Devon Energy Corporation (DVN) Q2 2010 Earnings Report, Transcript and Summary

Welcome to Devon Energy's Second Quarter 2010 Earnings Conference Call. [Operator Instructions] 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 comment, Jeff Agosta, our 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 seniors members of the management team are with us today as well for the Q&A session. And 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 homepage. During the call today, we will 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 in the call, we will find an 8-K later today that will have the details of our updated 2010 guidance. And the Guidance section of our Web site 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 Web site. Before we get to the discussion of the quarter, we're obligated to remind you that this discussion will contain information of our expectations, plans, forecasts, estimates; all of this is considered forward-looking statements under U.S. 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 U.S. securities law. If you would like to review those disclosures, they are available on our Web site. 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 closing 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 the information on 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 review of our international results, we've also provided information in today's press release regarding that. As far as the straight earnings forecast go, most analysts reporting estimates to First Call have excluded discontinued operations. The mean estimate of those analysts, 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. Main driver was higher-than-expected deferred tax rate in the second quarter. 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 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, and that's up nearly 6% over the first quarter of 2010. With the better-than-expected performance from our retained properties, we’re raising our 2010 production guidance for our retained properties by 2 million to 3 million barrels to a revised range of 223 million and 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 profits. 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 of signed 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 interest in the ACG [Azeri-Chirag-Gunashli] field in Azerbaijan to BP and the closing of that transaction is now scheduled for August the 16. In Brazil, the sale to BP continues to move through the multi-layer 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 the 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. And if you include the shares we purchased in July, we now have 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 some other industry projects in the Kirby area. This acquisition substantially increases our footprint in SAGD [Steam Assisted Gravity Drainage] 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 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 have 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 acreage is in 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 are 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 divestitures 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 and our upcoming close of 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 analyzed 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 economic. The balance, that is the remaining 20% of our budget, is largely focused on securing term acreage or de-risking 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 crude reserves and 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 David Hager for a review of our quarterly operating highlights. David?

Thanks, John. Good morning, everyone. I'll begin with a quick recap of the 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 nine 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, in 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 wellhead 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 wellheads and determined that the issue is isolated to the three wellheads on one pad. We will be making the necessary modifications to the wellheads, and subject to regulatory approval, expect to bring the effective pad back on stream in the next couple of weeks. The production impact from the incident is minimal – about 5,000 barrels per day while the pad is offline. 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 SAGD 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 prospective 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 Helen 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 perspective 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 IP-ed at over 500 barrels of condensate per day, 500 barrels of NGLs per day and 3 million 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. Although we have not talked much about our Granite Wash position in the past, we delivered some 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 the 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 and 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 primarily term and located in the liquids-rich portion of the play. We are currently running nine 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, included in 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 in-field [ph] 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'll be moving one of these rigs to the Granite Wash later this month. But 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 de-risking 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 San Augustine County, we brought our first Bossier Shale well online in the second quarter with a 24-hour IP of about 8 million cubic feet per day. In Southern Shelby County, the Haynesville Motley #1H was brought online at more than 7 cubic feet per day. To help secure our acreage in the southern area, we have begun farming in industry partners on a promoted basis on some of our term acreage. Given the service cost environment in the Haynesville and a 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 the seven planned horizontal wells for this year. We plan to bring these four new wells on to 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 [estimated ultimately recoverable] 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 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 a 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 U.S. 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 U.S. 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 ceiling of $109 per barrel. 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 realization 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 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, or 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 U.S. 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 continued 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 of 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 the $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 of from continuing ops. The most significant item that influenced our quarterly tax rate was a non-cash $52 million charge related to the expected repatriation of foreign earnings. Additionally, a non-recurring taxable gain on the sale of our Gulf assets affected our current and deferred tax allocation for the quarter. This gain on sale 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've 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 30% 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 for $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 BPs interest in Kirby-Pike. We ended the quarter with cash on hand of nearly $3 billion in a net debt to adjusted cap ratio at a multi-year 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 & Co. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: Seen a lot of acquisitions this year and you raised 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’d 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 kind of 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, with kind of fairly low entry costs and a relatively low royalty burden. And so we tried 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 gives us the kind of critical mass in those areas that we need in order to really be as efficient as we can. So we have intended to try to get into bidding wars in kind of some of the high-profile plays because we just don’t think that we can be competitive in that environment in any event. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: That $700 million year-to-date, can you give any distribution per region or to try it 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 trade areas are more competitive and you may not want to detail.

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 weighting 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 weighting has certainly been in those two areas, and outside the Cana has been on condensate-oriented plays or oil plays.

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

I'd 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 liquid-rich acreage, but rather gas acreage, thinking a little bit longer-term and trying to invest at least contra-cyclically. I wonder if you can 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?

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 one. 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 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 acreage that we already have.

On the royalty payout on Jackfish?

Mark, this is Vince. We’ve looked around the table at each other and nobody’s 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, I think, 5% on our production to payout. 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 only.

And 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 though that application, we’ll determine whether these are separate projects or not.

Your next question comes from the line of Doug Leggate from Merrill Lynch.

The capital commitment side, 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, just generally what it means for your activity levels and things. Obviously, you’re not going to want the longer-term.

This is Dave. First, 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 that closed yet, and that’s primarily BP on the Brazil assets. There is 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 there. They liked 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.

Let’s assume you had another discovery down there from an exploration well. Is there any recourse to change negotiated price on the asset?

No. There is no recourse. And of course, either way, may have a discovery or dry hole, and I think, frankly, we are 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.

My follow-up is completely unrelated. I guess Pike and the potential development planning, I just wonder if you can 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?

Well, 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 strut drilling and 3D seismic we’re going to do out there, as well some engineering work. But given all that, I can give you kind of a rough and tentative 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 will depend somewhat on the results with 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 team somewhere around mid-2015 and potentially reaching peak production probably on that first phase somewhere in late 2016. All of that’s a tentative schedule and have a lot of work to go yet to know if we can accomplish that. But again, that’d 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.

When you think about it, if you look at Kirby or Pike and Jackfish together, I think we talked about this before. We have been keen to acquire that acreage, that Kirby-Pike acreage, for many, many years and it really came together as a result of the 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, Dave was just saying 250 wells. So there's a lot of wells there that we have core samples from. So we’re pretty enthusiastic about this development prospect on this acreage over the next five to 10 years.

When you go to 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.

Your next question comes from the line of Scott Wilmoth of Simmons & Company.

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

Well, our goal still, as we said earlier, our goal is going to be to have about 50% of our production of both natural gas and oil hedged each year. We set that out as goal. When we do it, how we do it may change. And I think our view as well has been that we’re going to try to lock in prices that will give us some real protection and don't just give protection at the bottom end of the 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?

Well, I think you covered it. As Jeff, I think, pointed out, we have to a 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 you cooling season period right now and right in the middle of potential hurricanes, which actually have the tendency, historically, to move price quite a bit. So we’ll probably be in the market in the $5 to $5.50 range over the next few months and do expect to get to that 50% level by the end of the year.

Any preference for callers or swaps in that regard?

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

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 do you think the rig count heads into 2011?

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 OBO wells that give us a good indication of potential. We want to get term 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.

One last on the Avalon, can you just speak generally about the geologic makeup of the Avalon? Just kind of some general characteristics?

I can give you a few stats here if you’d like. The Avalon is essentially the source rock for the Bone Springs out there. I’ll give you a few stats here if you’d like. It tends to have porosity generally in the range of around 8% to 15%. It is a shale, it’s is a fairly thick shale; it’s a fairly homogeneous shale there out there. The thickness on it ranges on the New Mexico side, probably on anywhere of 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 noted it's a very liquids-rich play on the New Mexico side. It is less known how liquids-rich it is on the Texas side of the play, and that’s part of what we’re going to determining with our drilling program when we add a rig on that side as well. But it's a thick, homogeneous shale with a good porosity, normally pressured, but with, apparently, a very high liquids content. On the depth of it, if you’re curious here, is also on the order around 7,000 feet to10,000 feet on the New Mexico side; a little bit shallower on the Texas side, more like 6,000 to 7,000 feet.

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

Following up on some of the earlier questions about leaseholds, and just maybe this is a clarification question, how much did you actually spend in leaseholds in the first half? What is then 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 that you see as ongoing over the next few years?

I tell you what, while we’re looking up the amounts spent in the first half versus the second half, let me just tell you philosophically, Brian, that while we think we always need to have a leasehold 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 balance of resource capture and research development. And we’re very mindful of that. While we’ve had some opportunities to beef up our positions here, we will balance the capital going forward.

And Brian, to just remind you that 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. And as Vince said, we’ve got to do this all the time. What we also have to do, though, it may make some other projects that we have non-competitive. We may want to move them out or farm them out or do other things with them. So there is probably, as Vince said, a disproportionate amount that we’ve done this year as part of this reallocation process.

The acreage acquisition throughout 2010 outside of Kirby is roughly equally spaced first half of the year to expected second half of the year.

As a follow-up, you generally made the comment since the restructuring, that despite the divestitures, your liquid versus gas mix wouldn't change much, partly considering the growth of Jackfish. With the activity and leasehold changes and the more liquid-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?

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

While about 1/3 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.

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

John, I was wondering if you could elaborate a little bit on Cana in terms of when you’d expect to have a good idea on the down spacing and whether that is going to work. Is it six months?

Let me turn it over to Dave. Dave can answer that question, Ray.

The 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 down spacing. So if this down spacing is successful, and I think we’ve characterized Cana before, but it was about 8.8 Tcf equivalent. If this down spacing is successful, then we could add to that total significantly, hopefully.

I was wondering, I guess, given that the large increase in acreage, I was wondering what do you see as a sustainable growth rate, based on $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 optimizing growth per debt adjusted share. So there's a lot of variables into how we allocate capital going forward. We've got the potential in our resource base, given in of 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, for our equities trading and a variety of other factors. We’re not going to pin down a number on that.

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

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 they make plastics and they’re using refineries and that's about it. It doesn’t have the degree of flexibility that a propane product would have. So we do think that there is a possibility if there's a 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 just still think that it will trade at a 20% to 25% premium to natural gas, if you're looking at gas prices in the $5 to $5.50 range. So little bit of downward pressure, but still traded at a premium.

Your next question comes from John Hurling [ph] from Society General.

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

This is Dave. I’d say it was a different approach to the project management. I would say that it was the overall contributor to that where we did a lot of project management. We 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 cost. And so we just really incorporated a lot of the learnings that we had on Jackfish 1 and the Jackfish 2, and we’ll use those again in Jackfish 3.

With Avalon, Dave, how long are the horizontals? How big are the fracs? And also you didn't mention the organic content. How does this formation compare to say, the Barnett?

I don't have the data in front of me. I’m sure we can get back to you. The horizontal lengths we’re planning to drill, it’s about 4,000 feet on these wells. TOCs, total organic content on these, John, I’d better double check before I say some numbers, but it’s pretty darn rich. I can tell you that.

You're in a lot of plays that are competitive. Are you locking in consumables like pipe or trying to lock in more rigs in terms of your future spending since you have stepped it up?

John, this is Darryl. We have some longer-term contracts on some of our rigs. I think right now, we have 23 under long-term contracts. Those contracts 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 rigs 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 long-term rigs. The bigger issue is really the cost has to do with the frac-ing costs. And those costs went up significantly. And while they started being played 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 providing services that they don't want to lock in any 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. And 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 frac-ing and stuff, I don’t see that, that’s going to happen anytime soon.

Your next question comes from the line of Phillip Dodge from Tuohy Brothers Investment.

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?

We’re right around that level, doing where we currently are, around 15 to 17, somewhere in there.

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

Well, we’re still optimizing the number of frac stages that we would have in the Horn River. We think it's going to be most likely somewhere in the eight to 11 area. We’re getting a little bit over a Mcf per frac stage and it's just really a cost trade off there on what provides the best economics. On the lateral length for the Horn River Shale, again, we’re optimizing that. We anticipate it's going to be somewhere in the range of around 4,600- to 5,900-foot.

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.