德文能源 (DVN) 2010 Q2 法說會逐字稿

Welcome to Devon Energy's second quarter 2010 earnings conference call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question and answer session. This call is being recorded. At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you, and good morning, everyone. Welcome to Devon's second quarter 2010 earnings conference call and webcast. I will begin with some housekeeping items, as usual, and then I'll turn the call over to our President and CEO, John Richels, for his overview. Following John's remarks, Dave Hager, our Head of Exploration and Production will provide an operations update. And then finally, after Dave 's comments, Jeff Agosta, Chief Financial Officer, will review Devon's financial results and our outlook. At that point, we'll open it up to Q&A. I want to point out that our chairman, Larry Nichols, and other senior members of the management team are with us as well for the Q&A session. As a reminder, we will ask each of you in the Q&A session to limit your questions to one and one follow-up. We'll keep the call to an hour. So if we don't get to your question, we'll be around the rest of the day to answer any questions you may have remaining. A replay of this call will be available today through a link on Devon's home page.

During the call today, we'll update some of our forward-looking estimates based on the actual results for the first half of the year, and our revised outlook for the second half of 2010. In addition to the updates that we're going to provide on the call, we will file an 8-K later today that will have the details of our updated 2010 guidance, and the guidance section of our website at DevonEnergy.com will also have the updated forward-looking information. That information is under the guidance link, found within the Investor Relations section of the website.

Before we get to the discussion of the quarter, we're obligated to remind you that the discussion will contain information about our expectations, plans, forecasts, estimates, all this is considered forward-looking statements under US Securities Law, and while we strive to give you the very best estimates possible, there are many factors that could cause our actual results to differ from the guidance that we're going to provide. And so we would encourage you to review the discussion of risk factors that can be found in the 8-K that we are filing today.

One other compliance item, we will refer to various non-GAAP performance measures in today's call. When we use these measures, we're required to provide additional disclosures under US Securities Law. If you would like to review those disclosures, they are available on our website.

I also want to remind everybody that the strategic repositioning that we are currently in the midst of, affects the financial and operational data for all periods reported. Our decision to divest the international operations resulted in the related production being excluded from our reported production volumes for all periods presented. The revenues and expenses associated with those international operations are collapsed into a single line item at the end of our Statement of Operations, labeled Discontinued Operations. Conversely, while we have divested all of our assets and operations in the Gulf of Mexico, oddly enough, the Gulf results are required to be reported in our results from continuing operations through the close of the sales. Said another way, the results from continuing operations reported today include both our North American onshore assets that we are retaining, and the results from our divested Gulf of Mexico operations, through the date of the closings of those sales.

Most of our comments today on the call will focus on the results from continuing operations, but we will also provide some additional commentary, specifically referencing our North American onshore results. And we provided information in the press release that enables you to isolate those results, so that you can see what our go-forward business will look like. For those interested in a more detailed view of our international results, we've also provided information in today's press release regarding that.

As far as the Street earnings forecast go, most analysts reporting estimates to First Call have excluded discontinued operations. The mean estimate of those analysis, that is the mean estimate for earnings excluding discontinued operations, was $1.39 for the quarter. Our adjusted earnings came in $0.05 lower, at $1.34 per share. A main driver was higher than expected deferred tax rate in the second quarter. The second quarter included a true-up in deferred taxes for the first six months of the year. This non-cash deferred tax expense did not affect our cash flow in the second quarter, and after the adjusting items, cash flow from continuing operations came in at $3.02 per share, which was well above the First Call estimate of $2.80 per share. With those items out of the way, I'm going to turn the call over to John Richels.

Thanks, Vince, and good morning, everyone. The second quarter was another very solid quarter for Devon. Second quarter production from retained properties, that is our North American onshore properties, exceeded our guidance, growing to about 620,000 BOE per day. That's up nearly 6% over the first quarter of 2010.

With the better than expected performance from our retained properties, we are raising our 2010 production guidance for our retained properties by 2 million to 3 million barrels to a revised range of 223 million to 224 million barrels equivalent. Operating cash flow from continuing operations totaled $1.3 billion for the quarter. That's a 40% increase over the second quarter of 2009, and second quarter net earnings were more than double that of the prior year, coming in at $706 million, or $685 million after adjusting items. And finally, our marketing and midstream business delivered another solid quarter, generating $125 million in operating profit.

Perhaps equally important is the progress we made during the second quarter with the strategic repositioning that we announced last November. In the second quarter, we completed our exit from the Gulf of Mexico, and finalized our sale of the Panyu Field in China. To date, we've received aggregate pretax proceeds of approximately $4.6 billion. The remaining $5.3 billion assigned transactions yet to close, consists of our divestitures in Azerbaijan and Brazil, and our remaining assets in China.

Last week, we received the necessary approvals for the $2 billion sale of our interests in the ACG field in Azerbaijan to BP, and the closing of that transaction is now scheduled for August 16. In Brazil, the sale to BP continues to move through the multilayer approval process of the Brazilian government, and we remain on track to close that around year end. Aggregate proceeds from the divestitures will approximate $10 billion, or roughly $8 billion after tax. And this is well above the $4.5 billion to $7.5 billion of after-tax net proceeds that we expected when we announced our repositioning last November.

As we've always said, our objective is to redeploy our capital through the combination of E&P projects, share repurchases, and debt repayment, that optimizes growth on a per debt adjusted share basis. Year to date, we've reduced our debt balances by some $1.7 billion, which includes the repayment of all of our commercial paper balances, and $350 million of senior notes. In addition to repaying debt, we've been active with our share repurchase program that was announced in early May. During May and June, we repurchased 7.6 million common shares at a cost of $495 million. If you include the shares we purchased in July, we have now purchased 11.9 million shares at a cost of $761 million. This represents nearly 3% of our outstanding shares. At this pace, we're well on track to complete the entire $3.5 billion share repurchase initiative within the 12 to 18-month timeframe we initially expected.

As we indicated when we announced the strategic repositioning last November, we're also investing a portion of the divestiture proceeds in our go-forward North American onshore business. As part of the asset sales to BP, we announced that we were applying $500 million of the sales proceeds to purchase 50% of BP's interest in the Kirby Oil Sands leases, which are immediately adjacent to our highly successful Jackfish project. We finalized the joint venture agreement with BP during the second quarter, and we changed the name from Kirby to Pike just to avoid confusion with other industry projects in the Kirby area. This acquisition substantially increases our footprint in SAGD oil and extends Devon's visible growth in SAGD oil production for the remainder of the decade. Dave will talk more about the activity that we have planned at Pike later on in the call.

We're also investing a portion of the divestiture proceeds to deepen our oil and our liquids-rich gas inventory in North America. In fact, for the year 2010, we have leased or are in the process of leasing more than 450,000 net acres in oil or condensate-rich plays, in addition to the Kirby Pike acreage. Almost half of this acreage lies in the Permian basin, where we've leased 58,000 additional net acres in our Wolfberry Oil play, 115,000 additional net acres in the Avalon Shale play, and 19,000 additional acres in the Third Bone Spring play. The balance of the acreages and oil plays in the Permian basin and elsewhere that we won't be ready to talk about until we've completed our leasing programs.

During the second quarter, we were also leasing additional acreage in the Cana play. Recently we entered into agreements to acquire about 50,000 additional net acres in the liquids-rich portion of the Cana. This brings our position in the Cana to roughly 230,000 net acres, representing many years of drilling inventory. As many of you know, some industry observers have characterized our Cana play in western Oklahoma as one of the most economic shale plays in North America. The liquids-rich portion of the play offers a significant oil or condensate component, as well as natural gas liquids.

When we entered the year, we expected our 2010 E&P capital, including expenditures associated with the divestiture assets, to total about $5.6 billion. Originally, you might recall we expected to spend $1.5 billion of this budget on the assets being divested. However, the faster than expected progress with the Gulf divestitures in our upcoming close on the sale of ACG has allowed us to redirect about $800 million of that capital to onshore North America, primarily for the new resource capture in the areas that I just covered.

In addition, we've allocated roughly $200 million of the divestiture proceeds to our 2010 capital budget. That brings our 2010 E&P capital budget to $5.8 billion, including the $700 million of capital that we're spending this year on the divestiture properties. Of course this does not include the $500 million Kirby Pike acquisition, which was done as part of the BP transaction. It's worth noting that while the $700 million of capital associated with the divestiture properties will be reported as capital spending by Devon in 2010, the terms of the purchase and sale agreements allow us to recover that capital from the purchasers in the form of purchase price adjustments.

When we analyze our 2010 North American onshore E&P capital spend in terms of product mix, roughly 80% is focused on crude oil, condensate, and liquids-rich projects. Of this 80%, roughly half is focused on crude oil and condensate projects and the other half is focused on projects where natural gas liquids production is the dominant driver of the economics. The balance, that is the remaining 20% of our budget, is largely focused on securing term acreage or derisking natural gas plays in our existing portfolio.

When you step back and view the repositioning of the company as a whole, following the close of the pending asset sales, we will have sold roughly 10% of Devon's proved reserves in production with after-tax proceeds from these divestitures exceeding 20% of our enterprise value. Assuming completion of the balance of the share repurchase program at today's stock price, we will have reduced our share count by 12%, while significantly strengthening our balance sheet and deepening our inventory in some of the highest margin oil, condensate and liquids-rich gas plays in North America. This puts us in an extremely competitive position for the future, regardless of the macro environment.

With that, I'll turn the call over to Dave Hager for a review of our quarterly operating highlights. David?

Thank you, John. Good morning, everyone. I'll begin with a quick recap of Company-wide drilling activity. We exited the second quarter with 65 Devon-operated rigs running. During the second quarter, we drilled 315 wells, including 306 development wells, and 9 exploration wells. All of these wells were successful.

Capital expenditures for exploration and development from our North American onshore operations were $1.1 billion for the second quarter, bringing our total through the first six months to $2.1 billion, excluding the Kirby Pike acquisition. This level of activity increased second quarter production from retained properties by 6% over the previous quarter, and 8% over the fourth quarter of 2009.

Moving now to our quarterly operations highlights, at our 100% Devon-owned Jackfish thermal oil project in Eastern Alberta, our second quarter daily production averaged a little over 29,000 barrels per day net of royalties. Following the close of the quarter on July 10, we had a minor well head release of steam and bitumen. A small hole in the wellhead, likely caused by sand erosion, resulted in the release. Cleanup is about 90% complete, and we expect to finish it in the next couple of weeks. Our technical team has completed an ultrasonic testing of all the Jackfish well heads and determined that the issue is isolated to three well heads on one pad. We will be making the necessary modifications to the well heads and subject to regulatory approval, expect to bring the affected pad back on stream in the next couple of weeks.

The production impact from the incident is minimal, about 5000 barrels per day, while the pad is off line. However, third and fourth quarter Jackfish production will be impacted by a plant turnaround scheduled to begin in September. Accordingly, our net Jackfish production is expected to average about 23,000 barrels per day for the second half of 2010.

With construction of Jackfish 2 roughly 85% complete, the project is about $100 million under budget, and remains on schedule for first oil in late 2011. We expect total project costs through startup for Jackfish 2 to come in below the industry average at approximately $30,000 per flowing barrel. For Jackfish 3, we expect to file the regulatory application in the next few weeks. Pending regulatory approval and formal sanctioning, we could begin site work by late 2011, with plant startup targeted for late 2014. I will remind you that Devon has a 100% working interest in each of these three Jackfish projects.

At Kirby Pike, this is our 50/50 SAGD joint venture with BP that Devon operates. We estimate gross recoverable resources there of up to 1.5 billion barrels. To determine the optimal number of development phases needed, we will initiate a drilling program and begin shooting 3D seismic over the Kirby Pike acreage later this year. With the addition of Kirby or Pike to Jackfish, we expect to grow our net SAG-D production to 150,000 to 175,000 barrels per day by 2020. In our Lloydminster oil play in Alberta, we drilled 14 new wells in the second quarter. Lloydminster production averaged 41,000 barrels equivalent per day in the quarter, a 4% increase over the first quarter.

Moving to the Permian basin, as John mentioned earlier, we have been actively acquiring acreage in several of our key oil plays. In our Wolfberry light oil play in West Texas, we have added 58,000 net acres since the beginning of the year and now have 200,000 perspective net acres in the play. We have four operated rigs running and drilled 26 wells during the second quarter. The second quarter activity included our best well to date in the play, the Hellen Crump B-11 came online, flowing over 500 barrels of oil equivalent per day. While we are still in the early stages of evaluating our large Wolfberry acreage position, results to date have been encouraging.

Also in the Permian basin, we have been building a position in the Avalon shale play. To date, we have assembled 235,000 prospective net acres in this condensate and liquids-rich gas play. Although we are still in the early evaluation of the play, initial drilling results indicate an attractive, repeatable play, with outstanding economics. The best wells we have drilled to date have IPed at over 500 barrels of condensate per day, 500 barrels of NGLs per day, and 3 to 5 million cubic feet per day of gas. Well costs in the play run between $3.3 million and $4 million.

We expect Avalon wells to have average IPs of 300 barrels of condensate per day, 300 barrels of NGLs per day, and 2 million cubic feet of gas per day in the heart of the play. We expect per well recoveries to average over 600,000 barrels of oil equivalent. These characteristics give the Avalon shale great return potential. We expect to participate in 32 Avalon wells this year, including 20 that we will operate.

We have not talked much about our Granite Wash position in the past, we delivered very encouraging results there during the second quarter. We brought two Devon-operated Granite Wash wells online, with an average 24-hour IP of 29 million cubic feet equivalent per day, including 585 barrels of oil or condensate, and 1,330 barrels of NGLs. With recent success in both the Cherokee and Granite Wash A sands, we are stepping up our activity in the area. We currently have two rigs running in the play and plan to add a third rig that we will move from the Barnett later this month.

We have an inventory of about 150 Cherokee and Granite Wash A locations and 200 additional undrilled locations in other Granite Wash formations. Since we hold our position in the Granite Wash with existing production, we are under no pressure to drill. However, given the attractive rate of returns generated by these wells in this environment, we are reallocating capital to this play. We now plan to drill 16 Granite Wash wells this year.

Moving to the Cana Woodford shale in western Oklahoma, as John indicated, we are in the process of acquiring a significant amount of additional acreage in this play. Most of this new acreage is primary term and located in a liquids-rich portion of the play. We are currently running 9 operated rigs and will bring additional rigs into the play over the next few months to secure this term acreage. We continue to see outstanding results from Cana, and believe that the field offers some of the best economics among gas plays in North American shale. In the second quarter, we brought 10 operated wells online, with average 24-hour IP rates of 6.8 million cubic feet equivalent per day, including 86 barrels of condensate, and 350 barrels per day of NGLs.

Second quarter net production from Cana averaged a record 105 million cubic feet of equivalent per day, including 1,000 barrels per day of condensate, and 3,000 barrels of NGLs. This was up 43% on a sequential quarter basis. Earlier this year, we initiated an infield pilot program at Cana to help us better understand optimal well spacing. This was a joint project with another operator that consists of nine total horizontal wells being drilled and completed within one square mile. Five of these wells were spaced at 500 feet apart, and the other four wells at 660 feet apart.

Excluding the first well in the section that had been producing for some time, the average 30-day IP from the eight new wells was 5.4 million cubic feet equivalent per day, including 46 barrels of condensate per day and 245 barrels of NGLs per day. These results are encouraging. We will continue to monitor the performance from these wells to determine if the results support this reduced well spacing.

Moving to the Barnett Shale field in North Texas, we are currently running 17 Devon-operated rigs. But as I mentioned, we will be moving one of these rigs to the Granite Wash later this month. We plan to run the remaining 16 rigs in the Barnett for the rest of 2010. We continue to be very selective with our Barnett drilling, focusing our activity in the liquids-rich areas. Our net production in the Barnett exceeded 1.1 Bcf equivalent per day, including 39,000 barrels per day of NGLs and condensate. Although hidden by the rounding, the second quarter daily rate was up 3% from the first quarter. We continue to expect our Barnett production to reach our previous record production of 1.2 Bcf equivalent per day during the third quarter.

Shifting to the Haynesville shale, after derisking much of our held by production acreage in the Carthage area during 2009, our 2010 activity has focused on our term acreage in the southern area. In addition to the Haynesville potential, we are evaluating the southern acreage for Bossier shale and James Lime potential. In St. Augustine County, we brought our first Bossier shale well online in the second quarter to 24-hour IP of about 8 million cubic feet per day. In southern Shelby County, the Haynesville Motley 1-H, we brought online at more than 7 million cubic feet per day. To help secure our acreage in the southern area, we had begun farming in industry partners on a promoted basis on some of our term acreage. Given the service cost environment in the Haynesville and the deep inventory of other attractive opportunities in our portfolio, we believe this is the most prudent path to take.

And finally, in the Horn River basin of Northern British Columbia, we continue to methodically secure our 170,000 net acres with drilling. We have drilled but not yet completed four of seven planned horizontal wells for this year. We plan to bring these four new wells onto production by year end and the remaining three in the first quarter of 2011. Our producing wells at Horn River continue to perform very well, supporting an EUR of 7 to 8 Bcf equivalent per well.

With that, I will turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

Thanks, Dave, and good morning, everyone.

Today I will take you through a brief review of the key drivers that affected our second quarter financial results and provide our outlook for the second half of the year. As Vince mentioned earlier, we have reclassified the assets, liabilities, and results of operations from our international assets into discontinued operations for all accounting periods presented. As a result, most of my comments will focus on our reported continuing operations. Our reported results from continuing ops include both our retained North American onshore assets and a partial quarter's result from our Gulf of Mexico operations that we've exited during the second quarter.

Looking first at production, in the second quarter of 2010, Devon produced 58.5 million barrels of oil equivalent from continuing ops, or approximately 643,000 BOE per day. Excluding volumes from the Gulf, our retained North American onshore properties produced 620,000 BOE per day. This exceeded the high end of the guidance range provided during last quarter's conference call by roughly 15,000 BOE per day, about 9,000 of which was attributable to a favorable royalty adjustment on natural gas production in Canada related to prior periods. The balance of the production beat is due to better than expected results from both the US onshore business and Canada.

Based on our year-to-date performance and our outlook for the second half of the year, we now expect full year production from our North American onshore properties to climb to between 223 million and 224 million barrels of oil equivalent. We expect our production to range between 610,000 and 620,000 BOE per day in the third quarter and 625,000 and 635,000 BOE per day in the fourth quarter. The midpoint of our third quarter estimate reflects an increase in sequential quarter production after adjusting the second quarter for the out-of-period royalty adjustment that we reported.

Moving to price realizations, in the second quarter, the WTI oil index remains strong, averaging $78.16 per barrel. That is a 31% increase from the second quarter of 2009. During the quarter, regional differentials widened compared to the first quarter, especially with our heavier crudes in Canada. However, our second quarter oil price realizations were right in line with the midpoint of our guidance at 80% of WTI, or $62.35 per barrel.

For the third quarter, we expect our oil price realizations to approximate 95% of WTI for the US and 70% for Canada. In the second half of 2010, we have 79,000 barrels per day, or roughly 70% of our expected oil production hedged, with an average floor of $67.47 and an average ceiling of $96.48 per barrel. Looking ahead to 2011, we have collars in place for 33,000 barrels per day with floors of $75 and average ceilings of $109 per day.

On the natural gas side, the second quarter Henry Hub index averaged $4.09 per Mcf. Our company-wide gas price realizations, before the impact of hedges, were 89% of Henry Hub or $3.62 per Mcf. In the second quarter, we had 61% of our natural gas production hedged, with a weighted average protected price of $5.82. Cash settlements from this hedging position boosted our average realizations by $1.06 per Mcf, bringing the second quarter price up to $4.68.

For the remainder of 2010, our natural gas hedging position will continue to protect roughly 60% of our gas production at an average price of $5.98 in the third quarter and $5.87 in the fourth quarter. For 2011, thus far we have entered into price swap hedges totaling 225 million cubic feet per day at an average price of $5.54 per Mcf. Later this year, we expect to add to our 2011 hedge position.

Looking briefly at NGLs, our price per barrel in the second quarter averaged $30.90 for about 40% of WTI. We expect third quarter realizations to be similar to the second quarter. Seasonal factors should improve NGL realization somewhat in Q4. However, supply growth in the US could put negative pressure on NGL prices over the longer term.

Shifting now to expenses, second quarter lease operating expense came in at $442 million. This equates to $7.56 per barrel, or 2% higher than the first quarter of this year. Looking ahead to the second half, with higher cost Gulf properties now divested, we anticipate LOE will decline to between $7.20 and $7.50 per BOE. For the second quarter, our DD&A expense for oil and gas properties came in at $7.28 a barrel, a 5% decline from last quarter. Overall, our DD&A rate benefited from the sale of our Gulf assets, which lowered our depletion base. For the remainder of 2010, we are forecasting that DD&A expense will be between $6.90 and $7.20 per BOE.

Moving on to G&A expense, we continue to reduce G&A expenditures in the most recent quarter. Second quarter G&A was $130 million, or 25% lower than the year-ago quarter. For the first half of the year, G&A declined by nearly $70 million when compared to 2009. This reduction is largely attributable to lower personnel costs and efficiencies realized through our strategic repositioning. Based on the positive results for the first two quarters 2010, we are now lowering the top end of our full year guidance by $20 million. Our new full year estimate for G&A is a range of $580 million to $600 million.

Looking at interest expense, we reported $111 million for the second quarter. Of that expense, $19 million resulted from the early retirement of $350 million of 7.25% senior notes which we redeemed in June. Excluding this one-time charge, second quarter interest expense totaled $92 million. For the remainder of 2010, we expect interest expense to decline to a range of $80 million to $85 million per quarter.

Looking at income taxes, our reported second quarter income tax expense from continuing operations came in at $261 million. This implies a 43% tax rate on $613 million of pretax income from continuing ops. The most significant item influenced our quarterly tax rate was a non-cash $52 million charge related to the expected repatriation of foreign earnings. Additionally, a nonrecurring taxable gain on the sale of our Gulf assets affected our current and deferred tax allocation for the quarter. This gain on sales shifted $622 million of second quarter tax expense from deferred into current.

When you back out the impact of all the unusual items that are generally excluded from analyst estimates, you get an adjusted tax rate for the second quarter of 35%. This rate on non-GAAP earnings includes a true-up adjustment to bring the year-to-date tax rate up to the 33% we now expect for the full year. In today's news release, we provided a table that reconciles the effective items that are generally excluded from analyst estimates.

Going to the bottom line, earnings from continuing ops, adjusted for special items, came in at $597 million, or $1.34 per diluted share. Operating cash flow from continuing ops totaled $1.3 billion for the second quarter, a 40% increase over the second quarter of 2009. In addition to our operating cash flow, we also received $3.3 billion of pretax cash proceeds from the closing of divestitures in the Gulf and China. We utilized these sources of cash to repurchase $495 million of common stock, reduce debt balances by $461 million, and fund all of our capital demands, including the $500 million acquisition of 50% of BP's interest in Kirby Pike.

We ended the quarter with cash on hand of nearly $3 billion and a net debt to adjusted cap ratio at a multiyear low of only 14%. Overall, we are extremely well positioned to continue to operate our business from a position of considerable financial strength. Continuing to execute on the plan we announced last November positions us for strong growth per debt adjusted share in 2011 and beyond.

At this point, I will turn the call back over to Vince for the Q&A.

Operator, we're ready for the first question.

(Operator Instructions). Your first question comes from the line of David Heikkinen of Tudor Pickering, Holt. Please proceed.

Good morning, guys. Seen a lot of acquisitions this year in your earnings operations and you guys have cash available and have been competitive buying some properties. As you think about bidding processes and amount of capital you commit to acquisitions, can you talk at all about how competitive you've been, any amounts that you think you could actually invest this year, or any thoughts around the overall budget for acquisitions.

David, it's John. As you can see, the areas that we've gone into this year have been areas where we either had a presence and wanted to increase it or areas that were not subject to the same kinds of acquisition climate that some other areas were. When you look at our asset base, as you know, it tends to have some fairly similar characteristics. You tend to have fairly low entry costs and a relatively low royalty burden. And so we try to continue to focus on that.

The roughly $700 million or so that we will have spent this year on acquisitions really helps to augment that base and give us the kind of critical mass in those areas that we needed to really be as efficient as we can. We haven't tended to try to get into bidding wars in some of these high profile plays because we don't think we could be competitive in that environment in any event. That $700 million year to date, can you give any distribution per region to try to tie to the acreage positions that you've had, or at least in the Permian, where you've given acreage? I know some of the other traders are more competitive and you may not want to detail.

Yes, David, this is Vince. First of all, the $700 million that John mentioned was our full year budget now, including the acquisitions of acreage that we've made year to date and also those that we expect to close in the second half of the year. As the waiting to date, year to date has been in the Permian basin and the Cana, we are avoiding specific acreage cost discussions because we are still leasing acreage in those areas. Hope to lease more, but the waiting has certainly been in those two areas and outside the Cana has been on condensate-oriented plays or oil plays.

Thanks, guys.

Your next question comes from the line of Mark Gilman of Benchmark Company. Please proceed.

Guys, good morning. I would like to follow up on the prior question, at least in my first one. It just seems to me that this is probably a time not to be aggressively trying to acquire oil or liquids-rich acreage, but rather gas acreage, thinking a little bit longer term, and trying to invest at least contra-cyclically. I wonder if you could just comment strategically on that. Secondly, more specifically, give me an idea when royalty payout occurs on Jackfish 1 and the assumptions that you might be making in answering the question.

Well, Mark, I'll take a crack at the first one. You know, as you may be aware, we already have a very, very large position in North American natural gas. Matter of fact, we're in a real fortunate position when you look at the companies in the sector, where we have roughly 40% of a 13.5 billion-barrel resource base that is in the form of either oil condensates or liquids-rich plays and 60% that's more in the gas So we've got quite a bit of that and what we're trying to do is simply allocate our funds to the expenditures that give us the best return at the time. We think we've got a lot of running room in the gas area as well. Doesn't mean that we won't continue, as we always have, to continue to augment positions in those areas, but we've got a lot of running room in the acres that we already have.

Okay. Pat, on Jackfish?

Mark, this is Vince. We've looked around the table at each other and nobody is really certain -- oh, John, you're certain of the answer?

Mark, I think we're getting right to the royalty payout level now, and the way the royalty setup in Alberta is now, we pay 5% on our production to pay out and now that we're two and a bit years into production there, we're just about reaching that payout level. On the first phase. Sorry, on the first phase only.

One, two and three are separate projects for royalty payout calculations and purposes?

That hasn't been determined yet. We're making our application for Jackfish 3 and through that application will determine whether these are separate projects or not.

Okay, thanks, guys.

Your next question is from the line of Doug Leggate from Merrill Lynch. Please proceed.

Thanks, good morning, everybody. The capital commitments, John, that you have discussed on the discontinued operations, can you give us some color a little bit on how you basically get that capital back and whether or not there's any commitments to maintain levels of activity and just generally what it means for your activity levels and things. Obviously you're not going to want for the longer term. That's my first question.

This is Dave. First, that is just simply to get the capital back, that's just simply a purchase price adjustment because the effective date of the transaction is January 1 of 2010. So it's just part of the purchase price adjustment, very simple process. And we are communicating actively with the purchaser of the discontinued assets that have not closed yet. And that's primarily BP on the Brazil assets.

There's an agreed upon plan that we had prior to the divestment of these assets, and we are executing that plan. We're having discussions with them. But there's really no source of contention at all about what we're doing. They like the plan. That's why they bought the assets, and we're continuing on with the plan and there's really no issue about what the next step should be between now and close.

This is maybe a little impertinent let's assume you have another discovery from an exploration well. Is there any recourse to change or negotiate the price on the asset?

No, there's no recourse. And of course either way, you know, discovery or dry hole, and I think frankly, we were able to very fairly represent the potential of all the wells that we're drilling right now and we think we got paid for it.

Okay, great. My follow-up is completely unrelated. It's I guess Pike and the potential development planning. I just wondered if you could give a little bit more color. You talked about the level you expect to get to by the end of the decade, but what's the likely timing on Pike in terms of when you might actually think about breaking ground on that project.

We have quite a bit of work to do yet before we know for sure on that on what the timing may be. Obviously we're going to enter a busy winter with our additional strat drilling and 3D seismic we're going to do out there as well as some engineering work, but given all that, I can give you kind of a rough intuitive timetable, provided that we have adequate reservoir delineation through this winter's drilling program. We could have an application for the first phase of Pike somewhere in late 2011. Now, how large that phase is has not yet been determined and it really depends somewhat on the results of this winter's drilling program.

But then with that, you might have regulatory approval somewhere in early 2013 and then you could begin facilities construction, have first steam somewhere around mid-2015 and potentially reaching peak production probably on that first phase somewhere in late 2016. All that's a tentative schedule and we have a lot of work to go yet to know if we can accomplish that. Again, that would be the first phase, and whether the first phase is 35,000 barrels a day or 70,000 barrels a day or something like that, we don't know yet. We have to do the work this winter and that will give us a lot better handle on that.

I would just throw into that, when you think about it, if you look at Kirby and, or Pike and Jackfish together, and I think we've talked about this before, we have been keen to acquire that acreage, that Kirby Pike acreage for many, many years and really came together as a result of this larger transaction we did with BP, we've got continuous projects coming on. The second phase of Jackfish, the third phase of Jackfish, and then several phases of Kirby. And we feel pretty darn good about that Kirby acreage. As Dave said, we got to do a lot of delineation drilling, but we have a lot of wells there already that we had core samples for, from 250, Dave was saying 250 wells, so there is a lot of wells there that we have -- we're pretty enthusiastic about this development prospects on this acreage over the next five to ten years.

Terrific. Very quickly, when do you get a 15% tax rate up there, John?

Well, it depends on whether these projects get lumped together as one large project or individual projects. We haven't finally determined that yet with the regulator.

Great. I'll leave it there. Thank you.

Your next question is from the line of Scott Wilmoth of Simmons and Company. Please proceed.

Hey, guys. Just thinking more about 2011 natural gas hedges, sounds like you guys are started to put some hedges on and roughly looks like about 10% of production. Are you guys still targeting a corporate level of 50% hedged and is there a price that you guys would not add natural gas hedges at?

Our goal still, as we said earlier, our goal is going to have about 50% of our production, both natural gas and oil hedged each year. We set that as a goal. When we do it, how we do it may change. I think our view as well has been that we're going to try to lock in prices that give us some real protection and don't just give a prediction within, at the bottom end of a range that we believe to be likely for the year. Darryl's here. Darryl, do you want to add anything to kind of what the market looks like today and where we might be going with our hedges in the next little while?

No, I think you covered it. As Jeff I think pointed out, we have 225 million today hedged via swaps at $5.55 or thereabouts on the gas side. We do intend to get up to that 50% level. Our view is that we could have prices anywhere from $4 to $6. We're in the middle of a real heating season, or cooling season period right now and right in the middle of potential hurricanes, which actually have historically had a tendency to move price quite a bit. We'll probably be in the $5 to $5.50 range in the next few months and do expect to get to that 6% level by the end of the year.

Any preference for collars or swaps right now?

Right now we're targeting mainly swaps on the gas side and we do have a preference for oil on the, or for collars on the oil side, as is indicated by I think 33,000 or 35,000 barrels we have already. We tend to like swaps on gas and collars on oil.

Okay, thanks. And then jumping over to the Avalon, can you guys just comment on how many rigs you guys are currently running, and considering things are going well, where you think that rig count heads into 2010, 2011. Excuse me.

Well, hopefully it's going up. We're running one rig right now. We're going to be adding a couple more rigs here later on this year. We're really just getting the first results of our operated wells. We have participated in a handful of OVO wells that give us a good indication of the potential. We want to get some results from our operated wells also, but the potential liquid content that we see in the heart of the play here, this could be a very attractive play for us economically. And if it all works out, I can see us significantly increasing our activity next year on this play. But we just need to get a little bit more results, but we're very encouraged with what we know so far and think it could be a pretty big play for us in the future.

And just one last one on Avalon. Can you speak generally about the geologic makeup of Avalon, generally characteristics?

Yes, I can give you a few stats. Avalon is essentially the source rock for the Bone Springs out there. Give you a few stats. Tends to have porosity generally in the range of around 8 to 15%. It is a shale. It's a fairly thick shale. It's a fairly homogeneous shale out there. The thickness on it ranges on the New Mexico side probably anywhere from around 125 to over 300 feet thick.

Similarly, on the Texas side of the play, which is much less mature from a drilling standpoint at this point. We know it's that a very liquids-rich play on the New Mexico side. It is less known what the liquids rich, how liquids rich it is on the Texas side of the play. And that's part of what we're going to be determining with our drilling program when we add a rig on that side as well. But it's a thick homogeneous shale with good porosity normally pressured, but with apparently a very high liquids content. If you're curious here, also on the order of around 7,000 to 10,000 feet on the New Mexico side a little shallower on the Texas side, more like 6 to 7000-foot.

We need to move on to the next person in the queue at this point.

Thanks.

Your next question comes from the line of Brian Singer of Goldman Sachs. Please proceed.

Thanks, good morning.

Good morning, Brian.

Following up on some of the earlier questions on lease holds and just needed a clarification question, how much did you actually spend in lease holds in the first half? What has been implied for the second half? And does that get you to where you want to be in your key plays you're pursuing, or is this something you're seeing as ongoing over the next few years?

I tell you what, while we're looking up the amount spent in the first half versus the second half, let me tell you philosophically, Brian, while we think we always need to have a lease hold acquisition component to have a sustainable business, we've done a disproportionate amount of leasing in 2010 to what we would expect on an ongoing basis. And to the extent that additional acreage at reasonable prices is available in these very attractive plays, we would continue to take on additional acreage. We always have to work towards a balance of resource capture and resource development. And we're very mindful of that. So, while we had some opportunities to beef up our positions here, we will balance the capital going forward.

And, Brian, I would just remind you, we kind of look at this as part of this ongoing repositioning. The repositioning involved not only the sale of our Gulf and international operations, but also some increase in our positions in some of these areas. As Vince said, we got to do this all the time. What we also have to do -- we may want to move them out or farm them out or do other things with them. So there is probably a disproportion national amount we've done here as part of this reallocation process.

Brian, coming back to the first part of your question, the acreage acquisition throughout 2010 outside of Kirby is roughly equally spaced first half of the year to expected second half of the year.

Great, thanks. And then as a follow-up, you've generally made the comments since restructuring, despite the divestitures, your liquids versus gas mix wouldn't change much, considering the growth at Jackfish. With the activity and lease hold changes and the more liquids-focused spending shift, do you expect that this should further shift your production mix more towards liquids, and can you quantify how much and where you see and when you see that happening?

Well, it's certainly -- the extent we have more acreage in these oil, condensate and liquids-rich plays it, does increase that. I would go back to pointing out, as you know, we've already got such a large portion that's oil or liquids-rich that it's not like we're going from a very small proportion to suddenly doubling it. So it will make a difference. I don't know exactly how much of a difference that will make, Brian, but as you looked at our, you know, we've talked before about our 32,000 drilling locations before any of these acquisition, the resource acquisitions that we made this year, and 13.5 billion barrels of resource potential, that was already about 40% focused on oil, condensate and liquids. So by adding this, it certainly augments it, but it's not like we are suddenly trying to get into the oil, condensate or liquids business. We were already in it.

Brian, I might point out that while we're about a third of our current production is oil and liquids, about 40% of our proved reserves are oil and liquids. So we're definitely based on our proved reserve mix, our production mix would move that direction, all things being equal over time.

Thank you.

Your next question comes from the line of Ray Deacon of Pritchard Capital. Please proceed.

Good morning. John, I was wondering if you could elaborate a little bit on the Cana in terms of when you would expect to have a good idea on the downspacing and whether that is going to work. Is it six months or--?

Sure. Let me turn that over to Dave to answer that question, right.

Six months is probably a pretty good estimate. We want to get a good production history on these wells before we really make a decision on it. I will remind you that at least when we talk about our perspective, the potential in Cana, the potential does not include any resources associated with this downspacing. So if this downspacing is successful, and I think we characterize Cana before, was about 8.8 TCF equivalent. If this downspacing is successful, then we could add to that total significantly, hopefully.

Got it, great. And I was wondering, I guess given the large increase in acreage and I was wondering, what do you see as a sustainable growth rate based on a $5 gas and $75 oil world at this point, given the repositioning in your CapEx?

This is Vince. The problem with the question is we're really trying to optimize growth per net adjusted share. So there's a lot of variables into how we allocate capital going forward. We've got potential in our resource base, given enough capital spend, to deliver double-digit top line growth for a long period of time. Whether that's the right decision or not depends on our outlook for oil and gas prices with our equities trading and a variety of other factors. We're not going to pin down a number on that.

Okay, got it.

Thank you.

I guess just one more kind of bigger picture question, you know, with the industry's focus on liquids plays, what's your outlook for -- do you think ethane, butane, propane will continue to trade at a premium to gas, or are you looking to hedge as your volumes ramp for those products?

Yes, this is Darryl. Obviously at least in the short-term, over the next year or two, we do believe there could be some additional pressure on liquid prices, primarily ethane. There's limited market in terms of -- that make plastics and using refineries and that's about it. Doesn't have the degree of flexibility that a propane product would have, so we do think there's possibility if there's continued increase in capital spend on these projects throughout the industry that you could see some downward pressure, primarily on the ethane side of the business, but we still think it will trade at a 20 to 25% premium to natural gas, if you're looking at gas price in the 5 to 5.50 range. A little bit of downward pressure but still trade at a premium.

Got it. Thanks very much.

Operator, we're ready for the next question in the queue.

Your next question comes from John Herrlin from Societe Generale.

With Jackfish 2, you mentioned that you had a good savings in terms of the development. How was that manifested? Was it just lower labor costs, or what was going on there?

Hi, John. This is Dave. It was a different approach to the project management, I would say was the overall contributor to that, where we did a lot of the project manager, did more internally versus externally on Jackfish 1, and that really allowed us to have greater control of the overall project and greater control over the costs. And so we just really incorporated a lot of the learnings we had on Jackfish 1 and Jackfish 2 and we'll use those again in Jackfish 3.

Okay, great. With Avalon, Dave, how long are the horizontals, how big are the fracks? And also you did mention the organic content. How does this formation compare to, say, the Barnett?

I don't have all that data in front of me. I'm sure we can get back to you. The horizontal lengths we're planning to drill is about 4000 feet on these wells. TOCs, total organic content on these, John, I better double-check before I say some numbers, but this is pretty darn rich. I can tell you that.

Okay, great. Last one for me, you're in a lot of plays that are competitive. Are you locking in consumables, like type, or trying to lock in more rigs in terms of your future spending since you have stepped it up?

Yes, John, this is Daryl. We have some longer-term contracts on some of our rigs. I think right now we have 23 under long-term contracts. Those contract lengths vary from a year up to three years. I think Dave said we are running 65 rigs, so obviously we have a lot of rigs that are not under long-term contract. And while we may move some of those rig under long-term contracts up a little bit, I don't think it would be very much. Historically we've tried to stay somewhere between 40 and 50% on our long-term rigs.

The bigger issue is related to costs, has to do with fracking costs and those costs went up significantly and while they started being quite high in the Eagle Ford and the Haynesville, that has certainly progressed to the rest of the country now. Our experience has been in dealing with these people that are providing the services is that they don't want to walk in and -- long-term projects unless it's at a real premium price, even in today's market. They still believe costs are going to go up, so we have not had really any positive response from any of those service providers in terms of wanting to lock in long-term contracts at current prices. So I don't imagine we will probably do that. There are some things that we are locking in. We're locking in some fuel prices for some of our rigs and things of that nature, but some of the bigger service costs in terms of the fracking and stuff, I don't think that's going to happen any time soon.

Okay, thank you.

Okay, operator. We've got time for one more question.

Your next question comes from the line of Philip Dodge from Tuohy Brothers Investment. Please proceed.

Good morning, everybody. Two quickies. First, on the Barnett, your production guidance for the September quarter, 1.2, going forward, how many rigs would you have to employ to maintain that level?

Right around that level, where we currently are, 15 to 17, somewhere in there.

Okay, and then on the Horn River, you gave EUR number of 7 to 8 Bcf per well. Could you tell us what lateral length and number of fracturing stages are embedded in that EUR?

Yes, we're still optimizing the number of frack stages that we would have in the Horn River. We think it's going to be most likely in somewhere in the 8 to 11 area. We're getting a little bit over an Mcf per frack stage and it's just a really cost trade-off, provides the best economics on the lateral length for the Horn River shales. Again, we're optimizing that. We anticipate is going to be somewhere in the range of around 4600 to 5900-foot.

Okay, thanks very much.

Okay. We're a couple of minutes past the top of the hour, so we'll wrap up the call for today. Thanks for joining us, and as we said earlier, we'll be around the rest of the day for any follow-up.

Thank you for your participation in today's conference. This concludes the presentation. And you may now disconnect. Have a great day.