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Devon Energy (NYSE:DVN)

Q1 2010 Earnings Call

May 05, 2010 11:00 am ET

Executives

Vincent White - Senior Vice President of Investor Relations

J. Nichols - Co-Founder, Chairman, Chief Executive Officer and Chairman of Dividend Committee

Jeffrey Agosta - Chief Financial Officer and Executive Vice President

David Hager - Executive Vice President of Exploration & Production

John Richels - President and Director

Analysts

Rehan Rashid - FBR Capital Markets & Co.

Monroe Helm - CM Energy Partners

Allen Chan

Philip Dodge - Stanford Group Company

Mark Gilman - The Benchmark Company, LLC

Raymond Deacon - Pritchard Capital Partners, LLC

David Tameron - Wells Fargo Securities, LLC

Harry Mateer - Lehman Bothers

Douglas Leggate - BofA Merrill Lynch

David Heikkinen - Tudor, Pickering, Holt

Scott Wilmoth - Simmons

Brian Singer - Goldman Sachs Group Inc.

Operator

Welcome to Devon Energy's First Quarter 2010 Earnings Conference Call. [Operator Instructions] 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.

Vincent White

Thank you, and good morning, everyone. Welcome to Devon's First Quarter 2010 Earnings Conference Call and Webcast. Today's call will follow our usual format. I'll take care of a couple of housekeeping items and then Larry Nichols, our CEO, will give his thoughts on the quarter, as well as an update on our strategic repositioning. Following Larry's remarks, our President, John Richels, will provide a financial review and then Dave Hager, our Executive Vice President of Exploration and Production, will cover our capital budget and the operating highlights. We will follow with a Q&A period and as usual, we will hold the call to about an hour. As always, we ask that participants on the call to keep their questions in the Q&A session to one question and one follow-up. A replay of this call will be available later today through a link on our homepage.

And also during the call, we will update some of our forward-looking estimates based on actual results for the first quarter. Since the revisions are pretty minor, we are not planning on issuing a new 8-K, but we will post these changes to the guidance area of our website. To find that, just click on the Guidance link found in the Investor Relations section of Devon's website.

Please note that all references in today's call to our plans, forecasts, expectations and estimates are forward-looking statements under U.S. securities law. And there are many factors that could cause our actual results to differ from those estimates. We encourage you to review the discussion of risk factors and uncertainties that is provided with our forecast in our Form 8-K.

One other compliance note, we'll use certain non-GAAP performance measures in today's call. When we use those measures, we're required to provide certain related disclosures. Those disclosures are also available on the Devon website.

Finally, I want to remind you that our financial and operational reporting has been complicated by the restructuring that we're undergoing. Our plan to divest our international operations has triggered accounting rules for discontinued operations. Under those rules, we're required to exclude our international oil and gas production from our reported production volumes for all of the periods presented. The related revenues and expenses for our international operations are collapsed into a single line item at the end of our statement of operations. That line item is filed discontinued operations. For those of you interested in a more detailed review of the international results, we have supplied additional tables in our news release.

And to make matters worse, even though we are selling our assets in the Gulf of Mexico, the accounting standards for discontinued operations do not apply to this Gulf assets. The results of operations from those divestiture assets reside in our continuing operations up to the date of closing of the sale of those properties. Throughout the call, our comments will generally be directed to results from continuing operations but wherever possible, we'll provide additional commentary specifically targeting our North American onshore results or our keeper properties. Information is also provided in our press release to enable you to isolate certain results from Devon's North American onshore operations.

The accounting treatment of the divestiture properties also complicates the comparability of earnings estimates. About 2/3 of the analysts that reported estimates the first call this quarter excluded the impact of the discontinued operations. The mean estimate of earnings per share from analysts that excluded discontinued operations is $1.43 for the first quarter. That compares to our non-GAAP earnings from continuing operations of $1.65 per diluted share for the first quarter. For those analysts that included discontinued operations in their estimate, the mean estimate was $1.50 per share as compared to our adjusted diluted earnings per share of $1.85. So in either case, our first quarter results were significantly better than the Street's expectations.

At this point, I'll turn the call over to Larry.

J. Nichols

Thanks, Vince, and good morning, everyone. Clearly, the first quarter of this year was a very good one for Devon. First quarter production from our retained properties and that is, of course, the North American onshore properties grew to 587,000 Boe per day, which is up nearly 3% over the fourth quarter of 2009. And it's worth pointing out that 186,000 barrels per day of this production were roughly 1/3 is oil and NGLs.

With production near the top end of our guidance and with strong price realizations relative to benchmark prices and with lower costs in nearly every expense category, first quarter earnings handily beat Street estimates. Also our Marketing and Administering business delivered another solid quarter generating $133 million in operating profit. And finally, we continue to maintain a very strong financial position. We ended the quarter with one of the strongest balance sheets in the NP sector, following the repayment of $1.2 billion of commercial paper and ending the quarter with cash on hand of nearly $1.2 billion.

During the first quarter of 2010, we also made remarkable progress with the strategic repositioning that we announced just last November. Early in the quarter, we closed the sale of three lower tertiary projects for aggregate sales proceeds of $1.3 billion. Then in March, we announced the sale of our remaining assets in the deepwater Gulf of Mexico and Brazil and Azerbaijan to BP for $7 billion and other long-term commitments. Because of the confidentiality agreements, we're not at liberty to disclose at this time the allocation of value among the various components of the sale to BP. However, the deepwater Gulf assets are clearly a significant piece and this portion of the transaction is now closed. As a result, we're essentially out of the deepwater Gulf of Mexico as of today.

We also recently announced the sale of the last of our assets in the Gulf of Mexico, which are the shelf assets, to Apache for $1,050,000,000. And finally, last week, we announced the sale of our Panyu field in China to CNOOC [China National Offshore Oil Corporation] for $515 million. We expect both the shelf and the Panyu transactions to close during the second quarter. So we're making great progress in all these sales.

When we first announced our plan to strategically reposition Devon, we expect that total after-tax proceeds from the divestitures of somewhere between $4.5 billion and $7.5 billion. The transactions that we've announced to date ensure that we'll exceed the top end of that range, including the few remaining international assets that remain to be in our contract. We now expect total after-tax proceeds of approximately $8 billion.

To date, we have used $1.2 billion of the sales proceeds to retire all of our outstanding commercial paper balances. We're also using $500 million of the sales proceeds to increase significantly our resource potential and our steam-assisted gravity drainage oil with the purchase of 50% of BP's interest in Kirby oil sands leases, which is a transaction we expect to close by the end of this month, by the end of may. This balance of the sales proceeds leaves us with tremendous flexibility to retire debt, to fund incremental E&P projects and to buyback stock. Given our outlook for natural gas prices and our continuing refusal to get caught up in the growth-at-any-cost mentality, we will not accelerate our dry gas production growth. The dry gas wells we're drilling are focused mostly on securing our acreage position and our shale plays such as Haynesville and Horn River and evaluating that you few new play concept. However, given the prevalence of oil and liquid-rich gas opportunities within our portfolio, most of our 2010 capital budget is focused on oil and liquid rich plays. As Dave will address later in the call, we're allocating some capital to increase our footprint in some of our oil and liquid rich plays in and around existing areas of opportunities.

As we consider the alternatives for the deployment of capital, our objective is always to optimize growth per share on a debt-adjusted basis. There are, of course, many factors that affect the relative attractiveness of the various alternatives. Current circumstances make the repurchase of our own common shares very attractive. These conditions led us to the announcement we made today to initiate a significant share repurchase program. Devon's Board of Directors has authorized the repurchase of about $3.5 billion of Devon's common shares. $3.5 billion worth of Devon's common shares. At today's share price, that represents about 12% of our shares. The pace of our purchases will, of course, depend upon marketing conditions as been our practice in previous year of repurchases. Having said that, though, we haven't taken steps to begin purchasing our shares immediately.

It is worth noting that when you take into account the divestiture proceeds and putting modest value of our Midstream business of 8x annual profit. The purchase of a Devon share today, well, at yesterday's closing price is $66.35, represents significantly less than $10 per Boe of post-divestiture proved reserves. These analyses attributes no value to our thousands of unproved locations across all of our shale plays. No value to the continued expansion of our Canadian oil projects, Jackfish and Kirby. And no value to the unproved acres we've established across North America, much of which was oil and liquid-rich areas. Suffice it to say, we believe that Devon stock represents a very compelling value.

With our transformation of Devon approaching completion, we cannot be more pleased with the way we have positioned Devon for the future. We have significantly reduced the company's risk profile. We have improved the company's overall cost structure. We have maintained a balance of natural gas and liquids production. We have established a deep inventory of development projects, both in oil and in liquid-rich gas. And we will emerge with one of the strongest balance sheets in our peer group. When the dust settles, Devon will have retained the projects in our portfolio with the most attractive risk-adjusted returns, with a balance sheet that will allow us to aggressively pursue the development of those projects and with a highly competitive overall cash structure. We will be well-positioned to weather any industry downturn.

With that, I'll turn the call over to John Richels for a financial review.

John Richels

Thanks, Larry. Good morning, everyone. Today, I want to take you through a brief review of the key drivers that affected our first quarter financial results and review how those factors influenced our outlook for the remainder of the year. As Vince mentioned earlier, we've reclassified the assets, liabilities and results of operations for our international assets in the discontinued operations for all accounting periods presented. As a result, I'll focus most of my comments on our reported continuing operations and just to reiterate, our reported results from continuing operations include both our retained North American onshore assets and the Gulf of Mexico assets that we are divesting.

Let's begin with a review of our production. In the first quarter of 2010, we produced 55.8 million oil equivalent barrels or 620,000 barrels per day. This result represents a 2% increase in daily production from continuing operations over the fourth quarter of 2009 and was really right in line with the guidance that we've provided in our previous earnings call.

When you look specifically at the assets that Devon is retaining that is our North American onshore properties, you'll find that production increased to 587,000 barrels per day in the first quarter of 2010, 3% over the fourth quarter of 2009. Our liquids rich Barnett, Cana and Arkoma-Woodford Shale plays, as well as increased oil production from our Permian Basin properties drove the production growth.

Looking ahead to the second quarter of 2010, we expect production from our retained North American onshore properties to increase to between 595,000 and 605,000 barrels per day. Since we have now closed the deepwater sale to BP, we expect that the Gulf of Mexico will only add an incremental 1 million to 2 million barrels of production in the second quarter depending upon the timing of the close of our shelf-divestiture package.

With respect for our 2010 production guidance for our North American onshore operations, we remain on track to deliver 221 million barrels equivalent. If you include the production from our Gulf of Mexico divestiture properties, we expect full year production from continuing operations to be in the neighborhood of 225 million to 226 million barrels.

Moving to price realizations beginning with oil, in the first quarter, the WTI Index price rose to an average of $78.54 per barrel. That's an 82% improvement over the first quarter of 2009. In addition to the higher benchmark price, regional differentials, as a percentage of WTI, narrowed pushing company-wide price realizations above the top end of our forecast range. The most notable regional outperformance occurred in Canada. This is because heavy oil differentials remained narrow in the first quarter due to strong demand.

In total, Devon's first quarter realized oil price came in at $67.58 per barrel or approximately 86% of WTI. That's a $36 per barrel improvement in our oil price realization compared to the year-ago quarter.

Looking to the remainder of 2010, we protected the price on over 70% of our North American onshore oil production using collars, with a weighted average floor of $67.47 per barrel and a ceiling of $96.48 per barrel.

On the natural gas side, the first quarter Henry Hub Index increased to an average of $5.30 per Mcf. Overall, the company-wide gas price realization before the impact of hedges were 91% of Henry Hub or $4.80 per Mcf. We had hedges covering about 1.4 billion cubic feet per day for the quarter, with weighted average protected price of $6.12 per Mcf.

Cash settlements from these hedges and our basis swaps increased Devon's realizations by $0.42 per Mcf, giving us an all-in price, including hedges of $5.22 per Mcf. For the second quarter, we now have hedges covering 1.5 Bcf per day, that's nearly 2/3 of our North American onshore production with a weighted average protected price of $5.88. A more detailed hedging schedule is available in the Guidance section of our website.

Turning now to our Marketing and Midstream business, once again, our Marketing and Midstream operations delivered strong results, generating $133 million of operating profit in the first quarter. Higher commodity prices and strong cost controls were the key performance drivers during the quarter. With the first quarter in hand, we're very well-positioned to achieve our full year forecast range of $450 million to $525 million.

Let's move now to expenses. The company did a very good job of controlling costs during the first quarter. Our first quarter lease operating expenses from continuing operations totaled $414 million. This translates to $7.41 per barrel produced and that's about $0.10 below the low end of our guidance range for 2010.

When compared to the first quarter of 2009, LOE expense declined by 6%, and that's in spite of significantly higher Canadian to U.S. dollar exchange rates and increased energy costs. To illustrate the effect of that, if we exclude the impact of the strengthening Canadian dollar, first quarter LOE declined 13% compared to the first quarter of 2009 instead of that 6% that I mentioned earlier.

When you isolate the performance of Devon's go-forward North American onshore asset base, the per unit lease operating expense is even more competitive at $7.19 per barrel of production. This is especially impressive considering that roughly 1/3 of this quarter's production was liquids. Looking to the second quarter, we expect unit LOE from our retained assets to be between $7.20 and $7.50 per Boe.

Devon's reported DD&A expense for the first quarter was $426 million or $7.63 per barrel, near the low end of our guidance range. Looking ahead, the sale of our Gulf of Mexico assets will lower our go-forward DD&A rate. As a result, we expect our second quarter depletion expense to decline to a range of $7.30 to $7.50 per barrel produced.

Moving on to G&A expense, our first quarter G&A expense decreased to $138 million. That's about 16% reduction in G&A expenditures when compared to the first quarter of 2009. The year-over-year decline in G&A costs is largely attributable to operational efficiencies that were achieved through our restructuring.

Shifting to interest expense, interest expense was right in line with our expectations at about $86 million for the quarter. In the second quarter, due to the sale of our deepwater Gulf of Mexico operations, we will capitalize less interest. And as a result, even though our overall borrowing costs are declining, we're forecasting that our reported interest expense will rise to about $95 million.

The final expense item I'd like to touch on is income taxes. For the first quarter, we reported income tax expense from continuing operations of $514 million or 32% of pre-tax income. After backing out the impact of special items, you get an adjusted tax rate of 31%. And this is made up of current tax rate of 13% of pre-tax income and deferred taxes of 18%. This is in line with our full year forecast and similar to the rates we would expect for the remainder of the year.

In today's earnings release, we have provided a table that reconciles the effects of the items that are typically excluded from analyst estimates. So moving to the bottom line, in the first quarter, our adjusted earnings from continuing operations were $740 million or $1.65 per diluted share. Adjusted earnings from discontinued operations added another $91 million or $0.20 per diluted share. So in aggregate, after backing out the items that are typically excluded from analyst estimates, our adjusted net earnings for the first quarter were $831 million or $1.85 per diluted share.

Our reported net earnings for the quarter were much higher, almost $1.2 billion, due primarily to the $334 million impact of unrealized gains on hedges. All in all, Devon delivered a very strong performance led by production at the top end of our guidance, strong price realizations for both oil and natural gas and very good cost control.

Before I turn the call over to Dave Hager for an operations update, I want to spend a few moments reviewing our financial position. During the quarter, we generated cash flow before balance sheet changes of $1.4 billion, up 45% over the first quarter of 2009.

In addition, we also received $1.3 billion of cash proceeds from the closing of the sales of three of our lower tertiary discoveries in the deepwater Gulf of Mexico. Looking briefly at our capital structure, we utilized our sources of cash to fund all of our capital expenditures for the quarter and repay $1.2 billion of commercial paper borrowings. As a result, at March 31, our net debt balances declined to $4.9 billion and our debt-to-capitalization ratio reached an 18-month low of 22%. We ended the first quarter with cash on hand of $1.2 billion as well.

Overall, we're very excited about Devon's future and we believe that we're extremely well-positioned to continue to deliver a strong per share growth in both the near and the long term.

At this point, I'll turn the call over to Dave.

David Hager

Thanks, John, and good morning, everyone. I'll begin with a quick recap of company-wide drilling activity. We had as many as 80 Devon-operated rigs running during the first quarter, but our winter drilling program in Canada wound down, we ended March with 60 Devon-operated rigs running. This is about the level of activity we expect to maintain for the remainder of 2010.

During the first quarter, we drilled 454 wells, included 426 development wells and 28 exploration wells. All of the development wells were successful and all but one of the exploratory wells were successful.

Capital expenditures for exploration and development from our North America onshore operations totaled $1 billion for the quarter. Given the abundance of oil and liquids-rich gas opportunities in our portfolio, going into 2010, our initial capital budget for the year was already weighted towards oil and liquids-rich gas plays. As a result of the earlier-than-expected sales of the deepwater Gulf of Mexico and international assets, our 2010 capital budget for the divestiture assets has decreased by roughly $900 million. This gives us the opportunity to reallocate some of this capital to capturing additional acreage in onshore oil and liquids-rich gas plays and potentially to increase drilling on some of these plays.

During 2010, we have either leased or in the process of leasing approximately 300,000 additional net acres in oil and liquids-rich plays. This include additional leasing in the Wolfberry and Cana plays, as well as significant acreage additions and potential new plays in the Permian and Rockies. We're currently conducting a mid-year capital review and if necessary, we'll provide updated capital guidance during our second quarter call.

Moving now to our quarterly operations highlights, at our 100% Devon-owned Jackfish thermal oil project in Eastern Alberta, our daily production reached facilities capacity during the first quarter. However, minor operational issues, which now have been addressed, limited our production for the quarter to an average of just over 26,000 barrels per day net of royalties. Jackfish continues to be one of the best performing SAGD projects in the industry. Construction of our Jackfish 2 project is now roughly three quarters complete and remains on budget. Had drilling continues and the project remains on schedule for first oil in late 2011.

At Jackfish 3, we continue to work toward filing the regulatory application in the third quarter of this year. Pending regulatory approval and formal sanctioning, we could begin site work by late 2011 with plant startup targeted for 2014. I will remind you that like Jackfish 1 and 2, we expect Jackfish 3 to average 30,000 barrels per day net of royalties over the life of the project and to recover approximately 260 million barrels of oil after royalties.

Devon has 100% working interest in each of the three Jackfish projects. At Kirby, we are currently working through the details of our joint venture agreement with BP and expect to have a signed agreement in place later this month. Our first step on the Kirby oil sands leases will be to further evaluate the size of the resource and to determine the optimal number of development phases needed.

To accomplish these, we expect to drill approximately 170 delineation wells beginning as early as the third quarter. When you combine our three Jackfish projects and our potential on the Kirby leases, we estimate our net production from these projects will reach 150,000 to 175,000 barrels of oil per day by 2020. This represents a compound annual growth rate for our Canadian oil sands production in the high teens for the next decade.

In our Lloydminster oil play in Alberta, we drilled 67 new wells in the first quarter. Lloydminster production averaged 40,000 barrels equivalent per day in the quarter. In 2010, we plan to spend $82 million drilling approximately 140 wells to roughly maintain current production levels.

Moving to the Permian Basin and our Wolfberry light oil play in West Texas, we recently added 11,000 net acres and now have 160,000 prospective net acres in the play. With average well costs under $1.4 million, this play provides repeatable, low-risk, high-return drilling opportunities. In the first quarter, we added a fourth rig. Until recently, we focused our drilling in the Odessa South area, where during the first quarter, the Clara Edwards #11 was brought online, flowing 450 barrels of oil equivalent per day, our best well to date in this play. We are utilizing two of the four rigs to delineate the Wolfberry potential in other parts of our acreage position. We plan to drill approximately 80 Wolfberry wells this year and have significant running room, with more than 1,100 remaining risk locations.

Elsewhere in the Permian Basin, we are currently running four additional rigs drilling for oil or liquid-rich gas targets. We are adding another two horizontal rigs in May. This rigs are drilling both conventional and unconventional targets, as well as accelerating the derisking of our acreage positions in new plays.

Right around our home city, here in Oklahoma City, we continue to be impressed by the growth we're seeing in an area that has not been on anyone's radar screen until a couple of years ago, the Cana-Woodford Shale. We recently added to our position and have continued to derisk our acreage and refine our technical view. As a result, we now have 180,000 net acres in what we believe is the best part of the play. We added two rigs last month, and we're currently running nine operated rigs. The additional rigs will allow us to accelerate further the process of derisking and securing our acreage. We continue to see outstanding results from Cana.

In the first quarter, we brought 16 wells online with average 24-hour IP rates of about 6 million cubic feet equivalent per day. We grew first quarter net production to over 73 million cubic feet of gas equivalent per day, up 210% from the first quarter of 2009. By the end of the first quarter, our Cana production inclined to a record 100 million cubic feet equivalent per day.

During the quarter, we drilled the two highest IP rate wells to date in the field. The Bingham 127H and Kurt 114H [ph], both came online with initial production rates over 10 million cubic feet per day equivalent and each are expected to have ultimate recoveries in excess of 10 billion cubic feet equivalent.

With our low cost of entry and low royalty burden, the Cana-Woodford continues to offer some of the strongest economics among North American shale plays. Our Cana economics are further enhanced by the liquid-rich nature of the gas over a good portion of the field. In the rich areas of the core, our liquids content is as high as 120 barrels per million cubic feet, of which roughly a quarter is condensate.

Production history from our 70 long lateral horizontal wells drilled in the core areas of play continue to support a tight curve approaching 11 Bcf equivalent per well, including 500,000 barrels of NGLs.

To capture this additional value, we are building a cryogenic liquids extraction plant at Cana. This facility, which remains on schedule for startup in early 2011, has an initial capacity of 200 million cubic feet per day and is expandable to accommodate our future production growth.

Moving to the Barnett Shale field in North Texas, we are currently running 18 Devon-operated rigs. We increased our drilling activity during the quarter, and we began working down our inventory of uncompleted wells. At the end of March, we are back to our normal inventory level of approximately 150 wells awaiting completion. We are focusing our Barnett drilling into more liquid-rich areas where it is not uncommon to have wells produce as much as 100 barrels of liquids per million cubic feet.

Our net production in the Barnett averaged 1.1 Bcf equivalent per day for the first quarter, up 5% from the fourth quarter of 2009. We continue to expect Devon's Barnett production to reach its previous high mark of 1.2 Bcf equivalent per day during the third quarter.

In the Woodford Shale in Eastern Oklahoma's Arkoma Basin, we are running four operated rigs and will continue at that pace for the remainder of 2010. We're achieving solid per well recoveries from our long lateral horizontals. In the first quarter, we brought eight operated well online, with an average IP of 5.5 million cubic feet per day. Devon's net production in the play climbed to a record 88 million cubic feet equivalent per day in the first quarter, up 23% from our fourth quarter average.

Shifting to the Haynesville Shale, in the first quarter, we completed three Haynesville wells located in Shelby and Nacogdoches Counties. These three wells have an average 24-hour IPs of about 6 million cubic feet per day. These rates are consistent with our previous results in the area, and further confirm that we have a repeatable economically attractive play under a normalized price environment on our 110,000 net acres in the greater Carthage area. Our activity for the remainder of 2010 will focus on securing and derisking our primary term acreage in the Southern and greater Carthage areas.

Moving to the Rockies, in the Washakie Basin in Wyoming, our net production averaged a record 135 million cubic feet of natural gas equivalent per day in the first quarter, up 14% year-over-year. We were in two rigs throughout the first quarter and drilled 13 operated wells. Both of these high-efficiency rigs will continue to drill these high-return opportunities in the Washakie area this year.

And finally, in the Horn River Basin of Northern British Columbia, Devon has assembled a position of approximately 170,000 net acres in what appears to be some of the best parts in the play. We began drilling the first of seven horizontal wells in early April. We expect to complete four of these horizontal wells in the third quarter, and we'll provide you with those results later this year. The three horizontal-producing wells we do have online continue to perform better than expected during the first quarter. A significant planning effort is underway for a larger program in 2011. At this point, I'm going to turn the call back over to Vince to open it up for Q&A.

Vincent White

Thanks, Dave. Operator, we are ready for the first caller.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt

I had a specific operating question as you think about the Permian and adding rigs on the horizontal side. Can you talk at all about the Avalon Shale in Bone Spring, and then kind of how much acreage you might have in that area?

David Hager

Well, we're not going to go into too much detail on it, David. I can tell you that we are interested in that area. We continue to add acreage as we speak. We do have, overall, several hundred thousand acres in the Delaware Basin. We already have a large acreage position, and we are looking to add to that position as we speak.

David Heikkinen - Tudor, Pickering, Holt

And then one other question, now shifting to the Horn River Basin and thinking about any opportunities beyond just gas and hearing some opportunities on the oil and more liquids side. Is there anything on your acreage or any plans to try to test that in the Horn River Basin, or extending that into Alberta kind of chasing the same trend?

John Richels

Yes, there is some potential up there, David. There is a -- specifically, it appears maybe an Exshaw oil play that exists or there's been some people that have talked about -- specifically, I know Quicksilver is talking about potential up there is immediately to the west of the Northern part of our Horn River play. We do plan to evaluate that oil potential with our future drilling program. We don't have a lot of details on it as we speak, but we recognize the potential exists there. We just need to get some more work done it to really evaluate how significant that may be.

David Heikkinen - Tudor, Pickering, Holt

And then, as you think about just the share repurchase program and $1.2 billion of cash on hand, can you walk through kind of how cash flows into the company from asset sales? You talked about asset sales closing in the second quarter. I guess, the Brazilian assets will be one large lump. Can you just kind of walk us through how you'd allocate that cash and how active you could be on the share repo?

John Richels

Sales are going to close throughout the year. So probably the next tranche that'll close is the shelf assets. We don't quite have a good visibility around exactly when the Brazilian and Azerbaijan assets will close, just because there are other approvals that are required. But we are pretty confident that will all going to close in the next little while. As you look at what we're going to due with the funds, I mean, we've talked about the $3.5 billion share repurchase today, because we just think that buying back our stock is a really compelling application of our funds right now. We just don't think our stock is valued where it ought to be, and so that's the right thing for us to do. As Dave has already said, as we move forward, we don't want to pigeon all ourselves, with regard to exactly what we're going to do with the funds because we are looking at some additional leasing opportunities and potentially some additional drilling opportunities in liquids-rich and oil lead plays. And we want to fully develop that through our midyear capital review process, and we'll give you further visibility on that. You've got to remember too, we have a couple of billion dollars of debt coming due in 2011, which we will want to deal with on a kind of an organized basis, as we go forward.

David Heikkinen - Tudor, Pickering, Holt

Is it fair to think that $900 million of capital that was allocated to assets that were being sold though, is probably a reasonable range of how much capital you can commit to leasing?

John Richels

Well, it certainly gives us the opportunity, whether it's to leasing or to incremental oil- and liquids-rich opportunities. It gives us the opportunity to reallocate some of the funds that would otherwise have gone to those properties, if we had held them for a longer period of time.

Operator

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

Mark Gilman - The Benchmark Company, LLC

Wondering if you could just comment, in general, on what kind of oil price you need, with respect to the favorable economics, with respect to some of the liquids-rich and oil plays that you're shifting your emphasis toward?

David Hager

Well, certainly, it's the existing oil price, as they generate extremely strong rates of return. And I would suspect -- I don't have an exact number for you, Mark, but probably much closer around a $60, $65 range are still going to generate pretty strong economics. And certainly, where we are now, there are 40%, 50%-type rates of return?

Mark Gilman - The Benchmark Company, LLC

Is that applicable to the Wolfberry, Dave? $60 to $65 generating good returns?

David Hager

Yes.

Mark Gilman - The Benchmark Company, LLC

Can you talk just a little bit about your plans for drilling in the San Augustine County area the rest of the year?

David Hager

Yes, we have several wells that we're planning to drill down there, because San Augustine County is where we have exclusively term acres down in San Augustine County. We also have term acreage up in Shelby. And so some of the wells we've been drilling in Shelby, and I alluded to, were actually to evaluate the term acreage in Shelby. We have both term and acreage held by production in Shelby. But we are currently -- we have one well that has finished drilling down there, and we're waiting a frac on that. That would be the sublet well, where that frac should start around the end of May or so. We also have a couple of wells that are currently drilling down -- that well, by the way, is a Bossier Shale well that's awaiting frac-ing. We also have two more wells that we're drilling currently down in San Augustine County, one a Bossier Shale well, one a Haynesville Shale well. And we're going to focus the bulk of our activities for the remainder of the year on San Augustine, Sabine and the Southern parts of Shelby County to really get a good handle on what the potential is of our term acreage.

Vincent White

When you say that, Dave, you mean the bulk of our activity in the greater Carthage in the Haynesville play. Yes.

David Hager

Yes, yes. In that play, I mean. Yes.

Operator

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

Douglas Leggate - BofA Merrill Lynch

I guess it's a similar question to Mark's, but this time, on the cash side. Could you just kind of bring us up to date, given the shift that you're seeing in some of the liquids content, particularly in the Barnett? What is that doing to your gas break-even prices? I guess, they can't really breakeven with the key plays. So let's say, Cana, Haynesville, Barnett and maybe Horn River. Could you give us an idea?

Vincent White

Doug, this is Vince. I've looked at this and in the more liquids-rich parts of the Cana and the Barnett, it pushes our full cycle, not breakeven, but the price we need to generate what we consider an acceptable rate of return, which is about a minimum of about 20% after tax. It pushes the realized price below $5 that we need in those plays, more like the $4.50 range. And I might add that we also generate midstream return in the Barnett, on the liquids-rich plays over and above that 20% after-tax rate of return at those price levels. So that gives you a feel for it.

Douglas Leggate - BofA Merrill Lynch

Vince, I guess what I'm trying to go with this is, I mean, obviously, gas prices right now are still a bit under pressure. I mean, you are spending in these areas. So leaving hedging aside, does that mean that these investments you're making right now are below breakeven?

Vincent White

No, not at all. In fact, they're above, based on the current strip, they're above a 20% after-tax rate of return.

David Hager

To give you a little bit further color on that, we've gone back and re-examined all of our capital we'll be spending the remainder of the year. And essentially all of the capital that we're spending for the rest of the year, we're confident that these price levels that we're seeing generate a 20%-plus rate of return, with the lone exception, the one challenge we have, really, is in the Haynesville area. And that's where I was -- we just really need to evaluate the potential, particularly on our term acreage down in San Augustine and Shelby counties. But that's the most challenged part of our portfolio, but we don't fully understand that yet, from a science standpoint. But everything else has generated very strong rates of returns. We just completed that review.

J. Nichols

Let me go back and emphasize one thing -- this is Larry -- is that you got to remember that one of the things that distinguishes Devon in several of these areas that we own and operate, the gas processing plant in the whole Bridgeport area, we have the largest over 40 gas processing plant. We built processing plant for the Arkoma Basin. We're in the process of building one for the Cana-Woodford play. So that allows us an exceptional competitive position there.

Douglas Leggate - BofA Merrill Lynch

If I can raise my follow-up, Vince. I'm not sure if you can answer this, but I'm going to try anyway. So basically, from what you've told us, you have now sold the rest of the Gulf of Mexico. And I guess, according to John, it sounds like you're not probably going to complete the balance of the sales maybe until after the second quarter. So I guess my point is, when you report second quarter, we're going to find out anyway what the proceeds were. So can you give us an idea what the incremental cash received was, so we can just true up your balance sheet?

Vincent White

Yes. Just to clarify, Doug. We have essentially completed the sale of all deepwater assets. And we've got a contract with Apache. They're committed to moving forward. And we expect to close that transaction in the near future. You are correct that at some point, that data will be right for disclosure, and we will be required to disclose the allocation of value, in terms of what we received for the Gulf assets in the second quarter. But we are under a confidentiality agreement and we are not yet prepared to do that.

Operator

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

Scott Wilmoth - Simmons

On the Cana-Woodford, how much of your 180,000 net acres would you consider core? And how much acreage is still available in the play to be acquired?

David Hager

Well, we think that as all essentially core acreage. There is a liquids-rich portion within that core acreage, which is where we're really getting the 11 Bcf equivalent per well, and even better economics in the rest of the play. But all of that, we feel, lies within the heart of the Cana play. And that is a significant increase from the numbers we've been talking about previously. That's because we have picked up on the order of about 60,000 additional acres into play, and the play does appear to be moving a little bit off to the West and Northwest to bring those acres into the core.

Scott Wilmoth - Simmons

So how much of the 180,000 is liquids rich?

David Hager

I can't give you an exact number on that. I'd probably got to get back to you. But I'd say, at least half of that play is liquids rich and probably closer to 2/3.

Scott Wilmoth - Simmons

And then my follow-up is how many rigs do you guys need to maintain throughout 2010? And what do you think that looks like in 2011, in order to hold all that acreage?

David Hager

Well, we currently have nine rigs active in the play, and we feel that's adequate to hold the acreage.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

When you think about the new or existing liquids plays in the U.S. that you're now shifting a bit more attention to, what is the materiality in what that could do to your overall production? I think, a little bit more than a quarter of U.S. onshore production is in liquids. Do you have some sense for where that can go over time?

Vincent White

Brian, I'll take a stab at this. We're about a third oil and liquids in our North American onshore assets, which is reflective of our capital budgets allocated in a similar fashion. If you look at dry gas versus oil- and liquids-rich plays, we've got a -- of course, the future will be opportunity driven. We clearly have a strong growth rate out of our oil sands production, going forward. But depending on market conditions, we have a lot of growth potential and dry gas opportunities as well. So I figured, it's very much going to depend on what we choose to do, going forward, and that will reflect our view of future prices.

J. Nichols

And of course, you need to bear in mind, we've been working on the oil side of our portfolio for a long time. It's not a new thing for us, as well as liquids rich. It's why we built these gas processing plants in the areas that we've been playing, so it's -- while there is a shift, it's not nearly as dramatic for us, as it is for some of the other companies. Probably the biggest shift is in the heavy oil up in Canada, and that's only because of our ability to get Kirby. If you look at the long-term potential there of Jackfish 1, 2 and now, 3, as well as Kirby, that's going to add a lot of oil to Devon over a very long period of time.

Brian Singer - Goldman Sachs Group Inc.

And now shifting to Cana-Woodford, I believe you've talked in the past about choking back some of the wells and monitoring potential improvements in EUR. Can you just talk about completion technique and what you're seeing, in terms of decline rates?

David Hager

Yes, well, I think the main thing is we did have a couple wells that came on here during this quarter. I mentioned at around 10 million a day. And these are wells -- we are continuing to refine our completion techniques, and so these are ones that we felt we could bring on at the higher rate without risking any reservoir damage here. And no promises, but it looks like things are continuing to improve as we learn more out there. And so it looks like we're continuing to get higher initial rates on these. These wells do have -- amongst the shale plays, I'd say, probably on the lower end of decline, you tend to have first year declines on the order of about 60% to 65%, which obviously, is lower than a lot of the things we're seeing in some of the other plays, such as the Haynesville.

Brian Singer - Goldman Sachs Group Inc.

Shouldn't we interpret that to mean that you're comfortable with the existing technique of kind of keeping the wells open, and the risk or lack of it associated with that and that choking things back in Cana-Woodford is not necessarily value additive?

David Hager

Well, not given the completion technique, we're not going into all the details of what we're doing out there. But no, we're comfortable with -- we bring on these wells at higher rate and not risk a formation. That's right.

Operator

Your next question comes from the line of Harry Mateer with Barclays Capital.

Harry Mateer - Lehman Bothers

Just going back to the question of further debt reduction with the asset sale proceeds. When you look at your 2011 maturities and you have the cash coming in, I mean, are you guys considering paying it down early? Or may we actually see you just sit with the cash on the balance sheet until the maturities come up, and then just pay it down at the time?

Jeffrey Agosta

I think that we would continue -- this is Jeff Agosta, by the way. I think that we would continue to evaluate opportunities if we could do something that was NPV positive, it would be something that we would consider, but otherwise, we would just continue to evaluate other opportunities within our portfolio, and with balancing that with our share buybacks for the use of proceeds.

Harry Mateer - Lehman Bothers

But are you considering at least leaving a portion of the cash on hand to fund those maturities when they come due?

John Richels

We're trying to maintain some flexibility, as we go into the next while. So having some of those funds certainly available for those maturities when they come up is a positive. I mean, when we get around to the middle of next year and see the market conditions, our outlook for oil and gas prices and our view of the industry at the time, and our view of the financial markets at the time, we can make a decision as to whether we want to allocate those funds to that, or whether we're going to roll over those bonds, or -- there's a number of things we can do.

Operator

Your next question comes from the line of Allen Chan with Sasco Energy Partners.

Allen Chan

I just had a quick question regarding the Wolfberry play. In regards to that 450 a day you're seeing at our Clara Edwards well, what are the associated gas volumes that you've seen along with the oil?

David Hager

There's very little gas associated with that. It's essentially all oil.

Allen Chan

Is that fairly typical for the play?

David Hager

Yes.

Operator

Your next question comes from the line of Phil Dodge with Tuohy Brothers.

Philip Dodge - Stanford Group Company

Going back to the Cana-Woodford, can you tell us, of the acreage additions in the quarter, how much was Northwest of the core area, particularly Dewey County?

David Hager

The most of the -- we picked up some within and amongst where we already had acreage, but the bulk of the acreage addition was off to the Northwest, and I think what you'd consider between the continental well that has been talked about and our existing acreage position.

Operator

Your next question comes from the line of Monroe Helm with Barrow, Hanley.

Monroe Helm - CM Energy Partners

Question for John Richels. Can you be a little bit more specific on what you think the potential -- how good you already have on what the Exshaw potential could be at Horn River, and what the timing it would be for you to try to determine if it's perspective on your acreage?

John Richels

I'm going to turn that over to Dave. He can answer that better than I can.

David Hager

Well, that's something that we're going to be evaluating, really, probably with our 2011 program.

Monroe Helm - CM Energy Partners

And this question is for Larry Nichols. The gas industry continues to kind of draw itself to hold acreage, accreting too much supply. Do you think there's going to be a -- no one seems to be interested in gas properties these days. But can you see an environment where the gas prices stay depressed enough to where you could increase your exposure to natural gas, going down the road in a meaningful way through acquisitions?

J. Nichols

It's not there today. Well, through any source on the acquisitions would be one source, but just picking up acreage that other people are not able to get to would probably be a much more interesting source than some of the players paid awfully high royalties to get what they now have. We've been contrary at some times in the past. And could we envision a time when increasing our exposure to natural gas, for the longer term, might be appropriate? You can certainly envision that. It's not there today, but I can certainly envision that some time in the future. And I'd just emphasize, not so much on acquisitions because of the leases that a lot of companies bought. But if you look at the underlying leases that some of these leases are letting go, that could be an opportunity.

Operator

Your next question comes from the line of Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co.

On your risk resource potential of about $13.6 billion, how sensitive is this to gas price changes? Do we lose some portion of it at $5 gas, $4.50 gas, $4 gas?

Vincent White

Yes, Rehan. It would be a curve, and I don't have the details in front of me. But we certainly lose some of that potential at $4 gas. We're looking at the recoverable potential under our overall acreage position, based on our long-term view of prices, which would be above $4 in the current cost environment. And that's the other component that has to be considered when looking at what's economic.

Rehan Rashid - FBR Capital Markets & Co.

In aggregate. So then, below $4 is when you begin to lose some of it?

Vincent White

Oh we certainly lose some there. Right. And of course, liquids prices and oil prices also interplay into that resource potential as well.

Operator

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

David Tameron - Wells Fargo Securities, LLC

Larry, when you think about share repurchase, can you walk us through the decision process? You talked a little bit about where the stock is trading, $10 per Boe. But can you talk about how you weighed that versus perhaps finding something in the market or paying down debt? Can you just give us a little more color?

J. Nichols

Well, of course, we are paying down. As you look at all the choices out there, we are paying down debt. We paid out $1.2 billion in commercial paper, or so, in the first quarter. We are repositioning to, as we said last year, we were forced to starve our North American portfolio for capital. And we're having great fun reinvesting as these proceeds come to us, reinvesting that capital in our North American properties, both oil and the liquid-rich portion of the gas where we see attractiveness. When you look at where our shares trade and the asset portfolio that we have versus other opportunities, one might look at in looking at other companies, it's a very, very simple decision. The return we get by volume Devon shares is dramatically better than anything else we look at. So we'll be buying Devon shares.

David Tameron - Wells Fargo Securities, LLC

So Vince, you mentioned earlier, 20% rate of return is some kind of the hurdle rate on something. So from your internal analysis, it would imply that the share buyback is generating, I guess, well in excess of that?

John Richels

David, it's John. It's very tough. As you know, its very tough to -- we're trying to do everything. We invest all of our funds on a return basis. It's really tough to figure out rate of return on stock, because you have to make a whole bunch of the assumptions going out in some of the stock price when you're buying it back. So there are other measures that we can look at that, and that we do look at, every time we decide to allocate another dollar between E&P programs, or acquisitions, or share repurchases or debt repayment, whatever we can do. And that is what we've been focused on for many years, and continue to focus on, is per debt-adjusted share growth in production reserves, earnings and cash flow. And that can provide a pretty good proxy for you, in terms of whether buying back stock is a better allocation, from a return perspective, than some of our opportunities. And as Larry said, we're absolutely convinced with these levels that buying back our stock is very, very accretive and measures up well in all of those metrics, besides just the F&D metric we've talked about.

David Tameron - Wells Fargo Securities, LLC

Now I think, it's absolutely the right thing to do. I was just trying to get a sense of how you guys are reviewing it and how you're looking at it.

Operator

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

Mark Gilman - The Benchmark Company, LLC

Dave, what did you pay for the additional Cana acreage, more kind of royalty on it?

David Hager

We're not going to say specifically what we're out there paying for acreage, Mark. But we are very happy with the price we paid, and then we still generate very strong economics.

Mark Gilman - The Benchmark Company, LLC

Royalty in line with what you have on the existing acreage?

David Hager

Yes.

Operator

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

Raymond Deacon - Pritchard Capital Partners, LLC

I was just curious if you could elaborate a little bit on sort of expected returns from your oil sands projects, both Kirby and Jackfish, versus the Permian, as you see them now, I guess. And I know there's a lot of assumptions in there about gas prices, but -- and did the change in the Canadian tax laws affects Canada positively or no?

John Richels

Ray, hi, it's John. Jackfish and our SAGD projects have been tremendous. They've given us tremendous return. And part of that is because Jackfish, and we're pretty convinced Kirby as well, are some of the top-performing SAGD projects in the industry. When you look at some of the things that influence the returns that we see on the heavy oil -- of course, there's WTI, but there's also the heavy/light differential, which has been much narrower than it has historically, and which we believe is going to stay narrow for the foreseeable future. And then this big disconnect between natural gas and oil prices has just made the SAGD projects highly, highly economic. So I don't have the exact measure of how it compares to our Permian oil, but it's right up there, in terms of the kinds of returns that we're seeing. Your question on the changes in the Alberta structure, I think you're probably referring to the royalty structure?

Raymond Deacon - Pritchard Capital Partners, LLC

Right.

John Richels

We kind of gone around the horn on this thing. But even though the rules are different, we haven't seen all the details of the new regulations that have been put in place. We think that we're pretty close to where we started three years ago, in terms of the overall effect of the royalty regime on our production in Canada. And it's making -- even the conventional production in Canada is looking very, very positive and competes pretty well for capital in the portfolio.

Raymond Deacon - Pritchard Capital Partners, LLC

And I guess if you were to net what you're saying that's new this quarter in Cana Shale, I guess, what would you say the EURs look like at this point? And I guess, sort of are you able to get more of the reserves up front? Is that kind of gist of what you're saying on the IP rates this quarter?

John Richels

Well, I think the thing that we're seeing is, overall, the EURs, average together the entire play, we're seeing about 8 Bcf equivalent and about 11 Bcf in what you might want to call the heart of the play. And as I said, probably 50% to 2/3 of the play has a pretty strong liquids content as well, which enhances the economics. And we're going to be able to, next year, even get greater value out of those liquids when we have our processing plant there as well. We are also, additionally, increasing the initial rate on these wells. And so all of these things are contributing to strong economics throughout the play. The higher IPs, the liquids content that's in the play, and additionally, we're expanding the play. So we don't worry much.

Vincent White

Okay, we've got no more callers in the queue, so we'll end today's call. Thank you for your participation.

Operator

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect, and have a great day.

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Source: Devon Energy Q1 2010 Earnings Call Transcript
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