Devon Energy Corporation (DVN) Q3 2011 Earnings Report, Transcript and Summary

Welcome to Devon Energy's Third Quarter Earnings Conference Call. [Operator Instructions] This call is being recorded. At this time, I'd like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you, operator, and good morning, everyone. Welcome to Devon's Third Quarter 2011 Earnings Call and Webcast. Following my preliminary housekeeping and compliance items, our President and CEO, John Richels is going to provide his perspective on the quarter. Then, Dave Hager, our Executive Vice President of Exploration & Production will cover the operations highlights. And following that, Jeff Agosta, our CFO will finish up with commentary on our financial results and positioning. We'll conclude with a Q&A period. And as usual, we'll hold the call to an hour. Also with us today is Larry Nichols, our Executive Chairman, and other members of Devon's senior management team for the Q&A session. A replay of this call will be available later today through a link on our home page. And during the call today, we're going to provide guidance for key fourth quarter metrics. We will not be issuing a revised 8-K today because our full year estimates generally remain within the guidance ranges that we've provided in the 8-K we filed in August. Any refinements to our guidance provided during the call today will be available on our website. You can always get the latest guidance through the Guidance link on the Investor Relations page or section of Devon's website. Please note that all references in today's call to our plans, forecasts, expectations and estimates are considered forward-looking statements under U.S. securities law. And while we strive to give you the very best estimates possible in every case, there are many factors that could cause our actual results to differ from those estimates. A discussion of risk factors related to these estimates can be found in our SEC filings. Also on today's call, we will reference certain non-GAAP performance measures. When we use these measures, we are required to provide certain related disclosures. Those disclosures are also available currently on Devon website. With those points out of the way, I'll turn the call over to President and CEO, John Richels. John?

Thank you, Vince, and good morning, everyone. The third quarter of 2011 was our first full quarter following the completion of our repositioning. As a company focused entirely on North America, Devon delivered a very solid third quarter performance. Let me begin by highlighting some of our results. Our third quarter adjusted net earnings from continuing operations of $1.54 per diluted share increased 18% over the year-ago quarter and exceeded the first call mean by $0.09. Our cash flow from continuing operations of $4.19 per diluted share increased 26% over the year-ago quarter and surpassed the first call mean by more than 20%. For the third quarter, we increased North American onshore production 8% over the year-ago quarter, driven by a 17% increase in oil and natural gas liquids production. With strong growth in liquids production and a focus on controlling costs, Devon's pretax cash margin increased to more than $26 per barrel equivalent in the quarter. Also during the third quarter, we repurchased 10.8 million shares for $697 million, remaining on track to complete our $3.5 billion stock repurchase program by year end. And with $6.8 billion in cash and a net debt-to-cap ratio of 10%, our balance sheet remains in terrific shape. In addition to the development drilling that's driving our current production growth, we're continuing to actively evaluate the oil and liquids potential on our 1.2 million net acres in 5 high potential new venture plays. This includes our positions in the Tuscaloosa, the Mississippian, the Niobrara, the Ohio Utica and the Michigan Basin. Our 40-well program across those 5 plays is well underway. We have drilled our first wells in each of the plays and have additional wells in various stages of completion. While it's still early on, we've been very encouraged with our results as well as those from industry peers near some of our positions. To improve the risk/reward profile of these new venture plays, we've been conducting a data room process to bring in a partner. We're clearly not pursuing this because we need the money. Given the strength of our balance sheet, we could easily pursue all of these opportunities simultaneously, with 100% ownership. However, we see many advantages to bringing in an exploration partner. First, the joint venture could improve our capital efficiency, both by recovering the costs associated with establishing the acreage positions and by providing a reduction of our capital requirements in the future. Second, the joint venture would allow us to accelerate the derisking and commercialization of these new venture positions. And third, the joint venture could allow us the opportunity to seek exposure in more new play types with less risk. So a joint venture presents us with the opportunity for accelerated commercialization, improved capital efficiency and risk mitigation. Given that we're currently engaged in this data room process and still adding to our positions, we're not going to report specific well results in our new venture activities today. However, I can tell you that the indications of interest we have seen from potential partners have been very strong. Now before I turn the call over to Dave, I would like to address the subject of a number of recent questions concerning our capital outlook for next year. Although we're still in the process of finalizing our 2012 capital budget, our philosophy remains steadfast: We remain fully committed to optimizing value by maximizing growth on a per-share basis adjusted for debt. In order to achieve that goal, we remain keenly focused on exercising capital discipline, maximizing our full cycle returns and maintaining a high degree of financial strength and flexibility. Based on this philosophy, we will not compromise our per-share results for top line growth by funding projects with low rates of return. Instead, we will strive to optimize the allocation of capital among our alternatives of investing in our oil and liquids-rich opportunity base, capturing additional resource and repurchasing our shares. Of course, the relative attractiveness of these various options changes with movements on Devon's stock price, our borrowing costs and our outlook for commodity prices and industry costs. Since we've not finalized our 2012 E&P capital budget, I cannot provide specific capital guidance. However, I will provide some directional comments. In 2012, we expect to implement a drilling program with activity levels similar to 2011. Our focus in 2012 will be on developing the high-margin oil and liquids opportunities in our existing portfolio and accelerating the evaluation of the many new plays that we have captured. Our preliminary 2012 capital budget does not contemplate a repeat of the roughly $700 million of acreage acquisitions that we are making in 2011. And therefore, in total, we expect our capital outlay in 2012 to be less than 2011. The majority of our 2012 capital will be focused on core development projects. In Canada, we expect to begin construction on the third 35,000-barrel per day phase of Jackfish in the first quarter of 2012. In the Barnett and Cana, we will continue the aggressive development of our inventory of thousands of undrilled locations in the liquids-rich portions. Furthermore, in 2012, we'll be expanding our gas processing plants in each of these plays to keep pace with our growth and capture additional value. In the Permian, we will continue investing in our reliable development plays, including the Wolfberry, the Delaware and the Bone Spring. And in addition to investing in these low-risk development plays, we will continue to actively evaluate our acreage positions established through our greenfields new ventures. These exploration plays, coupled with the emerging plays that we're just beginning to evaluate in the Permian and in Western Canada, hold tremendous future potential for Devon. We strongly believe that the Devon's stock creates a differentiating opportunity for investors in the E&P space. Our deep and diverse inventory of oil and liquids-rich opportunities provides us with great flexibility in allocating capital based on market conditions. Our superior financial strength allows us to consistently invest in our business based on our long-term outlook regardless of the near term macro economic backdrop. We remain intently focused on optimizing margins and continuing to position ourselves as a low-cost producer. And finally, we maintain a disciplined approach of balancing resource development with resource capture to optimize the value of our entire portfolio. All of these factors position Devon to deliver competitive growth in cash flow and production per share. So at this point, I'll turn the call over to Dave Hager for a review of our quarterly operating highlights. Dave?

Thanks, John, and good morning, everyone. I will begin with a quick recap of 2011 capital expenditures for our exploration and development activities. E&P spending was $1.6 billion for the third quarter, including $250 million of undeveloped acreage acquisitions. This brings our E&P capital through the first 9 months to $4.7 billion. We expect fourth quarter expenditures for exploration and development to be approximately $1.5 billion. While this would take us outside our guidance range for E&P spending, it is partially offset by our midstream capital, which should fall well below the midpoint of our guidance range. Consequently, we expect our total capital expenditures for 2011 to come in near the top end of our guidance range. Our 2011 E&P capital program is delivering outstanding results. Our cornerstone development areas including the Barnett, Cana, the Permian and Jackfish are all performing very well. We also continue to move forward with evaluating and derisking the upside potential in our various emerging and new venture plays. So let's take a closer look at some of the third quarter highlights in these areas. Starting with our thermal oil projects in Eastern Alberta. Jackfish continues to deliver industry-leading performance. During the third quarter, Jackfish 1 production averaged 32,000 barrels per day, net of royalties, and continued its trend of excellent plant reliability and efficiency. At Jackfish 2, we continue to be very pleased with the ramp up of production. In the third quarter, our net production averaged 4,000 barrels per day. And in October, it averaged almost 9,000 barrels per day, exceeding planned volumes. Review of our regulatory application for Jackfish 3 is nearing completion. Pending approval, we will begin construction in the first quarter of next year, with plant start-up targeted for late 2014. Devon operates all 3 Jackfish projects and owns 100% working interest in each. At our Pike joint venture, our 2011, 2012 winter drilling and seismic program will begin later this month. We plan to drill roughly 140 stratigraphic wells and shoot approximately 50 square miles of seismic this winter. The program will focus on confirming the resource potential for a third 35,000-barrel per day project in the Pike 1 Complex. This will bring the identified resource at Pike up to roughly 900 million barrels gross, which translates to gross production potential of over 100,000 barrels per day. Devon operates Pike and owns a 50% working interest. Ultimately, we believe the Pike acreage can support the equivalent of 4 or 5 Jackfish-sized projects. In aggregate, between Jackfish and Pike, we expect to drive our net thermal oil production to between 150,000 and 175,000 barrels per day by 2020. Moving now to the Permian basin. We currently have 19 operated rigs pursuing targets in numerous play types across the basin. Our third quarter Permian oil and liquids production increased 17% over the year-ago quarter. In total, our Permian production averaged 50,000 equivalent barrels per day in the third quarter with 75% of that being oil and natural gas liquids. In our Wolfberry light oil play in the Permian, we currently have 4 operated rigs running as we continue the evaluation and development of our 160,000 net acres. Our net Wolfberry production climbed to a record 9,500 barrels of oil equivalent per day in the third quarter. While we are currently developing the Wolfberry on 40-acre spacing, we have a 20-acre infill pilot program underway. We brought our first 220-acre Wolfberry infill wells online during the third quarter with encouraging results. The remaining infill wells in the pilot program are currently drilling, as well as our first horizontal well in the Wolfberry development area. The additional potential represented by 20-acre well spacing and horizontal Wolfcamp wells in certain areas provide upside to our current inventory of more than 850 net risk Wolfberry locations. Moving to the Bone Springs oil play also in the Permian. We currently have 8 operated rigs running. We continue to see outstanding results from our horizontal program on both the New Mexico and Texas sides of the play. With average EURs ranging from 400,000 to 600,000 barrels equivalent and well cost between $5 million and $8 million, most of these wells are generating rates of return in excess of 50% based on the current strip pricing. In the third quarter, we completed 11 Bone Springs wells with 30-day average IP rates of 540 barrels of oil equivalent per day. Production from our Bone Springs horizontal program has increased 300% to almost 5,000 equivalent barrels per day since the beginning of the year. Elsewhere in the Permian, we continue to run 2 rigs, targeting the conventional Delaware oil formation. We drilled 7 wells and completed 4 of them during the third quarter. The 30-day IP rates for the completed wells averaged nearly 400 barrels of oil equivalent per day. Like the Bone Springs, these wells offer outstanding returns based on strip pricing. We have approximately 125 net risk locations remaining in the Delaware. Also in the Permian, we increased our Wolfcamp Shale oil position in the Midland Basin during the quarter, to approximately 92,000 net acres. We brought our first horizontal wells online during the quarter and are very pleased with the results. Much of our acreage is located in the area where current industry activity is concentrated, and our initial results indicate that this acreage is commercially viable. We plan to drill 8 Wolfcamp Shale wells this year, with 6 or 7 completed and online by year end. Moving north to the Texas Panhandle in the Granite Wash play, we continue to see solid results from our Cherokee and Granite Wash A wells. We brought 10 operated Granite Wash wells online during the third quarter. The 30-day IP rates from these wells averaged over 1,250 barrels of oil equivalent per day, including 180 barrels of oil and 405 barrels of natural gas liquids per day. We were also drilling our first wells in the area to test the Atoka Wash and Caldwell zones, which provide upside to our Granite Wash position. Moving now to the Cana Woodford Shale in Western Oklahoma. Reconstruction of our Cana gas processing plant is now complete. We began processing gas in late October and are currently running about 138 million cubic feet per day through the facility. Ramp-up will continue over the next several weeks as we expect to reach the plant's inlet capacity of 200 million a day in September. We have also started work on a planned expansion at Cana. This will increase the capacity of the Cana plant to 350 million a day with liquids extraction capacity of more than 30,000 barrels per day. The expansion allows us to keep pace with our growing Cana Woodford Shale volumes and roughly doubles our liquids extraction capacity in Cana. We expect the increase in capacity to be operational in the fourth quarter of next year. On the drilling front, we ended the quarter -- the third quarter with 17 operated rigs running in the Cana, 6 rigs fewer than in the previous quarter. We have achieved drilling efficiencies that allow us to now maintain the pace of our Cana program with fewer rigs. Accordingly, we made the decision in third quarter to release 2 rigs. In addition, while awaiting the recommissioning of our Cana plant, we elected to sublease 4 additional rigs to another company for the remainder of the year. With the Cana plant coming back online, we are confident in achieving our year-end exit rate target of 275 million cubic feet equivalent per day, net to Devon's interest. In spite of the planned operation -- or interruption, excuse me, our third quarter net Cana production increased 6% over the second quarter to a record 200 million cubic feet equivalent per day including more than 8,100 barrels per day of liquids. Shifting to the Barnett Shale field in North Texas. We currently have 12 operated rigs running. In the third quarter, we brought 77 Barnett wells online. We are continuing to see outstanding results from our Barnett program in the liquids-rich portion of the play. Our net Barnett production increased to a record 1.3 Bcf equivalent per day, including 46,000 barrels per day of liquids. Upon completion of our Bridgeport planned expansion in the first quarter of 2013, we would expect to see our net volumes climb to an all-time record of more than 1.4 Bcf equivalent per day with our current 12-rig program. On the exploration front, in addition to the progress that John mentioned in the other new ventures plays, we continue to evaluate the potential of our position in a number of plays emerging in our historical areas of operations. In Canada, our exploration efforts are ongoing as we target oil and liquids-rich opportunities across our more than 4 million net acres. In aggregate, we completed 19 exploration wells and tied 10 of them into production in the third quarter. The best results we saw were in the Cardium. In the third quarter, we brought 3 Cardium oil wells online in the Ferrier Area of Central Alberta. Average 30-day IP rates from these wells were 770 barrels of oil equivalent per day. We are currently completing 2 additional wells in the area. Another encouraging result from our third quarter exploration program in Canada came from our Viking light oil play at Saskatchewan. We completed 4 wells in the third quarter with 30-day IP rates of up to 70 barrels per day. These are shallow wells, and we would anticipate cost of roughly $1 million per well in the development phase of this play. While we're still working to optimize our drilling and completion approach, we are encouraged by these early results. I'll remind you that we own 100% of the surface and minerals in a very large acreage position with more than 1,000 potential drilling locations. Also in Canada, we brought 2 Slave Point oil wells on in the Swan Hills area, with average 30-day IPs of 300 barrels per day. We have an inventory of more than 160 undrilled Slave Point locations and plan to drill 3 additional wells in the fourth quarter. Of the 10 exploration wells brought online in Canada during the quarter, 9 were successful. So while it's still very early in the process, we are excited about the results we have seen. In summary, all of our key development projects are delivering excellent results and we continue to take important steps in evaluating a deep inventory of exploration opportunities across our portfolio. With that, I'll turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

Thank you, Dave, and good morning, everyone. This morning, I will take you through a brief review of the key drivers that shaped our strong third quarter financial results. I plan to limit my comments to items that require additional commentary or outside our forecasted guidance range. The first item I would like to cover is our production. In the third quarter, we produced 60.8 million oil equivalent barrels or approximately 661,000 equivalent barrels per day. This result was just above the midpoint of the forecast we provided on our second quarter call. And as John said, it represents an 8% increase in production over the year-ago quarter. On the liquids side of the business, we again delivered robust growth. For the quarter, our oil and natural gas liquids production increased by 17% over the third quarter of 2010 to an average of 226,000 barrels per day. Strong year-over-year oil growth from the Permian Basin and Jackfish, combined with liquids growth in the Cana and Barnett, drove this impressive performance. Looking to the remainder of the year, we remain on track to deliver full year production of 238 to 240 million equivalent barrels. When compared to our North American onshore production in 2010, this represents top line production growth of about 7% to 8%, driven by liquids growth in the high teens. With the Cana plant starting back up, we expect Q4 production to increase to a range of 665,000 to 675,000 BOE per day. Given our growth in oil and natural gas liquids production and the current weakness in natural gas prices, nearly 60% of our third quarter upstream sales revenue came from liquids. Regional oil prices remained strong during the quarter, and petrochemical demand pushed NGL realizations higher. Our E&P revenues were again supplemented by cash settlements from our attractively priced hedges. In total, cash settlements increased revenues by $96 million in the third quarter and boosted our company-wide price realizations by $1.58 per BOE. Not only were our upstream revenues strong, but our marketing and midstream operations made another strong contribution. We generated $138 million of operating profit in the third quarter, which represents an 11% increase over the third quarter of 2010. To put this into perspective, our marketing and midstream operating profit enhanced our company-wide margins by $2.27 per BOE. Based on our results for the first 9 months, we expect full year 2011 operating profit to be in the top half of our guidance range of $515 million to $545 million. Shifting to expenses. In the third quarter, we were successful in partially mitigating the impact of industry inflation. Expenses in most categories showed a moderate increase, but were generally in line with our expectations. In aggregate, our pretax cash costs totaled only $13.56 per barrel for the quarter or about 2% higher than last quarter. This continues to give us a very competitive cost structure within the industry. We remain well positioned as a low-cost producer and expect to continue to generate full cycle margins that are among the best in our peer group. Looking ahead to the remainder of the year, we remain comfortable with the expense forecast provided in our August 8-K. One noteworthy item for those of you who model our results, is that fourth quarter G&A expense will include approximately $20 million of noncash expense due to the issuance of annual equity compensation. Including this noncash expense, we expect fourth quarter G&A expenses to range between $170 million and $180 million. Looking briefly at income taxes. For the third quarter, we reported income tax expense from continuing operations of $498 million or 32% of pretax income. After backing out the impact of special items typically excluded from analyst estimates, you get an adjusted tax rate of 35%. This is made up of a current tax rate of negative 12% and deferred taxes of 47%. This atypical distribution of current and deferred taxes was driven by a change in our estimate for our full year taxable income. The cumulative impact of this change was recorded in the third quarter. Looking ahead to the fourth quarter, we would expect our overall tax rate to range between 30% and 35%, with essentially the entire amount being deferred. Going to the bottom line. Non-GAAP earnings from continuing operations totaled $640 million or $1.54 per diluted share. Strong liquids production and pricing, coupled with our reduced share count, drove our adjusted earnings from continuing operations up by 18% per diluted share over the year-ago quarter. As John mentioned earlier, this result exceeded the first call mean by $0.09. As most of you are aware, in May of last year, we commenced a program to repurchase $3.5 billion of our common stock. As of today, we have repurchased $3.4 billion, and we expect to conclude the buyback program in the fourth quarter. We have a history of buying back shares when we believe it is the best use of our capital. Since 2004, we have repurchased 114 million shares, reducing our outstandings by approximately 20%. In conjunction with finalizing our 2012 capital plans, we will determine what role, if any, additional share repurchases will play in our 2012 capital allocation. I would like to conclude with a quick review of our financial position. In the third quarter, cash flow before balance sheet changes totaled $1.9 billion. On a per-share basis, cash flow from continuing operations increased 26% over the third quarter of 2010. During the quarter, we comfortably funded all of our capital demands ,and returned nearly $800 million to our shareholders in the form of stock buybacks and dividend payments. We ended the quarter with cash and short-term investments of over $6.8 billion and a net debt-to-cap ratio of 10%. As we have discussed in previous calls, we currently have more than $6.6 billion of cash and short-term investments outside the United States. If a more favorable tax situation develops for the repatriation of these funds or if we deploy the proceeds into Canada, we can reduce our tax expense by up to $900 million. Until we have better visibility into these opportunities, we plan to keep this cash outside the U.S. Given our short-term borrowing rates of less than 30 basis points, it is certainly worth our time to be patient and observe how opportunities, including the repatriation legislation, evolve. Regardless of where our cash balances reside, we clearly possess a great deal of financial strength and flexibility. At this point, I will turn the call back over to John.

Thank you, Jeff. All the results we're seeing in 2011 are a great example of our disciplined approach to the business. Let me just summarize that for you again. In the third quarter, we delivered a very strong quarter. We continued to execute in our key development plays, delivering oil and NGL growth of 17% over the year-ago quarter. We took important steps in evaluating a number of emerging and new venture opportunities. We delivered another excellent performance in terms of containing costs in an inflationary industry environment. We delivered another solid quarterly performance in our midstream business. And we continued to maintain a pristine balance sheet. As always, we remain committed to exercising capital discipline, maximizing margins and optimizing growth per share. At this point, we will open the call up to your questions. Vince?

During the Q&A session, we ask each of you limit your questions to one initial inquiry and one follow-up. And operator, we're ready to take the first question.

[Operator Instructions] Your first question comes from the line of Brian Singer with Goldman Sachs.

When we think about the 2012 and your kind of drilling program, are there any rigs drilling today where if gas prices hold, you would look to drop? Or do you feel comfortable based on the liquids contribution from your current operated rig count that the rates of return in the current price environment are acceptable?

Brian, as you might remember, we're spending over 90% or allocating over 90% of our capital in 2011 to oil and liquids-rich opportunities. And even at today's prices, in any of the rigs that are drilling in the gas plays where the returns are enhanced by liquids recoveries are still providing a good rate of return. So we're not spending any material amount today on plays that aren't providing a good rate of return.

Okay, and then when we look at some of the new venture plays where you didn't necessarily discuss individual well results, Duvernay, the Utica, Tuscaloosa, A, do you feel your acreage positions are where you want it to be, or should we expect that you would expand these positions. I think you mentioned in your opening comments not to expect the $700 million of acreage acquisitions you are planning or have made in 2011. And then B, when you think about bringing in JV partners, is essentially your view that selling a JV interest, and potentially buying more Devon shares with that cash has a superior rate of return versus drilling over time and retain any upside from otherwise keeping a higher interest?

Let me start with the latter question and then maybe I'll turn it over to Dave to talk about our acreage positions. But what we're doing here, Brian, with the -- with our joint venture -- as you know, it's something we've not typically done and we wouldn't be -- it doesn't make sense to us to take a development project, for example, and joint venture it because we have pretty low cost of capital. But we're doing this for different reasons. We have some acreage positions that are clearly exploratory in nature. And as we said, bringing in a partner to try to diversify some of that risk and at the same time improve our capital efficiency in the future just seems to make a lot of sense for us. So there are a lot of reasons for us to be doing this. The way I kind of look at it, if you look at these 5 new venture plays and you think about when we're in the exploration business drilling wells, it's like 5 couple of hundred million dollar or more exploratory wells and we would always brought a partner in, not for the cash flow management as much as for the risk diversification. And thankfully, even the Exxons of the world tend to do that. So that's the rationale behind the exploring of this joint venture. Maybe I can have Dave address the question on some of these land positions.

Yes, and once again, I think that whenever we have the opportunity to essentially eliminate the upfront negative cash flow associated with acquiring the acreage, and then that gives us the opportunity to redeploy that capital either back into drilling or share repurchase -- of course, we haven't made a decision on that, it certainly improves the capital efficiency and it certainly improves our ability to grow on a cash flow-per-debt-adjusted share basis. But more specifically on the acreage, we're very, very happy with the acreage position we have. We have been conducting the data room and as John said in his comments -- prepared comments, we've had outstanding interest from the companies who have reviewed our acreage position, so we feel there's -- not only do we like it, there's a lot of independent confirmation from other people out there that we have a great acreage position. Having said that, it is possible that with good results on or continuing good results on some of these, we may incrementally add some acreage on some of these plays. But that's really only going to be driven by the well results that we see. That's one of the reasons we don't want to go into too much detail on what we're seeing right now, because there is some acreage available in some of these plays and we'll be driven by the success of the plays. But even if we don't add any, we're very happy with the position that we have.

Your next question comes from the line of Bob Brackett with Bernstein Research.

Considering these JVs, a couple of questions. One is, would you consider the Cardium and Viking in a sort of JV package? And the second is what's changed -- if we go back, we've known of these 5 sort of new venture plays for a while now, but this is the first we've heard of a JV approach. What's changed in your thinking?

Well, first of all I, mean right now, Bob, we're just talking about those 5 plays, whether we would do anything in any of our Canadian plays, and I think that remains to be seen. But really nothing has changed other than the fact that we see a lot of opportunity in these 5 plays and a lot of capital commitment over time. And as I said, to bring somebody in at an early stage in the exploratory play to help diversify that risk just seems to make sense to us in terms of keeping the maximum capital efficiency and pursuing a prudent investment philosophy. So nothing's really changed other than the fact that these all have a lot of potential and a lot of capital investment over time.

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

Another question on the joint venture. It seems like the topic today. But what kind of structure can you say in general you're looking for? Are you looking for like one party to work with you in all these plays? Or you're looking potentially having different partners in different areas? What kind of structure are you looking at from that perspective? And then in terms of like the consideration, are you looking for a carry with some cash upfront or an all carrier? What are your thoughts on that?

Well, we've been open to the structure, but typically, these have been structured in a way that there's some cash upfront. The good thing about that is it allows you to recover all or the majority of your capital investment to date and then some kind of a carry in the future. But we're not looking at doing a whole bunch of joint ventures with different parties. What we're really pursuing is the idea of creating a joint venture with one partner where we clearly align the interests of our joint venture partner with the interest of the company. So as we move down the road on some of these projects, that we don't just continue to drill because we got a bunch of joint venture cash out there, but we can move it around, make sure that we continue to allocate the capital both from our point of view and the joint venture partner's point of view to a place where we're making some money.

Okay, that's make a lot of sense. And then I would assume that you'd like to retain operatorship?

Yes, we'd like to retain operatorship.

Okay, okay. And then as a follow-up, in the Permian Basin, what are the governors there for you right now in terms of like increasing activity from where you're at right now?

Yes, I'd say the primary governor on it is the technical understanding and confidence to -- of how quickly we could ramp up. Most of these are not what I would call your classic pure resource plays where you can just go in and carpet bomb these things on a set acreage spacing. There's a lot of science involved in these. And so it's really to have the right level of technical knowledge on all these plays. Additionally, there is some -- particularly in 2012, I would say, there's a secondary concern, but there are some takeaway capacity issues that exist in the Permian. Those are being addressed and we don't think they're going to be long-term issues. But in 2012, it is something that we're certainly taking into account in how many rigs we're putting in what area. We're making sure that we can really move the production out of there.

Your next question comes from the line of Scott Wilmoth with Simmons & Company. Scott M. Wilmoth - Simmons & Company International, Research Division: When thinking about your potential JV partner, is there any defining characteristics in terms of you're looking for in someone with exploration technique or expertise? Or is it more just to derisk the investment?

It's always good to have some technical expertise in your partner. But what we're really looking for as well is we recognize that entering into a joint venture like this on 5 plays is not something that lasts for 2 years or 3 years or 4 years. It's something that lasts for the next 20 years. And so we want a partner that we also believe will be aligned with us in our investment objectives and that we can work with over time. Scott M. Wilmoth - Simmons & Company International, Research Division: So how much interest are you guys looking at selling down in each of these plays?

Yes, that's still really to be determined, Scott. We got this with this process open and we're going to be a little bit flexible on that, so I can't tell you that at this point. Scott M. Wilmoth - Simmons & Company International, Research Division: Okay. In the Cardium, positive well results out of the 3 wells you guys released. What are the EURs? Does that make you think -- rethink the EURs in the play? And what was does your inventory look like in the Cardium?

Well, we really have the Cardium in 2 different areas. We have some in the Ferrier Area and we also have Cardium in the Deep Basin play overall. We see, if the whole think could work, we're going to have up to 1,500 gross risk locations, a resource potential somewhere 50 to 100 million barrels. We're seeing EURs, it's still early on, but we're anticipating EURs somewhere in the 200,000 to 300,000 barrels equivalent per well range.

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

Dave, I've seen some stuff recently about the possibility or the potential for a shale play in the Washakie Basin. Is this something that might be applicable to you guys' legacy production or interest in the play?

Once again, you have me there, Mark. We have a big position in Washakie, but we frankly have not been looking significantly at a shale position in the Washakie. And if there is, we'll take a look at it. But it's -- we're looking at a lot of places, but the Washakie is not one that's been hit the radar screen real high for us right now.

Okay, just as an unrelated follow-up. Dave or John, can you give me some idea -- I mean I'm assuming, as part of a potential joint venture, you would be looking for a pretty good promote. Can you give me any ideas as to the scale of that promote that you might be seeking?

No, I think it's too early on to really go into the details of the scale of the promote that we're looking at. All we can say is we've been very encouraged by the interest from the companies who've been through the data room.

Your next question comes from the line of David Tameron with Wells Fargo.

I'm going to ask a question about the joint venture. So if I hear what you're saying, it sounds like rather than drill the acreage yourself and prove it up and try to sell it at a later date, which in theory would have more value, you're choosing to mitigate the risk by doing this upfront? And then the second part of that would be as part of the thought process, not only a strategic partner for these shales, but somebody that perhaps you could JV with up in Canada, and a larger partner that gives you some more flexibility down the road. Am I thinking about that, right?

Sure. I mean, we could well if we have the right partner and have the right relationship, this could well expand, not only to Canada, it can expand to other new plays as well. But -- and again David, I'll say that one of our objectives here -- and this is a little bit different joint venture. Most of the joint ventures that you've seen in the business so far have been play-specific. This is one that covers a lot of different plays and has some unique characteristics from that point of view, because it does align both parties with pursuing the ones that make the most sense. We may find that some, as we develop them, we want to sell and put that money into other opportunities within that joint venture, and would be very well aligned with our joint venture and would be very well aligned with our joint partner on that. So I think there's a lot of flexibility. It's early stages in terms of what the exactly a deal like that would like, but it gives us a lot of flexibility to develop these opportunities on a fairly accelerated basis.

Okay, and if Vince will allow me an unrelated follow-up. If I think about Canada versus -- Permian versus Canada, can you talk about the different rates of return? How you guys see that as far as your decision to allocate rigs and capital?

Well, we obviously, as a global statement, we look at our entire E&P portfolio and allocate capital to what we think are the best return projects across our entire portfolio. So we certainly compare their rates of return in Cana to those in Permian and those in Canada, so we have a good understanding and make sure we're putting capital in the right places. The Cana, the returns do vary somewhat. I'd say particularly the core of Cana where we're currently even conducting the downspacing pilot project, a series of those, those liquids-rich returns are extremely strong. And we're still booked at 5 wells per section in the core of Cana and we see the opportunities of downspacing, we could go to 8 to 10 wells per section. And we frankly only grilled it on one well per section right now in most areas, so we have a lot of liquids-rich opportunities remaining in Cana. Some of the areas do get somewhat leaner. And as you would expect, as you get leaner, then the returns diminish somewhat, but we're careful that we're concentrating our capital in the highest return parts of the plays that compete on a portfolio-wide basis.

To restate -- just to make sure I have the answer, it sounds like core Cana would be at the top and then non-tier Cana somewhere down below Cardium and Permian. I put some editorial comments in there, but is that the right way to think about it?

Well, and there's varying degrees. I think you're looking for a simple answer and it's the wells are a spectrum, I'd say, from the core being the absolute best and as you get somewhat less condensate in natural gas liquids, then you have a continuing down to rates. But again, we're funding -- we make sure that we only fund those that compete competitively or compete well with the Permian or the Cardium or any other opportunities in our portfolio, so...

Yes, this is Vince. I'd add to that, too. When you try to compare a specific play to the Permian, we've got a number of different play types in the Permian ranging from light oil where the -- in the current environment, the rates of return are very, very strong to shale plays that we're just trying to derisk and understand. So there's a wide spectrum of returns in the Permian.

Your next question comes from the line of Doug Leggate with Bank of America.

So a couple of quick ones, one-on-one follow-up. Your liquids pace has picked up again this quarter. As you try and pull the whole thing together in terms of rig activity where you're targeting capital and so on, can you give us some kind of idea as to how you see the projection of your liquids as a proportion of your portfolio going forward. I guess keeping pace with the 90% cost of capital you're putting into those plays. And I've got a quick follow-up, please,

Well, I'd say that we see in the future that we are going to continue to allocate the vast majority of our capital, 90%-plus to liquids-rich plays. And so I would expect that for some time frame that our liquids growth rate would be consistent with what we're achieving this year in the upper teens because that's what we're focusing our capital.

We've talked before, Doug, about the fact that in places like the Permian, we ought to be able to grow that to the high teens or even up to 20% for the next few years. And as we're continuing to bring additional volumes that we talked about earlier with our planned expansions on in places like the Cana and the Barnett, we're going to get additional liquid volume and of course, Jackfish ramps up from -- the Jackfish 2 from a small number of barrels right now up to somewhere approaching 35,000 barrels a day through next year. So we got a lot of places that we ought to be seeing pretty strong liquids growth over the next year.

Yes, if you just look at 2011, we're growing oil and liquids production in the teens, high teens and we're growing gas production in the low single digits. So clearly our production mix is moving towards our reserve mix, which is more oil and liquids as a percentage of total reserves.

It's very helpful, Vince. My quick follow-up is really on NGL pricing. You guys, I guess, historically have a fairly [indiscernible] and I guess I'm really trying to figure out how sustainable you believe that the strength of NGLs is when you take the interplay of propane exports with brand pricing and so on. Just some color there and I'll leave it at that.

This is Darryl Smette. Well, what we have seen, as you probably know, is a greater increase in activity and that has led to a much greater increase in supply. The positive side of that is that we've seen a substantial increase in demand, both on the export side of things, propane primarily, and some increased activity in the manufacturing sector, including refinery. We expect that demand will continue to increase as we go through 2012. We have a little bit of concern as we get into the middle of 2013 that we might see supply exceed demand for a while until some of the new petrochemical plants come onstream and the expansion in the greenfields. So we think that -- there could be some weakness as we get to the mid-2013, maybe into 2014. But past that, we see demand from some of these new projects coming online. And so we think that we'll start seeing the value of NGLs pick up again after we get into 2014.

Your next question comes from the line of John Herrlin with Societe Generale.

Two quick ones. With the Bone Springs wells, what kind of decline rates are you seeing?

I don't have the exact number in front of me, John. I don't think here. Well, in general it's somewhere around 70%, first year decline, I think -- excuse me, 50%. I see I looked at the wrong number on my spreadsheet, 50%.

Okay. With the oil field services, are you seeing any moderation in pricing? Should we anticipate you becoming sand miners soon? What are you seeing?

This is Darryl again. We really do not have any plans to be sand miners. But we continue to see price escalation, primarily on the service side of our business. Drilling rigs and other services have increased about 2% in the third quarter from the second quarter. Overall, we're going to probably see a 10% to 12% increase in cost this year. We expect that we're going to see some pressure on costs, primarily in the service sector as we go into 2012. The biggest areas where we've seen the biggest increase in service costs have been recently in the Permian. They continue to grow fairly rapidly in Canada. And then industry, I think, has seen some pretty strong service costs to South Texas, but Devon's not a big player in South Texas. But they have started winding down a little bit from where we saw in the first half of the year, but they're still increasing primarily in the simulation side in the drilling rigs.

Your next question comes from the line of David Heikkinen with Tudor, Pickering. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Now can I ask a joint venture question. As I think about your '11 CapEx on the midstream side, how much of that presses into 2012? And how much of that is just absolute cost savings?

This is Darryl again. We're probably going to see about a $300 million midstream cost in 2011. While we haven't finalized our budget for 2012, we know we're going to spend about $200 million of the roughly $300 million on our Cana plant and our Barnett plant in 2012, so there's not been a lot deferred quite frankly. But while we haven't finalized our budget, we'll probably see $200 million in plants, the 2 plants that I mentioned. We have about $75 million to $80 million of what I call maintaining capital that we spend every year on compression and things of that nature. So $305 million this year. My guess is that we're going to be north of $300 million next year, could be a little bit stronger than that depending on where we drill the wells, how much infrastructure is needed, whether we need CO2 removal facilities, additional compression, that type of thing. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: But the new areas like the Permian where you had midstream constraints, you don't see a big ramp in spending?

No, we do not in the Permian. Devon's position in the Permian and not unlike, quite frankly, a lot of the other industry participants is that most of that infrastructure is old infrastructure. And most of Devon's acreage with the exception of some of the new acreage that we've acquired there has been committed long term to other midstream parties, and so it really dependent upon them and industry as a whole to move product out of there. So Devon does not see that we're going to put a lot of capital in the Permian basin, although we'll put in some gathering systems. We'll put in some treating facilities. We'll put in some compression. But in terms of large capital expenses, in terms of processing plants or pipelines out of the area, say, down to the Gulf Coast, right now we don't see that, that's a space we'll be in. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, and I'm just thinking bigger picture capital spending, John, as you talked about your 2012 CapEx trending down year-over-year. Thinking about, and I'm not trying to link the joint venture in, but you all are targeting capital efficiency as the primary goal and the output is that adjusted growth, any new area initially that capital efficiency for leasing and science wells is generally going to be and that returns will be lower than in things like you just mentioned, which would be the Permian and Canada versus your new ventures. So really when I think about that joint venture in your overall plan, you're really just trying to focus on capital efficiency more so than -- and maybe some risk mitigation than trying to judge or call anything about the quality of acreage or opportunity?

Absolutely. And in fact, we are more positive about the opportunity. And as you can imagine, the more opportunity we have, the more that initial investment becomes as well. And you quite rightly point out, David, that the negative cumulative cash flow on these new projects is not insignificant. And so to the extent you can level that out and put additional funding into some of our development project, it really improves the rate of return and drives more to the bottom line.

Your last question comes from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co., Research Division: Just a very quick one, Vince maybe. The stock buyback, I mean once you finish up in the fourth quarter, what room does it have for capital allocation next year?

Rehan, as John said, we are always comparing the various levers that we have, that is spending in our E&P business to the share buybacks, and trying to select the optimum mix that gives us the best growth and cash flow and production per debt adjusted share. So as we are moving towards finalizing our 2012 capital budget, we'll look at the potential for additional share repurchases, look at the impact on our per-share results over time and make a call. Thank you. That ends today's call. Thank you for participating.

This concludes today's conference call. You may now disconnect.