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Executives

Bruce Connery – Vice President, Investor and Media Relations

Doug Foshee – Chairman and CEO

J.R. Sult – CFO

Jim Yardley – Chairman, Pipeline Group

Brent Smolik – President, E&P Company

Analysts

Jonathan Lefebvre – Wells Fargo

Xin Liu – JPMorgan

Carl Kirst – BMO

Craig Shere – Tuohy Brother Investors

Kevin Smith – Raymond James

Ella Bjornik – RBC Capital Markets

Faisel Khan – Citigroup

El Paso Corporation (EP) Q2 2010 Earnings Conference Call August 4, 2010 10:00 AM ET

Operator

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

I will now turn the conference over to Mr. Bruce Connery, Vice President of Investor and Media Relations.

Thank you. Mr. Connery, you may begin your conference.

Bruce Connery

Good morning. Thank you for joining our call. In just a moment, I will turn the call over to Doug Foshee, Chairman and Chief Executive Officer of El Paso. You’ll hear from three other speakers whose on our call this morning, J.R. Sult, CFO; Jim Yardley, Chairman of our Pipeline Group; and Brent Smolik, President of our E&P Company.

As you know, this morning, we issued our second quarter earnings press release and filed it with the SEC. During this morning’s call, we will be referring to slides that are available in Investor section of our website elpaso.com.

Also, on our website, you will find a financial and operational reporting package that includes information that we believe will be helpful as well as GAAP financial statements and non-GAAP reconciliations. I hope you’ve downloaded this package, so that you have all relevant financial information available to you.

During this conference call, we will make a number of forward-looking statements and projections. We’ve 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, there are a variety of factors that could cause actual results to differ materially from the statements and projections expressed during this call. You will find those factors listed under the cautionary statement regarding forward-looking statements on slide two of this morning’s presentation as well as in some of our SEC filings. Please take the time to review them.

El Paso does not assume any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Again, thank you for joining our call. And, I’ll now turn the call over to Doug.

Doug Foshee

Thanks Bruce, and good morning. We’re excited to follow-up a successful first quarter with another very good performance in Q2. We’ve talked a lot about execution since our December 10th Analyst Meeting. And, so far in 2010, we’ve delivered on our execution promises, both operationally and financially.

In the pipes, the projects put in service so far this year, the Elba Expansion and the Elba Express Pipeline were both on time and on budget. And at $900 million in total capital, this is a large part of the backlog that you can now check off as successfully completed.

In a few minutes, Jim will show you that we have more projects to go into service this year, and we think we have a good chance of delivering those projects on time and under budget.

The Ruby Pipeline, our largest single project in our backlog, just reached another milestone, and is now under construction. As important as this step is though, we now start the critical phase of review, the construction of 675 miles of pipe across the Western US. This is a large complex project, one that will employ 5,000 people at its peak, roughly the same number of folks that work at El Paso in total today. So there is no time to take an early victory lap.

We’ll focus now on executing this project safely, on-time, and on budget, and we have the best team of folks on the job; experienced members of team El Paso as well as a cadre of highly skilled contractors.

On Tennessee Gas Pipeline, last week, we announced yet another expansion, to supporting our customers in the Marcellus unconventional shale play. This isn’t a big one, but cumulatively we now have $1.1 billion in growth capital that will leverage our position right in the heart of this important new resource play.

In E&P, we had another very solid quarter. Production has now risen for the last three quarters and the Haynesville continues to lead the way. Unit cash cost were below our first quarter number. And, you’ll recall that, we lowered our cash cost guidance last quarter. We’ve continued to grow our position in the Eagle Ford, adding more inventory, particularly in the liquids rich portion of the play.

Our investment strategy in E&P hasn’t changed at all. E&P is leaving within its means, staying focused on continuous improvements in operations, leading to improvements in unit costs, generating good returns, and continuing to grow our inventory of repeatable low-cost, low-risk growth opportunities for the long term.

On the Midstream front, we continue to evaluate potential projects, particularly in the Eagle Ford and Marcellus. None have reached maturity yet, but we continue to look for projects that we provide synergies with our existing business. Eight projects wouldn’t likely come to service before 2012 and wouldn’t cause us to back away from our free cash target in 2012.

On the finance front, our financing needs for 2010 have already been put to bed. We also already have about $200 million of 2011 capital spoken for and will continue to look to grow our MLP in the second half.

Finally, we raised our full-year 2010 guidance today for adjusted earnings per share to a range of $0.90 to $1 a share, up from our original guidance for the year of $0.75 to $0.95.

With that, I’ll turn the call over to J.R., and comeback at the end, to wrap things up.

J.R. Sult

Thanks Doug, and good morning. As Doug just highlighted, we did have another good quarter and continued success executing on our financing plan. We think our results provide further crew for the benefits of our focus on executive.

So let’s chip right in and talk about the quarter. Adjusted diluted earnings per share was $0.22, which not surprisingly is down slightly from a year-ago. Growth in pipeline earnings and higher E&P production volumes were more than offset by lower natural gas prices including our hedges.

A significant portion of our 2009 gas production was hedged with a floor of $9. Now, our actual GAAP reported earnings for the quarter was $0.21 per diluted share. Items impacting the second quarter include the impact of our E&P hedges, a gain on sale of our Mexican pipeline assets, and the impact of market-to-market on our legacy power book.

In the Pipeline Group, adjusted EBIT increased 11% for the quarter, driven by largely by the impact of expansion projects. Higher reservation revenues from the Elba and expansion in the Elba Express Pipeline that went into service earlier this year, as well as the expansion project that went into service late last year, led our growth.

In addition, pipeline results also benefited from an increase in AFUDC or allowance used for funds during construction on the capital employed and our pipeline expansion projects that are not yet in service. The AFUDC is reflecting in both EBIT as well as a reduction of interest expense in our result.

In E&P, adjusted EBIT declined from a year-ago, primarily due to lower natural gas prices including our hedges.

Interest expense was higher for the quarter, mostly due to debt associated with the Ruby Pipeline Project, as well as a one-time adjustment to AFUDC to reflect the lower interest rates we achieved on the Ruby Project financing and the final capital structure expected for the project.

Let’s shift gears and talk about operating cash flow and capital investment. Our capital plan remained on track. This roughly $4 billion capital budget and $1.6 billion spend to date, activity and spending levels will be considerably higher in the second half, driven by construction of the Ruby Pipeline.

On the E&P side, despite continuing to fight the headwinds of service cost increases, we remained focused on lending within our means. If you’ll recall, we front loaded a portion of our 2010 capital program to get out ahead of some of the expected cost increases. Brent, will give you an update on what we are doing to proactively manage AFE cost increases.

Our liquidity remains very strong. There’s $2.7 billion available at the end of the July. Now, this does not include the $1.5 billion Ruby Project financing that will be used to fund the construction of the pipeline.

Finally, cash flow from operations for the quarter was below last year’s level, again due largely to lower commodity prices including our hedges.

Successfully managing commodity price risk is an important element when we talk about financial execution. We’ve got a disciplined approach to price risk management, it’s the responsibility of our Price Risk Management Committee. Brent, Mark, Dave Whitehead the Head of our Strategy, and me sit on that committee. This Group meets weekly to discuss market conditions and oversee the execution of our hedging strategy.

So let’s take a look at our 2010 and 2011 hedge positions on slide seven. By the way as a side note, our 2010 hedge positions contributed about a $100 million to cash flows in the second quarter alone.

As you can see from the slide, about 75% of our domestic natural gas production is hedged for the remainder of 2010 at just over $6. We added modestly to our fourth quarter position since our last call, when market conditions permitted. While some of our peers have 2010 hedge positions comparable to ours, we think our 2011 positions lead the pack.

We’ve got about 65% of our domestic natural gas production hedged in 2011 with a $6 floor. We think this syncs up well with our pipeline expansion backlog, the majority of which is expected to be placed in service by late 2011.

Now, going forward, you should expect us to continue to prudently manage commodity price risk, to protect our balance sheet and cash flows.

Let me wrap up my remarks today with just a couple of additional comments on our financing plan. In our security, $2.5 billion of funding came like a really big challenge to many when we announced our 2010 capital program back in December. But we had a good planning and then we have confidence in our ability to execute against that plan.

As Doug mentioned, we reached our $2.5 billion target during the quarter. As a result, our focus immediately shifted to 2011 and the far more modest level of funding needed to meet our 2011 capital needs. In fact, the $2.7 billion of financings completed this year, we’ve got a substantial start on 2011. In addition, we may meet our 2011 needs, our focus will remain on advancing the longer-term improvement in our balance sheet.

As for the MLP, well, I think as Doug indicated, we’ll continue to grow the MLP. Recently, I met with an investor who asked me a similar, what about the MLP question this way. He said, “J.R., you’ve completed two drop-downs to the MLP this year. Are you done? Or is the peddle still to the metal?” I’ll tell you the same thing I told him. “We have not let our foot off the accelerator.” We will continue to execute our drop-down strategy, because it’s value enhancing for both El Paso and El Paso Pipeline Partners. Bottom-line, you should expect us to stay the course with EPB.

That’s my update for you this morning. We’re very pleased with the financial performance for the company so far this year, and are happy to have completed our 2010 financing plan early.

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

Jim Yardley

Thanks J.R. The pipes had another excellent quarter. Adjusted EBIT was up 11% from second quarter 2009, after backing out the gain from the sale of our Mexican business. As J.R. said, essentially, all of this increase resulted from our expansion programs.

We continued to execute well on our growth projects. We started construction on four additional projects this quarter as planned. And this is an addition to three others that are well underway, South System Expansion, FGT's Phase VIII, and the Gulf LNG Terminal. And we were successful in adding another project to our growth backlog, our third expansion out of Marcellus. As Doug said, we’ve now committed to over $1 billion of Marcellus expansions.

Slide 11, shows a snapshot of our throughput, and it reflects the overall economy, weather, and changes in supply sources. Going around the horn, throughput is up a little on TGP and the Northeast, it’s up a lot in the Southeast due to a cold winter and hot summer. It’s down in the Southwest, partially due to the economy. And then, on our Rockies space, due to lower production, which has now started to recover over the last few months.

Overall, these throughput changes, both up and down, had only a smaller impact on our revenues, because of the reservation charge nature of our business. Over 80% of our revenue comes from monthly reservation charges. But we are watching closely a couple of throughput items.

First, on TGP, there’s been a significant change in the sourcing of supplies, proceeds from Marcellus and Rex in Ohio, together are up over 800 a day year-to-year. These receipts have displaced imports from Canada at Niagara and long-haul volumes from the Gulf Coast. So capacity utilization has declined through the middle part of TDP system. And we’re watching the impact of this on short-term volumes and rates, fuel usage, and our O&M costs.

Second, our EPNG, the decline in throughput is somewhat of function of the economy in the Southwest, but it’s also a result of the increased imports into California, both from LNG arriving at Costa Azul and indirectly imports from Canada. It’s not clear one of these trends on EPNG are temporary or more long lived. But, in combination, that resulted in lower freight rates available on short-term capacity sales on EPNG. And we filed a rate case on EPNG this fall for new rates to be effective next spread.

On Ruby, we’ve received FERCs and BLMs construction underway. Obviously, this is a major milestone. It results from a 2.5 year process involving a comprehensive review by BLM, FERC, and various Federal, state, and local agencies. In fact, this is one of the most extensive records we’ve seen in the new pipeline application. Hundreds of thousands of pages of comments were filed by various groups and they’re been addressed one by one. The agencies have carefully balanced stakeholder issues with a need for this important infrastructure project.

Now, we’re focused on delivering Ruby on-time and on budget for the benefit of markets on the West Coast and Rockies producers. Relative to our original planning a two years ago, construction is starting two months later than planned. We’ve adjusted by adding an additional construction spread in one of the more not necessaries to complete that section before winter. So there’ll now be eight spreads working on Ruby simultaneously. And, as Doug mentioned, 5,000 workers.

We’re also likely to reconfigure our spread deploying it in the western section of the Erath, also to make up some time. We’re focused on delivering Ruby for in-service next spread.

On side 13, Marcellus – Marcellus continues to be a very exciting new area for us. Over 700 a day of Marcellus gas is not flowing into TGP, it’s flowing under a variety of transportation arrangements, including firm backhauls that ramp-up overtime and they’ll bring in about $60 million of annual revenue by 2012, all requiring very little new capital.

And we now have in the backlog three, four, haul expansions amounting to over $1 billion of investment. These three projects are essentially all fully subscribed under long-term contracts. Construction’s underway on the first of these, the line 300 Expansion and we’re starting into the regulatory approval process on the other two.

Our success in the Marcellus is obviously the result of having existing infrastructure in the area, but the magnitude of this opportunity is a pleasant surprise for us.

Turning to slide 14, we’re focused across the country on executing on our large backlog. You’re aware that we placed them service, our Elba projects on-time and on budget. In fact, the Elba Tank was placed on service July 1, a month ahead of schedule.

Three more projects still in service later this year. They’re all well along now in construction at their own schedule. I’ll be very surprised that if they’re not completed at low budget.

The backlog projects as a group have been significantly de-risked, while some involve Greenfield construction, some are straight-forward pipeline and looping and compression upgrades of existing systems.

The pipe has been purchased for all these projects. All the construction contracts are in place. They’re either fixed price arrangements or unit priced in which the contractor varies the productivity risk or has significant productivity incentives.

And, finally, in terms of de-risking, in total, the backlog is approximately 90% subscribed under long-term contracts with high-quality customers.

So, in summary, the pipes had another strong quarter, and we have our heads down and are executing on our growth projects.

And now, I’ll turn it over to Brent.

Brent Smolik

Thanks Jim. Good morning, everyone. We had another solid quarter of financial and operating results in the E&P Company. Our production increased to 788 million a day, while we kept our cash costs low at a $1.77 per Mcf equivalent.

And, as I noted in our last call, we tend to run a very focused-driven program in the second half of the year, and we’re devoting capital to the programs and off with the highest returns and we’re leaving within our 2010 capital plan.

So in the second half of the year, we’ll operate eight rigs in our core programs. There will be four in the Haynesville, two in the Eagle Ford, both of those would be being in the liquids rich area and two in the Altamont.

I’m sure most of you are aware that the pressure pumping and the stimulation services have been tight and the costs have been going up. Last year, we had really good coordination with our frac crews and led the onsite, ready to begin the frac work soon after we finished drilling the well, and that hasn’t been the case lately. And, like others in the industry, we’ve developed a backlog of Haynesville wells that are been drilled and are awaiting on completion.

In response, we’ve recently entered long-term agreements for stimulation services in all three core programs, which will help us improve our cycle time and it’ll give us costs certainty on our future drilling programs.

Internationally, we’ve drilled successful wells in Brazil and Egypt in the quarter. In Brazil, we drilled an exploration discovery with Petrobras in the ES-5 block, that’s the block where our Camarupim project is located. And we [inaudible] and we’re working with Petrobras to design a production test. Given success would ultimately tieback to the floating production facility that’s on the Camarupim production and El Paso will have a 35% working interest in the project.

In Egypt, we drilled a well in the South Alamein block with SEPSA that also had very encouraging shows. We’re not currently drilling in that block, we’ll take some time off to assess our results today, and then likely begin a phase of drilling in the block later this year.

Total production was up versus the second quarter of 2009, with much of the growth in the Central region, which includes our Haynesville program. That trends visible on the left side of the chart on slide 17, and on the right side, you can see that we’ve added roughly 50 million a day of production over the past three quarters, again largely from the Haynesville program.

In Q2, we continue to trend near the high-end of our full-year production guidance. So going forward, we raised our lower end of our range to 760 million a day. We maintained the high end of the target range of 780 million a day for several regions. First, we’ve factored in the production uncertainties of the Petrobras-operated Camarupim build in Brazil.

Second, we’re running two rigs in the second half of the year which is again consistent with our 2010 capital plan, but it’ll be harder to hold the current levels of production with lower activity levels. And then, finally, we’ve got more uncertainty regarding the – when the wells in our Haynesville backlog will come on line. And we expect those wells to produce in the 15 million to 20 million a day range initially, so the timing of first production on those wells really matters. Looking back, though, we had good production results in Q2 with exceptional performance from our domestic divisions.

I’ll now turn to the Haynesville. And, as Doug noted, this program just continuous to exceed our expectations. On slide 18, you can see that our net production has risen by more than 100 million a day since the second quarter of 2009. We now have about 13 wells that have been drilled and are waiting on completion, so we’ve got line of sight for continued production growth, although at a lower growth rate than we’ve seen so far.

Now, we continue to look for ways to mitigate our service cost that I mentioned earlier and we’ve blocked in rates for the next two years from much of our projected pressure-pumping needs. We also continue to chip away our drilling times. Our current best pace is 22 days from spud to TD. And we see a few companies that are below 30 days, but none to our knowledge that are in the 20s, so we’re definitely setting the standard for drilling performance in the play. And, maybe more important, our average well production is as good as any operator in the play. So we benefit from having a great lease hold position in the Haynesville, but our teams also have done a terrific job of continuously improving the program and delivering great results.

Our Eagle Ford program continued to perform well during the quarter also. Since our last call, we’ve expanded our acreage position as Doug mentioned and has completed three very good wells. Two of the wells were in our Northern area, and both of them had very high oil content, and they both exceeded our pre-drill expectations.

The map on slide 19 shows our Eagle Ford acreage relative to the dry gas and the liquids rich areas. We ran another 5,000 net acres which brings our total position to a 170,000. We’ve not included those newest lands on the map, since we’re still attempting the lease in those areas. But the new acreage is generally north of our LaSalle county position on the oilier side of the play. We’re currently completing two wells, one each in each year, and I will keep two rigs running in the liquids rich area for the remainder of the year.

Although, we’ve got a smaller backlog of completions in this program, we’ve also secured long-term contract with stimulation services in the play. And, again, that’s going to give us clarity on our cost, equipment, crew availability, and it's going to shorten our cycle times.

And, as I mentioned before, we plan to further wrap up our Eagle Ford program in 2011. And, although we don’t have an approved budget yet, we have a significant inventory here to develop, and this is currently one of our most economic programs. Given higher relative oil prices, Altamont-Bluebell continues to be a very economic program also.

Slide 20 shows, how we’ve grown total net production volumes over the last three plus years. Year-to-date, we’ve averaged over 7,500 barrels a day net, and we’ve recently produced over 10,000 barrels a day on a given since we brought on some relatively high rate new completions.

Now, this is an older more mature old field, where improving execution is the name of the game. And, this year, we’ve continued to reduce drilling times and cost, and while at the same time, improving our initial producing rates. And we’ve made great strides in reducing our lifting cost here. Year-to-date LOE is almost 20% lower than the first half of 2009 and less than $0.13 a barrel or so, which is good, considering the depth of the wells and the waxy nature of the crew.

Overall, we’re pleased with the success of the program. But, as we met with investors and analysts in recent months, it’s become clear that Altamont is probably the least well known and the well understood of our core capital programs. And, given that, we have over 800 locations and over a 100 million barrels of recoverable oil potential, we need to have a better job of explaining the program. So our plan is to host a conference call that’s devoted to Altamont sometime in the fall.

So let me conclude by saying that, I’m really pleased with the execution of our teams. We’ve developed a deep drilling inventory and we’ve continued to focus on improving in all aspects of our operations in our capital program execution. We’re carefully allocating our capital for the programs that create the greatest value. And, although our Eagle Ford and Altamont programs don’t offer the same high equivalent gas rates as the Haynesville wells, the economics of these two programs are strong and that’s primarily due to oil prices and to a lesser degree to the higher liquids pricing.

So we’ll continue to focus capital on these three core programs for the balance of the year.

And, I’ll turn it back to Doug, for his final comments.

Doug Foshee

Thanks Brent. We’ve had a good first half of 2010 and we’re very confident that the second half of the year will be very bit as good. As Jim showed you our pipeline backlogs in good shape, but we can’t claim victory yet. So we’ll stay on task, so that we can deliver the balance of our growth backlog on-time and on budget.

E&P delivered another good quarter. In the second half, we’ll stay focused on our three core areas, Haynesville, Eagle Ford, and Altamont, places where we had deep inventory, consisting competencies, and competitive advantages, that allow us to generate predictable results at the lower end of the cost curve.

With our 2010 capital program already financed, J.R. and the rest of the finance team are staying ahead of the game and working diligently to put 2011 financing needs to bed. We’re also actively exploring ways that we can continue to improve our balance sheet and accelerate our return to investment grade and free cash flow. We think these things will continue to reward our shareholders and put us on track to achieve our longer term goals.

And, now, this morning, we’re happy to open it up to your questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from Jonathan Lefebvre with Wells Fargo.

Jonathan Lefebvre – Wells Fargo

Good morning, guys. Nice quarter.

Doug Foshee

Thank you.

Jonathan Lefebvre – Wells Fargo

In terms of the E&P side, I just wanted to talk about the cost inflation and maybe some of the tightness that you are seeing. I think last call, you said you have all the capacity you need on pipelines in Haynesville and Eagle Ford. But it sounds like you’re experiencing cost inflation. How should we be thinking about that in terms of 2011? Do you think you’ll be able to hold the line there?

Brent Smolik

Yes, Jonathan, let’s take them stepwise. On 2010, I think what we’ll wind up seeing overall with most of the pressure coming on the rigs that are capable, we’ll drill in the horizontal wells and pressure pumping and stem side. I think we’re going to windup seeing kind of single digit, 5%, 6%, 7% increases over what we would have expected for 2010. And that, I think that’s largely because we’ve managed to front load as J.R. said, our capital program into the first half of the year before they started increasing as much, and in partly, because we’ve locked the services in longer term.

So we’ve gotten our rigs currently contracted at least till the end of this year and some in the next year. And then we’ve got stimulation contracts now for the three core programs that are two-year contracts. So they go from kind of midyear this year to midyear 2012. And so, we think we’re in pretty good shape on the things that have – that have had the most of the increases in the recent run.

Jonathan Lefebvre – Wells Fargo

Great. I appreciate that. And then, in terms of the Haynesville backlog 13 wells, do you think you’ll have those all on line by the end of the year? And what was in your kind of current – your original plan or budget for number of wells there?

Brent Smolik

Yes, we’ll probably exit at the end of the year close to that. The new stimulation contract kicks in this next month and so we’ll ramp up completions between now and yearend, could be as low as six, seven, eight, that will have an inventories we start to catch up on the backlog. It will never be zero. Remember, we can’t – we’ll always have with four rigs running, four, five will be a normal backload. So if we exit the year, seven, eight – six, seven, eight something like that, we’ll be in great shape.

Jonathan Lefebvre – Wells Fargo

Great. And then, just in terms of Brazil, on the Pinauna project, can you give us some maybe updated thoughts on what you’re thinking there?

Brent Smolik

It’s really no change in what we’re thinking. The biggest obstacle that we’ve been working through is working to try to solve is the environmental permit. Remember, that’s an oil project, and it’s offshore. And I think the whole world is every place that has offshore oil production is – the tension level is a little higher right now. So it’s the same permitting process we’ve been working through. It’s just a little bit more higher, a little bit more cautioned in the approval process that we’re working through now.

Jonathan Lefebvre – Wells Fargo

And do you think you might make a decision to move forward on that this year?

Brent Smolik

It all depends on the permit. I mean, we’d hope to have in hand by yearend and we’ve talked about that publicly before. And that feels a little harder now with – as the world reacts to what’s going on in Gulf.

Jonathan Lefebvre – Wells Fargo

Got you. And then, just finally on the MLP, you talk about accelerating the drop-downs, I’ll commend you there, you’ve done a great job. Longer-term, when you do think you start maybe easing up on the accelerator?

Brent Smolik

I think there is certainly nothing that we see on the horizon that would cause us to want slow the rate of growth in the MLP. Now, MLP markets could change. A lot of things can change about that. But looking at the market as we see it now and particularly given the size of our interstate natural gas pipeline asset base remaining in the company, I think we see growing into MLP for the foreseeable future.

Jonathan Lefebvre – Wells Fargo

Okay. I appreciate the comments. Thanks.

Brent Smolik

Yes, thanks John.

Operator

Your next question comes from Xin Liu with JPMorgan.

Xin Liu – JPMorgan

Good morning, guys.

Doug Foshee

Good morning.

Xin Liu – JPMorgan

Can you give us an update on your drilling and completion costs in the Haynesville?

Brent Smolik

Yes, this is Brent again. We’ve gotten those wells down to where there were averaging, that’s an $8 million per well. And, today, we’re probably seeing something like 8.5 on average. So we’re seeing an increase. We’re just not seeing anything near like the levels of increases we're hearing others talk about.

And I think it goes back to – we’ve optimized the drilling program and we’re drilling them as faster than anybody out there which helps. And then, I think we’ve optimized the completion designs on them and worked hard on getting our contracts fixed on the cost side. So I think we’re advantaged in that – we’re at that kind of $8.5 million level.

Xin Liu – JPMorgan

And for your – for the service contract, what kind of rig count do you sort of bake in in terms of to sustain those contracts both in Haynesville and Eagle Ford?

Brent Smolik

What kind of lead times on the equipment?

Jim Yardley

No, what kind of rigs –

Xin Liu – JPMorgan

Rig count.

Jim Yardley

Rig count.

Brent Smolik

Rig count, so right now, we’ve got eight rigs under contract. Most of them, all of them, through the end of the year, some of them dribbling in the next year.

Xin Liu – JPMorgan

But in terms of the service contract, you entered the two-year service contract. How many rigs does the contract support?

Brent Smolik

The Haynesville contracts, we’ll be able to keep up with four and five rig program, depending on how fast you drill the wells, but you should comfortably keep up with four to five rig program.

In the Eagle Ford, we’ll be able to keep up with the two to four rig program, again depending on how many fracs per well and how fast we drill them. And then, on the Altamont field in Utah, we’ll be able to keep up with three rigs. And so the next – generally those rig levels that we’ve been at this year is kind of high low is where we structure them for the next two years for the stimulation services.

Xin Liu – JPMorgan

Okay. In the Altamont, who is the nearby operators there? And have you seen activity picking up there in costs, inflation?

Brent Smolik

And, if you look basin-wide in the larger geographic area, New Field and us would be the biggest operators. But if you look in the Altamont-Bluebell field proper, we’re about far the largest operator and have the most undrilled locations and the most activity there. And remember we’ve done a couple of acquisitions, we’ve bought Forest interest out and we bought Flying J interest out, so we continue to consolidate the Altamont-Bluebell field proper, and we’re by far the biggest operator.

Xin Liu – JPMorgan

Thank you.

Brent Smolik

Thank you.

Operator

Your next question comes from Carl Kirst with BMO.

Carl Kirst – BMO

Thank you. Good morning, everybody, and a nice quarter as well. Brent, appreciate all the added color here on Altamont. I know one thing at least earlier in the year we were still trying to figure out what the optimal completion was as we were going to go to single stage to multistage frac, et cetera. Where are we in that process? And how much more sort of science is there to kind of get to that optimal cracking of the code so to speak?

Brent Smolik

Well, it gets easier with higher oil prices, Carl. So right now the current approach we’re using is fracking most of the interval in multiple stages, multiple relatively small stages and the co-mingling the entire vertical section. And I think it looks like – that to me it looks like we’ve kind of optimized it today.

What we were trying to do last year just to tieback was we were trying to target, we’re working from the bottom up, the highest productivity zones, and it’s hard to tell. There’s such a fixed stack here of such rated rock that it’s hard to tell we’re the best, where the best zones are. And so, we found that it’s better off just to frac it all and co-mingle with all in the section.

Carl Kirst – BMO

Great. And so now that we've kind of hit the optimal completion and risk of perhaps front running here, the fall call, what do you see as the average D&C cost and perhaps now the incremental IRR at $80 oil on the Altamont well.

Brent Smolik

Well, why don’t we hold that for the call, Carl.

Carl Kirst – BMO

Okay.

Brent Smolik

I think there was going to be a lot of good information, we’ll go through the total resource to all the inventory future wells and update everybody on that project returns. But they’re some of the best in the portfolio right now. At $80 – we’re running our economics at $70 flat and they’re still at that level, some of the best in the program, and we’re getting returns that are north of 20% with that $70 oil price.

Carl Kirst – BMO

Okay, fair enough. Jim, if I could, there was a mention of possibly of some of the future projects coming in under budget and I apologize if you said this in your prepared remarks. But I was trying to get better color on what you're seeing there and how we should be thinking about that in terms of potential?

Jim Yardley

So, I think the simple answer to that is that each of those three projects that I’ve cited, the estimates quite frankly were put together during a pretty heavy period, as you recall when pipe prices were very and construction costs were going through the roof. And as things have unfolded, I think that we probably just had a little bit too much conservatism in our estimates. So it’s not one thing, we’re seeing it both in terms of the hardware as well as the construction cost themselves.

Carl Kirst – BMO

Should we think of – be thinking of that in terms of low single digit as far as potential cost savings or something more material?

Jim Yardley

It’s probably little bit too early to go there. But we’ll have more reported down the road. These will come in during the fourth quarter.

Carl Kirst – BMO

Great, appreciate it. And then, last question if I could. And, Doug and J.R., I really appreciate your comments on doing things to kind of keep everything on track from a balance sheet standpoint, accelerating getting back to investment grade. Clearly, as we're looking to the future MLPs, it's just a matter of time, knock on wood, before we do the next one. That point's going to close out your free cash flow funding needs for 2011. As we look at the three things sort of on deck whether that is paying down some of the debt that matures here in 2011, potential, more meaningful dividend coming back, or simply increasing the CapEx depending on the projects in front of you at the time. And, understanding it's impossible to answer with specificity here, but is there any color right now as you see it with the preference of the next one or next even two MLP drops?

Doug Foshee

Well, a couple of things, Carl. First off, remember, we're not free cash positive in ’11. And so, while we have a good head start on funding our 2011 capital needs, we still have a ways to go. Second thing, I’d say is, we feel like we’ve put a stake in the ground with regard to free cash flow in 2012 and we still intend to generate significant positive free cash in 2012.

Now to the extent that something gets ahead of our plans, either a more robust MLP markets that allow us to do more in the way of drops going forward or outperformance by one of the two hopefully seemed to be three business units, then that’s a high-quality problem to have. I think as we sit here to day, we are – as you could tell from our comments really focused on continuing to improve our balance sheet and getting back to investment grade. What that means, if we get significantly ahead of our own plans down the road remains to be seen, but I think you can – you could say that we’re likely to be fairly conservative.

Carl Kirst – BMO

Great. Thanks for the comments and best of luck.

Operator

Your next question comes from Craig Shere with Tuohy Brother Investors.

Craig Shere – Tuohy Brother Investors

Hi, good quarter.

Doug Foshee

Thanks Craig.

Craig Shere – Tuohy Brother Investors

With regards to the third leg of the stool here with Midstream that you'll be looking to get back into, to Doug's comments about that any announcement there would not cause you all to back off your 2012 free cash flow guidance, can you comment about third-party financing options for any kind of Midstream efforts and if we should kind of especially in the Eagle Ford TGP area, as more driving equity returns from leveraging E&P in pipes rather than equity returns from the third leg of the stool itself, the Midstream?

Doug Foshee

Let me answer the second part of that first. I think I would not characterize that strategy as the way you expressed the second part. We – what we look to do with the Midstream is have a Midstream that takes advantage of existing core competencies that delivers very good risk adjusted rates of return that exceed our cost of capital.

And then, if we can marry that with some synergy to some other physical asset that we currently own whether it’s in Brent’s business or in Jim’s pipeline business, then we’ve created in effect the tri factor, right? We’ve got a good standalone project, analyzed and underwritten based off on its standalone returns, and we’ve done something good for the enterprise whether that means get – moving gas to an El Paso pipeline that might not otherwise have gotten there or helping E&P with its – control its ability to move its volumes from a new play. Those are the kinds of things we’re looking at.

Craig Shere – Tuohy Brother Investors

But I guess the question is how do we move the needle much in terms of equity returns directly off Midstream if we don't invest equity capital?

Doug Foshee

I don’t think we haven’t said we’re not willing to invest in Midstream. What we’ve said is, we’re not willing to allow our entry in Midstream to move us off of generating significant free cash flow in 2012, and right now, we don’t see those as mutually exclusive.

Craig Shere – Tuohy Brother Investors

Understood. If I could just return real quick to the Brazilian Tenawana [ph] play, I understand that the environmental issues and the whole BP thing might be putting off the final approvals for that. But can you all speak to the reserve potential and interest in just monetizing this play once approvals come in rather than building it out?

Brent Smolik

The reserve potential hasn't changed. So the numbers that we shared with you back in December at the Analyst Day are still exactly the same. And then, in terms of selling it, we’ve talked publicly before about the willingness to take on a partner and we would consider and looking across to Doug, that we would consider exiting for the right deal and the right opportunity. But I think the critical path for either of those decisions still goes through the environmental permit. And so, with far more likely to entice somebody, if we go down that path after we figure out the regulatory environmental approval at hand. So that’s where –

Doug Foshee

At a value that we find acceptable.

Brent Smolik

Yes, so that’s the approach we’ve been taking. And it’s really the same approach we’ve been on for the last year or so, and we’re just going to continue down that path, and eventually we’ll get a permit that allows to get started. And I’m linked, I referenced to the Gulf deal, just because it’s offshore.

Remember, this project is shallow water. We’re only in about a 100 feet of water with this project. And all of the surface, all the well controls, and everything is above surface. So it’s much more like a Gulf of Mexico shelf well, than it is like a deepwater well. But it’s still – it’s just a – it’s a heightened caution out there.

Craig Shere – Tuohy Brother Investors

Sure. Last question. If you are able to sell at a respectable evaluation, Tenawana once you have the approvals in hand, and you do, I don't know, let’s say another six dropdowns by the end of next year, shouldn't we be thinking about a material acceleration of the goal of 2012 investment-grade metrics?

Doug Foshee

Sure. That means, if we’re able to – we’re constantly looking for ways to do that. So if we get materially ahead of our own internal plans or cash flow generation or cash generation, either from some sort of an assets now related to the MLP or something else, then, yes, that would accelerate our goal of getting back to investment-grade metrics.

Craig Shere – Tuohy Brother Investors

Okay, thanks a lot.

Doug Foshee

Yes.

Operator

Your next question comes from Kevin Smith with Raymond James.

Kevin Smith – Raymond James

Hi, good morning, gentlemen.

Doug Foshee

Good morning.

Kevin Smith – Raymond James

Just a question. It looks like you're dropping a rig in Altamont, is that correct? You're going from three to two – I don't know exactly when you did it.

Brent Smolik

Yes, we did it, right at the end of the quarter. And, yes, we more than anything else that we picked at least worst performing of the three rigs and worked it out of the inventory, and then we’ll be back, we’re back in the market looking to add a rig back to the program. It does fit well with our capital, October capital that remains and for the full year. But more than anything else, it was the worst performing rig.

Kevin Smith – Raymond James

Okay. So it didn't have anything to do with the rate of returns in the play other than just rig performance?

Brent Smolik

Don’t – we don’t want to signal anything that – that’s one of our top three performing capital programs especially at current oil prices.

Kevin Smith – Raymond James

Fair enough. And then, another question on Ruby's initial capacity; I know there was talk for a while of whether you were going to add the compressors to get to 1.5 or stay at guess around the 1.3 level for initial capacity. Where do we stand on that?

Jim Yardley

We have – we’re committing to put in the 1.5.

Kevin Smith – Raymond James

Okay. So full – all the compressors will be operational on day one?

Brent Smolik

Yes.

Jim Yardley

Yes.

Kevin Smith – Raymond James

Okay, perfect. And then the other question, last question. You mentioned obviously you picked up acreage in the Eagle Ford in the oilier section of the play. Do you have a preference on which window you prefer to be in and which one you think was going to drive the best economic rate of returns?

Doug Foshee

Today, it looks like more oil is better than less oil. And that can swing if we get back, the gas projects look like they’re kind of marginally economic to us and that’s why you’ve only seen us today three wells that are kind of pilot testing and data gathering this year.

But it doesn’t take much higher gas prices and we’ve got a nice options for a big inventory of development there. So what our plan is we’ll take those three pilot wells and everybody else’s industry data and we’ll assess the gas window, we’ll focus to the rest of the year and beginning of next year on the oilier side.

Kevin Smith – Raymond James

Okay. Is the acreage cost significantly different between the three plays or the three windows?

Doug Foshee

The acreage cost, it varies some. I think we're at that point in the leasing cycle when we're getting later. And so it's as you do in that, the cleaning up the last acreage is always a little bit more expensive than the early days. And so that’s a little more expensive, but that’s true on both sides of the trend.

Kevin Smith – Raymond James

Thank you very much.

Operator

Our next question comes from Ella Bjornik with RBC Capital Markets.

Ella Bjornik – RBC Capital Markets

Good morning. Going back to your guidance increase for the year, I know you've touched throughout the prepared remarks on areas of strength across the business. Could you just for sort of explicit detail give a little bit more clarity on – in addition to narrowing the production guidance what other areas of the business you're seeing better than expected performance driving that increase?

J.R. Sult

Again, what we did today was two things. We – as you have indicated, we brought up the bottom end of the guidance for production volumes based on what we’ve seen today in terms of first and second quarters.

And, two, as a result of our overall earnings performance, if we go back and look at our first quarter performance relative to our plan, as well as the second quarter performance, we clearly indicated to you everyone at our first quarter call that we were at the top end of that guidance.

Well, in terms of the E&P results, improve production, lower cash costs, and as well as the pipes, the pipelines as well. So we just felt that was prudent to ultimately really more bring up the bottom up end of that guidance from an EPS standpoint and show where we think we made ultimately shakeout for the year.

Doug Foshee

And, I’ll just the – the one other thing which really I would say cuts across both business units and at the corporate level. And that is, we had some pretty aggressive cost reduction targets that we began to implement in the second half of 2009. And through the first half of this year, we’ve gotten at or better than project cost control, and we think we’ll hold out for the balance of the year.

Ella Bjornik – RBC Capital Markets

Great, thank you very much.

Operator

Your next question comes from Faisel Khan with Citigroup.

Faisel Khan – Citigroup

Good morning.

Doug Foshee

Good morning.

Faisel Khan – Citigroup

I just have one question. On the liquids volumes that you guys are getting out of the Eagle Ford, do you have an idea yet of what that composition of that liquids barrel is, is it mostly condensate or ethane or propane or something else?

Brent Smolik

Faisel, this is Brent. What we produce in the field is largely oil or condensate. And so the volumes, if you go back to the what we released on the last couple of wells were close to 600 barrels a day, kind of wells on the test rate. The liquids it will give from processing the gas downstream is about half of it methane and about half of it is the other liquids products, propane, butane, isobutane, products that we get. So, we kind of think about it that way.

Faisel Khan – Citigroup

Okay, got you. When you guys report the liquids number, it's a – there's a condensate and an oil part of that. That's all part of that barrel. And then the rest, when you process the gas, you're getting an ethane and propane stream separately?

Brent Smolik

Right.

Doug Foshee

Exactly.

Brent Smolik

That’s right.

Faisel Khan – Citigroup

Got you.

Brent Smolik

And I think we don’t have it on this call, but on the last call, we showed kind of the impact if you convert it all that to gas, so you can see kind of the relative impact on the revenue side from each of those components between the difference a 1000 Btu gas and 1,350 Btu gas for the NGLs, and then the incremental benefit from the content barrel.

Doug Foshee

And we’ll try to be consistent in all our disclosures as Faisel did. If we call it crude, it’s crude and condensate. If we call it natural gas liquids, that’s where all the processed liquids show up.

Faisel Khan – Citigroup

Okay, great. Thanks for the detail. I appreciate it.

Doug Foshee

Yes, thank you.

Operator

At this time, there are no further questions. Gentlemen, do you have any closing remarks.

Doug Foshee

Well, great. Thank you for attending the call this morning.

Operator

Thank you. This concludes the conference. You may now disconnect.

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