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Executives

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

Analysts

Carl Kirst – BMO Capital

Faisal Khan – Citigroup

Lasan Johong – RBC Capital

Craig Shere – Tuohy Brothers Investment Research

Monroe Helm – Barrow Hanley

Jonathan Lefebvre – Wells Fargo

Becca Followill – Tudor Pickering and Holt

Shen Lou [ph] – JP Morgan

Ted Durbin – Goldman Sachs

El Paso Corporation (EP) Q4 2009 Earnings Call Transcript March 1, 2010 10:00 AM ET

Operator

Good morning. My name is Tiffany, and I will be your conference operator today. At this time I would like to welcome everyone to the El Paso Corporation fourth quarter earnings release conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. (Operator instructions) Thank you.

Mr. Bruce 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, El Paso’s Chairman and Chief Executive Officer. 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 Web site at elpaso.com. This morning, we issued a press release and filed with the SEC as an 8-K and is also in our Web site.

Please note that we have a financial and operational reporting package in the supporting materials of the webcast details located in the investor section of our Web site 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.

One thing we would ask when we do get to Q&A, if you would limit to two questions please it’d be very helpful.

And with that I will turn the call over to Doug.

Doug Foshee

Thanks, Bruce. Good morning. I would like to start this morning on Slide #5 with a quick run down of our overall performance for 2009. First though, I would like to thank our employees for a great year operationally and financially under very challenging conditions.

In a year like 2010, where execution across the board will be so critical to El Paso’s success. It’s worth looking at how we did in 2009 versus our objectives in pipeline construction and drill bit performance and in providing adequate funding for our operations.

Three key determinants of our success in 2010. If the past is prologue, then 2010 is shaping up to be an outstanding year for El Paso.

Jim and his team in the pipes had another very strong year in 2009. Adjusted EBIT was up 12% over 2008. We secured a 50% partner for the $3 billion Ruby pipeline, the largest single component of our pipeline backlog.

We continued to show good execution on capital spending putting four new projects in service on time and on budget. And we continued to make good progress on the balance of the backlog, the remainder of which remains on time and on budget.

As for the E&P company, Brent and the E&P team performed better than at any time in my tenure.

Production came in at the high end of guidance despite spending less capital. We saved almost $0.20 off our per unit direct lifting costs which we believe will put us in the top quartile on this measure of efficiency again for 2009.

Reserve replacement costs before price revisions came in at $1.57, down significantly from $2.87 in 2008 and this was accomplished while keeping our proved undeveloped researches as a percentage of total proved reserves modest relative to our peers at 31%, giving us further confidence that these results are sustainable.

Our risk unproved resource rose by 44% for the year. Our Haynesville area went from a standing start to an exit rate of 150 million cubic feet a day gross and 110 million a day net by year-end and this was accomplished at costs that are as good as anyone in the play.

We got off to a strong start in the Eagle Ford, putting our first well on production and building an acreage position from scratch that now totals 138,000 acres and counting.

We’re currently completing the second well on our acreage and have made a decision to add a second rig into Eagle Ford likely for the balance of the year.

And finally, E&P generated $600 million in cash flow after CapEx for the year even after the purchase of the Flying J assets in Altamonte at year-end.

With regard to balance sheet management, Mark Leland, John Hopper and more recently J.R and their teams did yeoman work staying well ahead of our financing needs in 2009.

We completed $3.8 billion in new financings between the fourth quarter of 2008 and the fourth quarter of 2009, keeping liquidity very strong throughout the year. We ended the year at the high end of our guidance for liquidity, $1.8 billion after funding the Altamonte acquisition in December.

And finally, we generated strong earnings for the quarter at $0.34. For the year at $1.29 on an adjusted basis as a result of the combined contribution from pipes and E&P as well as significant companywide cost reductions.

Now, moving to 2010, we’re off to a great start on the goals we’ve laid out for you back in December at our Analyst Day.

On Ruby, we received our final environmental impact statement in early January. We expect to receive FERC approval this month and we expect to begin construction in the May/June timeframe all consistent with our previous guidance.

As J.R. will detail in his comments we now have in hand financing commitments in excess of our needed $1.5 billion and at very favorable rates. And we see an increasingly positive macro for Ruby, as new shales compete for eastern markets, making western path more attractive for Rockies producers and have Canadian production continues to decline.

In E&P, a strong start to the year gives us confidence to edge up our production guidance by 20 million a day from the original range of 720 to 760, to the new range of 740 to 780 a day.

With regard to the pipeline backlog, we complete another major milestone today, as we put both the third expansion of the Elba Island LNG terminal and the Elba Express pipeline in service and generating revenue.

This represents over five years of effort and close to a billion dollars in capital and both start service on time and on budget. And we continue to build on to the pipeline franchise.

In a most recent instance, we added another Marcellus related growth project at TGP, the northeast upgrade. Together, with the previously added line 300 project, that makes a billion dollars in new growth on TGP, fully subscribed with long-term contracts and in-service dates in 2011 and 2013.

These big project wins validate both the skills of our commercial team and the value of having a large existing footprint in the key market and supply areas across the US.

As we alluded to back in December, we just announced an agreement to sell our Mexican infrastructure business for $300 million, an important component to our overall financing plan for 2010.

And finally, El Paso pipeline partners, our MLP, completed a very successful equity sale in January, generating almost $240 million in proceeds, which I expect they will put to work soon.

With that I will turn the call over to J.R. and come back at the end to wrap up and then take your questions. J.R?

J.R. Sult

Thanks, Doug, and good morning to everyone. In early December, at our Annual Analyst Meeting in New York, I outlined our financing plan for 2010. And although we’re only 60 days into the new year, we’ve already accomplished a great deal toward meeting our 2010 funding needs. I’ll update you on our progress in a minute, but first I’ll review our fourth quarter and full year 2009 financial results.

I’m starting on Slide #11 titled 2009 Fourth Quarter Financial Results. Adjusted diluted earnings per share for the quarter was $0.34, an increase of 62% over the $0.21 per share in 2008. As we’ve reminded you on previous calls, our results for the quarter do not include $0.04 per share associated with the early settlement of our $110 per barrel oil hedges, which we realized in the first quarter.

Our earnings would have been $0.38 per share for the quarter if we had held hedged positions to maturity. Actual GAAP reported earnings for the quarter was $0.36 per share.

A summary of the adjustments and the reconciliation to our reported earnings per share are included in our financial and operational reporting package on our Web site.

Items impacting the fourth quarter included international ceiling test charges, severance costs related to our recent reorganization, the impact of our E&P hedges, certain legacy matters and the tax benefits associated with the liquidation of certain foreign entities.

Our GAAP effective tax rate for the quarter after adjusting for the tax benefit associated with the liquidation of foreign earnings was 35%. Results for the quarter was driven by strong performance in both the pipes and E&P, each posting solid increases in adjusted EBIT and adjusted EBITDA.

In the Pipeline Group, adjusted EBIT increased 19% for the quarter, driven largely by the impact of expansion project placed in service and lower operating costs across franchise.

In E&P, lower cash costs and DD&A together with higher realized commodity prices which benefited from our hedging program led to performance improvement.

We’ve also included for your reference in our reporting package our adjusted pro rata EBITDA results including our share of both Citrus and Four Star.

Now, turning to Slide #12, for the full year we reported adjusted diluted earnings per share of $1.29 roughly in line with our 2008 performance despite realized natural gas prices of 7% below 2008 levels.

GAAP reported earnings per share for the year was a loss of $0.83 which was significantly impacted by the first quarter ceiling test charges. I would once again refer you to our reporting package for the items impacting our full year earnings per share.

In the Pipeline Group, adjusted EBIT increased 12% to 1.4 billion supported by incremental expansion revenues and capacity sales, higher retained fuel revenues, lower electric compression costs and lower operating costs. Jim will elaborate further in a few minutes.

The Pipeline Group placed four new expansion projects in-service in 2009 on time and on budget. Adjusted EBITDA surpassed $1.8 billion for the year. In the E&P group lower DD&A and cash costs helped offset the impact of lower commodity prices and production volumes. Our successful hedge program contributed about a billion dollars to our 2009 results.

Moving on to Slide #13, cash flow from operations for the year was 2.1 billion compared to 2.4 billion for 2008, despite significantly lower commodity prices.

Capital expenditures came in on target at $2.8 billion for 2009, essential flat for 2008 spending levels.

Pipeline capital of $1.7 billion was split $1.4 billion through expansion and $0.3 billion to maintenance. Major expansion projects included Ruby, Elba, and Elba Express in line 300 among others.

On the E&P side total capital ended the year around 1 billion, reflecting the pull-back earlier in the year in response to low commodity prices coupled with then higher service costs.

Despite the reduction in capital allocation, the E&P Group grew proved reserves 8% reduced its domestic reserve replacement cost to $1.57 and delivered production volumes at the high end of our full year guidance.

Importantly, we ended the year with strong liquidity, 1.8 billion. The amount was at the high end of our December guidance after spending about $100 million for the Altamonte oil property acquisition at year-end.

Liquidity is comprised of 1.3 billion, in fact, with all our capacity, about a $0.5 million billion in cash. Now, (inaudible) total liquidity excludes about $400 million of combined cash and credit facility capacity to meet expansion capital needs at EPB and Ruby.

As Doug mentioned in his opening remarks, this year is all about execution. And the finance group is no exception. For my organization that means delivering on the finance plan we laid out to you in December period.

Moving Slide #14, we’ve made significant progress in the first 60 days. On Ruby, we’re very pleased with where we’re on the financing and I’ll give you an update on the next slide.

On asset sales, we told you back in December that we anticipated news regarding asset sales would come earlier in the year rather than later. And last week we announced the sale of our Mexican pipeline assets for $300 million. The vast majority of these assets are in joint venture with Pemex.

Finally, on the MLP front, El Paso Pipeline Partners was among the first MLP of accessing the equity markets in early January. Demand for the units was strong. (inaudible) steel is upside for nearly 10% and substantially, all the green sheet was exercised.

Total net proceeds from the offering was nearly $240 million. With the proceeds in hand, I would expect the partnership to put the money to work in the near future.

Turning to Slide #15, as Doug previously indicated, we’ve received executed commitment letters from a diverse group of financial institutions totaling over 1.5 billion to provide project financing for the Ruby pipeline project.

Commitment letters are subject to various customary conditions precedent and execution of definitive loan agreements. We’re in the process of negotiating these agreements so we won’t be providing much detail on the specifics of the transaction.

However, the terms for the facility are expected to be typical for project financing of this nature. One detail I will share is the facility will be structured to the seven-year traditional bank project financing.

Based on current market conditions, and assuming required hedging, we would anticipate an initial interest rate of less than 7%. As I said in December, Ruby is the preeminent project financing transaction in the market this year and has attracted the top tier project finance banks from around the globe.

Although we still have additional work to close the financing prior to start of the construction we believe receipt of the commitment is an important milestone in the project to reflect strong interest in our project from the financial community.

I’m very pleased with the progress we’ve made and the support of our group of banks and helping to bring the financing closer to the goal line.

Before I turn the call over to Jim Yardley, I want to remind you of the considerable commodity price protection we have in place for our 2010 and 2011 natural gas and oil production.

On Slide #16, you see intense positions are designed to provide us greater cash flow certainty as we complete the backlog pipeline expansion projects in 2010 and 11. We have $6.41 in floors, and are roughly 80% of our domestic natural gas production for the full year 2010 with the positions weighted towards the first three quarters. Nearly fully hedged through the third quarter and about 30% hedged in the fourth quarter.

In 2011, about 60% of our domestic gas production is hedged with a floor price of $6. For oil, we’ve hedged substantially all of our production in 2010 with a floor price of $76 and about 25% of our estimated 2011 production with an $80 floor.

We’ve included our customary detailed schedule of all our hedge positions in the reporting package. That’s my update for you this morning.

Both our businesses performed well in 2009 and have carried forward that performance level into 2010. We’ve made excellent progress on our financing plan and I look forward to sharing further updates with you in the near future

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

Jim Yardley

Thanks, J.R. Our Pipeline Group had a very productive 2009. The 12% increase in adjusted EBIT represents another year of meaningful growth for the pipes.

EBITDA for the Pipeline Group adjusted for a portion of interest in citrus is now $2billion. And we’ll continue to see earnings growth as we execute our backlog of growth projects.

We’ve placed four more in service in 2009 on time and essentially on budget, and as Doug said, today, we placed two big ones in service. The expansion of our Elba Island Terminal and its associated Elba Express Pipeline also on time and budget.

Ruby continues to meet milestones towards the start-up of construction in late spring. And finally, we added a significant new project to our committed backlog we secured commercial arrangements with shippers to move forward with a major expansion out of the Marcellus.

Let me digress here to say that while this slide accurately summarizes our financial and growth achievements for 2009, it doesn’t do justice to our solid blocking and tackling operating performance.

We successfully served our customers 24/7. We settled a major rate case. Our multiyear pipeline integrity program is now nearly 90% complete. And we made major steps to do all this work more efficiently as evidenced by our financial results. So my hats off to our pipeline workforce in the office and field locations across the country.

On Slide #19, a throughput summary. For the first year in many our throughput decreased by 3%. This is generally a result of the economic slowdown. Remember, the throughput has only a minor impact on our financials, because of the demand charge nature of our business.

Throughput on EP&G decreased due to the economy in Arizona and southern California as well as the start-up of a competitor service lateral into the Phoenix area.

Also, our pipes are impacted both by lower industrial demand, particularly, in the southeast, and a mild summer in the northeast on TGP. Increasing power gen demand in the southeast including some displacement of coal loads somewhat offset these declines. As did supply related throughput, especially in the Rockies where we capitalized on our various recent expansions.

Slides #20 and #21 review our Elba and Elba Express projects. Both projects enter service today and are now generating revenue. At the terminal the expansion of the vaporization send-out capacity is in service and the new tank capacity will go in service this summer as planned.

These two projects were conceived more than five years ago, so we’re celebrating today a major achievement in the culmination of a huge effort by our employees, contractors and suppliers, customers, and regulators. And the going in-service on-time and on-budget.

These are very attractive projects for us. Together, they represent a capital investment of approximately $900 million. They will generate solid regulated like returns. They’re supported by very long-term contracts for 100% of the expansion capacity. The contracts are with Shell, clearly a high quality customer.

And as you know, our revenue stream is demand charge based, so that our profitability is not sensitive to how much or how often the capacity is used.

Both the Elba expansion and Elba Express are examples of excellent project execution. Elba Express on Slide #21 is a major new pipeline from the Elba Terminal through an interconnect with the Transfill [ph] Mainline which, of course, is a significant supplier to the Northeast and Mid-Atlantic.

This was a very large construction project, large diameter pipe nearly 200 miles long, much of its green field. Two major directional drills, one are half mile long through solid rock. A varied topography along the pipeline road, significant wetlands, rolling hills, rocky terrain at the northern end. And constructed through very wet, rainy, muddy conditions in the southeast during the late summer, late fall and winter. So the take-away here is that we executed very well, on time, on budget.

Slide #22 provides an update on our Ruby pipeline project. It remains on schedule and on budget. We received the final EIS in early January. The EIS provides more certainty about environmental mitigation, construction conditions and the pipeline route. All subject to FERC approval. We expect that approval this month with the BLM right-of-way grant expected in April.

We then plan to start construction in May/June, over 85% of the right-of-way on the privately owned land has already been acquired. As you know, we will be utilizing seven different construction spreads from four experienced contractors.

For each spread we’ve devoted a lot of time to the construction planning together with the contractors. At the peak of construction this summer, we’ll have approximately 4,300 people working on the job.

Also, over half the pipe has now been produced and continues to move west in unit trains. Pipe production is on schedule. So we’re executing. And 2010 is obviously an active year for the Ruby project.

Finally, on the Northeast, as you know, TGP has a $1 billion expansion program to move Appalachian and Marcellus gas to markets. The line 300 expansion will go in service in late 2011 for equitable and the northeast upgrade project that we just announced with Chesapeake and Stat Oil will go in service late 2013.

On the line 300 expansion, we just received an important permit from the New Jersey DEP. Also, FERC just issued its environmental assessment on the project and we expect FERC approval in April. Both these projects are fully subscribed under long-term contracts and provide solid regulated returns.

In addition to these two forward haul projects, we’ve secured firm transportation back haul business with Marcellus producers who will provide an additional $50 million of annual revenue by 2012. So we’re right in the middle of the activity in Marcellus, it’s providing us a significant and profitable growth.

So, in summary, on the pipes, we executed well in 2009, in 2010, we’re executing again and will be another busy year for us.

And with that I will turn it over to Brent.

Brent Smolik

Thanks, Jim, and good morning everyone. I will begin on Slide #25 this morning which lists some of our 2009 highlights all of which are relevant to our 2010 plan. Due to a strong fourth quarter we’re ending the year with a lot of positive momentum.

Our full year production volumes when we include our interest in Four Star averaged 763 million a day which was at the high end of our full-year production guidance.

Our domestic direct lifting costs which were already among the lowest in the industry got even lower. We shaved $0.19 off of our 2008 results coming in at about $0.70 per Mcfe. As I noted in our last call we got some benefit from deflation, but a lot of our progress is due to the efforts of our production operations teams.

For some time now we’ve talked about the work we’ve done to improve our portfolio. That’s shifting to more onshore, more unconventional, and more predictable opportunities. And those shifts are visible in our improved domestic reserve replacement cost of $1.57. And our unproved resources grew significantly as well. We had a 44% increase in risk resources that came mostly from the Haynesville and Eagle Ford shales.

We also believe that we’ve got good opportunities in the Hopper to grow the 5.1 Tcf of unproved resources going forward.

And finally, we advanced several of our key programs. As Doug noted, the Haynesville was a fairly minor contributor as we began 2009 and now generates more production than any other single asset currently close to 15% of our total net production.

During 2009, we wept from one rig to five rigs, with excellent drilling and completion performance throughout the year. That’s still early days for the Eagle Ford, but it’s moving quickly, thanks to our Haynesville experience. And I’ll give you an update on that program in a few minutes.

We’re pleased with the results of our Altamonte oil program. And we closed a very nice bolt-on acquisition in the field right at the end of the year and we have ramped up to three rigs in that development.

And we continue to advance international programs. We established first production from our project Camarupim in Brazil, and we drilled one additional well in our South Alamein block in Egypt, which has been temporarily abandoned while we evaluate the drilling and logging results.

Turning to Slide #26 we show you the full year production numbers as well as monthly production profile during 2009. The graph on the right also shows our drilling rig level at the end of each month. Production declined from 2008, which was consistent with our planned drop in capital spending.

The central division grew nicely, thanks to the Haynesville program and the Gulf Coast division declined as we chose to pull back investment in those assets. Remember, this shift in capital resulted in a significant excess cash flows that the E&P Company generated last year.

The chart on the right side of the page shows that our production bottomed in September after we cut activity down to six rigs. Currently, we’re back up to 14 rigs, with five of those in the Haynesville, three in the Altamonte, and one rig drilling Eagle Ford.

Our fourth quarter volumes averaged 742 million per day and as you can see in Klein, throughout the quarter. As a result of a strong start to the year with an entry rate of about 750 million per day we’re raising our 2010 guidance by about 20 million a day to 740 million per day to 780 million per day.

On Slide #27, we show per unit cash costs. We’ve made great progress here. Remember, that our volumes were down in 2009, so having a lower denominator makes this improvement in unit cash costs even more satisfying for us.

Domestic lifting costs went from $0.89 last year to $0.70. As I noted earlier a lot of that reduction was due to the efforts of our operations teams. Note the unit G&A went up year-over-year. We had some one-time benefits in 2008 and some one-time costs in 2009 that account for most of that difference. So, it’s a great story in total, for total cash costs in 2009.

For 2010, based on our improved production guidance and continued focus on costs, we’re updating our guidance slightly to $1.85 to $2.15 per Mcfe versus December guidance which had a midpoint of $2.05. The improved cash cost trends we established in 2009 are continuing, in 2010, and essentially the same levels for all the categories except for increases related to production taxes and international lifting costs.

Production taxes are up in the guidance due to higher gas price estimate in 2010 and reduction in the assumed production tax credits versus our 2009 actuals.

The lifting costs associated with our early production from the Camarupim project in Brazil will be elevated on a unit cost basis until we maximize the field production and add more production from the offset exploration projects and more efficiently utilize the FPSO.

Slide #28 shows a snapshot of our 2009 domestic F&D costs and the reserve replacement rate. Our $1.57 F&D that’s before price related revisions is a significant improvement over 2008 results reflecting the changes that we made in the portfolio over the last few years.

As Doug indicated, the new reserve booking rules had a minimal impact on us other than the negative price revisions associated with the new pricing methodology.

Overall, our PUD percentage of total reserves hasn’t changed much over the last three years. We were 29% in 2007, 25% in 2008 and now up to 31% in 2009.

And the 220% reserve replacement is even better than it appears on the surface since we spent over $600 million or about 42% less on domestic capital in 2009 than we did in 2008.

For the total company we reported a healthy 8% reserve growth and we look forward to post a good numbers again for 2010

On Slide #29 we show you the updated year end growth in our unproved resources since 2006. That’s a full doubling over that three-year period. And, again, the progress mirrors our shifts in the asset portfolio. Unconventional resources, particularly shales have driven that up dramatically.

But also the conventional low risk assets have also doubled. So we’ve done a lot to expand our sources of future proved reserves and production growth. When you had our pud reserves to our unproved resources we now have well over a 10-year drilling inventory.

Let’s turn to a quick update on our three major drilling programs. Slide #30 updates our Haynesville program. We now have 25 wells producing in the program and across the board results continue to be ahead of our models. In the Holly area, which constitutes about half of our acreage, the well results are still excellent. The average of 30-day IP rate in those wells is in excess of 17 million a day.

More recently, we’ve been dealing wells outside of Holly and the results continue to be very encouraging. The last five wells in this area have averaged IP 30s exceeding 10 million a day. So the story here is still positive overall.

Our well performance and our drilling efficiencies are still as good as anyone in industry and we’ll continue with our five rig drilling program throughout the year. So Haynesville will continue to be a growing part of our overall production.

On Slide #31 is an update of the Eagle Ford. We’re pleased with the drilling results of our second well and we were hoping to have a test results ready for this call, however, we’re still in the process of fracking the well. We plan to press release those results after we finish the completion and get a full production test.

We’ve continued to expand our lease position and we’re now up to 138,000 net acres. There s an incredible amount of industry activity taken place in the southwest part of the play and much of it surrounds two of our acreage blocks.

On the map, we show the lines designating the dry gas, gas condensate and oil areas. These lines are still moving as we continue to learn more about the trends, but generally speaking, the northwestern part of the play may even be more liquids rich than us and others have previously thought.

In order to accelerate our learning in the play we’ve decided to add the second rig in the March/April timeframe. That will also give us the option to reallocate capital toward the Eagle Ford and keep both rigs running in the second half of the year.

We’re learning quickly in the Eagle Ford and we feel that we benefit greatly in the Eagle Ford play from our Haynesville experience that exists in our organization.

I’ll wrap up with an update on the Altamonte program. As you know, we made a nice acquisition right before the year end of last year. This is primarily an oil property, so the $9 per barrel equivalent acquisition costs is very attractive.

The project really defines a bolt-on acquisition for us. The map shows just how well the Flying J properties line up with ours in terms of acreage. Some of the properties we bought were even non-operated interests in wells that we currently operate. We took over operations as soon as we closed and the integration has gone very smoothly since then.

Following the addition of these properties and a significant drilling inventory that comes with them we’ve raised our activity to three rigs in this field.

That concludes my update this morning. We’ve started the year strong. All of our major programs have a good deal of momentum, which allows us to raise our full year production guidance and lower our cash costs guidance.

Now I’ll turn the call back over to Doug.

Doug Foshee

Thank you, Brent. When we met with many of you back in December we felt good about our plan for 2010 and our longer-term objectives through 2012. We also felt confident that we’d be able to show you meaningful progress against those plans early in the year and we’ve done that.

We finished 2009 with a strong quarter, giving us momentum going into 2010. The Elba Terminal expansion and Elba Express Pipeline are in-service on time and on budget. Ruby is moving along nicely with financing commitments now in hand at favorable rates. FERC approval is expected this month and construction to begin soon.

E&P is off to a great start, strong enough to give us confidence in increasing production guidance and decrease in unit cash costs guidance.

And our overall financing plan is falling into place nicely with the Ruby commitments, the MLP equity sale in January and the recent announcement of the sale in Mexico, which we expect to close soon.

We indicated in December that we had great visibility into the elements of our financing plan and we did. So we’re on track for each of the goals we set out in December for 2010 and for 2010-2012 longer term objectives, including a goal to generate an average 15% annual growth in earnings per share. So, we’re off to a great start. You should expect to see more positive news as we continue to execute on the plan.

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

Question-and-Answer Session

Operator

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

Carl Kirst – BMO Capital

Hey, good morning, everybody and certainly, nice work. Just a quick question if I could on the asset sales, I guess maybe to the blended in with the funding for this year. But with the announcement from last week we now have kind of the minimum of what was the goal that was thrown out there. Of course, we still have about $3 billion of NOLs and if past is prologue, as you have said, the last two years we’ve had some nice rationalization on the E&P side. Is there any reason to think that we shouldn’t or perhaps we won’t see more asset sales if the market allows?

Doug Foshee

Yes, Carl this is Doug. First of all, we’re really pleased to be sitting here on March 1st having achieved the goal that we set out with the sale of Mexico. Having said that, we do always look at each of the pieces of the portfolio for the ongoing strategic fit. And if we see an opportunity that we think at the margin creates value we’ll take advantage of it. I would say, directionally, we’re in a position now by virtue of our position in the Haynesville and the Eagle Ford, in particular, where we have really good places to spend incremental capital dollars in core areas and that sort of over time, changes the calculus on what else might be core.

Carl Kirst – BMO Capital

Okay. And maybe a second question, actually, just kind of a drill-down question on the E&P unit cash cost side. Brent, I understand that essentially as (inaudible) continued to sort of take some time to kind of ramp up, I think back in the third quarter there was perhaps $0.19 or $0.20 of embedded costs, if you will, in the LOE. Is that the pressure you were alluding to earlier? Is that kind of the number that we would expect to see essentially in the unit numbers until that kind of comes fully on line?

Brent Smolik

Yeah, that s the right ballpark, Carl. Something around the high teens as we ramp up production and until we get additional production coming in from the offset exploration wells to be able to fully load the FPSO. So you got about the right ballpark and maybe to expand on that just a little for the other categories, we think of domestic LOEs kind of flattish to maybe up $4 million or 5 million. And G&A is probably going to be down by about that same amount, $4.5 million to 5 million year-over-year. So, it’s really international LOE and then whatever happens to production taxes, which will be, of course, a function of price in the U.S. that gets to us that $2 midpoint of the full year guidance.

Carl Kirst – BMO Capital

Great, thanks, guys.

Doug Foshee

Thanks, Carl.

Operator

Your next question is from the line of Faisal Khan with Citigroup.

Faisal Khan – Citigroup

Morning. I just wonder if you could on the pipeline side, can you talk about a little bit about the demand side of the equation and how your volumes were off because of the economics situation in some of those areas. On the supply side are you talking about what you’re seeing there, are you still seeing a supply push or are you seeing any slow down in some of the areas or are there is any sort of response from the rig activity?

Jim Yardley

So demand is taking its course. First of all, on demand side, there’s significant increase on the industrials. We see that clearly in the southeast, in particular, relative to a year ago. On the supply side, I think we see supply push coming out of the Haynesville clearly. It’s actually impacted in a slight negative way, our volumes on Tennessee in the supply area, because we have moved some volumes from west to east there that’s being displaced now by some of the new bigger pipes.

So what happens is that some of that goes northeast, some of it comes into the southeast, which is good for southern natural. In the northeast, we have big new volumes coming on in the Marcellus. We have a year ago at this time we probably weren’t taking much at all into TGP in the Marcellus, we’re up to over 300 a day. That’s provided us with obviously, good opportunities revenue-wise. It’s displaced some of the volumes coming in from Canada.

The Canada fall off we see very clearly. A lot of that’s happening coming into the northeast, some into the Midwest, less so into the west right now. Rex volumes are increasing. So the dynamics on TGP are changing, but for the most part, to the good [ph] there’s clearly much more opportunity than risk there.

Faisal Khan – Citigroup

Okay. And then just on the CapEx side for the pipeline, how much of the growth CapEx this year for the pipeline is going to actually will be funded at the MLP level?

Doug Foshee

How much of the growth capital will be funded at the MLP level?

Brent Smolik

Again, effectively, the capital associated with Wyoming interstate and the capital associated with Colorado interstate be funded at MLP level, Faisal. So that’s probably on the order of magnitude of $175 million to $200 million, I would tell.

Faisal Khan – Citigroup

Okay, got you. And then last question, on the E&P side, I think you explained it. The LOE lease operating costs going from $0.77 to $0.85 that was because of Brazil I think?

Brent Smolik

Yes, Faisal, If we’re talking about from 2009 actual to 2010 guidance, the two things that are moving it up are international, because of the start-up of the Camarupim project, and then because we’ve got a higher price deck assumed in our plan, we’ve got higher production taxes in the production tax side. On a unit basis, G&A and LOE domestically, should be very flat.

Faisal Khan – Citigroup

Okay, got you. All right, thanks, guys, appreciate the time.

Operator

Your next question is from the line of Lasan Johong with RBC Capital

Lasan Johong – RBC Capital

Thank you. What was your drilling only F&D cost and reserve replacement ratio in the domestic market?

Brent Smolik

So how are you defining drilling only in that case? There’s so many different definitions flowing around out there.

Lasan Johong – RBC Capital

Basically, excluding acquisitions and write-downs.

Brent Smolik

That’s pretty close to the $1.57.

Lasan Johong – RBC Capital

I’m sorry?

Brent Smolik

That’s pretty close to the $1.57. The only acquisition that we had was about $1.50 and it was the Altamonte at the end of the year.

Lasan Johong – RBC Capital

Okay, and your reserve replacement ratio?

Brent Smolik

Was over 200%.

Lasan Johong – RBC Capital

No, excluding the write-down in the acquisition.

Brent Smolik

Yes. More than doubled.

Lasan Johong – RBC Capital

So it’s basically the same. All right. What was your exit rate in 2009 for E&P?

J.R. Sult

Exit rate?

Brent Smolik

We were right at 750 million a day. You can see that on one of the charts that we showed the bar graphs monthly, but it’s right at 750 million a day.

Lasan Johong – RBC Capital

Excellent. Can I assume that the Haynesville decline rates are flatter than in some of the other shale plays? Is that a good assumption?

Brent Smolik

Yes, if you’re talking about late lines, I don’t think we know yet is in industry, but our belief is going to be fairly shallow declines, but early days, the initial decline rates are quite high. So we’re still seeing 70% to 85% initial declines on the wells that we have on line.

Lasan Johong – RBC Capital

Aren’t you choking down on your initial production because of the compaction problem in the fractures?

Brent Smolik

No, we’re not in that camp. We’re producing the wells that whatever rates we can deliver out of the fields. If we’re curtailing production every it’s short-term around takeaway capacity, if we bring a brand new 20 million a day well on, you can swap out part of the system. So as we bring them on, we may curtail them a little bit, but otherwise, we’re producing the wells. We’re not curtailing them.

Lasan Johong – RBC Capital

That’s great. Doug, strategic question. You chose to cut the dividend down to the bare bones penny a quarter. I think that was a very good strategic decision to try and fund growth CapEx. But when can we expect El Paso to return to growth mode on the dividend?

Doug Foshee

Tough to predict, but if you go back to our December Analyst Day, we showed a chart that took a look at free cash flow. And I think what you see when you look at that chart is 2010, obviously the heaviest CapEx spending year in our history, I think. $4 billion worth of capital roughly spent this year. That free cash flow number goes to about $500 million negative in 2011 and then swings to $500 million positive in 2012. So all other things being equal. We begin to make decisions about what to do with excess cash flow as we moved through 2011 and into 2012.

Lasan Johong – RBC Capital

That’s not saying that you don t think there’s any more growth beyond 2011, right?

Doug Foshee

No. Well, in fact, as the biggest proof point to that is the Marcellus project that we’ve just announced, which is $400 million most of that capital gets spent in 2013.

Lasan Johong – RBC Capital

Okay. And last question –

Brent Smolik

We’re trying to limit everybody to two questions because we’ve got a lot.

Lasan Johong – RBC Capital

I am sorry, I’ll follow up.

Brent Smolik

Thank you.

Doug Foshee

Thanks, Lasan.

Operator

Your next question is from the line of Craig Shere with Tuohy Brothers Investment Research.

Craig Shere – Tuohy Brothers Investment Research

Hi, good quarter. Congratulations on all the funding getting that trued up. Quick question. On the MLP, are you seeing that just over time as a funding vehicle as needed? Obviously you want to grow the distributions for the GP splits, but do you see it more fundamentally as an arbitrage and the valuation of the assets? And how would you look at the LNG upgrade and the overall terminal there in terms of its applicability to the MLP?

Doug Foshee

I think, to answer the second part of your question first, with regard to the Elba expansion and the Elba pipeline, I think if you were trying to craft sort of the prototypical MLP asset, thinking about it as a very stable revenue with long tenor to the contractual commitments and very low ongoing maintenance capital, you probably pick something exactly like the Elba Terminal and the Elba Pipeline. So, yes, we think those are very appropriate assets to exist in the MLP.

I think our strategy, with regard to the MLP, hasn’t really changed in that we’re sitting here with significant portfolio of what are some of the best possible MLP assets in a C-corp [ph] that has $3 billion NOL and is the owner of the GP and the vast majority of units of an MLP that trades at one of the two or three lowest yields in the marketplace. So we would very much like to grow that in a way that benefits both the unitholders and the EP shareholders.

We continue to look for ways to accelerate that growth. And frankly, I think the growth of our MLP is only limited by the ability of the market to absorb our MLP equity.

Craig Shere – Tuohy Brothers Investment Research

Your points are well taken. Is it really something that unless you can get hard cash to the C-corp that equity in exchange for assets at the MLP is really not what you’re looking for?

Doug Foshee

I think we have grown the MLP both by dropping assets down and upstreaming cash to El Paso. We’ve also grown the MLP by dropping assets down and upstreaming cash and units to El Paso. So I think our overall goal at the end of the day is to, on the EPB side to maintain really outstanding yields and growth to our investors and on the EP side to illuminate the value of our pipeline franchise.

Craig Shere – Tuohy Brothers Investment Research

Okay, thank you very much.

Operator

Your next question is from the line of Monroe Helm with Barrow Hanley.

Monroe Helm – Barrow Hanley

Hey, guys. I think you mentioned earlier in the presentation that your cash flow with the E&P Company was 600 million in excess of the cash flow last year. Was that correct?

Jim Yardley

That’s right.

Monroe Helm – Barrow Hanley

And can you give us some guidance on how you see that relationship for 2010?

Doug Foshee

I think what we said was that cash flow after CapEx was $600 million for 2009. So, in essence, the E&P Company at that level was a cash generator for the company.

Monroe Helm – Barrow Hanley

Right.

Doug Foshee

So this year, CapEx forecast for the E&P companies by about a billion dollars, so lot closer to the CapEx plan. So looking at our hedge position at J.R. outlined for you, largely, hedged at about $6, we’ll get to EBITDA levels that are pretty close to our CapEx for the full year.

Monroe Helm – Barrow Hanley

Okay. As we go into 2011 and the spending goes down on the pipeline, should we see that, you still spend your cash flow at the E&P Company or could we expect you to take cash flow on the pipelines and put into it E&P?

Doug Foshee

I think 2011 overall, as we haven’t planned now is much closer to break even. We showed in our Analyst Day at overall, about $500 million in negative free cash for '11. Of course, that’s average for the year, and that changes as you go through the year because we’ve got some big projects coming on in '11 that we get the full year benefit of in 2012.

So, I don t know that I would see as we sit here now big free cash generated out of the pipes going into being available to be used in E&P but certainly as you move into the second half of '11 and 2012, that’s when you begin to see the full benefit of the pipeline backlog and pretty significant chunks of free cash flow coming out of business.

Monroe Helm – Barrow Hanley

Okay, thanks for your answers.

Doug Foshee

Thanks, Monroe.

Operator

Next question is from the line of Jonathan Lefebvre with Wells Fargo.

Jonathan Lefebvre – Wells Fargo

Good morning guys, it’s Jonathan Lefebvre from Wells Fargo.

Doug Foshee

Hi, Jonathan.

Jonathan Lefebvre – Wells Fargo

Nice quarter. In terms of shifting back to the E&P, and I appreciate that you are going to press release this second Eagle Ford well, should we expect that you might have this done for this first quarter or should we be thinking about it being potentially a second quarter event?

Doug Foshee

The timing of the announcement, Jonathan?

Jonathan Lefebvre – Wells Fargo

That’s correct.

Doug Foshee

We’re just finishing up the fracking, so we should be within a few weeks be able to get full production test cleaned up post-frac to know we’ve got there. But the frac has gone very well, the drilling went very well, and we were very pleased with what we saw while drilling. So we’re optimistic where we stand today and within a few weeks we will know.

Jonathan Lefebvre – Wells Fargo

Great. And then in terms of the cost per well, is there anything there that you’re seeing that’s encouraging on this first well? It seems like some of the industries talking about some well costs coming down. Is it still kind of in the sites project phase?

Brent Smolik

That’s only our second well, Jonathan, so we’re clearly still piloting in our learning. But the second well, when we moved further north and west was significantly shallower, and so because we had less total measured depth to drill by several thousand feet, we were much close to lower drilling costs in the first well.

So we think it will wind up being less than half the cost will be drilling and the other half or greater than half of the costs will be in the completion up in that area. We’re still thinking about kind of $5.5 to $8 million well cost largely dependent on well depth or total measure depth and total completion costs. So, however many stages we settle on and where the service cost trends. So we’re still thinking about them in that $5.5 million to $8 million range.

Jonathan Lefebvre – Wells Fargo

Okay. And then just one follow-up if I may. On the spending in the Eagle Ford, I think you said back at the Analyst Day 62 million for 10 wells. Sounds like you’re thinking about adding a second rig. How many wells and where should we think about the CapEx for this year and can you give us a little color on that?

Brent Smolik

Yes, so, the pick up that second rig it does a few things for us. It gives us an option to be able to keep two rigs run in if we choose to. But we’re not currently contemplating additional capital. We’ll allocate that from elsewhere and likely places it would come would be the traditional vertical, Cotton Valleys, Ark-La-Tex or some of the traditional south Texas gas program and we would shift it over, if it’s just a matter of keeping those two rigs running for the rest of the years we’ll manage it within our total.

And again, it will be kind of a game plan call based on the results we get out of our wells and what we see coming from the trend. But we thought there was enough benefit in accelerating our learning for our planning for the rest of the year for the budgeting for next year and even as we think about midstream opportunities in our business.

Jonathan Lefebvre – Wells Fargo

Great. And for 10 wells is still the number or is that number going up as well?

Brent Smolik

10 wells what we currently have in the capital plan. If we run two rigs for the rest of the year that number would go up and that’s where we’d have to shift capital from elsewhere.

Jonathan Lefebvre – Wells Fargo

Got you. Thanks, guys.

Brent Smolik

Think about accelerating our ten wells in the front half of the year.

Jonathan Lefebvre – Wells Fargo

Understood, okay.

Operator

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

Becca Followill – Tudor Pickering and Holt

Hi, guys. Your production guidance for 2010, what is driving the Delta? And can you help us with how the timing of Brazil factors into it? Is there still uncertainty as to when those wells come on line?

Doug Foshee

As to which ones come on line, Becca?

Becca Followill – Tudor Pickering and Holt

The development.

Doug Foshee

I’m almost gotten to the point, Becca, where I’m thinking of it is just plug like 30 million for international a day annual average. We’ve got enough up and down as they repair the subsea leaks in the program and then we got new wells coming on line, so it s kind of in the guidance we’re thinking of it is kind of 30 million a day annual average impact coming from Brazil.

Becca Followill – Tudor Pickering and Holt

But does it ramp?

Doug Foshee

It will ramp but it will be up and down. Again as they take wells off line to do the subsea repairs and put them back on, especially, in the first half of the year. And it will be kind of more steady state ramp in the second half of the year. So if you’re talking about ramping by quarter, yes. But we should have all three wells on sometime in this first half of the year producing. So what will drive us to the high end of the range in the new guidance we’ve given you would be domestic growth and that would largely be Haynesville and then Eagle Ford if we keep the two rigs running, Altamonte programs got a little bit of growth in it over the year.

Becca Followill – Tudor Pickering and Holt

Thank you. And then you guys have previously mentioned that you expected production to trough in the first quarter, if I remember correctly. And it doesn’t look like that’s the case anymore just given the chart that you showed. Is it fair to -

Brent Smolik

I think I missed it, Becca. Even as we stood out there in December, during the Analyst Day in the discussions we had with everyone that day we didn’t anticipate doing as well as we did for the month of December. We had about four wells or five wells in a row that were all well north of 20 million a day for their initial rates and when we stacked all those up we went out of the year better than we even anticipated in December 9th or 10th or (inaudible) that was. So I think we kind of bottom and you could see them in the chart there about September.

Becca Followill – Tudor Pickering and Holt

Great, thank you, guys.

Doug Foshee

Thanks, Becca.

Operator

Your next question is from the line of Shen Lou [ph] with JP Morgan.

Shen Lou – JP Morgan

Good morning. Follow up the previous question on dropping that into the MLP. What’s your thoughts on doing seminary restructuring as Williams essentially dropping over the pipeline and taking back units?

Brent Smolik

Sure. Well, first of all, we have been looking for almost since the IPO or the MLP, for ways to accelerate the growth of the MLP. I’d point out a couple things. One is, remember, we are not motivated in terms of anything we might do by fixing a yield on an MLP because we already have an MLP that trades at one of the lowest yields in the marketplace.

Secondly, remember, we have very, very high growth pipeline assets, meaning, we’re spending lots of development capital in our pipeline business today, so it would actually be, in our view, inappropriate to contemplate dropping down all of our pipeline assets into an MLP, given the spending profile we have.

And third, remember that we have this $3 billion NOL, which is unique among MLP sponsors that allows us to continue to drop down in a measured pace assets in a very tax efficient way and create a really steady stream of growth in distributions and value to both the MLP unitholders and EPC itself. So, we continue to look at things. We’ve obviously done our own internal analysis of the Williams transaction and how Williams has traded post announcement we’ll continue to follow that.

Shen Lou – JP Morgan

Thank you.

Operator

Your final question comes from the line of Ted Durbin with Goldman Sachs.

Ted Durbin – Goldman Sachs

Hi. Just as you move closer to building Ruby, have you made any progress in terms of contracting the remaining capacity?

Jim Yardley

I think here’s what I would say about that. I think that we have good prospects on the market side as well as in the Rockies, but at the same time, given where the economy is today and the northwest it’s unlikely that we will get subscribers to sign up tomorrow. Likewise, I would say the same thing about Rockies producers.

The positive that has happened though, and Doug alluded to this in his opening remarks is that the basis is clearly trading very well in our favor. The west is being perceived more and more as somewhat isolated from all that’s going on with respect to the eastern shales and the basis is trading up very nicely on the west coast at Milan and otherwise. So, we expect when Ruby starts up for nice volumes to be flowing west.

Ted Durbin – Goldman Sachs

Thanks. And then just quickly on hedging, looks like you didn’t add any natural gas hedges for 2011. How are you thinking about kind of the appropriate level to hedge at here? Sounds like with production increasing you are adding rigs, just thing in and sort of cash flow needs. How are you thinking about the hedging profile going forward?

Jim Yardley

This year or next?

Ted Durbin – Goldman Sachs

For 2011, yes.

Jim Yardley

Right now, we’re at 60% with a pretty good floor at the $6 range that we’re looking at. So if we get another window to do more we might contemplate a little more but today that’s probably not even an option.

Ted Durbin – Goldman Sachs

Okay, great, thanks a lot.

Doug Foshee

Thanks, you all.

Bruce Connery

That concludes our call. We appreciate your interest. If you have other questions, please follow up. Thank you.

Operator

This concludes today’s conference call. You may now disconnect.

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Source: El Paso Corporation Q4 2009 Earnings Call Transcript

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