2012.

This business requires only minimal new capital. In addition, we’ve committed to a $1 billion forward haul expansion to move Appalachian and Marcellus gas to markets on a forward haul basis. Both of the projects are fully contracted under long term contracts and provides solid regulated returns. On the Line 300 expansion, we expect FERC approval soon. We’ll do some construction work later this year, but the bulk of the construction will be done in 2011 which is expected in service in November 2011.

The Northeast upgrade project is a step behind and is planned to go in service in late 2013. So TGP is in the center of the Marcellus activity in Northeast Pennsylvania and this is becoming a significant and growing business for us. Finally on slide 16, as you know we have several other great projects under construction this year in addition to Ruby and Line 300. We just started construction on both SNG, South System Pre-expansion and FGT Phase VIII expansion. Both of these are primarily pipeline looping and compression expansions.

Construction on Gulf LNG is well underway with the outer tank concrete work on both tanks now complete and construction will start soon on TIG’s expansion (inaudible). We just received last week our FERC certificate on that one. All these projects are on time and on budget and will start contributing revenue early in 2011.

In summary, 2010 is obviously a busy execution year for us. We’ve made very good progress so far and we’re on track with all the projects in the backlog. And now I’ll turn it over to Brent.

Brent Smolik

Thank Jim and Good morning. I’m beginning on slide 18, we’re also off to a very good start to the year. Our first quarter volumes came in at the high end of our range of expectations. Much of that increase was driven by the Haynesville which continues to deliver better results in our models, while all of our operating areas performed well versus our plan in Q1. We continued to find ways to further reduce operating cost. Our first quarter per unit cash costs were favorable and we’re modestly lowering our full year cost guidance and most importantly we believe there were any solid returns on our capital programs and as I’ll show you our capital is now largely focused in three areas and all three programs are progressing nicely.

We’re really excited about the Eagle Ford opportunity. We now believe that economics in the gas condensate area are even better than we anticipated. I’ll mention that Haynesville success and I’ll update you on drivers there in a few slides and the Altamonte program will continue to provide our good profitable oil option to our capital program and we’re now growing volumes in that area.

Oil and condensate production contributes about 13 to 14% of our total equivalent volumes, but due to the higher, to the combination of higher oil prices and more oil production in Altamonte almost a quarter of our domestic revenues are now tied to liquids pricing versus about 15% in Q1 of ‘09 and remember in Brazil, Camarupim gas volumes are also indexed to a basket of fuel oils and also benefit from higher oil prices.

On slide 19, on the left graph we show you our first quarter 2010 production compared to 2009 and we were down about 3% from a year ago. And remember we significantly shifted our capital allocation over the last year and you can see the impact to the capital shifts and year-over-year production changes. We’re not investing as much in the Gulf of Mexico or traditional South Texas areas as we have historically and you can see the expected decline in the blue bars.

We’re also spending less in some of our traditional Rockies programs in our western region but we’re still managing the whole production relatively stable in the west. We’re experiencing solid growth in our Haynesville program which is showing up in the green bands in our central region.

The graph on the right side of the chart maybe more importantly shows how our production has rebounded from the third quarter lows of last year as we’ve increased activity levels. As we look out the rest of this year, our production profiles should be relatively flat and I’ll show you in a few minutes our rig count were declined in the second half for the year, but we front-end loaded the drilling in our more traditional programs and much of that work is now being completed and we’ll see the production benefits through the year.

For now we’re maintaining our 740 to 780 million per day guidance, with the Q1 coming at 780, we have a chance to trend near the high end of the range for the full year. Slide 20 shows the summary of our cash cost. Total cash cost for the quarter were $1.88 which is down 6% as J.R. said from $2 a year ago and the big change is from domestic LOE which came in at $0.62 per unit.

We’ve been a top quartile performer for a number of years in this area but we found ways to further drive improvement in the cost. There has been some cost inflation since this time last year but you may recall that we’ve consolidated our domestic operations into one organization and we’re definitely realizing benefits from that change.

And the national LOE was manageable in the first quarter of 2009, but its present to 2010 with the addition of the Camarupim volumes. Those Brazil unit cost will trend down later in the year as we bring on the fourth well in that field. Given our progress with domestic LOE and the strong start to the year, we’re reducing our range of per unit cash cost down $0.05 to $1.80 to $2.10. If you turn to slide 21, I’ll give you an update on our Haynesville program.

At this time last year, we were kind of just catching up our stride in the Haynesville. Since then, we have demonstrated that our drilling and completion capabilities are as good as anyone in the play. We have recently drilled a well in 25 days from spud to rig release and that’s about three days better than our previous best well in the field. And then, while we don’t have the largest Haynesville position, we arguably have one of the best.

We look at numerous production comparisons including 30-day IPs, the first three months totals, the first six month total production. In all cases, our wells compete favorably with industry averages. As an example, for the wells that have been on production for six months, the El Paso wells on average have tuned (ph) about 1.5 Bcf of production versus about 1.2 Bcf for the industry average or roughly about 30% difference. So we have got an advantaged acreage position and we are doing a good job of drilling and completing their wells.

The only negative news in the Haynesville is the stimulation cost were up about 10% since the beginning of the year and we continue to experience upward cost pressure in the field. We have gotten our – we had gotten our average completed well cost down to about $7.5 million and today that cost is more like $8 million to $9 million for well.

And I believe this is part of why you have heard a number of operators discuss reductions in their Haynesville activity levels. We have not made a decision yet to reduce activity, but there is a logical limit to high service cost and low natural gas prices and we are getting close.

The good news for the quarter is that both our non-Holly and our Holly wells continue to perform as good or better than the models that we shared with you in New York in December, which again has contributed to domestic production running at the high-end of our expectations.

Slide 22, there is a 15-month history of our gross operated Haynesville production. A year-ago, we were around about 30 million a day. In the first quarter of 2010, we averaged above a 170 million a day, and we currently have eight wells waiting on completion. So we expect to produce a 180 million to 200 million a day during the second quarter. And remember that our net volumes here are roughly 70% to 75% of that gross total.

Now, if you turn to slide 23, I will give you an Eagle Ford update. When we had our fourth quarter call, our second well which is in the gas condensate area, it hadn’t been completed or tested. We announced the IP rate a few weeks later and it’s a nice well. It tested about 2.9 million a day of gas and 721 barrels of condensate per day.

Now the headline, 7.2 million a day equivalent volume is less impressive than Haynesville gas rates. But the liquids content of this well significantly improves the economics of the area. We had a second gas rig in the Eagle Ford program in March, and we are now drilling our third well in the gas condensate area, and we will continue to develop that part of the play.

We are also completing our second well in the dry gas area and assuming $4 net back gas well (ph). This area is not as strong as the gas condensate area. But when prices do turn, this is going to be a really good program for us. We will probably drill another well or two this year to continue the pilot tested to test this part of the play.

A key issue for the Eagle Ford is takeaway in processing capacity. And as you know, there is a lot of companies floating potential infrastructure projects. We are looking at a number of those options and we are also working on some ideas internally that could favor Tennessee Gas Pipeline. And we don’t have anything to announce yet, but we plan to get ahead of our takeaway capacity needs here just as we did in the Haynesville.

We continued to acquire additional acreage in the gas condensate part of the play and we now have closer to a 150,000 net acres overall with about 80,000 acres of the leases in the gas condensate area.

On slide 24, there is a chart showing some comparative data between the two areas in our first four wells. The first thing I would point to is the difference in the Btu content of the gas between the Briscoe (inaudible) that’s the southern dry gas area and the Hickson (ph) 1H that’s the northern gas condensate area. And you can see that’s a 970 Btu versus 1368.

And also note, the condensate is 731 barrels per day on the Hickson. And I will show you the impact of those liquids on the world economics in the next slide. And then, finally, our most recent wells – in our most recent well, we drilled a 5,000 foot lateral and we plan to complete this well with an 18-stage frac as we continue to optimize the drilling and completion designs in the play.

Slide 25 shows the economic impact of the liquids on the returns in the Eagle Ford economics. As I mentioned a moment ago, there is a big difference between the Btu content of the two areas and a $4 net back gas world, the natural gas liquid content improves the value of an Mcf of gas to north of $7.

And if you include an average of about a 150 barrels of condensate production per million of gas and note that our initial rate on the Hickson well was at a much higher condensate rate, it was more like 250 barrels per million. But if you assume that 150 barrels per million and you assume $80 oil price, we would add another $8 of value for every Mcf we produce.

And the text box at the bottom gives an indication of the returns for dry gas well and a condensate well at $4 and $80 price assumption. And the takeaway is gas pricing, we would expect sort of breakeven returns in the dry gas area and very attractive economics in the gas condensate area, which is why we are rapidly moving into development mode and while this area has quickly become a core program for us.

Now slide 26, I will give you a quick update on our two international programs. Our Camarupim project has three wells producing about a $130 million to $140 million a day of gross production, so that’s about $30 million to $35 million a day net to El Paso and the fourth well is still expected to be on stream in the fourth quarter. We have adjusted full-year international guidance down by 10 million a day to 35 million to 45 million a day, while keeping the total company range unchanged.

In the ES-5 block, we and our partners Petrobras are drilling an exploratory cast on our VISY (ph) project. And this is a look-like prospect to Camarupim and it would be tied back to the Camarupim production facility. Note, there were also drilling that inside the ES-5 block, so we have a 35% working interest in that project versus the 24% unitized interest we have in the Camarupim field.

We continue to make progress in Egypt with current activity in each of our three blocks. In South Alamein block, we are drilling our fifth well with the operator SEPSA and EP operated South Mariut Block, we have begun acquisition of 3D – of the second phase of 3D seismic, and in the RWE operated Tanta block, we are evaluating seismic and we will decide jointly whether or not we will drill a well later this year.

And finally, slide 27 provides the snapshot of our drilling program for the year as you can see we front loaded our 2010 rig schedule to some of our more traditional programs. And we did this, because we feared the service cost were headed higher and we wanted to ensure the economics of these wells. We will soon be down to eight to 10 rigs, that will be four to five in the Haynesville, two to three in Altamont, and one to two in the Eagle Ford. And these are our most profitable and most liquidous programs, so that will be the focus of our capital program for the remainder of the year.

We are going to be pretty fluid between now and yearend if gas prices remain soft and service companies keep trying to increase cost, then we may drop a couple of those rigs and be closer to eight. We will be disciplined about the capital spending in the current environment and we will allocate capital to the programs with the greatest value creation and return potential just as we did last year, and we will do the same thing this year as well.

So that’s it for E&P. We excited 2009 with a lot of positive momentum and we haven’t skipped a beat so far this year.

With that, I will turn the call back to Doug for closing comments.

Doug Foshee

Thanks Brent. I hope you see from our results that our businesses are really hitting on all cylinders so far this year. The pipelines continue to exit well on their growth projects, putting close to a $1 billion in service during the quarter on-time and on-budget, starting construction on two projects and receiving approval to start on a third.

We moved the ball down the field on Ruby toward a summer start to construction and we continued to add to the backlog in the Marcellus. E&P continues to perform very well both on the volume and cost fronts and we continued to add to our position in the Eagle Ford during the quarter, and we made significant progress on the balance sheet with the Mexican asset closing, another MLP drop, and the closing of the Ruby project financing.

As we look to the second half of 2010, we continue to monitor gas prices and oil field services cost closely. We are largely shielded from gas price issues, given the relative stability of our pipeline cash flows and significant hedging in E&P, all the way through 2011. In addition, most of our acreage in E&P is held by production, so we have very little need to drill the hole in 2010.

So our efforts are to make sure that we maximize returns by allocating capital to the best areas, given the combination of acreage position, commodity pricing, and costs. You see from Brent’s presentation that we now plan to focus virtually all of our second half capital on our three most profitable areas, Altamont and Eagle Ford given their liquids content, and Haynesville given our preferred position there.

We are currently planning to cut overall capital relative to our original guidance, which was basically already flat to last year. But we have begun to reallocate where it makes sense. And we don’t factor our hedges into any incremental capital decisions. Those hedges are there to ensure our cash flows not to justify drilling.

As the rest of industry, we are also very concerned about recent upticks in some service costs, particularly in this natural gas price environment, and we are prepared to cut back if those costs aren’t in line with the reality of the current gas price environment.

Finally, as I have discussed at the beginning of the call, the strong start to the year has us trending toward the high end of our guidance range is virtually across the board. So we will be working to sustain that in the balance of the year.

With that, we will open it up to your questions this morning. And let me ask – let me start by requesting that you limit yourself to a couple of questions, so we can accommodate everybody that’s in the queue.

Operator, we are ready to start with questions.

Question-and-Answer Session


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

Carl Kirst – BMO Capital

Hi, good morning, everybody, and a great start to the year. An E&P and a pipeline question, if I could. First on the E&P, really Brazil and – and actually Brent, can I ask you to – you said the international was down 10 million a day, I didn’t catch why that was happening?

Brent Smolik

That’s just mostly the – we have had some up downtime at the Camarupim project due to – in their summer months, there was little less demand and so as the project has been up and down a little. So we adjusted a two, one actuals and then sort of planned on a little bit more that going forward, and then we pushed the fourth well, kind of late in the fourth quarter.

Carl Kirst – BMO Capital

Okay. So –

Brent Smolik

We (inaudible) it’s in there, so everything is kind of on track and we will just anchor in what we have learned in the first quarter.

Carl Kirst – BMO Capital

Okay. So that’s not the subsea bolt issue, that’s just the – I guess the natural flow you might say, okay.

Brent Smolik

We have all of that behind us, Carl.

Carl Kirst – BMO Capital

Great. The actual question I wanted to ask on Brazil really was on Tijuana and understanding these are very much apples and oranges here. But just given Tijuana is offshore and a very environmentally sensitive area, has there been any discussion between El Paso and Elba (ph) over the last two weeks that has raised the BP issue?

Doug Foshee

No, and a lot of discussion with them ongoing normally and I think we are on track to get to the point of we will get to a public comment period here pretty soon. And then once we get through that, we will be looking for the next phase permanent to be released, but no, not related to the Gulf of Mexico.

Carl Kirst – BMO Capital

Great. And then, Jim, if I could on the pipeline summit – I am sorry.

Doug Foshee

And Carl, to clarify, these are very different. This about a 100 feet of water and it’s going to be drilled from well controlled equipment that’s up on the surface.

Carl Kirst – BMO Capital

No, absolutely. Just given the high-profile nature, I just wanted to make sure and asked. Jim, the one question with SNG’s volume coming down and I understand you go from time-to-time the rate cases at SNG, so it may not be an earnings issue per se. But when Ruby comes on line, are you expecting to see some potential cannibalization of those volumes?

Jim Yardley

You did mean SNG.

Carl Kirst – BMO Capital

I am sorry EPNG. I apologize, thank you.

Jim Yardley

Really, the – if you sort through it all, the economy in the southwest and (inaudible) in California, it doesn’t helping us here at all. Other than that, there have been – hard to say if they are sustainable or not, but things like the change in year-to-year withdrawals in California storage it impacted that throughput year-to-year substantially. Also, LNG coming into Brazil (ph) is that sustainable or not? Who knows, there is a startup volume, we thought it was going on in Asia and maybe that doesn’t play out.

Really and specific through Canadian imports impacting EPNG, hard to imagine that long-term, we think the macro is going to play out essentially. But Ruby is going to be backing out a lot without existing Canadian production coming in with very little impact and in the Southern California.

Carl Kirst – BMO Capital

Great, thank you.


Your next question comes from the line of Craig Scherer with Tuohy Brothers Investment Research.

Craig Scherer – Tuohy Brothers Investment Research

Great quarter.

Doug Foshee

Thank you.

Craig Scherer – Tuohy Brothers Investment Research

Brent, one for you, and then one for Jim. Again here – first, are you experimenting at all with choking back on Haynesville IP rates? And if so, what are you seeing from that effort? Are you looking at some of the announcements that others are doing in that regard?

Brent Smolik

Yes, Craig, our practice has always been to limit the drawdown on our completions. And so that’s – we are not starting to choke them back, we have always held them back. But the way you should think about that is somewhere else we are just capable of delivering more at relatively low drawdowns and that’s where we think we have got an advantage area.

These wells are just capable of higher rates, even though at the bottom, situation wouldn’t be drawn it down more than a 1500 to 2000 pounds. So we have always used that practice. We do watch the other competitors quite closely and we have got interest in a couple of those well, so we have got the dataset and we will continue to monitor them but we’re not pulling the wells hard.

Craig Scherer – Tuohy Brothers Investment Research

Well, to the degree you’ve had that practice in the past how flat is the initial production, is it three months or two months of good flat IP rate or how does that work?

Brent Smolik

Yes it’s just we get some early flattish production but it’s a month of two and then those wells go on decline. So we’re not curtailing them all the way back down to like 10 million a day when they’re capable of 20 but that’s what you’re getting at in those kinds of cases. But while we’re curtailing – what we’re managing closely is the drawdown at the completion across the fracs. And so the wells will decline fairly quickly but they’ll start at 20 – 17, 18, 20 million a day rates.

Craig Scherer – Tuohy Brothers Investment Research

I heard of at least one example of pulling back to 10-to 15 with another player, it’d be kind of interesting to hear more about this over time.

Brent Smolik

Yes, I think the real question is how much drawdown they’re putting across to completion.

Craig Scherer – Tuohy Brothers Investment Research

Understood. Jim, I’ve been a little concerned over time across a couple of your peers about recontracting risk for short term, long haul pipe into the northeast given wrecks in the advent of the Marcellus. I wonder if you can comment on the expected net effect on TGP from the combination of the headwind of narrowing basis differentials but then also the upside of filling up the pipe in the north with Marcellus volumes and in the south with potential Eagle Ford volumes.

Jim Yardley

I think it’s a very good question Craig and we come out that this is much more of an opportunity than a challenge. The situation is something like this. So Marcellus, we are right on top of it in northeast Pennsylvania. It’s allowed us to do forward haul expansions to the tune of a billion dollars, these projects stand on their own. By the way if you relate that billion dollars to the rig face today on TGP, the existing rate base is probably about $2.5 billion. So those are very meaningful expansions.

Coming back to the base business, the backhaul business that we have that is coming out of Marcellus protects us from a lot of downside challenges. While we are most challenged on TGP is in the mid section of TGP coming up through Kentucky and Ohio and in all – it’s that section that one would worry about wrecks lines or Marcellus backing up. But really in (inaudible) there, we’ve been challenged since probably 2000 or so. We have significant excess capacity there today and it’s highly, highly competitive in that area. So it’s not any backing out of additional business we don’t think is a significant thing relative to that backhaul business. In addition to that, we save on fuel, on electricity to run our compression and we will just naturally save on operating cost if that happens down there. So on balance when we look at the total picture we see much more positive than negative.

Craig Scherer – Tuohy Brothers Investment Research

How material can the Eagle Ford be for the pipeline in the South?

Jim Yardley

I think the way I’d answer that is that we have again idle capacity down on our line from essentially the Mexican border up through Houston up into Louisiana. So with that it would be a positive. It’s not a big revenue generating area to us today and so it’s going to be nothing but rig.


Your next question comes from the line of Rick Gross with Barclays Capital.

Rick Gross – Barclays Capital

Actually my question was asked on choking Haynesville.


Your next question comes from the line of Ted Durban with Goldman Sachs.

Ted Durban – Goldman Sachs

Yes, if I could just ask, I saw that you kept your production guidance flat for E&P. Should we think about that as change in terms of the mix of liquids versus gas? You’ve been – 15% of your volumes or so looks like historically but as we enter the year, should we get to more like 20% liquid than oil and what not?

Jim Yardley

It won’t quite go up that much, it will inch up a few percent as we grow volumes in Altamont and then the bigger ramp up could be in the ‘11 as we start to feel the full effect of an Eagle Ford expanded development program and an expanded Altamont program. And so we’ll trend up and then step up further next year.

J.R. Sult

And just to be clear we haven’t changed guidance but we have said today we’re trending towards the upper end of our guidance range almost across the board.

Ted Durban – Goldman Sachs

Got you, okay that’s helpful thanks. And then if I can just ask a little bit more bigger picture, if you look at what some of the – your other peers, integrated natural gas companies are doing, does it kind of make you think twice again about remaining integrated. I mean you look at the really strong cost to capital, your MLP, maybe just some thoughts again on the business model.

Doug Foshee

Yes. Well it’s a great question, it’s one that we’re going to – that we have and we’ll spend a lot of time discussing and analyzing internally as we go through the year. We now have two competitors who have announced restructurings of their business in order to unlock what they perceive to be discounts to their stocks. And one of those cases is to be accomplished by essentially moving all of their pipeline and midstream assets into one MLP all at once and that relieves them of future funding requirements there and highlights their (inaudible) franchise.

And the other, they intend to separate their businesses with a tax free spend of most of their E&P assets. In each of them we think has different drivers. For El Paso they represent too many possible alternatives and so we’ll watch closely to see whether either or both of those result in differential shareholder value. Here’s where we are. The next year for us is absolutely critical. We see the discount between our current share price in our NAV as composed really of three components. The first of those relates to the balance sheet. We don’t have investment grade statistics today and we’re in our peak year for capital spending.

We think there is some discount to our NAV that’s associated with concerns about our ability to adequately turn our pipeline business and at the same time fund E&P and our (nascent) midstream business. And we believe that as we get rid of those concerns, as we move toward our target of free cash in 2012 and as we move toward our target of investment grade in 2012, there is a significant value accretion to our shareholders.

Obviously, yesterday and that was a key day for us in that journey with the closing of the Ruby financing. The second component of discount between our NAV and our share price revolves, we think, around execution. Shareholders want to know that we can put pipeline projects on time and on budget and generate predictable sustainable earnings growth. We’ve got a – we think we have a differentiated track record on this front and we further that this quarter putting close to a billion dollars of new projects and service but we know we have to do this with the rest of the backlog.

We think as we show that through the balance of this year and into early 2011, our shareholders are going to be rewarded. On the E&P side, we have to show that the performance that we logged in 2009 was continued to trend and was a step function improvement, wasn’t a fluke and we can compete in this business at the high end of returns and at the low end to cost.

So putting up 2010 numbers similar to 2009 will go a long way toward eliminating this as a concern and we think it’ll result in going concern value of our E&P franchise being reflected in our share price. So, will by the way moving our Eagle Ford acreage into development mode as we did with the Haynesville in 2009.

And then the third component of the discount is driven by the fact that we are in a pure play. As we sit here today, we don’t know what the waiting of those three are, but we do intend to largely eliminate the first two as we put the backlog in service and as we deliver another good year in E&P as we bring our Eagle Ford play into full development as we complete our capital spending overall in 2010 and start to improve our balance sheet and we intend to do all of that much of it in the balance of 2010.

So while we intend to continue to monitor the performance of our competitors really closely to see if either of their decisions or some permutation of those decisions that generate excess returns to El Paso investors we think today at this red hot moment while we’re in the middle of the biggest CapEx year in our company’s 82-year history and while we’re in the midst of what maybe the best combined year for our business units it’s in our shareholders best interest that we stay laser focused on balance sheet improvement, execution and moving towards positive free cash.


Your next question comes from the line of Becca Followill with Tudor Pickering and Holt.

Becca Followill – Tudor Pickering and Holt

Good morning and thanks for that answer to Ted’s question, that was helpful. On the MLPs, you said that you’re just getting started on the dropdowns. Can you give us some more color as to – despite the fact that you’ve got your financing done for the year, would you do more this year and if you did, what you would use proceeds for?

Doug Foshee

I absolutely think if markets stay where they are we’ll do more this year. We’re incented to do that both by the incentive distribution rights that we hold in the GP and by the units that we hold and. So that’s been a good formula for us so far. We think it’ll continue to be a good formula. If you think about sort of the – we have always thought that the practical limit in the near term to the growth in our MLP is really the size of the MLP market and the capacity at least right now of the retail market to absorb new equity. So if you think about that as JR mentioned earlier kind of $300 million of equity at a time and $50 million debt-to-cap, that’s on the order of $600 million drop at a time. We think that we can do more than one of those a year and probably can’t do four of those in a year, so somewhere in the one to three range in a year given current market conditions.

Until we get to the holy grail for us, which is investment grade as a company and until we get to free cash, we think it’s pretty simple for us to figure out what we do with proceeds and that’s a great way for us with a really efficient source of capital to accelerate our deleveraging plan and move that 2012 date up if you can.

Becca Followill – Tudor Pickering and Holt

On Eagle Ford I know it’s really early but have you guys started to look at trying to contract for fractionation capacity. Do you have anything already or what are your plans there so that you don’t get squeezed out of a really tight market?

Doug Foshee

Yes, we think we think we’ve got enough visibility back up for this year and going to the next and then we’re working on beyond that. So, we could easily keep up with a tier rate program we think. It’s just if we can get ready to ramp up to a more expanded program, that’s the option we’re working on but there are a lot of options being discussed right now. So we think we’re going to be – we will get ahead of it just like we did in Haynesville before.


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

Jonathan Lefebvre – Wells Fargo

Hi guys, nice quarter. Just on the Ruby financing, congratulations for getting that in place. You said 6.5% kind of weighted average is that and correct me if I’m wrong but is that below what you had budgeted originally, I believe it was up near 9% and did that kind of enhance the economics there for you at all.

J.R. Sult

Yes, it does and yes, it was below our expectations.

Jonathan Lefebvre – Wells Fargo

Okay. And then just jump into the MLP and kind of Becca’s question there, did you guys – I know you said you’d pursue the additional MLP dropdowns possibly later this year. Did I hear you right that the preferences to put that capital towards the E&P program or would you use some of that to fund some of the (nascent) midstream opportunities you’re seeing?

Doug Foshee

Yes I think well it sort of it will depend on conditions at the time. But I think right now especially given the level of capital we’re spending in the two businesses combined and our perception anyway that a portion of the discount in our stock to our NAV is related to balance sheet strength and financial flexibility. I think the first order of business for us will very likely be continuing to improve the balance sheet if we can do better in terms of the volume of MLP drops that we could do in a given period of time sort of the first order of business is continue to improve the balance sheet.

Jonathan Lefebvre – Wells Fargo

So that essentially pushes out any type of pursing any type of midstream opportunities probably out to the 2012 type timeframe?

Doug Foshee

No, I don’t consider those necessarily to be mutually exclusive. I think what happens with midstream is a combination of first of all midstream competing for capital for future capital with both the upstream unit and the pipeline group and then secondly all sorts of opportunities for how to finance that business in a way, that’s balance sheet friendly.

Bruce Connery

Yes. Alright, that concludes today’s call. We appreciate your participation and your questions, thank you.


Thank you. This concludes today’s conference. You may now disconnect.

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