Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Executives

Bruce Connery – VP, Investor and Media Relations

Doug Foshee – Chairman and CEO

J.R. Sult – CFO

Jim Yardley – Chairman, Pipeline Group

Mark Leland – President, Midstream Group

Brent Smolik – President, E&P Company

Analysts

Steve Maresca – Morgan Stanley

Carl Kirst – BMO Capital

Xin Liu – JPMorgan

Jonathan Lefebvre – Wells Fargo

Craig Shere – Tuohy Brothers

Faisel Khan – Citigroup

Holly Stewart – Howard Weil

Kevin Smith – Raymond James

Ted Durbin – Goldman Sachs

El Paso Corporation (EP) Q3 2010 Earnings Conference Call November 3, 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 third 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 introduce 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 four other speakers on our call this morning, J.R. Sult, our CFO; Jim Yardley, Chairman of our Pipeline Group; Mark Leland, President of our Midstream Group and Brent Smolik, President of our El Paso Exploration and Production Company.

As you know, this morning, we issued our third 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 the Investor section of our website at elpaso.com.

Also, on our website, you will find a financial and operational reporting package that includes information that we believe you will find helpful as well as GAAP financial statements and non-GAAP reconciliations. I hope you’ve downloaded this package, so that you will 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 other SEC filings. Please take the time to review them.

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

Finally I’d like to ask those of you who will be participating in Q&A to limit yourselves to two questions so that we can give more people an opportunity to ask questions. Thank you for your help on this. I’ll now turn the call over to Doug.

Doug Foshee

Thanks Bruce, and good morning. We have a lot of things to cover on the operational side this morning. So in the interest of time, I’ll keep my opening comments brief. We made substantial progress against our goals this quarter and made several moves designed to position us for long-term success. In the pipes, we’re definitely in execution mode right now with several key projects under construction.

We expect our 2010 in-service projects to come in on-time and substantially under budget like 25% under budget. On Ruby, we’re under construction of making good progress. As Jim will share with you in a minute, our delays getting started mean that we now expect to be over our original budget by 10% to 15%. We never like a project to be over but the fact is we are on this on.

As we told you from the beginning though, we view our backlog as a portfolio and when you look at the entirety of the backlog, much of which is already completed or under construction, we expect to be within 5% or less of our original budget overall. We think that will put us at the ahead of the class in terms of new project execution and Jim will go into more detail on that later.

In E&P, we just continued to hit on all cylinders. Another good quarter operationally with volumes ahead of plan, unit costs trending down as our efforts of continuous improvement payoff and those same efforts in our drilling operations work to offset cost inflation. And in Midstream, Mark and his team continue to make progress both with existing assets that he now has dominion over, as well as with key new projects in the Marcellus and the Eagle Ford that we continue to move closer to the finish line.

In addition to these more tactical things though we made some strategic moves during the quarter that’s serve to increase our competitiveness and better position us for the long-term. First we added a new core area in E&P during the quarter with our substantial acreage acquisition in the emerging Wolfcamp play. This combined with our Eagle Ford position and our consolidated position in Altamont gives substantial increase in drilling inventory and at the same time a substantial increase in inventory with oil exposure.

Second, we added to an already enviable price risk management position during the quarter improving our line on gas in 2011 and 2012 and adding some hedges on oil in 2011, all in favorable prices that adds certainty to our ability to generate the cash flow needed to fund both maintenance and growth capital, even in a poor gas price environment.

And finally, we continue to accelerate our balance sheet improvement during the quarter redeeming a large portion of the five year financing we did at the height of the financial crisis in late 2008, and continuing to grow El Paso Pipeline Partners or MLP. The combination of steps we’ve already taken combined with planed actions between now and the end of the year, mean that we’ll end the year having completely funded our 2011 plans, another key step as we move towards free cash in 2012.

With those comments to set the stage, I’ll turn it over to J.R. to review our financial performance. J.R.?

J.R. Sult

Thanks Doug and good morning. As Doug just mentioned, we did have another good quarter with continued progress towards our long-term goals. During last quarter’s call, I told you that we would not let our foot off the accelerator to our MLP strategy and we haven’t.

Although I don’t have a third dropdown transaction to announce yet, with more than $400 million in new equity capital, El Paso Pipeline Partners is eager to put the money to work. We are as well. Make no mistake about it. We have the stamina and commitment to maintain our accelerated pace. Shortly, after our last call, we expanded our 2011 natural gas hedges and extended them in 2012. We took what was already a great hedge position and made it even better. Now remember our hedges do not support our drilling economics, but instead support our balance sheet and cash flows.

I’ll show you our current hedges in a few minutes. Finally as Doug said we took advantage of the strong credit markets during the quarter and replaced about $350 million of the 12% five year notes we issued in the midst of the financial storm in December 2008 with 6.5% ten year debt. We continue to look for similar opportunities that are aligned with our goal of accelerating balance sheet improvement. As a result of our success executing our 2010 financing plans and actions we anticipate completing before year-end, we expect to have our 2011 funding requirements met before the end of the year.

So let’s look at our quarterly results beginning on slide 6. Adjusted diluted earnings per share was $0.22 which roughly flat for a year ago. Actual GAAP reported earnings for the quarter was $0.19 per diluted share and is always a complete reconciliation of our non-GAAP measures to our GAAP reported financial measures included in our website. In the Pipeline Group, adjusted EBIT increased 2% for the quarter, driven largely by the impact of expansion projects. The Elba Island expansion and Elba Express Pipeline representing nearly $1 billion in growth capital went into service earlier this year.

In addition, pipeline results for the quarter reflect an increase in equity AFUDC or allowance for funds used during construction on the capital employed in our pipeline expansion projects that are not yet in service. AFUDC will continue to increase until the individual projects are placed in service. These increases were somewhat offset by higher non-controlling interest expense primarily resulting from our successful MLP dropdown strategy and a non-cash write down based on our recent FERC order on CIG.

Finally, third quarter results for the pipelines reflect continued regional, economic, competitive and changing GAAP slowed challenges impacting EPNG and TGP. Jim will have more on these dynamics shortly. In E&P, adjusted EBIT was down $30 million from last year. Now if you judged E&P’s third quarter performance based solely on earnings trends, you’d be making a mistake. The story for our E&P group this quarter continues to be about operational execution. More from Brent in a few minutes.

So what are the headlines? Production up 4% while unit cash cost decline 9%. The big differences quarter-to-quarter, although we had a large portion of our 2009 gas production hedged with a $9 floor compared with a $6 floor this year. And oil hedged $110 in 2009 versus $76 this year. Now don’t get me wrong, with gas prices currently below $4 we’re very pleased with our $6 hedges this year.

Interest expense was flat quarter-over-quarter and down from our second quarter as I projected during the last call. One last point before we leave this slide, our adjusted EBIT was down slightly, adjusted EBITDA was up 4% for the reasons I just discussed.

Let’s turn to operating cash flow on slide 7. Cash flow from operations year-to-date was below last year’s level primarily due to lower realized commodity prices and working capital changes. So far this year, our 2010 hedge program has contributed almost $250 million to operating cash flow above what otherwise would be market levels. The result, estimated fiscal year 2010 operating cash flows that are ahead of the expectations we had at the beginning of the year. Capital spending picked up during the quarter as we expected and we anticipate continuing this pace for the rest of the year.

If you’ll turn to slide 8, you’ll see the pipelines are running ahead of last year again consistent with expectations driven by the peak capital spending on the expansion backlog notably Ruby. On the E&P side, we’re up above $300 million from last year. You may recall that part of this is because we frontloaded a portion of our 2010 capital program to get ahead of the expected cost increases.

In addition, we acquired approximately 123,000 acres in the Wolfcamp oil field during the quarter almost – for about $180 million. As we indicated, we announced the acquisition we will fund the cost of entering the new play overtime through portfolio rationalization. We’ve also made additional investments in the Eagle Ford acreage funded through reduced international spending.

In the aggregate, we expect fiscal year 2010 CapEx to be essentially on budget before considering the significant strategic investment in the Wolfcamp shale. Finally, our liquidity remains very strong with $2.5 billion available at the end of September, not including cash or available credit facilities of our MLP for Ruby.

As I mentioned earlier, we advanced an already good hedge position during the quarter to an even better one as shown on slide 9. When we looked at our 6/9 callers, we saw positions that were effectively $6 swaps in the current environment. Now with those option positions still has substantial value. Rather than simply watch the value erode overtime, we leverage that embedded value to our advantage. The bottom line is that we were able to increase our 2011 gas hedges to 75% at $6 and add new positions on 25% of our 2012 gas production at $6.36. Now just a reminder the percentage hedged were all periods on this slide is based on estimated 2010 domestic production levels.

As we monitor industry hedging activity, we think our natural gas hedge positions are that as good as you’ll see. I’ll wrap it up with our oil hedges on slide 10.While we’re generally bullish on longer term oil prices, we remain prudent in minimizing downside risk when opportunities present themselves. We’re about 95% hedged with an $85 floor price in 2011 based on estimated 2010 production levels.

As our production shifts more to oil in the future, expect us to continue to manage the price exposure of that increase in supply to support our balance sheet and cash flows. That’s my update for you this morning. I’m pleased to have another good quarter under our belt and proud of the progress we’ve made. With that I’ll turn the call over to Jim for an update on the Pipeline Group. Jim?

Jim Yardley

Thanks JR. At the pipes, the third quarter was highlighted by continuing to execute on our backlog of growth projects. We advanced three more projects towards in-service in the fourth quarter and replace them in-service as Doug said on-time and approximately 25% under budget. That’s about $100 million under budget. The first of these, the WIC expansion (inaudible) and into the Ruby pipeline was placed in-service on-time on November 1.

And we’ll follow that up with a return expansion going in-service on December 1 and then the SNG South System expansion on January 1. On Ruby, although we’ve had some delays in obtaining cultural resources clearances, construction is moving ahead now on all spreads. And we’ve made good progress on the other projects in the backlog including the other large ones for in-service during 2011. TGP’s Line 300 expansion across Pennsylvania, Gulf LNG and the FGT Phase VIII expansion.

We’re also filing two new rate cases. Both of these are essentially the result of shifts in the way gas is flowing across the country. We just filed a rate case on EPNG and we’ll file one on TGP most likely by the end of the month. Let’s look at throughput and these changes in flows on slide 13.

In total, throughput this year is down approximately 3% from 2009. And it’s a mixed bag on our pipes across the country as you can see. I want to talk about a couple of throughput trends that are noteworthy and are driving the new rate cases. First, on TGP. While overall throughput is up, there has been a significant change in the sourcing of supplies. Receipts from Marcellus in Pennsylvania and REX in Ohio together are up about 1.3 Bcf a day year-to-year. These receipts have displaced imports from Canada at Niagara and long-haul transport from the Gulf Coast.

The impact of this on TGP is the short-haul and backhaul revenue out of Marcellus has increased, but long-haul commodity and interruptible transportation are down. Also TGP’s revenue from gas not used in operations is lower due to those lower fuel volumes retained and obviously lower prices. Because of these changes, we’ll file a rate case on TGP to fully recover revenue and structure rates that are more properly reflect the reality of today’s gas flows.

Secondly on EPNG, the decline in throughput is somewhat a function of the economy in the Southwest, but is also the result of increased pipeline competition and import into California. Both from LNG arriving at Costa Azul and indirectly imports from Canada. In combination this has resulted in lower freight rates available on short-term capacity sales, also some turn back of FT. And so we’ve recently filed a rate case on EPNG for new rates to be effective next spring.

Changing gas flows are a reality in today’s gas market. And they are varying impacts on individual pipes. In general because El Paso owns a large and diverse set of pipelines, we are better able to absorb these ongoing changes in market conditions. And remember that we have further protection because over 80% of our revenues comes from monthly demand charges and this percentage will likely further increase as TGP goes to a more traditional rate design in its new rate case.

On Ruby, slide 14. We’re well underway with construction in all spreads. As you recall, we started construction on July 31. This is about two months later the plan and after 2.5 year review process by BLM, FERC and the various federal state and local agencies. We now have eight construction spreads working on Ruby. Having out of the spread in one of the more mountainous areas of Utah to complete that section before winter. That section so called Spread 2 is proceeding very well. Ditching and pipe stringing are approximately three quarters complete and the welding of the pipe sections about two-thirds complete.

As shown on the photos, a lot is going on across the entire pipeline route. Some clearing and grading, ditching, stringing and some lowering end of the pipe. Our two manned camps are up and running in Western Nevada and Oregon to house and support up to 1000 men throughout construction. So we had a lot of activity ongoing on all spreads.

In general, on slide 15, construction is progressing very well on the eastern spreads and slower than expected on the western spreads in parts of Nevada and Oregon. On the western spreads, we’ve had some delays in obtaining cultural resource clearances. This in turn has restricted our construction activity there. We recently had over 150 archeologists in the field and now the permitting process is improved.

In Nevada and Oregon, we now have access to over half the right-of-way. We continue to get more released on a regular basis in Nevada. And in Oregon we’re seeing improvement in the permit approval timelines. As part of this process, Ruby continues to work with the tribes and their concerns about cultural disturbances. Separately, our compression station construction is going very well, and all four of our stations, nearly all the major equipment has been set on their foundations.

With respect to cost and schedule, as Doug said, we now expect Ruby to be 10% to 15% over budget, primarily due to the delays, and our target in-service is next June. The key variables will be weather this winter, the pace of getting final regulatory clearances, and dealing with various construction restrictions due to fish and game habitat or nesting periods.

In sum on Ruby, construction activity continues to ramp up, and as you know, both we and our major contractors are incentivized and focused on construction productivity.

Finally, slide 16. Slide 16 summarizes our multiyear major pipeline expansion program, both our performance to date and expectations. Our projects for in-service this year are either complete or nearing completion as scheduled. As I mentioned, these four projects as a group will be approximately a $100 million under budget.

For the five projects that will go in service next year, all are well under construction, and other than Ruby, all are essentially on budget. And at this point they have been substantially derisked with essentially all the pipe delivered and all the construction contracts in place either fixed price, unit price or incentive based.

While it’s a little early to talk about progress on our projects to go in service in 2012 and beyond, note that these are primarily lower risk pipeline looping and compression projects. So as Doug said, in total, this multiyear capital program including Ruby is expected to be within 5% of budget, and this holds whether considering gross CapEx or CapEx net to El Paso. And you’re aware that these projects have also been derisked on the market side. As a group they’re approximately 90% subscribed under long-term contracts with high-quality customers.

So our focus at the pipes is a very clear one, it’s executing on all these growth projects.

And with that I’ll turn it over Mark to update you on the Midstream business.

Mark Leland

Thank you, Jim. Well, it’s been a year since we announced our intention to enter the Midstream business, and I’m happy to report that we’re making visible progress on several fronts.

We’re now operating and in fact expanding a gathering system in the Eagle Ford, which will have a capacity of about a 150 million a day. In the Haynesville, we have a 70 million a day gathering system that delivers to Tennessee Gas Pipeline, and we’re about to begin construction on our 150 million a day [inaudible].

In the Uintah Basin of Utah we have the Altamont gathering and processing system which gathers associated gas from this oil field, and has about 800 miles of gathering line, 40 million a day gas processing plant, and just under 4,000 barrels a day at fractionation capacity. In all three of these areas, we’re evaluation future growth needs of El Paso’s E&P Company, and we’re being very successful in pursing third-party opportunities.

We’re in particularly excited about the growth potential in the Altamont system, which we’ll talk more about on our upcoming Altamont Analyst Call.

We have two major shale infrastructure projects under development, one in the Marcellus and one for the Eagle Ford. As you may have seen from our recent press release, we joined forces with Spectra to leverage more existing assets to make the Marcellus Ethane Pipeline System as competitive as possible.

In the case of El Paso, we’ll convert a Tennessee Gas mainline that is underutilized primarily due to changes in flows discussed by Jim. And for Spectra, we’ll contribute excess TETCO right away in the northeast.

At this point, we continue discussions with producers and petrochemical plant operators to assess demand for capacity either Mont Belvieu or like Charles and Baton Rouge. So depending on how discussions with these potential customers go, we would hope to have a binding open season later this year and then sanction of project shortly thereafter.

The Camino Real pipeline is a 600 million a day project. They’ll gather and process rich Eagle Ford shale gas with new pipelines that would tie into Tennessee Gas Pipeline that has existing capacity near Victoria, Texas. The gas will then move north on Tennessee to Paul County, where we’ll build a project processing plant. The NGOs will be shipped to Mont Belvieu via pipeline. We’re actively marketing this project to Eagle Ford producers.

The business that we’re building and the project we’re developing are very attractive, and we’ve been approached by industry and financial players wanting to participate with us in one form or another. We’re evaluating these partnering opportunities to not only enhance our business prospects, but to manage our capital requirements.

So you can see we’re starting to gain momentum on several fronts, and in all cases we’re leveraging El Paso’s asset base to provide synergies, build value for El Paso and enable the MEPS and Camino Real pipeline to be competitive solutions for Marcellus and Eagle Ford producers.

With my first Midstream update complete, I’ll turn the call over to Brent.

Brent Smolik

Thanks Mark, and good morning, everyone. I’m proud to report another good E&P quarter. Production was up from a year-ago and we’re tracking towards the high end of our full-year guidance range of 760 million to 780 million a day equivalent.

Cash costs were down as J.R. mentioned in Q3, and we’ve reduced our full-year guidance range again to a $1.75 to a $1.85. And as I mentioned on the last quarter call, we continue to run a very focused drilling rig program with four rigs running in the Haynesville, two in the Altamont field, and two in the Eagle Ford. So you’ll see growth from those areas while we continue to cash flow the remaining domestic assets.

And as Doug noted, our drilling inventory has grown and that growths come primarily from oil projects. We’ve got a significant boost on the Wolfcamp Shale Program, and in a moment I’ll explain why we believed at our new Permian leases have tremendous potential.

Production growth from the Haynesville and the Central division, Altamont in the Western division and Brazil drove the year-over-year increase in our third quarter volumes which you can see on slide 21. The Gulf Coast is down because we’re not reinvesting in our traditional programs and the ramp in the Eagle Ford is not yet overcome in the base decline, although in total we’re about where we expected for the Gulf Coast division.

Cash costs were down 9% with really good progress across the board. Our production operations and our supply chain teams have continued to deliver cost efficiency improvement.

So let’s turn to the Eagle Ford program which continues to perform very well also. If you were not able to attend our recent field trip then perhaps you’ve seen the charts on our website that provide a full review of the Eagle Ford play. The key takeaways from that presentation are that we have a very attractive acreage position that includes a lot of oily inventory.

We now have two gas wells in the southern area and seven oil wells in the central area with gross production of about 2,500 barrels a day of oil and 7.5 million a day of dry gas. The drilling results continue to be at or better than our pre-drill models, and in fact we’re currently testing a Frio County well at over 700 barrels of oil and over 800 barrels of an equivalent basis. And currently we have six wells waiting to be completed in our dedicated factories in place here, so we expect to maintain a relatively low completion backlog.

We drilled our first well in that northern block in October and we’ll complete it later this month. Wells in the Northern Canyons will be true oil wells and we’d expect the EURs in those to be like 300,000 barrels to 550,000 barrels.

The resource potential here is significant. We’ve got about 250 million barrels of oil and liquids and about 1.8 Tcf of gas on an unrisk basis. And given the size and the quality of our Eagle Ford acreage coupled with our entry into the Wolfcamp Shale play and our desire to maintain capital discipline, we’re considering taking an Eagle Ford partner to help optimize the value of our inventory.

We plan to keep two rigs running for the remainder of the year; add a third rig in 2011, and we plan to exit 2011 at five to six rigs, and most of our near-term drilling is going to be oil focused. With current pricing, this is our most valuable program, and we’re really happy with our returns in the oil production will become more meaningful to our volume mixes as we go through 2011.

Our Haynesville program continues to outperform others in the play. Our wells are still delivering about 30% more production than the industry average, and we’ve recently drilled a well to TD in 20 days, and I don’t think anyone else can come close to that drilling pace.

On the last call, I talked about how we had entered into a two-year contract for a dedicated frac crew, so that we could eliminate delays and getting our wells completed. And our completion backlog had grown to 16 wells in late August, so we worked that backlog down to 12 wells which would benefit our production in the fourth quarter. And recently, our net production has been over 170 million a day.

Now, while some companies are seeing a falloff in oil productivity in the Haynesville, we’re seeing very consistent IP rates and EURs, and I continue to believe that’s because we start with an advantaged acreage position just right in the heart of the play and then we continue execute well on the completion in their production operations areas.

I’ll keep my Altamont comments brief today since we have our schedule call on November 18th at 4:30 Eastern Time. Altamont remember is a huge resource originally about 3 billion barrels of oil in place, only about 10% of that’s been produced, so we’re busy trying to increase recoveries from the field. This is a textbook continuous improvement story. We know the oil is there, we’ve had a large drilling inventory, and we’ll continue to drill wells faster and more cost effectively over time, and we’ll continue to improve our completion design and well performance. So please join us for more regarding Altamont in a couple of weeks.

And then a few weeks ago, we announced our new Permian Basin oil program that we’re very excited about in the Wolfcamp Shale. Slide 25 shows we now have a significant position roughly 135,000 net acres all in large contiguous blocks with a single royalty owner as the State of Texas is part of the university land system. Now, we think we have more than 600 horizontal well locations just in the upper portion of the Wolfcamp, assuming a 75% acreage utilization factor which then translates to more than a 150 million barrels of oil equivalent resources.

I’ll show you a regional map in a moment, but one of the things we really liked about the play is that we’re dealing with a known reservoir. There have been hundreds of successful vertical Wolfcamp producers in this area and there’s plenty of existing infrastructure. So although it’s still very early days for horizontal activity in the Wolfcamp, six horizontal wells have been drilled offset to our acreage with very encouraging results, and we’re tracking the current drilling activity in the area.

We cored and tested one well before we bid on the university leases. And although we had some mechanical problems during the completion, we got all the information we needed to confirm the high quality of our lease area relative to our regional view of the play. And then finally, we believe that what we’ve learned operationally in the Haynesville and the Eagle Ford will be directly applicable to the development of the Wolfcamp.

Let’s step back a second and talk about why we targeted the Wolfcamp. Now earlier this year as our Eagle Ford program was moving into the development phase, we took a small position in Crockett County to study and pilot test the Wolfcamp. That recommendation came from our technical team following extensive review of the Wolfcamp Shale across the entire Permian Basin where they literally included thousands of oil logs and production histories over a 13-county study area.

The map on slide 26 shows vertical a Wolfcamp and Wolfberry production virtually surrounding our acreage. And not shown on the map, as you move from north to south towards our blocks to Sprayberry above the Wolfcamp actually gets thinner and the Wolfcamp Shale gets thicker. In fact the total upper and lower Wolfcamp Shale interval is almost a 1,000 feet thick in places. So we’re dealing with a known producing reservoir not just a known source rock, and better yet it’s an oil play with upside and all of the traditional vertically stacked Permian Basin oil reservoirs.

Let me compare and contrast the Wolfcamp Shale to other shales, we see a lot of things we like. On table 24, highlights the shale reservoir success factors, and a number of things jump out at you; shallower depth, so it’s going to be cheaper and easier to drill; a very thick section, 400 to 850 foot of net thickness; and clearly we can’t horizontally drill and complete a section this thick with one lateral. But having a very thick section creates a possibility of a second phase of horizontal development in the lower portion of the Wolfcamp, which would essentially double the resource potential.

High organic content, we need organic material to generate hydrocarbons, and a 4% to 15% indicates a very organic rich shale. High porosity with values ranging between 7% and 15%, the Wolfcamp has high oil in place storage capacity. And then finally low clay content. We want shales that have high quartz or carbonate content and low clay content. The quartz and the carbonates form brittle rocks that are easier to hydraulically frac and they tend to be more porous and permeable.

We all refer to the source rocks as shales, but what we’re really looking for is low clay content shales. So the Wolfcamp has a lot of things to like and I believe it compares very favorably to some of the more established shale plays.

Now another positive is its relative consistency of the Wolfcamp section across our acreage position. On slide 28, we showed two logs from the northeast to the south – northwest rather to the southeast across our acreage spanning roughly 35 miles. Now the laws we marked to Sprayberry, the Dean, the upper and lower Wolfcamp sections. And when our technical team was doing their original analysis, this consistency is part what we were targeting for our acreage objectives.

The laws tell us that the upper Wolfcamp is very good porosity and high organic content as we’ve discussed. And as importantly it shows that the section is very consistent all the way across our acreage position, and that consistency is what lead us to build the large acreage position quickly, and allows for the kind of repeatable inventory that can deliver predictable well results and returns that we looked for.

Now, we’ll obviously experiment with drilling and completion designs, but slide 29 summarizes our current type well economics. At the midpoints, we’ve seen 7,500 foot vertical depths, 5000 foot laterals, 16 frac stages, a 160 acres spacing, and completed well cost of about $5 million. We estimate initial producing rates of 250 to 300 equivalent barrels per day, although we’ve already seen wells offset our block that are much higher than this, and those rates would translate to gross EURs of like 300,000 to 380,000 equivalent barrels.

Ultimately the program PVR should be in the 1.25 to 1.35 range assuming $70 oil and $4.50 gas and the IRR should be in the 20% to 30% range. Now again, our model only assumes developing the upper portion of the Wolfcamp with possible upside value from the lower Wolfcamp horizontal development and horizontal development on tighter than a 160-acre spacing, and then all the other vertically stacked oil zones in the Permian basin. With all the resource potential on our new leases, we’ll hopefully be talking about the Permian Basin for a long time.

Going forward, we plan to spud another well in November, and keep that rig active into 2011. The formula we’ve used in the Haynesville and the Eagle Ford has worked well for us, so we intent do mirror that approach. We’ll start with one rig and then we’ll try different lateral links and numbers of frac stages and then find ways to reduce drilling and completion cost and time.

We’ll also be spudding wells across our acreage to better understand our position and to improve our long-term plans. One of the great things about having a single very knowledgeable royalty owner is that we can better optimize our development plan and we’ve already begun the process of unitizing the university lands. By using that approach and given success you should expect this to ramp up our drilling activity throughout 2011 just as we’ve done in our other core programs.

Now, I’ll turn the call back to Doug for closing comments.

Doug Foshee

Thanks Brent. We had a very good quarter operationally. We continue to make progress in executing on our pipeline backlog and not withstanding an anticipated cost overrun on the Ruby pipeline, we expect our growth backlog in total to be within 5% of its original budget.

In Midstream, we continue to make progress on key projects in the Marcellus and Eagle Ford, and are already seeing the benefit of Mark and his team’s stewardship of our existing Midstream assets in Altamont and in Haynesville. And in E&P, Brent just outlined a great quarter, and lots of reasons to be optimistic about the balance of the year, as well as the longer term.

As we plan for 2011 capital spending and E&P, it’s very likely that the bulk of our spending will be in areas that didn’t even exist as a possibility three years ago. A much large inventory comprised primarily of large core positions in areas where we’re advantaged and have a track record of performance with much more exposure to oil. That constitutes a dramatic shift in the competitive landscape over a very short period of time.

On the balance sheet side, we expect to have covered off all our financing needs for 2011 in the next two months. All of these actions served to increase our competitiveness even in a low gas price environment and we’re not sitting still. We have more plan for the balance of the year including as Brent alluded to the securing of the joint venture partner for our Eagle Ford acreage, allowing us to accelerate development, and optimize our own invested capital.

That concludes our prepared remarks this morning, and now we’d be happy to open it up to your questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from Steve Maresca with Morgan Stanley.

Steve Maresca – Morgan Stanley

Good morning, everybody.

Doug Foshee

Good morning, Steve.

Steve Maresca – Morgan Stanley

My first question is on the pipelines and on the rare cases you talked about Jim. If you could just provide some color as to how it works in a sense, you filed one for EPNG, and I guess these are Section 4 cases, and you followed one for TGP. What are the risk that there’s pushback and that this doesn’t happen and you don’t get the rate increases on these lines?

Jim Yardley

Yes, these are traditional Section 4 rate cases. It’s not unusual for us to file at one level. Typically we’ve settled rate cases, I think we have a long history of settling rate cases with our customers. Occasionally they will go to litigation and it will be sorted out by an ALJ and the commission. But, I – we have a very long history of being able to settle cases at reasonable returns.

If you think about where the commission is on returns these days, if you work through just the formulas, the dividend growth formula that use for proxy groups in the world of low interest rates, you can come up with a little pressure downward on a live returns. But over the long term, if you look over a 10 to 15-year period, relatively to those formulaic crisis, the commission has tended to dampen those returns both on the upside and downside, so that when we think about regulated type returns, we’re in the 14% to 15% range pretax return on capital.

Steve Maresca – Morgan Stanley

Okay.

Jim Yardley

And we’d expect something like that here.

Steve Maresca – Morgan Stanley

And my second and final question – I’ll get back in queue – is related to the drop down and J.R. already about keeping the foot on the accelerator. So part of it is, what is the delay I guess from timing wise in doing an equity offering and getting something done in the drop down? And as a part of that, you talked about being potentially funded for ‘11 by the end of this year, so what does that mean if you do drop downs in ‘11, where does that capital is going to?

J.R. Sult

Yes, Steve, I mean, again, the equity offering that we just did – the partnership did was at most 45 days ago, so we don’t view that as any delay. As you know there is a process what the partnership has to go through, and we remain confident that there will be an opportunity there for the partnership to put the money to work relatively quickly.

When I looked to 2011, the strategy remains intact, and I think the pace of the activity remains intact as well. I mean to the extent that the drop downs are not used for current year requirements into the extent we’re done this year which is what we’re expecting, and I see the bulk of that excess proceeds to El Paso going to pay down debt.

Steve Maresca – Morgan Stanley

Okay, thanks a lot, guys.

J.R. Sult

Thanks Steve.

Operator

Your next question comes from Carl Kirst with BMO Capital.

Carl Kirst – BMO Capital

Hi, thank you. Good morning, everybody. Doug, Jim, just to – on Ruby for a second – actually two questions around Ruby. One, there was the mention of the projects coming online by the end of the year, saving a $100 million. Does that accrue to the benefit of the company? I mean, should we be looking at this as perhaps instead of just the $300 million to $500 million increase at Ruby, that net overall we’re talking more $200 million to $400 million?

Doug Foshee

For the most part, yes, there is a little bit of a mixed bag there, and with some of the capital cost savings goes to customers, but more so to us.

Carl Kirst – BMO Capital

Okay. So it is sharing.

Jim Yardley

You’re talking about the three projects going in service this year.

Carl Kirst – BMO Capital

Correct. Okay, no, that answers that question. The – really kind of what I wanted to go to with Ruby, you mentioned several variables there in your slide, weather, et cetera. Are these things that could also perhaps telescope that project back in by a month or so or should we be reading that as ongoing risks to the June timeframe? And now that we are in this renewed timeframe that we’re – updated timeframe, what are the milestones here if you could help us out with that?

Jim Yardley

Well, first of all with respect to the weather risk, there is sort of upside and downside to that. When we say June, it is highly dependent on weather to the extent we have a benign winter, we can do better than that, and likewise doing the other way. But – so that’s the way I’d answer that. I think of the different risk that we face, we are at a formidable stage I’d say, we’re well underway in construction. But with respect to milestones, we’re going to know a lot more when we get into say February, March, maybe January, February, March.

When you think about Ruby construction, you ought to focus on three variables. One is winter weather and what that means with respect to construction productivity. A second is where we are on all these cultural clearances. And as I say, we’ve made some very good headway just in the last few weeks on that and we expect continued progress. And finally, there are different biological windows with respect to when you can build and when you can’t build to avoid migratory birds and the like.

The biggest near term weather window we have their concerns big game to the extent we have a normal winter. We think that we ought to be able to work through some of those big game windows. And if it were more severe and some of the Elk or whatever had to come down and do some grazing on lower areas without some more issues, so – but those are the three things to look for. But I think you can tell that over the course of the next month or so we’ll know a lot more.

Carl Kirst – BMO Capital

Yes, I know, I appreciate all of that. Is there an analog? If I recall correctly the original operating construction timeframe had, for instance, pipe being laid in and around the November timeframe. Is there an analog now? I mean, should all of that pipe, in order to meet the June timeframe be laid by April 1st or would it be sooner or later than that?

Jim Yardley

Yes, that’s probably about right. The spreads will complete at different time periods, but you can think about pre tie-in work that we would be complete in and around April. Remember, also, that we have in this build up on capital, we still have a significant contingency is the result of these milestones still lying ahead of us.

Carl Kirst – BMO Capital

I appreciate the color, guys.

Doug Foshee

Thanks.

Operator

Your next question comes from Xin Liu with JPMorgan.

Xin Liu – JPMorgan

Good morning.

Doug Foshee

Good morning.

Xin Liu – JPMorgan

Brent, you mentioned you secured frac crew in the Haynesville. How about in the Eagle Ford? What have you seen in terms of costs and have you secured a long-term service contract?

Brent Smolik

Yes, we have a – we’re pretty well covered for our 2011 program and beyond even for Haynesville and Eagle Ford. We may have to pick up the odd frac skid to complete our program, but we’re pretty well covered for those.

The only place we’re looking for frac equipment right now is that West Texas Wolfcamp program, and it’s just because we’re just now in the planning stages of deciding how we’re going to ramp up activity through the year. We’re not seeing – we did those contracts, we talked about it on the last call for both the Eagle Ford and the Haynesville, so we’ve already locked those prices in.

Xin Liu – JPMorgan

Okay. So the cost assumptions you guys had for Eagle Ford in the Eagle Ford shore that would stay the same level for the next couple years?

Brent Smolik

Yes, the only thing we could see there is, as we recontract rigs in the second half of ‘11, and we’re working on that today. And we don’t see it – we still see it in the ranges we gave you on the field tour.

Xin Liu – JPMorgan

Okay. And also any color on that specific problem related to that Wolfcamp well to completion?

Brent Smolik

The main thing that we had there was we drilled the well vertically and logged it and courted in and got a large suite of a log data and rock data that we would use for our modeling. And then we drilled a well horizontally, and in the horizontal completion, we had a tight spot in the casing that we weren’t able to get plugs down to isolate between fracs.

So what we ultimately did is only fracked it one time to be able to get all samples and indications of how well the rock fracked and those kinds of pressures and rates and those kinds of design things. And so we got – we got all the information we thought we needed. We just didn’t get to finish out the fracking and today we’re working on some alternatives where we may not need to use plugs, mechanical plugs, we might be able to isolate it, but viscose type plugs are something like that. And so we’re still work on the utilization for the well bore, but the main thing is we got all the data we needed to be able to do our assessment for the bid sale.

Xin Liu – JPMorgan

Okay, thank you, appreciate it.

Doug Foshee

Thank you.

Operator

Your next question comes from Jonathan Lefebvre with Wells Fargo.

Jonathan Lefebvre – Wells Fargo

Good morning.

Doug Foshee

Good morning.

Jonathan Lefebvre – Wells Fargo

Just on the Wolfcamp, I was wondering if you could maybe talk about the six wells that were near your acreage what you saw there, and I think you mentioned that there were some pretty decent IP rate of 300,000 to 380,000 barrels per day. And just was wondering what was the difference – how do we get there? And then maybe following up on that, there’s also a – some of your competitors talking about moving to 40-acre spacing, is that an option for you as well?

Brent Smolik

Yes, so the reverse numbers – I’m going to take them in reverse order Jonathan – the resource numbers I gave you were based on a 160-acre spacing.

Jonathan Lefebvre – Wells Fargo

Right.

Brent Smolik

And so it’s possible that we’ll ultimately drill on to – ultimately drill smaller spacing, but that only upside for the resources. The industry is sort of a mixed bag right now. We’re still trying to work on what’s the proper orientation to the well, with varying links, you’ve seen different links in the horizontal well and different numbers of fracs across the link to the horizontal.

And so with six wells, we’re really early into at least for this southern part of the trend, we’re really early into it. Because we’ve got these university lands, we’re able to unitize them, we’re going to be able to have lots of flexibility in terms of the length of the laterals that we drill. So we’re going to try to trend for longer rather than shorter as we start off our program here in a month or in a couple of weeks.

Jonathan Lefebvre – Wells Fargo

Understood. And then where do you expect costs can go? I mean, I think there was an estimate out there for $3.5 million. I think on the low end you’re seeing $4.5 million. I mean, when you get into a full development, do you see that cost might be able to go down to that level?

Brent Smolik

Yes, that is the cost that we’re using in our current full scale development economics now. But in the other plays, we’ve been able to improve on our early assumptions that we’ve made just about this from the learning that we have in this program.

Jonathan Lefebvre – Wells Fargo

All right.

Brent Smolik

And I think Jonathan you asked about those offset wells. We’ve seen offset well production well over 400 barrels a day in some of those offset horizontals. So we even think our initial rate assumption which generally translates to UR might be conservative. And one other quick correct while I get the mic is I think I said a Frio County well that we’re testing and the Eagle Ford, so it’s actually LaSalle County well which is the one testing above 800 barrels a day.

Jonathan Lefebvre – Wells Fargo

Yes, okay. So while we’re on the Eagle Ford maybe we can jump to the JV and just maybe you can talk about your interest in the type of JV, whether it be more on the oil or gas side? Do you have a preference? Is all the acreage on the table kind of timing and maybe what the capital might be used for?

J.R. Sult

Yes, I think, first of all of the options are opened to us right now. I think it’s likely that in today’s gas price environment there’s obviously going to be more interest in acreage that’s oily rather than gassy, and so we’ll take that into account. In terms of what that might ultimately be structured as and how much cash and how much carry and what, we’re going to be driven by the economic outcome to El Paso.

And I think you can sort of mentally think about any cash proceeds in effect paying for our entry into the Wolfcamp. But if you think about capital as being fungible, then it’s incrementally helping us with our 2011 capital program, which then allows us to get balance sheet repair more quickly from sources of capital from other sources of capital from other sources of capital.

Jonathan Lefebvre – Wells Fargo

Appreciate that. And then just moving to Brazil quickly, I know you got the Pinauna Project. Is that – timing on that, is that still fourth quarter or has that been pushed out at all?

Doug Foshee

We’ll answer that one and then we move on so other people with ask questions.

Jim Yardley

So Jonathan, I think that we clearly lost a little momentum with all the elections going on, their national elections are going on just like ours, and they had a runoff to the President. And so things got pretty sluggish, but we think we’re going to pick back up the attention that we’re getting on that permit. But we’re not going to get it by the fourth quarter of this year, it will drag into next year.

Jonathan Lefebvre – Wells Fargo

Yes –

Jim Yardley

[inaudible] we’re doing on that project if you think about it is we’re just advance it at whatever pace it takes to get it done and create an option for us to able to develop the project or take a partner or sell it or whatever we choose to do with it.

Jonathan Lefebvre – Wells Fargo

Right. Thanks, guys. I appreciate it.

Doug Foshee

Yes, thanks.

Operator

Your next question comes from Craig Shere with Tuohy Brothers.

Craig Shere – Tuohy Brothers

Hi. Thanks for the call, guys. One question for Brent. Did I hear you say that the majority of the drilling now is in the northern oily section, because I thought you had more rigs in the kind of middle condensate section? And then for Jim, can you comment about the effect of efforts to move underutilized gas pipelines into Midstream, what that effect has on the ability to get rate relief, and what the comparable returns might be if they went in the Midstream section?

Brent Smolik

You’re going to take second first or first – so just to answer your question, the rigs that are currently going right now Craig are what we call Central. It’s basically LaSalle County, the heart of LaSalle County is where we’ll have most of our activity. Those wells are effectively oil wells. They’re oil in the reservoir.

If you get on the southern edge of that block, you get into the more condensate area, and so that the gravity goes up a little bit. But if they’re very oily all across LaSalle County and that’s where most of our activity will be and then we’ll pilot test northern Frio and Atascosa County, we’ll work those in. What I meant to say about that was we won’t drill very many gas wells.

Craig Shere – Tuohy Brothers

Understood. But you only have one rig working in the northern section right now.

Brent Smolik

Right.

Craig Shere – Tuohy Brothers

Okay.

Jim Yardley

On the underutilized capacity question, so right now, for example on TGP, we probably have – probably about 250 to 300 today of unutilized capacity going up through say Tennessee, Kentucky, Ohio, to the extent we’re able to utilize that and of Mark’s midstream projects. Obviously that helps, it helps to the extent that in one form or fashion we’re getting a return on that capital, whereas today it’s if we’re getting it all it’s heavily discounted.

Craig Shere – Tuohy Brothers

And so this would all be incremental if it was able to be utilized in another fashion, and you don’t anticipate recouping meaningful returns on these underutilized sections through the rate process?

Jim Yardley

Well, we’re – I think the way to answer that is we’re mindful competition, at the same time we’re filing these rate cases, so that to the extent it’s used in midstream, I think there’s a much higher probability for getting a reason to return on that piece of pie.

Craig Shere – Tuohy Brothers

Okay, thank you.

Operator

Your next question comes from Tim Snyder with Citigroup.

Faisel Khan – Citigroup

Good morning, it’s actually Faisel from Citi.

Doug Foshee

Hi Faisel.

Faisel Khan – Citigroup

How are you doing? A couple of – few quick questions. One on EPNG and the pipeline, Jim, you talked about volumes being down because of the California economy. I was wondering if more that also has to with the weather in California and the snow pack levels, and if that’s what’s driving the volume metric declines, not the economy?

Jim Yardley

No, the economy tends to be I’d say, a decline year-to-year the economy is probably close to half of the decline with the other half being a mixed half of imports in the California from those LNG coming into Costa Azul, as well as Canadian imports coming in and effectively displacing Southern California needs.

Faisel Khan – Citigroup

Got you. And on the E&P side, G&A costs – I’m sorry, cash costs come down, and it looks like a lot of that came out of G&A costs and of course lower taxes too because of commodity prices. Can you give us – elaborate a little bit what drove down sequentially your G&A costs quarter-to-quarter?

J.R. Sult

Mostly there is nothing in there that’s unusual that we had bonuses in the first half of the year from last year that we don’t have in the third quarter here. And then otherwise it is just managing with a small workforce.

Faisel Khan – Citigroup

Okay, got you. And then in the Eagle Ford, what’s your production right now in the Eagle Ford?

Brent Smolik

The total we have is about 2,500 barrels of day of oil and about 7.5 million a day of gas and that’s gross.

Faisel Khan – Citigroup

Okay, got you. And if I am looking at your upper Wolfcamp economics, is it fair to assume that given the net reserves and the well costs you’re looking at $22 per BOE in development costs? Is that the right way to look at it?

Brent Smolik

The way it works out on gas, $5 million at the midpoint is what I would use if you want to pick a number, $5 million were well cost.

Faisel Khan – Citigroup

Okay, got you. And then I think one – go ahead.

Doug Foshee

Faisel.

Faisel Khan – Citigroup

Yes.

Doug Foshee

Faisel we got two questions and we’ve got folks.

Faisel Khan – Citigroup

Okay.

Doug Foshee

We’d appreciate it.

Faisel Khan – Citigroup

Fair enough, thank you.

Brent Smolik

Thanks Faisel.

Operator

Your next question comes from Holly Stewart with Howard Weil.

Doug Foshee

Good morning, Holly.

Operator

Holly, your line is open.

Holly Stewart – Howard Weil

Good morning, guys.

Doug Foshee

Hi.

Holly Stewart – Howard Weil

Quickly, just following up on the line of Eagle Ford opportunities. I mean you seem to have a pretty unique position here in terms of your size of your acreage block, your services are locked in, you’ve got a Midstream business to support your activity here. So can you just talk about where you stand in the process and kind of what your expectation is on timing if there is any?

Mark Leland

Are you talking about with regard to a JV.

Holly Stewart – Howard Weil

Yes.

Mark Leland

Yes, I think there is a chance that we could know what we’re going to do by the end of the year and I think our best guess would be that we’d actually transact sometime early 2011.

Holly Stewart – Howard Weil

Perfect. And then just my follow-up. Bigger picture question, Doug, is just really you guys have a unique look at the natural gas market given your pipeline business and you’re really shifting your E&P opportunities towards oil. So what does that say really about your longer term outlook for natural gas?

Doug Foshee

I don’t know that it necessarily says a lot about our long-term outlook for natural gas. I think what it says about the near term is that we think that there is a good change that natural gas prices are going to stay relatively low for certainly for 2011 and into 2012.

And when they rebound in our view is sort of some combination of the recovery of the US economy, so GDP going up for some sustained period of time, the beginning of the impact of old coal retirements, and the contingent fall off in exports from Canada. And how you assess the timing of that is, I mean there’s a great deal of uncertainty.

I looked at four or five of the big forecasters of just of US production for 2011 and I think by the end of the year they diverse by about 5 Bcf a day and a kind of a 60 Bcf a day market. So there is a lot of uncertainty.

I think what we’ve tried to do in position ourselves so that we’re not losing the optionality that we believe exists on at very favorable macro for gas in the long term, and in the interim we’ve got the ability because of the repositioning of our E&P portfolio to take advantage of a favored commodity right now in oil. We think that’s the right thing to do.

Holly Stewart – Howard Weil

[Inaudible] Doug.

Doug Foshee

Yes.

Mark Leland

Thanks Holly.

Operator

Your next question comes from Kevin Smith with Raymond James.

Kevin Smith – Raymond James

Hi, good morning, gentlemen. Thank you for taking my call.

Doug Foshee

Hi Kevin.

Kevin Smith – Raymond James

Just two questions on the Haynesville. First, can you discuss your well backlogs and where we’d look at that as far as drilled but not completed. And then secondly, can you talk about your EURs, Haynesville EURs in a $4 gas environment versus a $6 safety dollar environment, how sensitive they are? Thank you.

Brent Smolik

The EURs I don’t think they’re going to be very sensitive. The operating expense if that’s what you’re getting at is really low in the Haynesville and will stay low even in the late life when we’re running out in compression especially for us, because remember we’re drilling it under the old Holly field.

So I don’t think we’re going to see any late life truncation much of reserves, because we’re even in late life we’re going to be less than $0.50 a unit and today we’re more like $0.10 a unit for operating expense for the Haynesville. So I don’t think it’s sensitive to price at all. For us, it still kind of 6 to 7 Bs is the number that we think out for the core and of the Holly. What was the first question?

Doug Foshee

In terms of backlog.

Brent Smolik

On the backlog, as I said in the prepared comments, we’ve got it down to 12, and we’ll probably run in that kind of 8 to 12 range, because we need some amount of backlog to efficiently schedule all of the completion activities. But we’ve gotten up to about 19 wells in the backlog. So you can’t see it on the production chart that we included in the slides, because it’s Q2, Q3, but we’re going to see a step up in Q4, because we’re working that backlog off faster than we were in the third quarter.

Kevin Smith – Raymond James

All right. Thank you very much.

Jim Yardley

And our current volumes are up 40 million a day from third quarter on average.

Operator

Your next question comes from Mike Cerasoli with Goldman Sachs.

Ted Durbin – Goldman Sachs

Hi. It’s actually Ted Durbin from Goldman. Just a quick one. On the Ruby pipeline, are your contracts impacted at all by the delay? In other words, the returns here on the project going to be impacted just on the cost side or is there anything on the revenue side?

Jim Yardley

On the cost side – well, first of all, let me just make a – maybe this is where you’re going. But we have had on the cost side with our major contractors, we’ve had incentive based contracts. We still have incentive based contracts. In fact, we’ve just reformulated them given the delays that were outside the contractors control, we have put in place just recently new incentive based contracts with new target prices.

And the benefit – the value of going through that is that we’ve had now with four very highly respected contractors all of who are working on the Ruby, together with our own experience we’ve built through the one as you know Mike. But so, we have now a lot of commonality about expectations and incentives in place to perform. So to the extent we do better than target, that each contract does better than target, the capital cost comes down. So – am I responding to your question?

Ted Durbin – Goldman Sachs

Yes, no, and I was just – actually on the revenue side of actually your contracts with your – with the shippers themselves, is there any impact there to the delay?

Jim Yardley

The answer is no.

Ted Durbin – Goldman Sachs

Okay. Just checking.

Jim Yardley

Sorry about that.

Ted Durbin – Goldman Sachs

That’s all I had. Thanks.

Operator

Thank you. I will now turn the conference back over to Bruce Connery for closing remarks.

Bruce Connery

All right. Thank you for your questions, thank you for taking time with us this morning. We hope that you agree that our execution and the strategic steps we are taking are creating value for our shareholders and we hope that you will join us for Altamont call on November 18th. Thank you.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY’S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY’S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY’S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: El Paso CEO Discusses Q3 2010 Results – Earnings Call Transcript
This Transcript
All Transcripts