德文能源 (DVN) 2010 Q1 法說會逐字稿

Welcome to Devon Energy's first quarter 2010 earnings conference call. At this time all participants are in listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. This call is being recorded.

At this time I would like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you and good morning, everyone. Welcome to Devon first quarter 2010 earnings call. 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 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 the 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 home page 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 US 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 styled 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 these 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 on-shore 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 on-shore operations. The accounting treatment of the divesture properties also complicates the comparability of earnings estimates. About two thirds of the analysts that reported estimates to 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.

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 on-shore 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 or roughly one third 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 cost in nearly every expense category, first quarter earnings handily beat street estimates.

Also our marketing and mid-stream 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 MP 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 salse proceeds of $1.3 billion.

Then in March we announced the sale of our remaining assets in the deep water Gulf of Mexico and Brazil and Azerbaijan for other commitments. Because of the confidentiality agreements, we are not at liberty to disclose at this time the allocation of value among the various components of the sale to BP. However, the deep water gulf assets are clearly a significant piece and this portion of the transaction is now closed. As a result, we are essentially out of the deep water 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 billion. And finally, last week we announced the sale of our Panu field in China to Sinu for $515 million. We expect both the shelf and the Panu 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 expected 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 will exceed the top end of that range, including the few remaining international assets that remain to get under 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 are also using $500 million of the sales proceeds to increase significantly our resource potential in our steam assisted graft drainage oil with the purchase of 50% of BP's interest in Kirby oil sands transaction -- leases, which is a transaction we expect to close by the end of this month, by the end of May. This balance of the shales proceeds leaves us with tremendous flexibility to retire debt, to fund incremental E& P projects and to buy back 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 are drilling are focused mostly on securing our acreage position in our shale plays such as Haynesville and Horn River and evaluating a few new play concepts. 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 are 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 up to $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 has been our practice in previous share repurchases. Having said that, though, we have taken steps to begin purchasing our shares immediately.

It is worth noting that when you take into account the divestiture proceeds and put a modest value on our mid-stream business of eight times annual profit, the purchase of a Devon share today at yesterday's closing price of $66.35 represents significantly less than $10 per BOE of post divesture approved reserves. This analysis 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 is oil or in 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've established a deep inventory of development projects both in oil and in liquids 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.

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 influence 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 into 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 on-shore 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 provided in our previous earnings call. When you look specifically at the assets that Devon is retaining, that is our North American on-shore 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 production from our Permian Basin properties drove the production growth.

Looking ahead to the second quarter 2010, we expect production from our retained North American on-shore properties to increase to between 595,000 and 605,000 barrels per day. Since we have now closed the deep water sale to BP, we expect that the Gulf of Mexico will only add an incremental 1 to 2 million barrels of production in the second quarter, depending upon the timing of the close of our shelf divestiture package. With respect to our 2010 production guidance for our North American on-shore 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 companywide 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 by over 70% of the North American onshore oil production using collars with a weighted average floor of $67.47 per barrel and a ceiling of the $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, 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 a 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 two thirds of our North American on-shore 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 mid-stream business. Once again, our marketing mid-stream 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 were 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 a dime 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 US 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 on-shore asset base, the per unit lease operating expense was even more competitive at $7.19 per barrel of production. This is especially impressive, considering that roughly one third 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 a 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 deep water 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 rerise 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 pretax income. After backing out the impact of special items, you get an adjusted tax rate of 31% and this was made up of current tax rate of 13% of pretax 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's estimates. 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 our -- of three of our lower tertiary discoveries in the deep water 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 are 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.

Thanks, John and good morning, everyone. I'll begin with a quick recap of companywide 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 as -- drilling program in Canada wound down and 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, including 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 on-shore 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 deep water Gulf of Mexico and international assets, our 2010 capital budget for the divesture assets has decreased by roughly $900 million. This gives us the opportunity to reallocate some of this capital to capturing additional acreage in on-shore 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 includes additional leasing in the Wolfberry and Cana plays as well as significant acreage additions and significant new plays in the Permian and Rockies. We are currently conducting a mid-year capital review and if necessary will 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 earn 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 two project is now roughly three quarters of the way complete and remains on budget.

Pad drilling continues and the project remains on schedule for first oil in late 2011. At Jackfish three, 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 start up targeted for 2014. I will remind you that like Jackfish one and two, we expect Jackfish three 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 a 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 this, we expect to drill approximately 170 delineation wells beginning at 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 send $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 number 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 rest locations.

Elsewhere in the Permian Basin, we are currently running four additional rigs, drilling for oil or liquids rich gas targets. We are adding to -- another two horizontal rigs in May. These rigs are drilling both conventional and unconventional targets, as well as accelerating the derisking of our acreage positions and new plays. Right around our home city here in Oklahoma City, we continue to be impressed by the growth we are 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 had climbed 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 127 H and Curts 114 H 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 area of the play continue to support a type 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 start up 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 in the more liquids 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 and eastern Oklahoma's Arkoma basin, we are running four operated rigs and will continue at that pace for the remainder of 2010. We are achieving solid per well recoveries from our long lateral horizontals. In the first quarter, we brought eight operated wells 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 had 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 Washakee 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 ran 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 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 of 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 will 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 under way 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.

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

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

Good morning. I had a specific operating question when you think about the Permian and adding rigs on the horizontal side. Can you talk at all about the Avalon shale and Bone Spring and how much acreage you might have in that area?

Well, we're not going to go into too much detail on that, 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.

Okay. And then one other question now shifting to the Horn River basin and thinking about any opportunities beyond just gas and, you know, hearing some opportunities on the oil or 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?

Yes. We're -- there is some potential up there, David. There's -- specifically it appears maybe an X Shaw oil play that exists. There has been some people that have talked about specifically -- I know Quicksilver has talked about potential in a -- up there, it's 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 on it to really evaluate how significant that may be.

Okay. 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 would allocate that cash and how much -- how active you could be on a share repurchase?

David, these sales are going to close throughout the year, so probably the next traunch that will close is the shelf assets. We don't quite have a good -- you know, a good visibility around exactly when the Brazilian and Azerbaijan assets will close because there are other approvals that are required, but we're pretty confident they're all going to close in the next little while. As you look at what we're going to do with the funds, 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, so that's the right thing for us to do.

As Dave as already said, as we move forward, you know, we don't want to pigeon hole 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 oily plays and we want to fully develop that through our mid-year capital review process and give you further visibility on that. You've got to remember, too, we've got 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.

Okay. 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 could commit to leasing?

Well, it certainly gives us the opportunity, whether it's to leasing or to incremental oil and liquids rich opportunities, it give 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.

Hey, David, I'm going to jump in here. We're going to have to move to the next person.

That's cool.

Thanks.

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

Hello, guys, good morning. Wonder if you could just comment in general on what kind of oil price you need with respect to the economics or favorable economics with respect to some of the liquids rich and oil plays that you're shifting your emphasis toward?

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 $60, $65 range is still going to generate pretty strong economics and certainly where we are now, 40, 50% type rates of return.

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

Yes.

Okay. One -- just one other one, if I could, Dave. Can you talk just a little bit about your plans for drilling in the St. Augustine county area the rest of the year?

Yes. We have several wells that we're planning to drill down there because St. Augustine county is where we have exclusively term acres down in St. Augustine County. We also have term acreage up in Shelby, so some of the wells that we've been drilling up in Shelby that 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 a sublet well. That frac should start around the end of May or so. We also have a couple of wells that are currently drilling -- that well, by the way is a Bossier shale well that is awaiting fracking. We also have two wells that we're drilling currently in St. Augustine county, one a Bossier shale well, another a Haynesville and we're going to focus our bulk in the southern parts of Shelby county to really get a good handle on what the potential is of our term acreage.

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

Yes, in that play, I mean, yes.

Okay. Dave. Thanks.

Yes.

Our next question comes from the line of Doug Leggate with Merrill Lynch. Please proceed.

Thanks. Good morning, everybody. I guess this is a similar question to Mark's, but this time on the gas 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 the break even around the key plays, let's say Cana, Haynesville, Barnett, maybe Horn River? Could you give us an idea?

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 break even, but the price we need to generate what we consider to be an acceptable rate of return which is 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 mid-stream 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.

Thanks. Then I guess where I'm trying to go with this is obviously gas prices right now are still a little bit under pressure. You are spending in these areas of the leaving hedging aside, does that mean that these investments you are making right now are below break even?

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

Okay, great.

To give you a little further color on that, we've gone back and reexamined 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 St. Augustine and Shelby counties, but that's the most challenged part of our portfolio. We don't fully understand that yet from a science standpoint, but everything else has generated very strong rich returns. We just completed that review.

Let me go back and emphasize one thing, this is Larry. You've 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 bridge port area. We have the largest lower 48 gas processing plant. We built a processing plant for the Arkoma basin. We're in the process of building one for the Cana-Woodford play. So that allows us a exceptional competitive position there.

Perfect. Thanks, Larry. If I can have my follow-up, Vince. I'm not sure if you're going to 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 of what the incremental cash received was so we can just true up your balance sheet?

Yes, just to clarify, Doug, we have completed -- essentially completed the sale of all deep water 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 ripe 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 have not yet -- we are under a confidentiality agreement and we are not yet prepared to do that.

All right. Thanks, Vince.

Our next question comes from the line of Scott Wilmot with Simmons & Company. Please proceed.

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

Well, we think that is 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 than 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 in the 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.

So how much of the 180 is liquids rich?

I can't give you an exact number on that. I would -- I probably ought to get back to you, but I would say at least half of that play is liquids rich and probably closer to two thirds.

Okay. 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 of that acreage?

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

Okay. Thanks, guys.

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

Thank you, good morning.

Good morning.

When you think about the new or existing liquids plays in the US 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 US production is -- US on-shore production is in liquids. Do you have some sense for where that can go over time?

Brian, I'll take a stab at this. We're -- we're about a third oil and liquids with our -- in our North American on-shore assets and -- 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 -- you know, the future will be opportunity driven. We clearly have a strong growth rate out of our oil sands production going forward, but we -- you know, depending on market conditions, we have a lot of growth potential in dry gas opportunities as well. So I think it's very much going to depend on what we choose to do going forward and that will reflect our view of future prices.

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 of Jackfish one, two, as well as three along with Kirby, that is going to add a lot of oil to Devon over a very longer per of time.

Great, thanks. Shifting to Cana Woodford, I believe you talked in the past about choking back some of the wells and monitoring potential improvements in the UR. Can you talk about completion technique and what you're seeing in terms of decline rates?

Yes, well, I think the main thing is we did have a couple of wells that came on here during this quarter that I mentioned 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 that 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 decline. You tend to have first year declines on the order of about 60, 65% which obviously is lower than some of the things we're seeing in some of the other plays versus the Haynesville.

Should 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?

Well, not given the completion technique, without going into all the details of what we're doing out there, no, we're comfortable we can bring these back and not risk the formation, that's right.

Brian, we're going to have to move to the next question.

Thank you.

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

Hi, guys, 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, are you guys considering paying it down early or might we actually see you sit with the cash on the balance sheet until the maturities come up and pay it down at that time?

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

Okay. But the -- okay. But are you considering, you know, at least leaving a portion of the cash on hand to fund those maturities when they come due?

I think 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 want to roll over those bonds. There's a number of things we can do.

Got it. That's helpful. Thank you.

Your next question comes from the line of [Alan Chen with Sasco Energy Partners]. Please proceed.

Good afternoon, guys. I have a question regarding the Wolfberry play. Regarding what you've seen with the well, what are the associated gas volumes you're seeing along with the oil?

Very little gas associated with that. Excuse me, there's very little gas associated with that. It's essentially all oil.

Okay. Is that fairly typical for the play?

Yes.

Okay. Great. Thanks, guys.

Your next question comes from the line of Phillip Dodge with Tuohy Brothers. Please proceed.

Yes. Thanks for the comments. 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?

The most of the acreage -- 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 would consider between the continental well that has been talked about and our existing acreage position.

Okay. Thanks. I'm going to show will power here, Vince, and leave it at one question.

Thank you, sir. Appreciate you, Phil.

You get a gold star.

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

Congratulations on implementing your restructuring. Your timing looks very good. Question for John Richels, can you be a little bit more specific on what you think the potential -- or how good a read do you have on what the ex-Shaw potential would be at Horn River and what the timing would be for you to try to determine if it's prospective on your acreage?

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

That's going to be something we're going to be evaluating probably with our 2011 program.

Okay. And this question is for Larry Nichols. The gas industry continues to kind of drill itself into -- to hold acreage, creating too much supply. Do you think there's going to be -- 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 any meaningful way through acquisitions?

It's not there today. Well, through any source. I mean acquisitions would be one source, but just picking up acreage that other people are not able to get to, you know, would probably be a much more interesting source since 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 sometime in the future.

Okay. Thanks.

And I would emphasize not so much in acquisitions because of the leases that a lot of companies bought, but if you look at the underlying leases as some of these leases are not -- are let go, that can be an opportunity.

Okay.

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

Good morning, gents. On your risk resource potential for about $13.6 billion, how sensitive is this to gas price changes? Did we lose some or some portion of it at $5 gas, 4.50 gas, $4 gas?

Yes, Rehan, there is -- 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.

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

Well, we'd certainly lose some there, right.

Okay. Okay. Thank you.

And, of course, liquids prices and oil prices also interplay into that resource potential as well.

Absolutely. Just looking for broad brush thought. Thank you.

You bet.

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

Hi, good morning. Couple of questions, Larry. Could you talk about when you think about share repurchase, can you walk us through the decision process, you talked a little bit about where the stocks trade, $10 per Boe, but can you talk about how you weighed that versus perhaps buying something in the market or paying down debt? Just give us a little more color.

Well, of course, we are paying down -- if 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 on -- in looking at other companies, it's a very, very simple decision. The return we get by buying Devon shares is dramatically better than anything else we look at. So we'll be buying Devon shares.

So Vince had mentioned earlier 20% rate of return was kind of the hurdle rate on something, so from your internal analysis, you -- it would imply that the share buy back is generating, I guess, well in excess of that?

David, hi, it's John. It's very tough. As you know, it's very tough to -- we're trying to do everything -- 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 assumptions of what happens to the stock price when you're buying it back. So there are other measures that we can look at 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 at these levels that buying back our stock is very, very accretive and measures up well on all of those metrics, besides just the F& D metric we talked about.

Okay. No. I think it's absolutely the right thing to do. I was just trying to get a sense of how you guys were viewing it and how you're looking at it. Congrats and thanks.

Thanks, David.

Because I've done a poor job of policing the callers to one question and one follow-up, we're going to take the last couple of questions, even though we're at the top of the hour. So go ahead, operator.

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

Hey, Dave, what did you pay for the additional K&A acreage, what kind of royalty on it?

We're not going to say specifically what we're out there paying for acreage, Mark.

Okay. Thanks. I tried.

But it -- but we're very happy with the price we paid and we still generate very strong economics.

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

Yes.

Thanks.

I didn't think you would get that by him.

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

Go ahead, Ray.

Ray, your line is open.

Yes, hi. Good morning. Sorry. It was on mute. But 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 effect Canada positively or no?

Ray, hi, it's John. The Jackfish in our SAGD projects have been tremendous, they've given us a 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 also the heavy light differential which has been much narrower than we have seen historically and we believe will stay narrow for the foreseeable future and the big disconnect between natural gas and oil prices has just made these 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.

Right.

We've kind of gone all around the horn on this thing. 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 -- it's -- even the conventional production in Canada is looking very, very positive and competes very well for capital in the portfolio.

Got it, great. And I guess if you were to net what you're saying that's new this quarter on the Cana shale, is -- I guess what would you say the EURs look like at this point and I guess are you able to get more of the reserves up front, is that kind of the gist of what you're saying on the IP rates in this quarter?

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 two thirds 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 --

Great. Thank you very much. Great.

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

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