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Executives

Bruce Connery - VP, IR & PR

Doug Foshee - President and CEO

Mark Leland - CFO, EVP

Jim Yardley, President and CEO

Brent Smolik - EVP, President

Analysts

Rick Gross - Barclays Capital

Carl Kirst - BMO Capital

Lasan Johong - RBC Capital Markets

Shneur Gershuni - UBS

Faisal Khan - Citigroup

Nathan Judge - Atlantic Equities

Holly Stewart - Howard Weil

Pavel Molchanov - Raymond James

El Paso Corp. (EP) Q2 2009 Earnings Call August 6, 2009 10:00 AM ET

Operator

Good morning, my name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the El Paso Corporation second quarter 2009 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). Thank you, Mr. Connery you may begin your call.

Bruce Connery

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

Throughout this call we will be referring to slides that are available on our website at elpaso.com. This morning we issued a press release and filed it with the SECs and 8-K. It is also on our website.

During the call we will include certain forward-looking statements and projections. The Company has made every reasonable effort to ensure the information and assumptions of which these statements and projections are based are current, reasonable and complete.

However, variety of factors could cause actual results to differ materially from the statements and projections expressed in this call. Those factors are identified under the cautionary statement regarding forward-looking statements' section of our earnings press release as well as other of our filings with the SEC. And you should refer to them.

Company assumes no obligation to publicly update or revise any forward-looking statements made during this conference call or any other forward-looking statements made by the Company whether as a result of new information, future events, or otherwise. Please note that during the call, we will use non-GAAP numbers, and we have included a reconciliation of all non-GAAP numbers in the appendix to our presentation.

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

Doug Foshee

Thank you, Bruce, and good morning. Q2 was a really good one for Team El Paso. To start, we had good financial results in a tough environment. Adjusted EPS for the quarter was $0.25, and this doesn't account for the benefit of our oil hedges. We taxed those out last quarter for a $186 million in cash, but the benefit associated with those hedges for Q2 had we held them to maturity adds another $0.04 to get us to $0.29 in total.

We also kept our liquidity strong. We were free cash positive through the first six months of the year, and in spite of repaying a $1 billion bond maturity in May and funding our capital spending program, we ended the quarter with $2.3 billion in liquidity.

Mark will explain in more detail, what it took to get there, but our capital markets team had a very busy quarter with multiple transactions [under the dollar]. The pipes had another strong quarter with EBITDA 11% and throughput up as well even in a market with overall lower demand.

As we foreshadowed in last quarter's call, we secured a long-term partner for 50% of the Ruby Pipeline, we continued a string of bringing in new projects on time and on budget. And as pleased as we are with our current backlog, we believe we'll continue to add to that growth in the core areas of our franchise.

The E&P business had a really outstanding quarter, as well. Volumes were strong at $777 million a day, in spite of a 50% reduction in CapEx, and a delay in the startup of Camarupim in Brazil.

This was driven by good performance across the board domestically, highlighted by continued success in the Haynesville. Unit cash costs were down 16% in spite of a reduction in volume. And the Team continues to grow inventory both on existing acreage and through new acreage acquisitions that we'll share the details of as the year progresses.

I spoke last quarter about our view of the two key externalities affecting our business, natural gas prices and capital markets. Our views haven't changed since then, so I won't rehash them in detail. But in general, we still see risk in gas prices over the next two or three years. And while our capital markets have improved, we don't have conviction yet that this improvement has a nascent long-term recovery and not just something more fragile.

So our strategy given those two premises hasn't changed. Job one for us as a Company is to complete our pipeline backlog on time and on budget. People in the pipeline business dream about having the opportunities we have in front of us, and will stay laser focused on making sure we create value for our investors, from what we believe is the largest and best such backlog in the business.

In that vein, actions speak louder than words so we'll continue to share with you our performance on these projects as they come into service. We believe, we have an opportunity to distinguish ourselves in this regard, and we added to that with two more projects and service quarter on plan.

In the next 12 month, we have close to $1 billion in backlog coming online, and right now we anticipate that being on time and on budget.

In this commodity price environment, and in spite of our substantial hedge position, we're being caution us on E&P drill that spending and focusing only on our most economic areas. Right now, those are the Haynesville and our Altamont oil property. In both cases our Teams have made meaningful improvements in cost and in project execution, and we expect to continue to push the envelope on efficiency gains.

And across the Organization, we have a renewed focus on our organizational effectiveness. This isn't something new, but it's getting a shot in the arm in the current environment. Examples of this include leveraging the investments we've made in our supply chain management over the last three years to push on our supply chain for more cost savings, and better services, implementing an entirely new ERP system called project Delta. This project started 15 months ago and went live yesterday. It consumed a 140 man years of time from over a 100 people inside and outside our organization.

Delta goes a long way toward helping streamline our operations, reducing by half the number of manual reports, reducing by 90% the number of manual queries in the system and moving us from seven general ledgers companywide to one.

In addition to the obvious cost savings, this sets us up to spend more time on higher value-added analysis and planning and far less time on manual data mining. This was a seminal event for El Paso and I want to probably thank Russell Jackson and the entire Delta team for getting this one across the finish line.

And we're restructuring parts of our business to get both cost reductions and improvements in our effectiveness like the work completed last quarter in the operations group in E&P. These kinds of things are key to us continuing to improve our overall returns and prospering in a much more challenging environment.

And finally, we continue to look for opportunities to mitigate our risks and the risk to our investors to any downside and natural gas prices or in capital markets. That's why we put substantial hedges in place for 2009, 2010, and 2011 by trying to retain as much upside as possible, acknowledging that our crystal ball on prices in the near term is supposed. And that's why we've continued to be aggressive in accessing capital markets to secure funding now for future growth.

So with that, I'll turn the call over to Mark and come back at the end to wrap up. Mark?

Mark Leland

Thank you, Doug, and good morning, everyone. I'm starting on slide 8. As Doug mentioned, we're reporting adjusted earnings per share of $0.25 compared to adjusted earnings per share of $0.39 for the second quarter last year.

I'll cover the adjustments on the next slide. Reporting earnings per share for the quarter was $0.11. Key drivers affecting second-quarter earnings were lower commodity prices. Compared to the same quarter last year, natural gas prices on physical sales were down 69%, and even after factoring in the benefit of our strong hedge position, gas prices still were down 26%.

Offsetting the lower prices, however, were Pipeline EBIT that was up 11% and lower cost from the E&P segment. Jim and Bret will provide more color on business unit performance in a minute.

The items impacting earnings this quarter are highlighted on slide 9. The first adjusting item is the sealing test charge from a dry hole drilled this quarter in Egypt totaling $12 million or $0.01 per share. The second item is the $21 million pretax or $0.02 per share non-cash mark-to-market gain in the legacy power book primarily due to narrowing PJM basis.

The third item is a small mark-to-market loss in the legacy natural gas book. The fourth item is a $25 million pre-tax gain associated with a Legacy in [dandification] related to the sale of an ammonia facility.

The fifth item is a $22 million pre-tax for $0.03 per share adjustment for the loss on the sale of a note we acquired as partial consideration for the sale of our Porto Velho plant in Brazil.

And finally, we're adjusting for the impact of hedging in E&P segment which totaled a $151 million pretax gain or $0.14 per share. This adjustment consists of the exclusion of $55 million mark-to-market gain on financial derivatives and the add-back of $206 million of cash settlements in the quarter.

Making these adjustments bring adjusted EPS to $0.25. Not included in the $0.25 is the benefit of $0.04 associated with the early settlement of our oil hedges which we realized in the first quarter of this year. The $0.04 represents the amount that would have been recognized this quarter if those hedges would have remained in place.

Slide 10, highlights our business unit contribution on a combined basis. Our pipeline in E&P businesses generated $593 million in EBITDA and on an adjusted or proportional EBITDA basis, $651 million.

Both before ceiling test charges. Adjusted EBITDA is calculated with our 50% interest in Citrus and our 49% interest in Four Star on a proportional basis.

Marketing recorded EBITDA of $10 million, and I'll provide more detail on that in a minute. Power EBITDA was $21 million loss due to the sale of note I highlighted on the previous slide, and corporate EBITDA was $35 million due primarily to the ammonia indemnification mark-to-market gain I noted on the previous slides.

There's a chart in the appendix that provides the relevant details for adjusted EBITDA cancellations. The marketing segment is summarized on slide 11. This is the fourth consecutive quarter of improved results for this business. The book continues to shrink as contracts roll off which is contributing to smaller and less volatile earnings in the segment.

In fact, we'll likely move this slide to the appendix beginning next year. The primary driver for marketing EBIT this quarter is the $21 million mark-to-market gain in the power book due to the narrowing PJM basis.

I'm now turning to cash flow on slide 12. Our cash flow from operations for the first six months was just under $1.2 billion. Compared to $1.3 billion last year in a much stronger price environment.

Year-to-date CapEx was $ 1,363 million, we have generated $300 million in divesture proceeds and dividends and distributions were $89 million. So we continue to be slightly free cash flow positive this year.

Key drivers in our free cash flow position so far this year have been the flexibility around our E&P segment, CapEx, and our hedge position. As you'll see in [Brent's] slides, year-to-date E&P generated $739 million of adjusted EBITDA and $95 million of divestiture proceeds and spend $547 million in CapEx.

For total contribution of free cash flow of $287 million. We continue to make significant progress on the financing front which is highlighted on slide 13. Since our last call on May we've secured a partner for Ruby who will contribute up to $700 million in equity to the project. We hired a financing advisor for the project, and we're working with them to develop the ultimate financing strategy prior to receiving certificate which is expected in late first quarter next year.

We completed the drop down sales to El Paso pipeline partners. Our MLP which raised $215 million in cash for the parent. We've paid off those May maturities leaving no material maturities in 2009 and only approximately $250 million of maturities in 2010.

We also completed $315 million of new financings, $165 million project loan at the Elba Express pipeline and we added $150 million to our LC facility to accommodate for those that are expiring this year. Total we raised $1.23 billion since May, so we continue to stay out in front of our capital needs.

The results of these financing activities have left us in strong liquidity position which is highlighted on slide 14. After paying the $1 billion in long-term debt maturities in May, we closed the quarter with $2.3 billion of liquidity compared to $3.3 billion at the end of last quarter. Given our spending profile for the last half of the year and despite low gas prices we expect to end the year with liquidity in the $1.6 billion to $1.7 billion range, which should be sufficient to carry us well into 2010.

Our natural gas hedge positions through 2011 are summarized on slide 15. To protect our balance sheet and fund our pipeline growth projects, we've done more hedging over the next 30 months than we have historically done. We have about 70% of our 2009 domestic gas production floor at just over $9 per MMBtu.

If we produce the same volume in 2010 and 2011, as we will in 2009, we'll be about 75% hedged at a floor of $6.41 with a ceiling of $7.24 in 2010, and in 2011 we'd be about 60% collared with a floor of $6 and a ceiling of $8.66. All of these positions look pretty good in relation to today's forward strip, and if we're wrong on price, we have plenty of upside with our ceilings and unhedged production. More importantly, we have significant downsized production in the event of a long, low natural gas environment.

So to wrap-up, we had a very nice quarter from an operating results standpoint. We had solid earnings and cash flow in a tough operating environment. In fact, we're free cash flow positive so far this year. Our liquidity is strong. We continue to make excellent progress on financing our pipeline growth projects. In addition, our hedge program, coupled with our stable pipeline earnings, gives us a nice base of earnings and cash flow over the next several years even in a low gas price environment.

All-in-all, we're in excellent position to deliver the growth associated with our pipeline backlog while maintaining our opportunity set in the E&P business.

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

Jim Yardley

The pipeline has had a busy and successful second quarter. Financially, we delivered strong results. Throughput increased primarily from expansions, which offset the impact of the economic recession and we continue to make good progress on executing on our backlog of growth projects.

As Doug said, we placed two more in service on time and on budget. On Ruby, in addition to bringing in a partner, we also received our Draft Environmental Impact Statement from FERC, which is a major milestone and are on track to receive our final EIS this fall and FERC certificate early next year. Also, we filed our FERC application on the TGP Line 300 expansion.

Slide 18 reviews our solid growth for the quarter and year-to-date. EBIT was $327 million, up $32 million from second quarter 2008, an 11% increase. The EBIT increase was driven by both higher revenues and lower operating costs. The revenue increase resulted primarily from the new expansions. The lower operating costs were broad-based across both our field organization and on the office, and reflect ongoing efforts to manage our costs in this environment.

You see the numbers for EBITDA, also adjusted EBITDA for our 50% interest in Citrus. Note that adjusted EBITDA year-to-date is right at $1 billion. Capital expenditures of $392 million in the second quarter are comprised of about $311 million spent on the pipeline growth projects and the remainder on maintenance capital and hurricane repairs. The increase from second quarter 2008 is due primarily to higher backlog spending, mostly Elba Express and Ruby. So, a solid second quarter and year-to-date results for the pipes.

Slide 19 summarizes our throughput year-to-date. In short, increased throughput from the expansion projects placed in service in our Rockies pipelines offset the declines in market area demand elsewhere. The most significant Rockies expansions are CIG's High Plains expansion into Denver that started service last November, and [Wicks] Medicine Bow compression expansion out of the Powder River.

In the Northeast, we've had a very mild summer which has contributed to throughput declines on TGP. Warmer than normal weather in the Southeast has driven higher power gen loads on SNG, also due somewhat to fuel switching from coal. Industrial demand continues to be down, but not to the degree experienced earlier in the year.

On EPNG, throughput is down in Arizona, especially due to the economy, but also to the startup of a competitor's lateral into the Phoenix area. Just a reminder, throughput, although we track it closely, has only a minor impact on our revenue since our revenues consist predominantly of demand charges.

The next four slides update you on progress on executing on our growth backlog. On slide 20, this map of TGP system in the Northeast reviews our Line 300 expansion project, and in addition shows that TGP is well positioned to capitalize on new supplies developing in the Marcellus trend in Northeast Pennsylvania.

The Line 300 expansion is fully subscribed with Equitable for a 15-year term. The expansion, which consists of additional compression and looping of the existing pipeline, will move Equitable's growing Appalachian production in Kentucky and West Virginia to markets in the Northeast.

As the result of today's lower steel prices and contractor costs, our estimated CapEx is now approximately $600 million, down from $750 million. As I mentioned, we recently filed the FERC certificate with FERC. We expect the certificate next year, and after construction in 2010 and 2011, the expansion will go into service in late 2011.

Separately, Line 300 runs right through the heart of the Marcellus play in Northeast Pennsylvania. We're in the process of installing interconnects for several producers. The combined capacity of these interconnects into TGP will be approximately 2 Bcf a day. At the eight interconnects just recently installed, 80 a day is already flowing into TGP.

Under FT backhaul agreements recently executed with two producers, demand revenues will ramp up from approximately $7 million to $8 million this year to $40 million to $50 million annually by 2012. No additional CapEx is required to accommodate this backhaul business. Finally, Line 300 is well situated for further forward-haul expansions to the Marcellus in the future.

On slide 21, we updated our backlog each quarter for your reference. With the sale of a 50% interest in Ruby, the backlog is now just under $6 billion pro rata to El Paso's interest. This slide shows our capacity capital cost estimates and in service dates for each project. The only significant change this quarter is the reduction on the CapEx estimate for the TGP Line 300 expansion as I mentioned. As we continue to move these projects along, we grow more confident that we'll bring them in on-time and on-budget.

Slide 22 is a picture of how the composition of the backlog will have changed over the course of one year from the end of last year to the end of 2009. As you can see, the remaining capital net to El Paso's interest will have decreased by yearend from $6.5 billion remaining to $3.4 billion. This is due to the sale of a 50% of Ruby and spending in 2009. Of this $3.4 billion at the end of the year, over 40% will be funded from the project financing already in place at Gulf LNG, financing at FGT, which is investment grade, and the project financing at Ruby that Mark mentioned.

Also, the make-up of the backlog has changed where Ruby represented nearly 50% of the remaining CapEx, it now will represent approximately one third. And another point, the backlog in aggregate is approximately 90% subscribed with an average term of 20 years.

Slide 23 is a listing of the backlog projects that will go in service in the next 12 months. They represent nearly $1 billion of total capital, and as they now get closer to completion, we fully expect to bring them in service on time and on budget.

In the fourth quarter, we'll place in service two compression expansions that are now well along in construction. One is on WIC PiceanceLateral and the other TGP in New Hampshire. We'll also complete the drilling of additional injection wells for the Totem Storage project on CIG for Xcel Energy.

Then in early 2000, we are placing service both the Elba Express pipeline and the Elba expansion for Shell. Elba Express is our largest pipeline construction project this year and construction is ahead of schedule. At Elba the vaporization expansion will be completed in the first quarter of 2010, and the storage tank if construction is right on schedule as well will be ready later in the year as planned.

A 100% of the capacity in all five of these expansions is fully contracted under long-term contracts.

So in summary the pipes had an excellent quarter, both financially and operationally, and we're highly focused on executing on our growth backlog delivering these projects on time and on budget.

And I'll now turn it over to Brent.

Brent Smolik

Thanks, Jim. Good morning, everyone. As we discussed on our last call, E&P got off to a strong start for the year, and we continued to have momentum through the second quarter. Starting on slides 26, second quarter production averaged $777 million a day, I'm really happy with the domestic US part of our productions.

Production was up here well in spite of our drilling activity and our capitals being normal of what we where a year ago. Clearly we are benefiting from our Haynesville program, but we've also found ways to spend modest amounts of capital to optimize our production throughout our domestic programs.

Our unit cash costs were down significantly, which is always a win. But especially so in a flatter or declining production phase. I'll give you an update in a moment on the overall declines in service costs, but back in May, I indicated that we were seeing large drop in costs, and we continue to see those cost reductions right through the quarter.

On the capital front, we continue to manage our portfolio for changes in commodity prices and service costs and are bias on capital spending since the first quarter has been to lower end of our guidance. And we now expect our 2009 capital to come in around a $1 billion.

As Doug's often noted, one of the benefits of our integrated model is capital allocation flexibility between our business units. We're generating a significant amount of free cash today that can help Jim fund pipeline projects which is the right thing to do in the current E&P down cycle.

For the full year, we are maintaining our 730 million to 800 million a day production range. And finally in Brazil Petrobras now expects Camarupim to start up later this month.

On an annualized basis the Camarupim delays will cost us about $25 million a day, but better than expected domestic production has made up much of the shortfall so far for the year again that's why I'm so pleased with the domestic performance of our team.

Let's move to slide 27. As Mark said, our EBIT was down due to charge off in natural gas and oil prices, which was offset by lower DD&A and lower cash cost. There is a lot of numbers on this chart, but there is a few worth highlighting.

First note that our second quarter capital is roughly about half what it was a year ago. And second, if you look at the adjusted EBITDA and CapEx for the first six month period you can see that our EBITDA is exceeding CapEx by about $200 million. And then close down that column we've generated about $95 million from divestitures in the first quarter which also contributed to our liquidity.

Moving to slide 28, where we show two panels. On the left side, I noted earlier that we've produced $777 million a day in the quarter. As expected, the Gulf Coast division declined because we've allocated significantly less capital here since the third quarter of last year.

However, you can see that our western division production has held up well, and our central division production grew again in the second quarter to $326 million a day. Remember the assets in these two divisions, western and central, tend to be the more unconventional historically CBM and tight gas focused more recently focused on Shale gas.

Over the last few years there has been a real shift in capital allocation and production which evident by the chart on the right side of the page. In a matter of a few years production from unconventional type resources risen from 40% level to about 60% of our total production.

As a big move and based on our current project inventory I expect that trend to continue going forward. Slide 29, summarizes our operated rate count at the end of each quarter going back to the beginning of 2008 in our projections for the remainder of the year.

We're well into the third quarter, and it looks like we'll close the quarter with about five or six rigs running. Three or four of those are going to be in the [alcotex], one in the Altamont field, and one in South Texas. Depending on what our capital program levels out, we'll have somewhere between two to six rigs running at year end. And at the low end of that range, we'd only have a couple of rigs running at the Haynesville, at the high end of that range our activity would look a lot like it does today.

We'll keep you posted on how the E&P capital works out. But our focus in any case continues to be on ensuring that we create value as in the current cost and commodity price environment.

As I mentioned earlier, our per-unit cash costs look great for the quarter which is shown on slide 30. Total cash cost were down $0.32 from the first quarter, and remember that this is an improvement in spite of lower production levels.

Two things have taken place. First, we're clearly in a cost inflationary environment, which is a clear benefit. Second, last quarter, I mentioned that we completed a reorganization, which included the formation of a single US domestic light operations crew. Our team there is starting to realize the early benefits of that organizational shift, and I think we'll have more savings and efficiencies to come.

You'll notice that unit G&A is up from the first quarter from last year. Last year we benefited from a few unusual items, for example, some pension credits. First and second quarter this year, included in our organizational restructuring charges, negatively impacted the first half of the year by about $0.05. For the rest of the year, I expect us to be in the mid to high $0.70 range depending on production volumes.

Overall, I'm very happy with our progress in reducing our cash cost in the current environment.

The table on slide 31 shows the reduction that's we've achieved in various service and equipment categories. These reductions are benchmarked against our 2008 average cost for these same categories, which together represent about half of our capital spending. Many of the reductions were fully in place throughout the second quarter, and while the pace of the cost reductions have slowed some, utilization rates of most of these services and equipment are still down significantly. So we believe there's still more reductions to come in the second half of 2009.

Slide 32 recaps our Q2 activities in Brazil and in Egypt. As you know, Petrobras at Camarupim and they've been working to overcome some challenges with getting the wells tied-in and getting the development projects up and running. They're now planning to start up this month. We expect production will start about 20 million to 30 million per day equivalent net to El Paso and then we'll ramp up to $50 million to $60 million a day over the rest of the year as the additional wells are brought online.

We've continued to progress the Pinauna oil development project through the environmental process and we're revising the project costs as those costs have been coming down as well in the current environment. Jequitiba is a Petrobras operated exploration well that's been drilled with some encouraging results and is currently still under evaluation.

Switching to Egypt, we found hydrocarbons in both wells drilled by Sepsa on the South Alamein Block. These wells were drilled on separate structures and we're in the process of testing the second well to determine the production capacity and to determine if the finds are sizable enough to develop commercially.

In our EP operated South Mariut Block, we drilled a second dry hole in the quarter and we've suspended drilling there for the rest of this year. Remember this is a large concession and we really shot at 3D over a portion of the block. So we're now considering shooting additional seismic later this year or early next year in other areas of the block, which we'll then use to determine our drilling plans for 2010.

We're also working through the mapping and analysis of the Tanta Block, which is just east of our block, and developing our 2010 drilling plans on that block as well. So although the early results in Egypt have been somewhat mixed, remember this is a higher risk, higher potential area where we still have 1.5 million net acre position in those three onshore concessions.

Let's turn back to the US part of our business and focus on North Louisiana on slide 33. The news from the Haynesville continues to be good. Since our first quarter call we've brought on three more wells and I'll update those in a moment. We've always liked our Haynesville lands, but in our opinion though the position has continued to improve as we drill and complete more wells.

The shaded area on the outlined display is the boundaries as we see it today roughly. We've got more than 40,000 net acres in the play, most of which is held by production. There has now been enough industry drilling in the play to identify some clear trend, and the area in the red outline is where we're seeing the highest initial production rates.

Wells inside that boundary have tested well over $15 million a day and most of the highest rig wells, and we believe the highest reserve wells, have been drilled on that trend that goes from the Texas border through Desoto Parish into the area where Desoto, Caddo, Bossier, Bienville and Red River parishes all come together. That trend lines up very well with our acreage position. So the bottom-line is that with 250 to 300 potential locations in that part of the play, we expect to drill a lot of good Haynesville wells.

The net on this potential that we see here is over 700 Bcf. If we drill four wells per section, it's over 1 Tcf if we ultimately develop on denser spacing.

Turning to slides 34, we now have nine wells on line. It's three more than our last call. All of them are very good. As the top right panel indicates, we've got enough wells producing in the area where we're starting to get a good idea of the tight curve for the wells. Certainly, we'll get more accurate as we put more time on this picture, but we're beginning to see wells flatten out at and around 150 day mark or so, and we're improving on our ability to model the long-term performance of these wells.

Currently we're producing almost 40 million a day net to our interest. We're completing three wells. They all appear to be on par with our most recent wells. As I said earlier, we'll maintain at least a few rig program in the Haynesville for the rest of the year. The good news is that we continue to drill and complete these wells quicker and in lower cost, which brings me to the Haynesville summary chart on 35.

We show three sets of data here, which demonstrate our progress going from our first three wells to our most recent three.

In terms of our execution efficiency, we've gone from about $13 million a well on average to below $8 million. That's $8 million to drill, complete, equipped, and get them all the way into sales. Our last well was just a little bit North of $7.5 million. As we've cut our cycle time from over 100 days to less than 60 days, it's almost in half. And all of this while increasing our number of frac stages on average from nine to 11.

And importantly we are seeing increased productivity from the wells and we are not consistently getting $15 million to $20 million a day initial test rate, some even higher. And it looks like we'll end up with total reserves from well in the neighborhood of 6.5 to maybe seven per Bcf per well.

So the bottom line is that we are well positioned with the program, and our drilling and completion capabilities are as good as any of our industry peers.

So I'll wrap on slide 36. No question that we're operating in a difficult environment, but we've got very clear priorities for the E&P Company. On the top of that list is ensuring that we are earning a good return on our capital that we invest so we spend a lot of time updating our drilling inventory with the most current cost data and then prioritizing, reprioritizing our investments.

In this part of the cycle, high returning E&P investment opportunities are limited which is why we're content to spend less and generate more free cash flow.

In the meantime, our teams are busy preparing for the future. We've continuously developed a new idea and our total inventory of drilling projects is up nicely from the beginning of the year. We are also pursuing some interesting opportunities beyond the Haynesville that we aren't ready to talk about today. But we'll be updating you on those in the near future.

So in summary, I'm very pleased with our results and the progress of the E&P Company and the teams that have made through the first half of the year.

With that I'll turn it back over to Doug for his closing comments.

Doug Foshee

Thanks, Brent. To wrap things up this morning, we had a really good second quarter. In fact, operationally it may be the best quarter overall since I've been here. Both business units performed well, we delivered two more pipeline projects on plan, cost continue to come down on E&P, and we saw strong results from our Haynesville and Altamont assets. We secured a long-term partner for Ruby, we kept our liquidity strong and we are continuing to add opportunities for longer term growth in both business units.

Going forward, we'll continue to stay focused on our strategy to bring our backlog in as advertised. Generate maximum returns on our drilling program, reduce costs, and continue to find ways to mitigate against any downside risks to commodity prices and/or capital markets. And with that, we are happy to open it up to your questions this morning.

Question-And-Answer Session

Operator

(Operator Instructions). Our first question comes from the line of Rick Gross with Barclays Capital. Your line is open.

Rick Gross - Barclays Capital

I guess I'd like to start with the pipeline question. I'm kind of intrigued with the whole back haul strategy on Tennessee. I know you've got a deal with Cabot that they claim is around $0.20 back to West Virginia. You've done a deal with Equitable. And I was amazed I guess at the 2b's a day of interconnection. I know there is some compressors that are being hooked up and small lines being tapped in, but can you tell me how that kind of plays out, how you think will cause the displacement in revenue opportunity on Tennessee is going to look as you get, you know, Marcellus production into the line?

Jim Yardley

Yeah. That's a good question. So the thrust of what's going on here is that we are fortunate and that we are right on top of big new supply base, and it's happening. And I think the innuendo in your question is that, well, does this long term displace long haul demand charges on Tennessee. We think it's clearly a net positive. What we are seeing the past, Rick, for example several years ago when Tennessee started importing through Niagara, large amounts of Canadian gas which, by the way, has fallen off a good bit now, but in that case the capacity holders on Tennessee, the utilities in New York State and New England they continue to hold capacity all the way back to the Gulf. Not wanting to rely on just one source. And so we think that that same thing is going to happen here. On the positive side, this is right now the backlogs are incremental revenue that quiet candidly we wouldn't have expected a couple of years ago. But then positively long term to take advantage of demand growth in the northeast while we are right on top of an opportunity to expand very cheaply into New York State and New England. So net we think it's clearly a positive.

Rick Gross - Barclays Capital

Is this capacity going to be actually usable seasonal, or do you think it's going to be usable all year long?

Jim Yardley

Year-round.

Rick Gross - Barclays Capital

Year-round?

Jim Yardley

On a backbone basis.

Rick Gross - Barclays Capital

Okay. Completely different subject. Couple of quick E&P questions. And then I'll give up the mic. What is on Loe. It was down a lot I'm just wondering if aside from some of the things that were going on that there has been a lot less work over activity. How do I kind of filter that into the Loe decline?

Brent Smolik

Yeah, Rick. Remember the spread, remember last year we talked about with high oil prices we ramped up work over activity in the Altamont oil field? But we did a lot of that work last year. And so we had less of it to even do this year. So that's about the only place that we have operationally where we've done less year-over-year or quarter-to-quarter comparison. Everywhere else its activities are essentially the same, and it's been about trying to manage the costs down.

Rick Gross - Barclays Capital

Okay. How about fuel costs, compression cost and all that kind of thing. Is that a big piece has that's come down with gas prices or?

Brent Smolik

It's definitely shows up just about everywhere in the supply chain that has fuel input. So we're benefiting from that as well as some labor deflation and other supplier deflation we are getting. So it's all in the savings. It's not activity driven is what I want you to take away from that.

Doug Foshee

And the other thing I'd add, Rick, is in many cases if not most cases our work over activity still represents some of the highest returns on incremental capital. So that wouldn't be a place we would

Rick Gross - Barclays Capital

Yeah. So I would have thought. Okay. And then the last thing is you have a fairly large position in South Texas, and the Eagleford has heated up. And I'm just curious as is that we'll call it understudy, or is there something more tangible that we can talk about as far as Eagleford either potential or otherwise?

Brent Smolik

Yeah. I mean, you know that as we've got a long history down in South Texas, and we think we're as good of operators down there as anybody. So it would be sensible for us to be studying it and think about it. We are not quite ready to talk about how we view the play, but we're getting close.

Rick Gross - Barclays Capital

Would it be fair to say that you have current acreage held by production that would be suitable?

Brent Smolik

It's going to be West of most of our production, so its going to be grassroots leasing. Would be how we get in.

Rick Gross - Barclays Capital

Okay. Thank you.

Operator

Okay. And our next question comes from the line of Carl Kirst, from BMO capital. Your line is open.

Carl Kirst - BMO Capital

Good morning, everyone, and nice quarter especially in the current environment. Rick actually touched on two of the areas that I wanted to focus on, and maybe just to ask a little bit further, so it doesn't sound like that there was any real aberration then in the LOE number. In fact, you think that as we kind of continue this deflationary path, obviously, the trends have decelerated a little bit, but we could continue to see even lower LOE in the second half of the year?

Brent Smolik

Yes. I think we're going to continue to see some downward pressure on the cost of the services. Remember, we've only just reorganized the E&P operating division in the second quarter. So we're just now starting to see the benefits of standardizing some practices across all of our US operations and we're going to continue to see that. I think we'll see some benefits on both sides.

Carl Kirst - BMO Capital

Turning to some of the commentary about the acreage acquisitions and I understand it's too early to talk about it here, but are we potentially talking about extensions of current areas that we're near or could this potentially be whole new geographic areas, shall we say?

Brent Smolik

It's far enough west of us. The trend is, I think, by most people's views that it's new leasing.

Carl Kirst - BMO Capital

Last question perhaps for Jim. Recognizing the number of projects that you guys have coming online over the next 12 months, this billion dollars, the fact that all of that is fully contracted, we have been thinking roughly that you can build this for seven times EBITDA range. Is that still the case with these fully contracted projects or is that better or worse than the current environment?

Jim Yardley

No, that's about on the market. The only caution I'd put out there is that the Elba Express starts up probably March-ish of next year. The Elba expansion itself, most of the capital involved, while the vaporization starts up in March or thereabouts, the actual storage tank that involves most of the capital won't start up until third, fourth quarter as planned. The multiple you're using on total capital is still reasonable.

Operator

Our next question comes from the line of Lasan Johong from RBC Capital Markets. Your line is open.

Lasan Johong - RBC Capital Markets

Can you give us a little more color on your Ruby financial plans?

Mark Leland

I think that we're developing those plans as we speak. We're targeting something around 50-50 or 60-40 debt to equity depending on how the markets line out. I think it will be a combination of multiple pools of capital, both bank and capital markets.

Doug Foshee

We retained this quarter our financial advisor.

Lasan Johong - RBC Capital Markets

Right. You're not looking to project finance this, right?

Mark Leland

Yes. A component of the financing will be traditional project finance.

Lasan Johong - RBC Capital Markets

What component do you think it might be?

Mark Leland

That's what we're working on evaluating today. It's really dependent on the markets at the time that we go to finance the transaction, which will be early next year when we get FERC certificates.

Lasan Johong - RBC Capital Markets

Okay. There's some discussion about story levels being full driving pressures on pipelines. Are you seeing any of that?

Jim Yardley

What we are seeing is that for example on Tennessee where we have both production area storage as well as market area storage

Lasan Johong - RBC Capital Markets

I'm sorry. You're cutting in and out. I can't hear a thing you're saying.

Jim Yardley

Yes. Can you hear me now?

Lasan Johong - RBC Capital Markets

Yes.

Jim Yardley

Yes. So on Tennessee for example, where we have both market area storage and in Pennsylvania as well as production area storage in Louisiana, what we have seen is that the production area storage has typically filled up first. And so our storage in Louisiana is probably around 90% to 95% filled whereas market area storage is not as filled. So what that has meant is we've been moving more gas sooner proportionately to our northern storage that we wouldn't have otherwise.

Lasan Johong - RBC Capital Markets

Is this having any impact on any of your E&P businesses?

Brent Smolik

Not today. You know, we watch it pretty close at the exits of each of our fields. And there's, no short term kind of anomalous high pressures but nothing yet permanent.

Lasan Johong - RBC Capital Markets

Okay. Switching to the E&P side, on the Haynesville, any surprises both good and bad that you've kind of run across?

Brent Smolik

We continue to be pleased with the drilling and completion performance. As each time we drill a well, we seem to learn from the last and be able to improve the speed at which we're able to get things done. The completions are going well. They're high end technology. But we're getting them pumped successfully and we are getting them in the ground successfully. And so we're real happy with how the completion work's going. So all those price have been positive.

Lasan Johong - RBC Capital Markets

So it looks like between Newland and Travis Lynch there was a Quantum leap then the Travis Lynch, the RF Gamble was another Quantum leap. Is that all due to completion techniques?

Mark Leland

Partially completion and partially geology. Those were some of our most western most wells when we were starting out. So I think we were learning both and where to be within the play and then learning how to complete them.

Lasan Johong - RBC Capital Markets

And if I'm not mistaken, you've kind of figured out where the core of the play is now?

Jim Yardley

We think industry is just based on the production data is starting to line up kind of within that red circle that we included on the Haynesville slide.

Lasan Johong - RBC Capital Markets

Excellent. Thank you very much.

Operator

And our next question comes from the line of Shneur Gershuni from UBS. Your line is open.

Shneur Gershuni - UBS

Just a couple of questions. I was wondering if we can start on the E&P side with respect to reserves. You know, I guess a two-part question. One, given the fact that you're kind of expecting Brazil to start off at the end of this year, do you expect to book reserves there, and I guess the second part of the question is the reserve bookings for the US, your rig count is going to be way down. One can surmise excluding changes in pricing obviously that reserve bookings could potentially be down. Would that potentially be offset by the fact that you've shifted your drilling mix, to central and western division and so forth?

Doug Foshee

Yeah I think may be to summarize where you said accurately is we will book reserves this year for Brazil project. No question about that. And then as we shift our capital to more and more longer life unconventional type assets that naturally have lower F&D then we will get the benefit of that and that even though capital is lower we'll get more reserves booked for our capital dollar that we're spending. So depending on the total cost structure which is coming down which will benefit us in the F&D and the shift in the portfolio to the more unconventional benefit is an F&D.

Shneur Gershuni - UBS

Okay. And just a question on the pipeline. Obviously operating costs were quite good this quarter. Jim, do you kind of expect this to continue throughout the balance of the year? And do you kind of see your guidance for the pipeline segment go up as a result of the cost benefits?

Jim Yardley

You know, I think the way to look at is some of our costs are seasonal, but on a run rate basis, we've been achieving total O&M and G&A costs of around $800 million to $810 million. We're down relative to that favorable. And I think that it's looking more and more like we're going to end up on the slightly favorable side. So some of the benefits to date has been timing, but on balance we feel very good about where we are with respect to operating costs.

Shneur Gershuni - UBS

Okay. And just one final question just with respect to the Ruby partnership and so forth. I was wondering if you guys could walk us through what milestones you need to hit when and where and how to ensure that you retain at least 50% economics in the project if not more and kind of where your opportunity are there to potentially over earn relative to the 50% economic interest?

Mark Leland

Shneur this is Mark. So the key drivers in our ability to over earn or get on a straight-up 50/50 basis are primarily in capacity sales. So to the extent we sell 200 million at 250 million a day of firm long-term commitments above where we are today, we can force conversion to common equity of our partner. And a little below that essentially puts us on par with them. We will retain all of the short-term interruptible sales benefit. So that's a way to earn extra unless they convert to common. The other place and a very significant place to really enhance our IRR is to put the project in service under budget. We retained all that benefit.

Doug Foshee

So if you think about milestones, FERC certificates, commercial in service date, incremental volumes sold and capital costs versus plans, those are the big ones.

Shneur Gershuni - UBS

If you decided at the last minute to upsize the horsepower, something like that, would that be something that would benefit you guys in the end or no?

Brent Smolik

On that, the upside, that would help a lot. That would probably only be the case for capacity beyond the 1.5. So when Mark talks about the 200 to 250 range, that is going from the 1.1 we have today up to the stated capacity, which is between 1.3 and 1.5 before that compression you're talking about.

Mark Leland

Let me just clarify. When I say convert them to common, their preferred interest in Ruby would be converted to a common interest in Ruby as opposed to anything else.

Operator

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

Faisal Khan - Citigroup

On the TGP extension, the Line 300, who does the lower cost of that project, who benefits from the lower cost of that project? Is it you or EQT?

Doug Foshee

Think about it as being split. Some part of it flows through to Equitable and some we retain.

Faisal Khan - Citigroup

Just looking at the volumes on the pipelines this quarter versus the same time last year, except for EPNG, volume are up, which would be counterintuitive to a slower economy and slowing production. Can you comment on how you guys got those increases, was it taking market share or are volumes really up?

Mark Leland

Well, you're probably looking specifically at the second quarter comparisons as opposed to the year to date comparisons.

Faisal Khan - Citigroup

That's right.

Mark Leland

Sometimes that can be a little bit dangerous because just so much depends upon the relative weather from year-to-year as opposed to the underlying economy. I think that the drivers in what we see going on though are that we do have a slowdown in the economy affecting underlying industrial usage and to some extent electricity demand, but I'd be careful in reading too much into just the quarter-to-quarter comparisons.

Faisal Khan - Citigroup

In terms of what kind of rig count you guys need to keep production kind of flat or within your guidance going forward, given the success you guys have had in the Haynesville, how many rigs do you guys think you need to keep running to keep production relatively flat over the long run?

Doug Foshee

Think of it in terms of the capital and the total efficiencies of the program. We probably need in terms of rigs about 10 to maybe 12 or so. If that's not quite right, I'll jump back on here in a moment. I think that's about the right level assuming that we do a fairly high percentage of those as Haynesville wells in the mix.

Faisal Khan - Citigroup

On Pinauna, the cost of that project has moved around pretty extreme values up and down. I think first it was 400, then it was 700, and I just want to figure out where you guys inflection point is to move forward on that project? Are you still looking to get down at the 400 level or is it something less than that?

Mark Leland

I don't think we'll ever be able to recover 400. Remember, that assumed that we had all of the large portion of FSO treated as operating expense in the lease. As we look at it, we probably would treat that as a capital item. So, part of that step-up was just that. The rest of it was inflation that we were seeing in the environment. So we're hoping to claw back all of the inflationary pieces of it and we're seeing that.

I think Brazil's going to be slower than the rest of the world because they're generally pretty active in country, and so, it's going to be a little bit slower to get the cost to come back down. That project was approved based on that $700 million total CapEx level and $70 oil price. So it stands up quite nicely at today's oil price curve and what we've already realized for cost savings.

We're going to continue to push on the estimates as we continue to see the deflation in Brazil like we're seeing everywhere else.

Faisal Khan - Citigroup

Can you just give us a little more detail on the BM-CAL? Was that a discovery or are you still evaluating whether it's a discovery?

Doug Foshee

Found hydrocarbons, can't talk about it any more than that. It's still being tested as we speak.

Jim Yardley

Petrobras is operating that one. So we've got to be careful about what we talk about, but we found hydrocarbons.

Faisal Khan - Citigroup

Is the South Alamein Block, that's the well you tested there, is that oil or gas or you're still testing that too?

Doug Foshee

Not sure because we're still testing, but more oil front than gases are the early indications. The first well we got oil sample from, but not extended test. The second well we're going to test.

Operator

Our next question comes from the line of Nathan Judge with Atlantic Equities.

Nathan Judge - Atlantic Equities

I wanted to ask, you're now giving us some estimates as far as the Haynesville shale program statistics and resources, could you give us what the un-risk and what the risk resource estimates were when you gave us your total at the beginning of the year for Haynesville.

Brent Smolik

For the resources, we were probably in the less than 5 Bcf range, maybe right at 5 Bcf. Today we're more at 6.5 Bcf.

Nathan Judge - Atlantic Equities

So you've increased it. Of your total, there was about 1 Tcf of net risk unconventional resources, and you're saying now Haynesville is 750 to 900. Should we assume that the remainder would be rising or say stable or how do we look at that and how would we translate Haynesville into kind of what we would expect for booked reserves?

Mark Leland

If you jump all the way to booking, it's going to be interesting this year because of the role changes and we're using all the different pricing and how many offsets for Haynesville and horizontal wells, so let's not jump too far to bookings just yet. For the resources, we should have almost tripled the resources from what we had in the table at the beginning of the year to what we've seen today, should be about three times what we had before.

Nathan Judge - Atlantic Equities

For Haynesville?

Mark Leland

For Haynesville only.

Doug Foshee

So if you take the Tcf, embedded in that Tcf is about a third of what you see today in the Haynesville.

Nathan Judge - Atlantic Equities

Would the remainder be also stable or would we see a lower revision on that?

Mark Leland

The remainder would be a non-Haynesville. Net-net, everywhere we're going to see inventory grow. So we're going to see it up in all of the other basins as well. So we haven't lost any. We've thrown by Haynesville plus some others. From what we would have had at end of year last year to mid-year today.

Nathan Judge - Atlantic Equities

Okay. Just with regard to E&P, average realized pricing, it seemed that your basis differential was bit wired than it has been historically. At least in my calculation. Was there anything strange going on there or is that going to be a continuing trend?

Mark Leland

No. I think if there's anything, Nathan, it's short term. There's nothing going on, basis has been steady almost everywhere that we operate. Anything it's as NYMEX comes down basis is collapsing everywhere.

Nathan Judge - Atlantic Equities

And the pipeline you talked about ancillary service revenue being positive this quarter. Can you just quantify that and give us an idea if that's going to continue, that may have to do with the Marcellus issues, but just a bit more color on that?

Jim Yardley

Our base business, say X expansions, our volumes and our revenue move around a little bit from quarter-to-quarter, but basically the Marcellus is a net plus or a very significant net plus. Offsetting that we have had some weakness on El Paso natural gas as the result of the basis differential from Permian to California deteriorating. But I think it's safe to say that the deposit of Tennessee has been offsetting the negative elsewhere.

Nathan Judge - Atlantic Equities

So you would basically expect that kind of additional revenue from ancillary services to continue for the rest of the year?

Jim Yardley

I'd say that it's more than we would have expected at the beginning of the year. It's favorable. Modestly.

Operator

And our next question comes from the line of Holly Stewart with Howard Weil. Your line is open.

Holly Stewart - Howard Weil

Three quick one I guess. On going back to the TGP 300 line, the $150 million decrease, what's driving that? And then could that be extrapolated to other projects?

Jim Yardley

There are two primary drivers. One is steel and pipe. In this case even though we've locked in our pricing with the pipe mill, he in fact had not ordered steel. So we together with the pipe manufacturer able to take advantage of that. The second is that we had not embedded in the 750 was an estimate on our contractor cost which has come down significantly. We had not contracted for that service. And we still haven't for the installation. But we clearly see that the installation cost will be lower today. So those are the two primary element. As to extrapolating it to other projects, have to be a little bit careful there because we have for the most part our other big backlog projects. We have locked in at least the pipe component at this point.

Mark Leland

And in some places we have fixed priced contracts with contractors.

Holly Stewart - Howard Weil

Okay. And then just beating a dead horse on the Haynesville here, last quarter you were almost at $20 million a day. You've pretty much doubled that almost at $40 million a day now. What was in your original guidance for Haynesville production?

Brent Smolik

Less than that.

Doug Foshee

Less than that. But remember too, we were originally thinking more about $1.3 billionish for capital. And so we pulled back capital elsewhere and more than replaced that pullback with incremental production from the Haynesville.

Holly Stewart - Howard Weil

Okay, okay. And then last one I guess for Doug. Seeing lots of equity deals hit the tape here, you guys have had your stocks had a great run. I know you were fined for 2009, but any thoughts on an equity financing here?

Doug Foshee

Yeah. I think that equity is a tool in our toolkit. In essence we've already done that this year as we think about the sale of equity at the MLP level being an indirect sale of equity at the EP level. So I think we'll continue to look at that as we move through the balance this year and into '10 and'11.

Bruce Connery

We'll take one more question, please.

Operator

Okay. Our last question comes from the line of Pavel Molchanov with Raymond James. Your line is open.

Pavel Molchanov - Raymond James

Most of my questions have been answered just a few housekeeping items. Income tax rates seem to have bounced up this quarter. Any particular reason for that?

Mark Leland

It's just the Brazil ceiling test charge which there's no tax benefit there. It just happens to skew the rate for the quarter.

Pavel Molchanov - Raymond James

So for the future should we still be using something in the 35% range?

Mark Leland

Yeah. 35, 36.

Pavel Molchanov - Raymond James

Got it. Then on your E&P DD&A rate, that obviously came down very sharply following the write down. Should we assume also something in that I guess with $1.29 in the quarter per am?

Doug Foshee

Going forward we're going to as we add back in capital we'll see that climb back toward our F&D's, but our F&D's are going to be lower in the lower capital [one to grant] so but its going to be pretty close to the rest of this year.

Pavel Molchanov - Raymond James

Pretty close to the $1.29?

Doug Foshee

Up maybe $0.10 from that.

Pavel Molchanov - Raymond James

Okay. Very good. Thanks, guys.

Bruce Connery

All right. That concludes our call. We appreciate your interest. And please call us if you have any follow-up questions. Thank you.

Operator

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

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