El Paso Corp., Q2 2008 Earnings Call Transcript

| About: Kinder Morgan, (KMI)

El Paso Corp. (EP) Q2 2008 Earnings Call Transcript August 6, 2008 9:30 AM ET

Executives

Bruce Connery - IR

Doug Foshee - President and CEO

Mark Leland - CFO and EVP

Jim Yardley - President of Pipeline Group

Brent Smolik - President of E&P Company

Analysts

Shneur Gershuni - UBS

Carl Kirst - BMO Capital

Sam Brothwell - Wachovia

Faisel Khan - Citigroup

Rebecca Followill - Tudor Pickering Holt

Mark Afracozaci - Pemco

Rick Gross - Lehman Brothers

Nathan Judge - Atlantic Equities

Presentation

Operator

Good morning. My name is Casey, and I will be your conference operator today. At this time I would like to welcome everyone to the El Paso Corporation Second Quarter 2008 Earnings Conference Call. All lines have been placed on mute to prevented any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions).

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

Bruce Connery

Good morning and thank you for joining our call. In just a moment I will turn the call over to Doug Foshee, our President and Chief Executive Officer. Others with us this morning who are participating in the call are Mark Leland, our; Jim Yardley, who is President of our Pipeline Group and Brent Smolik, President of our E&P Company.

Throughout this call we'll be referring to slides which are available on our website at elpaso.com. This morning we issued a press release and we will file with the SEC as an 8-K and is also on our website. During the call we'll include certain forward-looking statements and projections. The Company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current reasonable to the plea. However, a variety of factors could cause actual results to differ materially from the statements and projections expressed in this call. Those factors are identified under the cautionary statement regarding forward-looking statements section of earnings press release, as well as in other of our filings with the SEC, and you should refer to them. The Company assumes no obligation to publicly update or revise any forward-looking statements made during this conference call or any other forward-looking statements made by the Company, whether as a result of new information, future events or otherwise. Please note that during the call we will use non-GAAP numbers such as EBIT and EBITDA, and we have included a reconciliation of all non-GAAP numbers in the appendix of our presentation.

Now I will turn the call over to Doug.

Doug Foshee

Thanks, Bruce. Good morning, and thanks for joining us. We're happy to report another good quarter for El Paso. $0.39 a share on an adjusted basis, a significant improvement over last year's second quarter and continued strong cash generation from our two core businesses. I want to start this morning by highlighting for you how we view our score card for the first six months. Accomplishments, challenges, and the expected outcomes for the year.

In terms of accomplishments in the pipelines, last year we began highlighting three potential projects in the pipes that we were chasing but hadn't yet landed. A new export line out of the Rockies, a significant expansion opportunity in the Southeast, and a significant expansion in the Northeast. We've now converted each of those into committed backlog.

Ruby and FGT phase 8 were announced earlier, and while our large Greenfield project in the Northeast hasn't yet materialized, we announced yesterday a great expansion out of Appalachia with our good customer equitable resources. Jim will talk more about this in his comments, but in total we now have a committed backlog of $8 billion, more than double the backlog from just a few months ago and by far the largest backlog in our history. This backlog will add $1.2 billion in EBITDA to our pipes over the next several years.

In E&P we're starting to reap the fruits of our portfolio work of the past couple of years as well as continuing to improve our inventory on legacy properties. Brent will talk about progress in the Haynesville, Niobrara, and Raton, Altamont oil and Raton CBM all of which should add to our non-improved inventory this year and play a growing role in our capital plans as we enter 2009. We have also made significant progress in moving our two Brazil development projects towards first production. In particular, I would point out the acceleration in the pace of development at Bia, now named Camarupim by the operator Petrobras with first gas now expected in Q1 '09 at 35 million to 50 million cubic feet a day net to El Paso and priced off of an index to oil.

We completed our divesture program in the first half and we added a bolt-on acquisition at the Altamont field taking our ownership their upto 100% in most of the field where we're now planning to go from 320 to 160-acre space. This is a mature old field with 3 billion barrels of original oil in place and very low recovery rates to-date. Today's oil prices combined with some improvements in drilling cost have made this opportunity very economic.

On the commodity price front, we continue to add to our 2009 hedging portfolio in the second quarter with both 9 by 18 collars and 10 by 17 collars as well as some $110 oil swaps. The combination will enhance revenues by over $250 million next year.

Last, as you know we increased our dividend this year and our board approved a share buyback program. To-date we spent $31 million of our approved $300 million program at an average price of $18.70 a share for a total of 1.7 million shares.

Finally, in E&P as a result of the success of our pilot programs in the first half of the year, as well as $40 million or $50 million in inflation on the existing capital program we're adding about $200 million to our drilling CapEx for 2008 giving us a good head start to '09 as we close out the second half of the year.

Now I want to spend time talking about our challenges in '08 some of which will be ongoing as we plan for 2009. The first of these is project management. We have the largest backlog in the 80-year history in the Company of our pipes and that's of course a good thing, but it is going to require strong execution by our internal staff to bring these projects in on time, on budget, and safely. We have the same issue on the E&P side. We now have the biggest project inventory we've had maybe in history but certainly in the almost five years I've been here.

In addition, we have three very important project to manage internationally, two development projects in Brazil, and a drilling campaign kicking off in the fourth quarter in Egypt. By the way, these are the kinds of high quality challenges we've been dreaming of having for the past five years. A big part of the challenge of project execution has to do with Item 2 on the chart, cost control. On the pipes, the challenges and overly complex. Managed steel price risk and managed construction costs. In E&P, there are larger number of items, but it essentially boils down to effectively managing the supply chain and continuing to gain efficiencies in longer term drilling programs.

So what are we doing to meet these challenges? We started investing in our supply chain management function well over a year ago in anticipation of much of this. In addition, we've added project staff, we've added training, we've improved our project costing skills. We've improved our real-time project surveillance, and we've tried to be diligent about the process of post project reviews so we incorporate learning’s from one project into the balance of our inventory as quickly as possible.

Finally, as you will hear in both Jim and Brent's comments we focused on locking in major cost components as early in a cycle as possible to mitigate the risk of cost inflation. The next item, acquisition integration, is purely self inflicted. The people's acquisition was the first we've done in awhile that came with significant staff levels. In hindsight we were a little too optimistic about our staff retention rates early on and as a result we didn't hit the activity levels we forecast in the first six months post closing, and the result is we're behind there on volumes. Brent will explain this in detail, but the shorter answer is we're now back on track, but the delay means we're likely to be at the low end of our guidance of 8.60 to 9.20 for the year.

We've now completed our reviews and we have incorporated the learning’s into our acquisition integration process for future acquisitions. The fact is we love the acquisition which improved our cost structure, added to the inventory, and already worth a lot more than we paid for it, but not hitting our early targets just isn't acceptable.

The final item on the challenges list is the mark-to-market volatility associated with our PJM basis position. I highlight this item not because it is a significant cash or value item, but because it’s the only significant remaining source of quarter-to-quarter earnings volatility from our legacy power and trading business. The cash impact of this item isn't material. This quarter was only about $9 million in cash, but it is a long dated item that's positively but not perfectly correlated with gas prices. That creates the potential for some ongoing volatility in our non-cash earnings as gas prices fluctuate. When you roll all of this up it means earnings of $1.40 to $1.50 a share assuming actual prices through August, and the strip for September through December, EBITDA of $3.8 million to $3.9 million, and our sixth consecutive year of improved earnings and return on total capital. This earnings number is consistent with what we previously have shown under various natural gas price scenarios.

The additions to the pine line backlog as well as increased drilling activity in E&P will spend about $3.8 billion in total capital this year, and the inventory we built in both business units really sets us up well for 2009. So while our share price has suffered with the rest of our peers over the last month or so, our excitement and optimism about 2009 has actually increased.

With that I will turn it over to Mark and come back later to wrap up. Mark.

Mark Leland

Thank you, Doug, and good morning, everybody. I am on slide 9 titled financial results. The Company generated strong earnings this quarter. We reported adjusted earnings per share of $0.39 compared to adjusted earnings per share of $0.29 for the second quarter last year. I will cover the adjustments on the next slide.

Reported earnings per share is $0.25 with net income of $191 million. Adjusted EBITDA was $865 million, up 6% from the same period last year which includes in this year includes $200 million of mark-to-market losses and other special items. Growth and earnings this quarter was driven by strong realized natural gas prices which were up $1.86 per Mcf to $9.53.

Interest expense was $221 million which was down from $231 million in the second quarter of last year. The items impacting earnings this quarter are highlighted on slide 10. The first is the $105 million pre-tax or $0.09 per share mark-to-market loss from the change in fair value of legacy power trading contracts in the marketing segment. I want to point out cash settlements on the related positions were only 8.8 million for the quarter.

As I highlighted in our April analyst meeting in New York, we have unhedged exposure to locational power price differences or basis in the PGM power region. Basis in that region tends to move with natural gas prices and in the second quarter run up in gas prices drove the widening of the east-west basis in PGM. I will spend some more time discussing this in a few minutes.

The second significant item impacting the quarters results is a $9 million $0.01 per share gain associated with the legacy indemnification related to the sale of ammonia facility. The third item is a $27 million pre-tax or $0.04 per share gain associated with other adjustments to legacy litigation liabilities. The last two items relate to our hedging portfolio. The first is the $52 million pre-tax or $0.04 per share loss from the change in fair value of puts and calls in the marketing segment used to hedge E&P cash flows. If you recall, these remaining transactions in the marketing segment relate to oil and gas hedges we entered into when we closed the Medicine Bow acquisition several years ago.

We've done all of our 2008 and forward hedging in our oil and gas production in our E&P segment and some of those hedges have not been designated for hedge accounting, so the final adjusting item is a $61 million or $0.06 per share mark-to-market loss in the E&P segment due to higher oil and gas prices at quarter year-end. These amounts are net of $14 million current quarter selling.

If we mark these positions today we would see a significant gain due to the recent reduction in forward gas prices. So, in the end adjusting for these items brings EPS to $0.39 per share.

Slide 11 highlights business unit contribution. On a combined basis our core pipeline and E&P businesses generated $895 million in EBITDA and adjusted EBITDA of 963 million. Adjusted EBITDA is calculated with our 50% share of Citrus and our 49% interest in Four Star on a proportional basis, and you recall there isn't any debt on Four Star.

Our marketing and trading of quarter to EBITDA loss of 153 million and I will give more color on that in a minute. Power EBITDA was 12 million, and corporate EBITDA was 43 million. There is a chart in the appendix that provides the relevant details on the adjusted EBITDA calculations.

Now turning to cash flow on slide 12. For the first half of this year cash flow of the four working capital changes was $1,285 billion, up $225 million or 21% from last year, and cash flow from continuing operations was $1,318 billion compared to $882 million this time last year.

CapEx through June this year is $1,175 billion, and we spent $336 million on acquisitions of the 50% interest in Gulf LNG and some producing properties in the Rockies. We completed the E&P property sales as well as two small international power plants and received $659 million in cash proceeds. So far this year we're cash flow positive taking into consideration strong operating cash flow and asset sales.

Slide 13 details earnings from the marketing segment for the quarter. As we have over the past couple of quarters, we've segregated the results to highlight the impact of derivatives used to hedge production cash flows which we view as strategic positions and then other positions which are primarily related to legacy trading book.

For the quarter we realized an EBITDA loss of $52 million due to the change in fair value of production related derivatives compared to last year's gain of $9 million. The losses were primarily driven by mark-to-market losses in our 2008 oil callers used to hedge Medicine Bow back in 2005.

In the other category of marketing positions the gas book was up $11 million primarily due to higher interest rates this quarter, and we recognize losses of $105 million in the power book mostly due to continued widening of PJM basis. I will give more color on this in the next slide. So when total marketing segment recognized a loss of $153 million this quarter.

Slide 14 chronicles the mark-to-market earnings impact and quarterly cash settlements of our long dated PJM basis position. PJM is a regional transmission organization that serves 13 states in the Northeast and operates a wholesale power market. As you recall our legacy contract position in PJM is the remnant from our power restructuring business. We have exposure to price differentials between the PJM west hub and four locations within the east hub. The contracts extend through April 2016 and have a total exposure of about 200 million megawatt hours. Energy typically flows from the supply areas in the west to high demand areas in the east hub. Settlements of those spreads are driven by transmission congestion, and marginal production costs. West hub price often is set by the base load coal and east hub is often set by natural gas fire generation.

At the end of the quarter we saw 32% increase in the forward price of natural gas which led to a 45% increase in the forward PJM basis driving the mark-to-market loss this quarter. Given the long dated nature of this contracted, we experienced large swings in the marks on these contracts which is depicted on the line in the graph. The bars on the graph depict the quarterly cash settlements on the contracts, so while we see a lot of volatility in earnings, the cash impact is relatively small. This quarter settlements were just under $9 million, and this is a fairly illiquid market, so we haven't been able to hedge this exposure but as in the past we continue to look for way to say mitigate the exposure. Given that gas prices have gone down sharply, we would expect to see an improvement in this position for the next quarter or two as basis readjusts.

Slide 15 summarizes our 2008 hedge program for July forward in short balance of our '08 program and includes 98 TBtu with an average forward price of $7.94 with an average ceiling price of $10.23. The hedges are weighted to July through October with November and December hedged about 50% of anticipated production.

On the oil side we have 1.7 million barrels hedged with an average floor and ceiling of just over $79. The oil positions are combination of old collars put on in 2005 and the 1.26 million barrels swapped at just under $18 executed earlier this year.

We added quite a bit to our 2009 hedge program which is highlighted on slide 16. The 2009 natural gas hedges have an average floor just over $9 on 176 TBtu and an average ceiling of just under $15 on 151 TBtu. Since our last quarter call we added about 100 TBtu of floors leaving significant upside in 2009.

On the oil side we recently completed swaps totaling 3.4 million barrels at an average price of nearly $110, so in short the 2009 hedge program covers more than 50% of our '09 production and will enhance revenues -- our revenue outlook by about $270 million compared to 2008.

In summary, second quarter financial performance adds to our good start to 2008. We're on track for our sixth consecutive year of improved profitability. Our balance sheet is in good shape to fund our backlog and our hedge program provides protection with upside to higher prices and our '09 hedge program will provide excellent basis for higher revenues in 2009.

Next Jim Yardley will put color on the pipeline results.

Jim Yardley

Thanks, Mark, and good morning. The big news at the pipeline group this quarter is that we've added four new projects to our committed backlog totaling $4 billion. Of as Doug said this doubles our backlog to $8 billion. We're highly focused on executing to place these projects in service over the next few years on time and on budget, and in addition we continue to deliver consistent near term financial results. Underlying all of this is an ongoing increase in throughput across our pipelines despite the high gas prices in the first half that demonstrate the strength of our pipeline franchise.

On slide 19, I will summarize our financial results. Our EBIT for the first six months is a little changed from '07. It is down 1%, and up 2% before the minority interest attributable to the MLP. For the quarter EBIT was down 5% before minority interests. We have seen increased revenues from expansions placed in service, higher throughput and capacity sales offset by increased O&M reflecting higher labor costs and additional maintenance on SNG and TGP. While higher these costs are consistent with our 2008 plan and we're on-track to achieve our EBIT target for the year. Our EBITDA performance has tracked EBIT. Our capital expenditures are slightly higher than 2007, and are on plan.

On slide 20 throughput continues to increase very nicely. This 6% increase year-to-date versus '07 is on top of annual increases of 6% to 7% in each of 2006 and 2007. To put these increases in perspective, our throughput growth has approximately doubled the rate of total U.S. gas demand over the last three years. So, our throughput results highlight again our pipes are in the most attractive markets and supply basins in the country.

This year more of our increase is supply driven than demand driven. I think you're aware that all of the independent sub-volumes from the deepwater Gulf come into TGP, increasing Rockies production continues to benefit CIG, WIC and Cheyenne Plains, and Rockies production is increasing faster than expected.

On the demand side we don't see signs of demand destruction despite the higher gas prices in the first half. The power generation sector continues to show clear increases in gas usage year-to-year. We hear from some of our LDC customers that usage per household has decreased but this is offset by modest increases in the industrial sector. Steel plants and fertilizer plants in particular served by our pipes shows strong demand. In total, very healthy picture on throughput.

On slide 21, slide 21 updates and breaks down our $8 billion committed backlog. We think this backlog is the best in the business. All of these backlog projects are support by long-term contracts with customers, and we in turn have committed to go forward with these projects. To put the $8 billion in perspective, our rate base of the pipeline group's existing pipelines is in the order of magnitude of $10 billion. The backlog provides us with substantial well known long-term growth.

While we're just starting into our annual planning cycle, we expect the 6% to 8% long-term EBIT growth guidance that we gave at the beginning of the year will now increase to double-digit growth guidance admittedly somewhat back-end weighted because most of the large projects in the backlog do not go in service until late 2010 or 2011.

Since the end of the first quarter we put in service on time and on budget, two projects, SNG, Cypress Phase II expansion to transport more gas to Florida and Cheyenne Plains expansion for Karl. So both of those projects have been removed from the backlog and are now earning revenue.

Over the remainder of 2008 we'll place in service four others shown on this slide including our CIG high plains expansion to serve Denver that is our pipeline, our major pipeline construction project for this year. I will talk about two large additions to the backlog, Ruby and TGP's line 300 on the next slides, but we also added two somewhat smaller projects this quarter, CIG's Raton 2010 expansion and a WIC expansion. Both of these Rockies projects help support Ruby by providing producers an upstream capacity path to Ruby at the Opal hub in Wyoming.

While on this slide let us me pick up on Doug's comments about the cost environment, its challenges and how we're managing it. Steel costs for pipe making have doubled since the beginning of the year. And the cost of large diameter pipe has increased approximately 60%. For the most part we've minimized the impact of these increases by locking in our pipe costs at or near the time we committed to go forward with our customers under long-term transportation contracts.

Having said that, since our New York analyst conference in April our expected total capital cost for the projects that were in the backlog at that time has increased by approximately 8%. This increase is due somewhat to higher than expected pipe costs but also increases in scope requested by customers. So, while costs have increased, our project returns have not materially changed due to risk mitigation plans we put in place with customers and better marketing results in general. We said at the analyst conference we expect the ratio of CapEx to run rate EBITDA for our backlog to be approximately seven times, and that is still the case today, and on a substantially larger backlog.

On slide 22 a Ruby update. We committed to customers in June to go forward with Ruby after obtaining binding long-term commitments with ten shippers for approximately 1.1 Bcf a day out of a total pipeline capacity of 1.3 to 1.5. At that time we also ordered on substantially a fixed price basis all of the pipe for the project, over $900 million of pipe. Some of it will be rolled in India, some in the U.S. We also executed incentive based contracts for the installation with three pipeline construction companies. We have been working with these contractors for the prior six to nine months on the routing and project planning. We have also been doing extensive stakeholder outreach with land owners and permitting agencies and we plan to make Ruby a green pipeline, one that will have nearly a neutral carbon footprint.

So we're very excited about Ruby. It is great for the Rockies producers, great for the western markets and obviously an important project for us. We formally started the FERC pre-filing process in January, and we'll file our FERC application in early 2009. We continue to work closely with the three contractors on construction planning which is very important on a project this size. For example, it will take 5, 800 rail car to transport all of the pipe to the job site. Construction will not commence until 2010 when we expect to have the FERC certificate. On the marketing front we have solid prospects for the remaining capacity.

On slide 23, yesterday as Doug said we announced the addition of TG P's line 300 expansion to our committed backlog. Line 300 runs across northern Pennsylvania to serve markets in the Metro and New York City area. We'll expand it by 300 a day at a cost of approximately $750 million. A subsidiary of Equitable resources is contracted for all of the expansion capacity. Equitable as you know is a major Appalachian producer, and this capacity will allow Equitable to move its production further downstream. Because of line 300's existing route through the Marcellus Plain in northeastern, Pennsylvania, this expansion also sets us up to do a follow on expansion for Marcellus producer as that plain further develops.

As with Ruby we locked in our pipe costs in this case with a Turkish mill at the same time we finalized agreement with Equitable.

On slide 24 in summary the pipeline group is at full throttle. We've never had a growth backlog like this, and our complete attention is on executing on it over the next few years, and we're on-track to achieve our 2008 earnings targets.

Now I will turn it over to Brent to discuss E&P.

Brent Smolik

Thank you, Jim, and good morning, everyone. I will begin on slide 26. We had a good second quarter, and I am going to review our normal quarterly statistics, but much of what I am going to talk about is the progress we made on the drilling front. We've had a lot of recent success that does a couple things for us. We continue to build on our 2.8 Tcf of non-improved inventory which in turn will enable us to deliver on our long-term volume growth objectives.

As Mark noted, our second quarter EBIT was up sharply from a year ago, and after adjusting for the people's acquisition in our asset divestitures production was up 3% from the second quarter of '07 and 4% from the first quarter of this year. Prices were strong and our realized natural gas price rose to 9.53 from 7.67 and oil prices for the quarter were 90.64 per barrel versus 56.87 a year ago.

As a result of our completing our portfolio upgrading our lifting cost are down nicely. As Doug mentioned, due to success we're having in our drilling programs we're committing to an additional 200 million of capital in 2008. Also recall that our non-improved inventory didn't include resources four the Haynesville Shale in the ArkLaTex, the Niobrara Shale in the Raton Basin or for additional down spacing in the Cotton valley in the ArkLaTex.

We're progressing on all of these opportunities and I will give you updates for each of these and other area this is morning. I will also give you a full update on two development programs in Brazil and as Doug said Bia is moving very quickly, and we expect to add 35 to 50 million per day from that project in the first quarter of 2009.

Turning to slide 27, our second quarter and six-month EBIT was up 29% and 32% from a year ago, but there is some noise in the numbers. Within the MP segment, we had $75 million and $110 million of mark-to-market losses for the hedges during the quarter and first six months of 2008 compared to losses of just $5 million and $2 million during the same periods in '07.

When you factor that in, our improvement in the underlying operations was up almost 60% for both periods.

During the quarter in six months EBITDA of the strong at $501 million and $955 million, respectively, and both of those numbers include those mark-to-market losses. The adjusted EBITDA numbers shown on the slide reflected our interest in Four Star in this case.

Our capital program was on track at $443 million during the quarter, and we're at $745 million including acquisitions during the first half of 2008. We did complete a small but important acquisition during the quarter that increased our interest in the Altamont-Bluebell Oil Field. Because of the relatively high oil prices, we've been looking at opportunities for in-fill drilling there and I will give you an update on our plans in a few minutes.

Turning now to the pyramid slide on Page 28, to review the drilling results for the quarter. This is almost a carbon copy of what we showed you in the first quarter. I think the chart makes the point clear that the bulk of our domestic program is very low-risk drilling, so our success rate should always be in the high 90s.

In the high risk category year-to-date were 10 for 16. That's our highest risk exploration wells with four dry holes in the quarter.

As Doug said, due to our overall success rate of the capital program and the relatively high commodity price, we're increasing domestic capital to $1.9 billion, about $40 million to $50 million of that total increase is going to offset domestic drilling cost inflation and the remainder of additional will bring additional about 40 to 50 wells across the portfolio.

This will also allow to us extend our rig levels and all the programs through the year, including the new programs like the Haynesville Shale.

Turning to Page 29, another bright spot for the quarter is that our controllable unit costs were down about 7% from a year ago, and below the full-year average for 2007. When we completed our divestures in the first quarter of this year, we removed the properties with high lifting costs, which is evident by the $0.79 lifting costs that we had for the quarter.

G&A is also down a bit. Production taxes are up substantially, but they're directly tied to the price of oil and natural gas, and we more than make up for that increase in the revenue line.

Overall, our EBITDA margins improved to $7.23 per M from $5.91 a year ago, so we continue to improve the profitability on a unit of production basis for the MP Company. Given our 2008 divestitures in the Peoples acquisitions, we provided an apples-to-apples comparison of the production picture for the Company on Slide 30. On the right side of the chart, we show the reported volumes for the second quarter of 2007 and for the first and second quarters of 2008.

On the left side of the chart is shows the pro forma numbers that include the Peoples production and removes the volumes from the properties that were divested from all periods. On a pro forma basis our production was up 4% from the first quarter.

Most of that growth came from the Texas Gulf Coast, which itself was up about 10% from the first quarter and then all the other divisions were flat to up versus the first quarter the year.

We achieved that growth despite a sluggish start that Doug referred to on the integration of our Peoples assets, where frankly, we struggled with some of the activity levels post closing.

We're back on track now and ramped up production volumes in the quarter, and we expect to continue to increase volume from the Peoples assets through the remainder of the year, and I will provide more details on the acquisition in a moment. The central long-shore division is essentially flat Q1 to Q2, but a little behind our expectations for the quarter. Activity levels are up there now, though, and you will see a nice improvement in the third quarter.

The western on-shore division was up from the first quarter and from a year ago that's largely driven by our drilling and recompletion results from the Altamont Field in Utah and the Gulf of Mexico was up slightly from the first quarter and has been performing well this year.

Remember back in April, we indicated we would like to keep the Gulf in $100 million to $140 million a day range for the year. In terms of outlook, we now expect to average approximately $860 million a day for the year which is at the low end of our full-year guidance. We still have over half of our capital program to go, and we still need to get through the rest of the storm and the hurricane season.

However, our activities are up in all domestic divisions and we have good visibility to achieve an exit rate of near $900 million a day. Achieving the $860 million a day annual average would result in 8% growth over the 2007 pro forma leverages.

Turning now to slide 31. I wanted to specifically review the Peoples acquisition, which we closed at the end of the third-quarter last year. Remember, we had several reasons for buying the assets. First, they fit hand-in-glove with our ArkLaTex and TGC assets. So we cored up in both of those areas.

Second, it provided us with roughly a year's worth of drilling inventory and the properties have a lot of additional resource potential because as we said. They are located in prolific gas basins with stack pays, and I will give you a couple of examples of that.

We still like the assets and still like our rationale for doing the deal. The green bars on the chart show our quarterly production results and the estimates for our Peoples assets.

Bottom line, we're essentially two quarters or $30 million a day behind where we wanted to be closing in each period. The slower ramp up was caused primarily by a couple of factors. The biggest single driver was lower activity levels than we forecasted early on, and as the graph indicates with the yellow line our average rig activity was fairly constant from the fourth quarter to the first quarter. But we ramped it up since then.

Our plan was to ramp up immediately post closing in the fourth quarter but our attrition rates for personnel were higher than we hoped early on and prevented us from hitting the activity targets. I am happy to say the challenges are behind us now and we're back to seven to eight rigs today and increasing to ten by year end on the Peoples assets.

We've taken some key learning’s from this, which are now incorporated into our acquisition processes, so we can do a better job of forecasting additional activity levels in our future acquisitions.

The second factor that contributed to the slower ramp up was the results of the drilling activity identified during that period between the announcement of it as a transaction and a closing, which weren't as successful as we had open hoped.

As we remediated both challenges, we're now seeing the appropriate response. We started the year at about $70 million a day net, and we expect to exit the year at around $120 million a day for these properties.

Also on the positive side of the ledger, we're already beginning to capture some additional upside, and the ArkLaTex region the acquisition included about 10,000 net acres in the heart of the Haynesville Shale play, which will play an important role in growing our non-proved inventory levels. And in south Texas, we extended a trend in the Vicksburg that added more value than we expected at the time of the acquisition.

We've already drilled six wells in the trend and added over $40 million a day net since February and we believe the area still has some more running room.

While I am not satisfied with the start-up issues post acquisition, I am still very pleased with the acquisition overall. Given the growth in inventory from the assets and the value of this asset package has grown significantly from the $890 million cost of the deal.

Let's shift gears now to some of the operational updates, and I will begin with the ArkLaTex on Slide 32.

After the Peoples acquisition this became our largest producing area at roughly $160 million a day and on our April Analyst Meeting, we showed you that we have about half a Tcf of risked resource potential in the area, and that number is growing. This is one of our most active drilling areas. We're running eight to nine rigs there, versus the five to six that we ran most of last year and we expect to get to nine to ten rigs by the end of this year.

Three of those rigs are capable of drilling Cotton Valley horizontals or Haynesville horizontal wells, and we drilled our first Cotton Valley well -- horizontal well in the [Leg Murdoff] field in Panola County in Texas. It came in at about $7 million a day, had a 30 day average rate of $4.4 million a day and appears to be one of the top-10 producers in the horizontal Cotton Valley trend.

On average, we expect about 25% to 30% improvement in F&D for the Cotton Valley horizontals versus our traditional vertical completions. We currently have identified about 30 more locations. And additionally, it maybe possible to apply the horizontal approach more broadly to our remaining inventory of vertical Cotton Valley wells. You'll recall that we recently updated our position in the play for the Haynesville to 42,000 net acres and we're currently completing our first Haynesville well.

Let's turn to the next slide on Slide 33. As you know, this play gained a lot of attention in the last few months, and there is no question that there is a lot of gas in place in the shale. The question is it producing rates and the ultimate recoveries per well. Our first test we drilled the Miller land Company, the 10 H number one well in the Bethany Longstreet field and DeSoto Parish in Louisiana. We cored about 75 feet of the Haynesville. We drilled to a vertical depth of about 10,600 feet. We backed up and then drilled 3,100-foot horizontal section, and we're currently completing the well and just finished frac in six stages on the well and within the next few days we'll be flow testing it and then we planned to drill two or three more Haynesville wells this year.

If the play works as we hope, we can ultimately drill more than 400 wells based on 80-acre spacing assumption, which means significant resources that are not anywhere reflected in the inventory we quantified for you back in April. They aren't reflected in the 2.8 Tcf of proved reserves or if the 2.8 Tcf of non-proved reserves.

Let's turn to the Raton now on Slide 34. This is our largest gas manufacturing area today with over 900 producing wells.

Additionally, we have two studies under way not in our discussion in April. We've done a lot of analysis, and we think it is time to begin in-field drilling. We filed for application with the state of New Mexico, and we're hopeful we'll receive an in-field order soon, and we'll be able to begin drilling some of the 80-acre in-field wells as part of our 2009 program.

The amount of future potential is significant, and we could drill another 500 or so wells that have more than 250 billion cubic feet of net resource potential. Back in April, we talked a bit about the Niobrara Shale. The shale has been tested in the northern part of the basin and there is clearly a large resource potential in the shale here. We've now drilled three test wells spread across the ranch, two horizontals and one vertical. All three have been completed and all are producing gas into sales.

While it is not as prolific as the Haynesville, the Niobrara costs per well are much lower at about $2 million to $3 million per well. And remember, we own about 600,000 acres of minerals here. We believe that about half or more than 300,000 acres are perspective for the Niobrara. Our plans to produce for awhile and incorporate more activity into the 2009 program.

Slide 35 shows that the Niobrara Shale is between about 3,000 to 5,000 feet, which is roughly 2,000 to 3,000 deeper than the typical CBM program. We have drilled two horizontal wells with lateral lengths between 3,000 and 4,000 feet. These were very successful mechanically and production rates with initial post-frac flow rates of more than $1 million a day.

The vertical well was drilled to a depth about 6500 feet through the Niobrara Shales. The well was fracked and IPed about 400 MCF a day. Although, economic, we currently believe most of them will be drilled and completed horizontally to take advantage of the extensive natural fracture system in the shales. We estimate that the two horizontal wells will likely average between a half and a million a day, once we get a full month of production behind us.

While it is still early and still learning, we're very pleased with the initial results of the pilot program.

I would like to now turn to the Utah Oil Project. The Altamont Bluebell Field on Page 36. Given the higher oil price environment, we have been looking at the potential for in0field drilling here. As a reminder, it is a big oil field. Back in April, we discussed that the field contains more than three billion barrels of oil in place and has only producted about 10% or about 300 million barrels to day. We increased our position here in Q2 with the $43 million bolt-on acquisition that brought us to essentially 100% working interest in many of our producing wells and bought the remaining interest in our gas plant there. The field is currently developed on 328 acre spacing and in some cases has only one well per section producing. We have been studying infield potential in the field and we will apply with the state of Utah this Fall to go from 320 acres to 160 acres spacing and that translates to more than more than 175 additional locations and more than 30 million-barrels of net resource potential.

We'll keep you posted on the in-field hearing process and progress and we'll give you more information as we announce our 2009 drilling program. But this is an exciting development for us, that can add inventory and add more oil through our production mix.

Turning to international, Slide 37 begins update on Brazil. It is good news story.

The Bia Project, now named Camarupim, is moving much more rapidly toward first production than we discussed back in April. Doug and I were in Brazil a few weeks ago, and we are pleased to do hear the progress made and the emphasis placed on this project by Petrobras. There is clearly a natural push for development of more indigenous gas. We have continued to advance the negotiation of the commercial terms and while we’re not completely finished there is a couple of important milestones to report. Our working interest in the unitized field will be approximately 24%. Remember that this is the first unitization that has been completed in Brazil since the opening.

We have negotiated a gas price for the project that’s indexed to a basket of imported fuel oils, or international fuel oils. Although, we can’t disclose the exact price, but based on world oil prices, it could be two to three times what we historically received for gas in Brazil. And the best news is that Petrobras now expects first production to be in the first quarter of 2009. And when all four wells are online, we expect our net production to be in the 35 to 50 million day range, which will be a meaningful contribution to our long-term volume growth objectives.

Slide 38 depicts the Bia development concept. We’ll drill four subsea horizontal development wells that will tie back to FPSO. The first of the wells on the Petrobras block BES 100 has been drilled and completed, and waiting to be tied in. The FPSO has excess capacity that can accommodate, help us fast track any successes that we have with follow-on exploration. And remember that we would with Petrobras, we now plan to drill two additional exploration prospects on this block this year. The FPSO has been selected and it is going to be in country this fall.

From the FPSO, the gas will be transported via 12-inch and 24-inch pipeline that takes to processing at Cacimbas. The installation of the 12-inch line is complete, and the installation of the 24-inch line is well under way.

So, as we finalize the commercial terms, we’ll file the unitization agreement in the field development plan for approval by the regulatory authority, which is ANP, and we hope to have approval before the end of this year.

Slide 39 provides an updated on our Pinaúna project still in Brazil. Back in April, we were still formulating a development plan that made the best economic use of the gas that we found in Açai well, and we’re still updating the project cost estimates. We since decide to do use the gas as fuel on the platforms and the FSO, and like most big projects around the world, we’ve seen escalation on the project cost. Some of that’s been driven by scope changes. For example, adding the Açai satellite wellhead platform and most related to general industry inflation.

As we expect now the expanded project cost to range from $700 million to $750 million, which now includes also approximately $100 million for our facility in FSO leases accounted for as capital leases.

Fortunately, we’ve seen greater increases on the revenue side of the equation, so we’re happy with the way the project is shaping up. Assuming a $70 oil price, the project generates very solid returns. And at current oil prices the returns are quite good, north of 30%, again depending on global oil prices.

The next slide shows our development concept with the wellhead platform in the FSO. The new item is in the bottom center. That’s the additional bottom left maybe. That’s the additional wellhead platform for the Açai gas producer. As we said previously, we decided to do take through mid-year of this year to decide whether to take a partner on Pinaúna, and while we’re exploring those opportunities two things happened.

First, we completed our exploratory drilling. One well discovered gas, which was unexpected, but we’re now going to use that for fuel gas. And more importantly, the oil prices improved significantly. And the combination of those factors meant that our expectations for value went up, and we decided now not to take a partner at Pinaúna. And that’s not to say that we won’t come to a different conclusion down the road, but we intend to move forward with Pinaúna as 100% El Paso development project.

Our current expectation is we’ll have first oil in late 2009 and production should peak between 15,000 and 20,000 barrels a day and expect to receive an oil prices somewhere around WTI minus $4. On the cost side, we signed an LOI or letter of intent with the FSO provider and we’re finalizing the contracts now, which will lock down a major critical path item of for us and lock down a major cost driver for the project.

The next major project milestone is the environmental permit for the project, which is clearly the critical path item in the first production. We are actively engaged with the IBAMA, which is the regulatory body in Brazil charged with issuing the permit. And in fact, Doug and I met with the new IBAMA leadership in Brazil a couple weeks ago and left encouraged this important project for us and Brazil is on track.

Now turning to the my last chart on Page 41. I know I’ve covered a lot of material but we made a lot of progress recently. Our capital project inventory is growing in both our legacy and our Peoples acquisition properties, in the Haynesville and Niobrara Shales, in the Raton CBM, and in the Altamont in-field projects. And although I didn’t cover it today, we have continued to evaluate and grow the exploratory potential of our international assets and we still expect to drill our first Egypt well in the fourth quarter of this year.

We are actively updating our inventory with all the learnings from the 2008 program, but expect to significantly increase our end of year non-proved balance of 2.8 TCF. And as we’ve had success in the 2008 capital drilling program, we are putting additional $200 million of capital worth, and while it won’t make much impact on our 2008 full year production, it will help our exit rate and get us off to a great start activity wise and production wise for 2009.

So, in summary we made a lot of progress since our April Analyst Meeting, all of which supports our long-term growth targets through 2010. With that, I will turn it back to Doug for closing.

Doug Foshee

Thanks, Brent. We’ve run a little long this morning. So let me wrap up quickly. We expect earnings and cash flow to be up significantly this year over last year and up significantly over our original guidance for this year.

We have now secured commitments for $8 billion in growth capital over the next several years on the pipes that will add $1.2 billion in EBITDA when completed, giving us a new long-term growth rate in the pipes of 10% plus.

Progress in the Haynesville, the Niobrara, Cotton Valley Horizontals, Altamont, Raton CBM mean we expect risks resources to go up significantly this year and ultimately that translates into proved reserves. This combined with the acceleration at Bia or Camarupim as it’s now called, sets up a very exciting 2009.

Adding 35 million to 50 million cubic feet a day net from Camarupim to an exit rate of around 900 million a day means we should be off to a great start in 2009 versus our expected 860 a day average for ‘08, with lots of gas price protection in place from average floors in the $9 range. We are very excited as we head into the last half of the year and dive into the planning process for 2009.

And with that, we are happy to open it up to your questions this morning.

Questions-and-Answers Session

Operator

(Operator Instructions). Your first question comes from the line of Shneur Gershuni with UBS.

Shneur Gershuni - UBS

Hi. Good morning, guys.

Doug Foshee

Good morning, Shneur.

Shneur Gershuni - UBS

Just a couple of quick questions here. Just starting with the pine line. You had a big jump in operating expenses this is quarter. You mentioned some of it’s due to personnel and so forth. But is some of those costs controllable, some sort, and this is not all, but is a new trend, but only some of it is new trend, or should we be thinking that we’re in a new higher OpEx paradigm?

Mark Leland

Yes, let me handle that one. The costs -- I think you will see in the Q a good layout of this, but costs are up for the first half by about $30 million. And you can roughly break that into two lumps. One are labor-related costs and one is the level of maintenance activity. Labor costs, I think we’ve done a lot of increasing of our staffs in engineering and supply chain management. Also, the result of acquisition of the Bluewater System. And so a lot of it is related to preparing for the growth mode that we’re in. Also, some of the labor is related to demographics, and getting ready for people retiring in the field in particular. So, that -- and a lot of that I think is now behind us. We may have a little bit more, but we have moved to a little bit higher plateau, if you will, on the labor side.

The other half; the maintenance activity. On balance, that was all planned for. There were a couple of unusual items, but maybe the activity level is a little bit higher than normal, but for the most part it is at a run rate level. So, I think on balance that was planned for, and we still expect to make our EBIT targets for the year.

Shneur Gershuni - UBS

Okay. If I can just turn to the E&P program for a minute, and specifically with respect to Brazil. If I remember correctly, I think the all-in reserve potential is about 1.1 Tcfe. I think there is about 250 booked in kind of the possible category. I was wondering if this working interest of 24% kind of changes your view of those numbers, and if any potential for it given the acceleration of the project, if we can see some proved reserve potentially booked this year or would we still have to wait for next year for that kind of booking?

Brent Smolik

Yes, Shneur, this is Brent. No, it doesn’t change our range. We’re within a percent or two of where we thought we would be all along on the unitization. And so that’s about consistent – that’s consistent with what we thought all along. We do have the possibility of being able to book some reserves. It’s going to be a function of if we get the approval from the regulatory body ANP and depending on wells that we get drilled and test data that we have to be able to book the reserves. And I am talking about Bia Camarupim, specifically. It’s on that project that we have ability to – the potential to build the book some more. We have to get through a couple of milestones to be able to make that happen.

Shneur Gershuni - UBS

Okay. And one final question, Doug, just sort of bigger picture. Given the increase in CapEx, given the fact you’re no longer pursuing a partner in Pinaúna and so forth, are you still going to be able to complete the share buyback programming? Obviously, the stock is below what the average price you bought it back and so forth. Is it on hold or it’s still being pursued at this point?

Doug Foshee

No, it’s not on hold. We still have the authorization. Remember that we said all along, we weren’t going to spend it before we had it. So, gas prices have come down. And so that’s an issue, but it’s still part of the portfolio. We still have authorization from the board to use it, and we still and on our cash flow is still up, though, we’re no longer today looking at a twelve plus dollar strip for 2009.

Shneur Gershuni - UBS

Great. Thank you very much.

Operator

Your next question comes from the line of Carl Kirst with BMO Capital.

Carl Kirst - BMO Capital

Good morning, everybody.

Doug Foshee

Good morning.

Carl Kirst - BMO Capital

A lot going on. Let me just ask a few quick questions if I could. Brent, on Brazil with respect to, I know you can’t give the details of the oil contract, but you mentioned it could be as much as two to three times historical gas price. My recollection was that the historical gas price in Brazil was in the 3 to 4 range. Is that correct, or am I off there?

Brent Smolik

Typically more like 2 to 2.5, Carl.

Carl Kirst - BMO Capital

2 to 2.5, okay. On Pinaúna then, as I understand what you’re going through, we will not see any gas to sales then in that development, that’s correct?

Brent Smolik

The current concept doesn’t have any gas sales. The next likely hurdle would be that we bring in the other satellite fields south or north. We may incorporate gas production. Right now it is fuel gas.

Carl Kirst - BMO Capital

Okay. With respect to the $700 million to $750 million development of that now, how much – once you kind of lock in the FSO, you said that was kind of material component. How much of that $700 million to $750 million all in will be locked down and just make sure I am on an apples-to-apples. Is that number the same number that was relative to the 4 to 450 we were talking about twelve to eighteen months ago?

Brent Smolik

It is relative to the comparable to the 4 to 450. The big difference is we didn’t have a couple of leases. We had them treated as expense before, and we moved them into the capital bucket. That’s about $100 million total. So, that would come off the 7 to 750 to make it apples-to-apples, and then we have added a couple things. We added the Açai platform and a gas well and gas flow lines. So, there is scope change in there that accounts for part of it, about $30 million. A little bit of increase in environmental scope, about $20 million, and the rest of it is just normal inflation.

Carl Kirst - BMO Capital

Okay. And all of that spending we should basically be seeing in 2009?

Brent Smolik

No. In 2008 and 2009.

Carl Kirst - BMO Capital

2008 or 2009.

Brent Smolik

Yes. We’re spending today, so you will see it show up this year and next.. Yes.

Carl Kirst - BMO Capital

Okay. And then just last question on that with respect to the – you may have mentioned it, in order to get first gas or first oil on by the end of next year, the environmental approval is basically the key milestone. When is sort of the latest we need to see that by in order to keep the project on track?

Brent Smolik

Yes. It is a series of approvals. The first one we would expect before year end of this year is called a terms of reference. That will be the next one you hear us talking about, and then there will be a series of licenses. Just like anywhere else in the world, all the way up to the last one is when we commission the facilities. So, the next one will be before year end, the terms of reference.

Carl Kirst - BMO Capital

Okay. And last question and I will get back in the queue. With respect to the Haynesville well that is completing now, can you tell us what a rough cost you guys are seeing for that?

Brent Smolik

This one is going to be high because we put a fair amount of science into it. We drilled it vertically and cored it and then we plug touchdown back and drilled a horizontal well and then have done a fair amount of testing and completion design evaluation work on the horizontal itself. We [fracked] six times now, and we’ll be putting it in a production test soon. So, it will be on the higher end. It’s probably closer to 10 million than 6 to 7 that we hope is a run rate down the road.

Carl Kirst - BMO Capital

Okay. Thank you.

Operator

Your next question comes from the line of Sam Brothwell with Wachovia.

Sam Brothwell - Wachovia

Good morning. Mark, just a couple of questions. First of all, the loss in power, obviously, with the gas run that we saw that shouldn’t have been unexpected. But going forward, you mentioned a couple things you see that might be able to mitigate that situation, and is it still just not worth trying to exit that position?

Mark Leland

Right. It’s just very illiquid market, and to exit that position couple of options, you could hedge it, but that market is really there hasn’t been any real live counterparties to hedge. We’re starting to see a little more activity in the market and may have an opportunity going forward. The other opportunity is just write a check and get out of it. And really when we’re seeing just a monthly or quarterly run rate of fairly low cash out versus writing a big 200 plus million dollars check to get out of that position, we felt that it’s better to just wait and write it out.

The actual cash settlements have never been as bad as the marks would imply near term. So, we’re looking at and we’ll be opportunistic going forward, if the basis comes in particularly.

Doug Foshee

Yes, Sam, I will tell you how I look at the PJM that we have. We are as a company very net-long, natural gas. And so, if you really believed in the mark that we took this last quarter on that PJM, you’d probably have to add well over $5 billion to the PV of our proved reserve base. And so, given that we are net long and this is an obligation that goes through 2016, our view is there is going to be a point between now and 2016, where the stars align and we think the value proposition is right to exit it. But we can be patient because in the worst quarter, it was $9 million cash in the quarter.

Sam Brothwell - Wachovia

Very good point. And then Brent, with respect to Raton and your working with the state of New Mexico. Governor Richardson seems to have a simple answer to any drilling in that state, and it’s no. Do you anticipate him causing you any trouble there?

Brent Smolik

We don’t think the Governor’s office will get involved in it. This is an area that’s already developed. We already had our hearing in front of the MOCD. It was unopposed by industry or any other interested parties. So, we think it’s just a matter of time. Hopefully, we’ll get our order. We don’t think this is an area that there draw a lot of attention.

Sam Brothwell - Wachovia

Okay. Thanks a lot.

Operator

The next question comes from the line of Faisel Khan with Citigroup.

Faisel Khan - Citigroup

Good morning.

Brent Smolik

Hi Faisel.

Faisel Khan - Citigroup

How are you doing? I just wanted to make sure I understood on the two new pipeline projects that are set to move forward. With Ruby, if I could get a clarification, when would you see first construction on a that pipeline.

Doug Foshee

Well, let’s say, we’ll file the FERC application in early ‘09 allowing a year for FERC process would be we’re planning to construct over the course of calendar year 2010. Planned service date is Spring of ‘011.

Faisel Khan - Citigroup

Okay. So construction to start beginning of 2010?

Doug Foshee

Early 2010.

Faisel Khan - Citigroup

Early 2010. Okay, and then the TGP line 300, same thing there. When would first construction start there as well?

Doug Foshee

Very similar, early 2010 it will be a small piece put in service for the end of 2010 and then the bulk of it in ‘011.

Faisel Khan - Citigroup

And the 300 million cubic feet a day underwrites the $750 million project, is that correct?

Doug Foshee

Yes.

Faisel Khan - Citigroup

Okay. Got you. And then shift to the E&P side of the equation for a second, the Pinaúna project, the capital cost escalation, what was the previous cost on 100% working interest?

Doug Foshee

The range was 400 to 450, Faisel. Now that compares to the 700 to 750. Like I pointed out, there is 100 million in there that we would have accounted for before as expense. So apples-to-apples, 400 to 450 looks more like 600 to 650.

Faisel Khan - Citigroup

Okay, got you. The surprise gas show doesn’t change the CapEx?

Doug Foshee

It did in a sense we now have a gas well, a wellhead platform to hold it up and flow lines to get it back to the facility. As you can see in that diagram we called it the Açai wellhead platform, and that’s going to add about $30 million to that, it’s in that total.

Faisel Khan - Citigroup

Okay, understood.

Doug Foshee

The difference in lease is basically the difference in whether you account for the FSO as operating lease or capital lease. The costs before it was in operating expense, now is in capital.

Faisel Khan - Citigroup

That's right. Can you remind us what else you have going on in Brazil in terms of future development opportunities or future targets that you may have identified?

Doug Foshee

We have three additional exploratory wells on our plans right now. They will be operated by Petrobras. Two of them will be in the same block, the Bia Camarupim project is in. One of those rigs is coming, as we speak --the rig for one of those, and then we have got additional wells -- additional well to be planned that's near the Pinauna project in the BM-CAL-5 block. Again, operated by Petrobras and it is currently drilling. And so, if the rig schedule holds up, we will get three more exploratory wells drilled. So, two development projects, Bia and Pinauna and then three more additional exploratory wells.

Faisel Khan - Citigroup

Okay. And when do you think you might have results from those three exploration wells, earlier next year or…?

Doug Foshee

They could be this year, depending on rig schedule. The one is drilling now could be this year. Remember that Petrobras has some influence over what we can say and when we can say it. But we should have three wells that are either down or near down by end of year.

Faisel Khan - Citigroup

And are you targeting oil in those exploration wells or is it gas?

Doug Foshee

In some cases not sure.

Faisel Khan - Citigroup

Okay.

Doug Foshee

And so you are not sure exactly where we are going to find, because we are far enough in the Pinauna example, the BM-CAL-5 example. We are far enough south where it could be either. The ones that are nearest to the Bia project and the ES5 block are likely to be gas.

Faisel Khan - Citigroup

Okay.

Doug Foshee

And that would be good news because it would go right into the Bia -- we would build a fast track right into the Bia project into the FPSO.

Faisel Khan - Citigroup

Okay. And then maybe I missed this. On the Niobrara Shale, I saw the targeted depths there for the shale A, B and C, but I don't think I heard you talk about the Pierre Shale at all. Is that still an opportunity or is that something that still is being explored by you and other operators in the basin?

Doug Foshee

I think it is still an opportunity. You have you to think about the entire shale section and the Pierre is near the top member is the way you can think about it. And then it is all Niobrara age, and we chose to put our horizontals in the Niobrara A and B Shale based on some of the things we saw in the out crop It looks like it is very highly fractured, so we started there for our horizontals.

Faisel Khan - Citigroup

Okay. Understood. Thank you.

Doug Foshee

I think it will be a function of horizontal versus vertical and the full development. But it is so early to know right now.

Faisel Khan - Citigroup

Okay. Thanks for the time guys.

Operator

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

Rebecca Followill - Tudor Pickering Holt

Good morning. Several questions for you on Brazil. What is the total capital that you guys plan to put in Brazil in '08, in '09?

Doug Foshee

The '08 CapEx that we have talked publicly about is 300 to 350 million. And it is really a function of how much of that exploratory drilling gets completed, and how fast we choose to spend on Pinauna and how fast Petrobras is able to go the Bia Project. So right now, it looks like we will get the one well that is drilled and completed on Bia. Will definitely be in this years’ CapEx, and hopefully, one or two more. But that is why there is a bit of a range. So kind of 300 to 350 million this year. And then long term, we’ve talked about a capital run rate that is in that same neighborhood.

Rebecca Followill - Tudor Pickering Holt

So the 700 to 750 million of spending for Pinauna, that's spread over '08 through 2010 or what's that? Since it is 700 to 715 million, it just seems like a -- that seems low compared to what you are spending on Pinauna?

Doug Foshee

Some actually would have been in 2007, especially environmental costs and the feed and front engineering design and those kinds of things. So seven, eight and nine, would be where we would spread that out.

Rebecca Followill - Tudor Pickering Holt

Okay. And given that you are going to spend a 100% at Pinauna and the opportunities now that you are seeing in Hayensville and some of these other area, does it change your longer-term view on CapEx spending? Also, with the pressure on costs in general and how do you finance it, or do you re-allocate capital?

Doug Foshee

Yes. Well, first off, Rebecca, it is a high quality problem to have, one we have been dreaming about having for most of the last five years, but I think the real answer is, first off, we have a lot of lead time because remember that a lot of this CapEx gets spent over the next four years, particularly on the pipeline side. So we have an awful lot of leverage withhold.

In addition, to internal generated cash flow, we have got an MLP out there, which we expect to grow overtime. We have lots of ability to flex back and forth in terms of the discretionary capital that we spend in E&P. We have the ability to take partners on almost any of the projects we have in the pipeline backlog if we choose to do that, and project finance alternatives. So it is a fun problem to have. We have got lots of lead time to get around it, and look forward to reporting that.

Rebecca Followill - Tudor Pickering Holt

Do you see the need for equity to help finance some of this?

Doug Foshee

No.

Rebecca Followill - Tudor Pickering Holt

Okay. Great. Thank you.

Operator

Your next question comes from the line of Mark [Afracozaci] with Pemco.

Mark Afracozaci - Pemco

Hi, there.

Doug Foshee

Hi, Mark.

Mark Afracozaci - Pemco

Could you just touch on the funding for this CapEx backlog now that it has grown to kind of where it is? And in the context of your solicitated goals of ultimately getting to investment grade at the holding company? And sort of how the financing is going to sort of play out here in the next few years?

Doug Foshee

Yes. I think that was -- that he is really the bulk of the question I was trying to answer for Rebecca. I think what we said in the April meeting was two things. One is, we want to protect the investment grade rating of our pipelines, and we expect to do that. And, two, that while ultimately we want to get to investment grade rating at the holding company level, we recognize that we have got a unique opportunity here, especially with now an $8 million backlog of growth projects in the pipeline business that may keep us from getting there, until we get to the back end of that and that $1.2 billion of incremental EBITDA starts flowing in.

Mark Afracozaci - Pemco

Okay. And then in terms of debt and cash, just pending the 10-Q can you just give us details there?

Mark Leland

Yes. We have about $12.5 billion of debt. We have about $150 million of cash. We have got about a billion six in liquidity as of the end of the quarter.

Mark Afracozaci - Pemco

Okay. And then with Ruby you mentioned the overall blended kind of EBITDA multiple you see on your CapEx backlog, about 7 X, but on Ruby, in particular, can you touch on where that would be vis-a-vis the seven blended average and sort of why it wouldn't be more like 9x?

Mark Leland

It is about 7X.

Mark Afracozaci - Pemco

What kind of dispersion do you see around that, sort of if you were to think of difference scenarios? What would be the 9x, for example?

Mark Leland

Very unlikely. I think we are on the revenue side we have essentially we are probably about 80% to 90% contracted at known pricing. So the only way that you get there would be substantial cost increases.

We have locked in steel and pipe, which represents about a third of the total capital. We have very good solid incentive based contracts with our contractors to perform. So that would be the way to get there, but we don't see it.

Mark Afracozaci - Pemco

Okay. That's very helpful. And then just in terms of stock buybacks, given your view of your stock and then pretty much the whole street in terms of some of the parts, you seem to lead to potential interest in larger scale stock buyback. Can you talk about that, how you sort of balance that against all your CapEx needs and then the longer term goal you mentioned of eventually getting to investment grade

Doug Foshee

Well, we have -- as I mentioned earlier we spent about $30 million of a $300 million board authorization for share buybacks. So we still have $270 million left in our tool kit. And we continue to weigh the alternative of that against incremental spending for growth capital balancing there what our actual cash flow is in this commodity price environment. So what we kind of said at the beginning of that -- of the board authorization for the buyback was we are very excited about it. We saw value in it for our shareholders, but we weren't going to spend that money before we had it, and I think we have been pretty consistent about that.

Mark Afracozaci - Pemco

Thanks a lot. Appreciate your time.

Doug Foshee

Thank you.

Operator

Your next question comes from the line of Rick Gross with Lehman Brothers.

Rick Gross - Lehman Brothers

Good morning.

Doug Foshee

Hi, Rick.

Rick Gross - Lehman Brothers

On Brazil you gave us some fun facts about receiving oil prices for the gas and related things, but I guess the punch line would be are the margins that you expect in Brazil going to be reasonably close to the US?

Doug Foshee

The margins, they are going to be lower, if you think about, it in terms of US getting $8., $9 average, but the economics are -- the returns if you go all the way to returns are going to be quite solid on the project.

Rick Gross - Lehman Brothers

I understand the returns are going to be good. I guess just from an incremental each MCFs if you add, are they going to be half as valuable, three quarters is valuable?

Doug Foshee

It is kind of tough to give you that information today since we can't give you the exact gas price mechanism because we're still in negotiations, but it won't be long. Well we are finalizing that stuff now, and I think you should have some confidence in that given that we are now projecting Petrobras is projecting first gas, first quarter of next year. That projected first gas, first quarter of next year. The other thing I would add to that, Rick, in this world where gas is a bit decoupled from oil, as we look out, I mean, there are worlds you can envision where this would be very comparable. If we have relatively higher global oil prices and low US gas prices for periods they could be very comparable in terms of the EBITDA margin.

Rick Gross - Lehman Brothers

Right. Okay. In the Cotton Valley, a couple of questions. Out west in Raton that you applied for in-fill, how close are you to applying for in-fill in your Cotton Valley properties out east?

Doug Foshee

Not as close. We are still looking at what's the right best places to do it, and do we want to do it horizontally and increase recoveries that way or do we want to drill more vertical wells. So in sequence, I would say Raton, CBM in-fields the farthest already had the hearing. Altamont infield is next because we have the hearing this Fall. Any then any Cotton Valley in-field potential would follow on next year,

Rick Gross - Lehman Brothers

The Cotton Valley horizontal is that basically the deepest member of the Cotton Valley that you are going to horizontally drill into?

Doug Foshee

It works best that way, Rick. If you have a thick basal member then you can drill a horizontal well into the thick basal member and still retain re-completion possibilities in the rest. If you have the upper most, if you have the opposite of that and the uppermost member is the thickest, and you put the horizontal there, then you essentially abandon at least for that the drilling location in the deeper section.

That's where we are starting. That is why we have got the first 30 identified. They are clearly the best in inventory and then we will use that screen and those results to look at the rest of the inventory.

Rick Gross - Lehman Brothers

Okay. That was going to be my follow-up. It is going to be an either or. It is either going to be vertical development or horizontal development, not a little of each?

Doug Foshee

I don't think within a field. I think within a field or within an area geographically, I think there is going to be a better -- a more efficient way to get at it, and we'll try to be smart about which is the most efficient way to develop each area.

Rick Gross - Lehman Brothers

Okay. And then in the Pierre, it looks like the productivity of at least the two horizontal wells, they were different members it looked like, but it appeared that lateral length was important, the productivity. Is this something that you are still going to fiddle with lateral length or you are going to fiddle with completion techniques or you kind of validate it where you want to go here?

Doug Foshee

I wouldn't say validate with two wells and a few weeks of production, but it is going to --you're right, the horizontal length is going to matter, and there will be an optimum length probably limited by more of the surface constraints and the use of existing pads and how efficiently we develop it. So more about geography -- geometry rather, of how it all fits together. So there will be an optimal link. There is also mechanical limit. This is not the easiest thing to drill. It is shallow. It is low pressure, and so we will probably wind up finding a mechanical limit that's kind of tied with the optimization of the producing rates.

The best news of it is, we got over a million a day rates out of these wells, and that was quite an unknown going in if we could, A, mechanically get them drilled and completed and fracked and then B, what kind of rates we get out of them.

Rick Gross - Lehman Brothers

Okay. And then one final question, a pipeline question. You showed your little TTP map, it ran from Kentucky all the way up through the northern section of the Marcelas, but you are little lateral there in the southwest Pennsylvania, actually gets closer to what's the heart of the play right now. And your buddy in Kentucky, Equitable is actually beginning to think about building a gathering system up in southwest Pennsylvania.

Is there something missed in the slide there or is it just not an area that you think you are going to be competitive in?

Mark Leland

What you say could be a possibility, but it is not a big factor in this project. There is clearly an opportunity there, but I think that's all it is.

Rick Gross - Lehman Brothers

Okay. Thank you.

Operator

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

Nathan Judge - Atlantic Equities

Good morning.

Mark Leland

Hi, Nathan.

Nathan Judge - Atlantic Equities

I wanted to follow up on CapEx, just a reconciliation. I know that increased from 3.36 to 3.9 billion, part of that was related to the Pinauna well, but there seems to be about $200 million of incremental spend, and I just wanted to clarify where that was going?

Mark Leland

Yes Nathan, this is Mark Leland. It is really two places. It is incremental capital, about 200 million of incremental capital at the E&P company going from 1.7 to 1.9, and that's not necessarily Pinauna. It was some inflation and some increased activity towards the last half of the year in some of the newer plays.

Nathan Judge - Atlantic Equities

Essentially all domestic?

Mark Leland

Yes. All domestic. And then the other is Ruby, where we have had to increase capital to pre-fund some of the steel and pipe purchases.

Doug Foshee

It wasn't in our original.

Mark Leland

It wasn't in our original plan.

Nathan Judge - Atlantic Equities

Right.

Doug Foshee

Just to clarify, Nathan. E&P increased its domestic, that's largely that 40 to 50 million inflation and the rest of it is essentially keeping rigs and equipment active in the programs that are working, including like the Hayensville Shale, where we stepped up a little there. So we will keep the rig working through the end of the year. So it is all US related, some of that being inflation, 40 to 50 new wells of activity.

Nathan Judge - Atlantic Equities

Just a follow on the 8% higher CapEx comment, is that particularly going to be focused in next year as it sounds like most of the CapEx increase is not necessarily related to this year?

Mark Leland

No. The 8% would really run out over a number of years because it applies to the what we had on the backlog of about $4 billion, and a lot of that is very little actually is in '09. So most of it is '01 and beyond.

Nathan Judge - Atlantic Equities

And also, I just wanted to follow up and get an update on your perception and appetite for dropping down more assets into an MLP given that EPV stock price is a bit lower than it was last quarter.

Mark Leland

Yes, Nathan, this is Mark. I think that our perception and desire hasn't changed. We think there is still an arbitrage between the [sea] corp. where the assets trade at the sea corporate and where they trade in the MLP ultimately especially. We have seen often prices come down, the yields gone up to around 6%.

We have a lot of flexibility in how dropdowns or finance in terms of El Paso. We like our pipelines whether they are in the form of hard assets or in the form of NLP units. So that gives us and we’ve said in the past that we've been willing to take units back, we may just take more back at lower rates, lower prices.

So we are mindful of what the long-term strategic benefit, the MLP provides for us, and that would require certain level of growth in the MLP and we are committed to ensure that happens through organic and through other means.

Nathan Judge - Atlantic Equities

Thank you very much.

Doug Foshee

Let me just wrap up this morning. I want to thank everyone for their patience. I know we went a little long this morning, but we had an awful lot of information. A lot of it good information or positive information to give out, and we appreciate your attention.

Operator

This concludes today's conference. Thank you for your participation. You may now disconnect.

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