德文能源 (DVN) 2010 Q3 法說會逐字稿

Welcome to Devon Energy's third quarter 2010 earnings conference call.

(Operator Instructions)

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

Thank you, and good morning, everyone.

Welcome to Devon's third quarter 2010 earnings call and webcast. Today's call will follow our usual format. I will begin with some preliminary housekeeping and compliance items, and then our President and CEO, John Richels, will provide his perspective. Following John's remarks, Dave Hager, our EVP of Exploration and Production will cover the operating highlights. And then finally, following Dave's comments, Jeff Agosta, our Chief Financial Officer, will review our financial results and our outlook. At that point, we'll open the call up to your questions.

Our executive chairman, Larry Nichols, and other senior members of the management team are with us today for that Q&A session. As a courtesy to other participants, we ask that each of you limit your questions to one initial inquiry and one follow-up. We'll limit the call to about an hour and we will be around for the rest of the day to answer questions after the call.

A replay of this call will be available later today through a link on Devon's home page. During the call today, we will provide some color on some of our forward-looking estimates based on the actual results for the first nine months of the year and our outlook for the balance of 2011 and 2012.

We will not be issuing a revised 8-K today because our outlook for the remainder of the year falls within the updated ranges we provided in the form 8-K that we filed last August. To access a comprehensive summary of our current guidance which includes any refinements we make today you can go to devonenergy.com and click on the guidance link found within the investor relations section of our website.

Please note that all references today for our plans, forecast, expectations, and estimates are considered forward-looking statements under US securities law and while we always strive to provide you with the very best data possible, many factors could cause our actual results to differ from those estimates. You can find a discussion of risk factors related to our estimates in the Form 8-K that contains these forecasts. One other compliance note. We'll refer to various non-GAAP performance measures in today's call. When we use these measures we are required under securities law to provide certain additional disclosures and those are available for your review on Devon's website.

By now, most you are aware that our decision to sell our international assets triggered the accounting rules for discontinued operations. We have therefore, excluded international production volumes for all periods presented as well as the revenues and expenses associated with those. Those are collapsed into a single line item at the end of the statement of operations. That line item is labeled "discontinued operations." For those interested in a more detailed view of our international results you will find an additional table in today's news release that includes a detailed statement of operations and the related production volumes that are attributable to the international properties.

As a reminder, the third quarter is our first reporting period without financial or operating results from the Gulf of Mexico. While the international divestiture properties are considered discontinued operations, the Gulf of Mexico divestiture assets are included in results from continuing operations for previous periods. For that reason, we are providing supplemental information in our press release that isolates the results from Devon's North American onshore operations, or in other words, the go-forward business.

As far as Street earnings estimates go, the majority of analysts chose to report estimates to First Call that included only our North American onshore operations. The mean estimate from those analysts that focused on continuing operations was $1.25 a share for the quarter. That compares to our non-GAAP earnings from continuing operations of $1.31 per share. So our actual results beat the Street estimate by $0.06 or about 5%.

With those items out of the way, I'll turn the call over to President and CEO, John Richels.

Thanks Vince and good morning everyone. For the third quarter of 2010, Devon delivered another very solid performance, both operationally and financially. Production from our North American onshore properties totaled 613,000 barrels of oil equivalent per day in the third quarter, a 4% increase over the third quarter of 2009. This production growth was driven by an 11% increase in oil and natural gas liquids production.

In the current environment, oil and NGLs now account for roughly half of Devon's total oil, gas and NGL sales revenue. Strong realized prices for our oil production and improved cost efficiencies resulting from the repositioning drove our adjusted earnings from continuing operations up more than 40% over the year-ago quarter, to $571 million or $1.31 per diluted share.

Cash flow before balance sheet changes climbed 47% over the third quarter of last year and combined with the divestiture proceeds, Devon's total cash inflows for the third quarter approached $4 billion, far exceeding our total capital demands for the quarter. As a result, we exited the month of September with an enviable position of $4 billion of cash on hand and a bulletproof balance sheet.

On the operations front, we continued successful execution of our focused North American onshore strategy as evidenced by quarterly production records at our liquids-rich Barnett and Cana Shale plays and a multi-year production high from our Permian Basin properties.

We also continue to make significant strides during the quarter towards completing the strategic repositioning that we announced just one year ago. In the third quarter, we completed the sales of our interest in the ACG field in Azerbaijan and our remaining assets in China. To date we have received aggregate pretax divestiture proceeds of approximately $6.8 billion.

The only significant divestiture package remaining, that's our Brazilian assets, is under contract for $3.2 billion. This transaction is pending approval by the Brazilian government and all indications are that this transaction will close as expected around year-end.

Following the closing we'll have realized total proceeds from our divestiture program exceeding $10 billion or roughly $8 billion after-tax. As we've always said, our objective in redeploying the divestiture proceeds is to optimize growth on a debt-adjusted, per-share basis.

To accomplish this objective, we have taken a balanced approach by directing $1.7 billion of sales proceeds to reduce debt and by allocating $1.2 billion to capture acreage opportunities across our North American onshore property based principally in oil and liquids-rich areas.

In addition we initiated a $3.5 billion share repurchase program last May. At today's stock price, $3.5 billion equates to approximately 12% of our outstanding common shares. Through today, we've purchased over 15 million shares for right around $1 billion. This puts us on pace to complete the buyback within the 12 to 18-month timeframe that we originally announced.

Buying back Devon's stock is an especially attractive alternative given our current stock price. Our shares currently priced in the mid-60s translate into a net enterprise value of under $10 per proven barrel. And this analysis attributes no value to the thousands of unproved locations that we have within our 13 million net acre resource base in North America.

Now, before I turn the call over to Dave, I just want to address a subject that we've received a number of questions about. That is our capital budget and our production profile for 2011. Given the significant divergence of oil and natural gas prices, similar to what we did in 2010, we expect to focus more than 90% of our 2011 capital on oil and liquids-rich opportunity within our existing portfolio.

Although we are still in the process of finalizing our 2011 capital budget and have not yet submitted it to our Board for approval, directionally we have a pretty good idea of where we want to go.

First, recapping 2010. We previously indicated that we expected full year E&P capital to total roughly $5.4 billion to $5.8 billion for our North American onshore business. We are still comfortable with that range but taking into account continued upward cost pressures in the sector, we now expect to be in the top half of that range.

This level of CapEx, I'll just remind you, includes a total of $1.2 billion of acreage capture. It includes the $500 million that we acquired -- that we invested to acquire the Pike Oil Sands acreage and about $700 million of additional leasing primarily in oil and liquids-rich plays in the Permian and Mid-Continent.

We would not expect to repeat this spend rate for leasehold acquisition in 2011. Adjusting for that gets you to a normalized spend for 2010 of roughly $4.5 billion for our go-forward North American onshore E&P capital budget.

Based on this starting point and assuming a similar level of drilling activity in 2011, with some inflation for service cost, I would expect our 2011 E&P capital budget to fall between $4.5 billion and $4.9 billion. When you take into account mid-stream and other capital, our total 2011 capital demands should be somewhere in the neighborhood of $5.5 billion to $5.9 billion. With that level of spending, we would expect overall production growth of 6% to 8% led by a roughly 20% growth in oil and NGL volumes.

I want to make this very clear. Our asset base has the capacity to grow at a much higher rate next year but topline growth is not what we are optimizing. We are focused on optimizing our growth per debt-adjusted share. We simply refuse to get caught up in the growth-at-any-cost mentality. Given the current environment, we can deliver optimum results through investing in our liquids-focused capital program, buying back our stock and taking a disciplined approach to our debt balances.

In 2011, we expect these actions to boost production per debt-adjusted share growth into the mid-teens. With that, I'll turn the call over to Dave Hager for a review of our quarterly operating highlights. David?

Thanks, John, and good morning everyone. I will begin with a quick recap of companywide drilling activity.

We exited the third quarter with 67 Devon-operated rigs running and during the quarter we drilled 407 wells. This included 384 development wells and 23 exploration wells. All but three of the wells were successful.

Capital expenditures for exploration and development from our North American onshore operations were $1.4 billion for the third quarter, bringing our total through the first nine months to $3.5 billion excluding the Pike acquisition. This level of activity increased third quarter production from retained properties by 4% over the third quarter of 2009, led by an 11% increase in oil and liquids production over the 2009 quarter.

Moving now to our quarterly operating highlights, first at our Jackfish thermal oil project in eastern Alberta, our third quarter daily production averaged a little over 21,000 barrels per day net of royalties. As we indicated in our last quarterly call, Jackfish was taken down for three weeks during the third quarter for scheduled maintenance. Following the turnaround, plant operations were restored on September 30. However, it will take a few weeks to fully restore the steam chambers and climb back to plant capacity.

Accordingly, fourth-quarter production at Jackfish is expected to average about 23,000 barrels per day net of royalties. Construction of Jackfish 2 is roughly 90% complete and continuing to trend under budget. We expect to begin injecting steam in the second quarter of next year delivering first oil in late 2011 with production ramping throughout 2012. Our third Jackfish project, Jackfish 3, has now been sanctioned and we filed the regulatory application during the third quarter. Pending regulatory approval, we could begin site work by late next year with plant start-ups targeted for 2015.

Detailed engineering work is already underway and we have locked down prices on roughly 85% of the major equipment orders. Devon operates the Jackfish projects and owns 100% working interest. At Pike this is our SAGD oil sands joint venture with BP that we formerly called Kirby. We have begun the appraisal drilling required to determine the optimum development configuration.

We expect to complete appraisal drilling this winter with a goal of launching the regulatory process for the first phase of development around the end of 2011. Between Jackfish and Pike, we expect to grow our SAGD oil production to between 150,000 to 175,000 barrels per day by 2020. In our Lloydminster oil play in Alberta we drilled 53 new wells in the third quarter, holding production steady at roughly 40,000 barrels equivalent per day in the quarter.

Moving to the Permian Basin. Our net production averaged just over 44,000 barrels of oil equivalent per day in the third quarter, up 18% over the third quarter of 2009 and 6% over the second quarter of 2010. Our third-quarter oil and NGL production in the Permian was up 23% over 2009 and accounted for roughly 70% of our total Permian volumes.

The growth in liquids speaks to the quality and flexibility of our property portfolio. As we mentioned last quarter, we are adding to the depth of this portfolio with approximately 200,000 additional acres and several oil and liquids-rich plays leased this year. We have ramped up activity in several of our key oil plays and now have 17 rigs running in the Permian.

One of these projects is our Wolfberry light oil play where we recently added a fifth rig. We drilled 27 wells during the third quarter, including one of our best wells today in the play, which had a 30-day IP of 500 barrels per day.

Our net Wolfberry production has increased nearly 150% since the beginning of the year to approximately 9000 barrels of oil equivalent per day. Our focus over the coming months will be to continue the evaluation of our 200,000 net acre Wolfberry position.

Also in the Permian Basin, we have four rigs running in the Avalon shale play. Devon has assembled over 200,000 prospective net acres in this condensate and liquids-rich gas play. So far this year, we have participated in 18 Avalon wells and have production data on a total of 30 wells covering a wide geographic area. While we are still in the early stages of evaluation of this play, the data support EURs of 400,000 to 600,000 barrels of oil equivalent per day depending on location within the broader play area, lateral length, etc.

We expect to participate in 14 additional Avalon Wells this year. We're encouraged with the results we have seen and we will keep you updated as we gain additional information. Another focus area in the Permian is the Bone Spring oil play where Devon has 170,000 net acres. The Bone Spring is an oil play historically developed by vertical drilling.

However, with the application of today's horizontal techniques, we have recently seen some outstanding wells. In the third quarter, we drilled and completed the Strawberry 7 Federal 4H that we brought online at more than 700 barrels of oil per day. Earlier results from the six horizontal wells we have drilled to date in this play, indicate EURs could have averaged around 300,000 barrels equivalent at a cost of $3.8 million per well. We currently have three rigs running in the Bone Spring and expect to drill approximately 20 wells in the play this year.

We are also running five additional rigs in the Permian targeting various conventional formations primarily with horizontal wells. Moving more -- moving north to the Texas Panhandle where Devon has approximately 58,000 net acres in the Granite Wash play, we stepped up drilling activity during the quarter with the addition of a third rig that was re-located from the Barnett shale.

In the third quarter, we brought three Devon-operated wells online with average IP rates of 4290 barrels of oil equivalent per day, including 605 barrels of oil or condensate and 1450 barrels of NGLs. With the attractive rates of return generated by these wells it is likely that we will add additional rigs in the Granite Wash as we head into 2011.

Moving to the Cana-Woodford Shale in western Oklahoma, we continue to add to our acreage position during the third quarter and now have approximately 240,000 net acres focused in the best parts of the play. This has increased our risked resource potential at Cana to more than 10 trillion cubic feet equivalent. In order to continue to derisk our position and secure the term acres that we acquired this year we have significantly ramped up our drilling activity over the past few months.

We currently have 19 operated rigs running and expect to add two additional rigs by year-end. We continue to see outstanding results from Cana. In the third quarter, we brought 11 operated wells online with average 24-hour IP rates of 5.3 million cubic feet equivalent per day including an average of 175 barrels of NGLs and condensate.

Third quarter net production from Cana averaged a record 117 million cubic feet of gas equivalent per day, including 1300 barrels of condensate per day and 4000 barrels of NGLs. This is a 12% increase on a sequential quarter basis. By year-end 2011, we expect to drive our net Cana production up more than 100% to 250 million cubic feet equivalent per day including 14,000 barrels per day of condensate and NGLs. In addition to enhancing upstream economics, the liquids-rich portion of the Cana field also creates opportunities from a midstream perspective.

To capture this value just as we have in the Barnett and Arkoma, we are building a gas processing facility. Construction of the Cana plant is essentially complete and we expect to begin processing next month. The facility will have an initial processing capacity of 200 million cubic feet per day and will be capable of extracting up to 15,000 barrels of NGLs per day. The plant's processing capacity is expandable to 600 million a day as our volumes from the field grow.

Shifting to the Barnett shale field in North Texas, in the third quarter our net production reached the previous all-time high of 1.2 BCF equivalent per day including over 40,000 barrels of NGLs in condensate per day. This illustrates the depth of our inventory in contrast to that of many of our peers. With virtually no lease expiration issues and thousands of remaining high-quality locations we have considerable capital flexibility in the Barnett. It is likely that we will choose to run a 12 rig program in 2011 with a focus on the liquids-rich portion of the play.

This level of activity should allow us to maintain our current production level. With most of our activity in the Barnett now focused on drilling multiple wells from a single pad we are finding that we are able to achieve even greater levels of efficiency. We have also continued to improve drilling efficiency and recently set a new record of eight days from spud to rig release for three recent Barnett wells. We are currently running 16 operated rigs in the Barnett but will relocate four of these late next month.

Moving to the Haynesville Shale, after de-risking much of our held by production acreage in the Carthage area during 2009, our 2010 activity has focused on our term acreage in the southern area. However, given the rising service cost environment in the Haynesville and the deep inventory of other attractive opportunities in our portfolio, our term acreage in the Haynesville does not currently attract capital within our portfolio. Therefore, we are continuing to bring in industry partners that are interested in developing this acreage.

Keep in mind the Haynesville drilling we did in 2009 in the Carthage area confirm that we have a repeatable, economically attractive play under a more normalized gas price environment. Since this acreage is held by production, we have the luxury of pursuing this resource when the gas price and the cost environment is most favorable.

And finally in the Horn River Basin of Northern British Columbia we have now drilled all seven horizontal wells that we planned for this year. Four of these wells have been completed and we expect to have them tied in and producing by year-end. Our producing wells at Horn River continue to perform better than expected supporting an average EUR of seven to eight BCF equivalent per well. Given that the Horn River is dry gas, we plan to spend minimal capital there in 2011.

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

Thanks Dave, and good morning everyone. Today I will begin by looking at some of the key drivers that shaped our third-quarter financial results and review how these factors impact our outlook for the upcoming quarter in 2011.

As Vince mentioned earlier we have reclassified the assets, liabilities and results of operations from our international assets into discontinued operations for all accounting periods presented. Since we completed our exit from the Gulf of Mexico during the second quarter our third-quarter results from continuing ops represent just our North American onshore operations, or in other words, the results of the repositioned Devon.

Looking first at production, in the third quarter we produced 56.4 million oil equivalent barrels or approximately 613,000 barrels per day. This was in line with the production forecast range we provided during last quarter's call and about 1% less than last quarter's production from our North American onshore assets.

You may recall that during last quarter's call we told you that production from the second quarter had benefited from a 9000 barrel per day royalty adjustment related to prior periods. Also, due to a scheduled plant turnaround, Jackfish was off-line for three weeks during the third quarter. As a result, average daily production from Jackfish was 8000 barrels per day lower on a sequential quarter basis.

Removing the out-of-period royalty adjustment, and the impact of Jackfish maintenance sequential quarter production was up almost 2%. On a year-over-year basis, third-quarter production from our North American onshore assets increased 22,000 barrels per day or 4%. As mentioned before, an 11% increase in oil and NGL production drove the favorable comparison.

Looking ahead, our high-quality North American onshore assets remain on track to deliver full-year production of 223 million to 224 million equivalent barrels. This implies fourth-quarter production of 625,000 to 635,000 BOE per day or roughly 10% over fourth quarter 2009 production. Moving to price realizations, starting with oil. In the third quarter the WTI Index averaged $76.08 per barrel, an 11% increase over the third quarter of 2009.

Companywide oil price realizations were near the top end of our guidance ranging 82% of WTI. The most notable regional performance was the narrowing of heavy oil differentials in Canada. On the natural gas side, the third-quarter benchmark Henry Hub gas price averaged $4.38 per MCF. Our third-quarter realized gas price before the impact of hedges was 84% of Henry Hub or $3.67.

Cash settlements from our hedging position and regional basis swaps increased our overall price realizations by $1.00 bringing our all-in price including hedges to $4.67. For the fourth quarter of this year, we remain well hedged with approximately 60% of our natural gas production locked in at a weighted average price of $5.87 per MCF. We also have roughly 70% of our fourth quarter oil production collared with an average floor of $67.47 per barrel and an average ceiling of $96.48.

Looking to 2011, we recently added 300 million per day to our gas hedge position bringing our total up to 525 million cubic feet per day for the year swapped at a weighted average price of $5.56.

As part of these recent additions, we sold call options on 12,000 barrels of oil per day for 2011 and 2012 at $95 per barrel and call options on 300 million of cubic feet per day of gas for 2012 at $6 per MCF. Also for 2011, we have collars in place on 33,000 barrels of oil per day with a floor of $75 per barrel and an average ceiling of $109. We will be posting a schedule on our website after the call with all the details of our hedge position.

Looking briefly at NGLs, our price per barrel in the third quarter averaged $29.01 or about 38% of the WTI index price. This compares to average realizations of about 40% of WTI in the previous quarter. We expect seasonal factors to provide a modest boost to NGL prices in the fourth quarter.

Turning now to our marketing and midstream divisions, they continue to deliver impressive results. For the third quarter our operating profit totalled $125 million, a 20% increase over third quarter 2009. Increased throughput and higher commodity prices drove the improvement. For the fourth quarter, we expect our marketing and midstream operating profit to be in the range of $110 million to $130 million. This would bring our full year operating profit to roughly $500 million.

Looking now at the main expense items for the quarter, as we move forward with the strategic repositioning, we are seeing the efficiency gains flow through to our reported results. On a sequential quarter basis, most expenses decreased during the third quarter on both an absolute and a unit of production basis.

Lease operating expenses totaled $415 million in the third quarter, or $7.35 per BOE. This represents a 3% decrease from last quarter. This rate is indicative of what we would expect for the fourth quarter.

Shifting to G&A, G&A expenses continue to be well contained in the third quarter totaling $131 million. For the first nine months of the year, our G&A costs have declined by $73 million or 15% when compared to the same period of 2009. Based on the actual performance for the first three quarters, we now expect our full year 2010 G&A expense to be near the bottom end of our previous forecast range of $580 million to $600 million.

Turning to interest expense, for the third quarter it came in at $83 million, right in line with our expectations. When compared to the third quarter of 2009, interest expense decreased by 8% due to lower debt balances. Looking to the fourth quarter, we expect interest expense to approximate $80 million.

DD&A expense for oil and gas properties declined by 7% from last quarter to $397 million. The improvement in DD&A resulted from the sale of our Gulf of Mexico assets. For the fourth quarter we expect DD&A expense to range between $7 and $7.25 per barrel. The final expense item I will touch on is income taxes.

After backing out the impact of items that are typically excluded from analysts' forecasts, our adjusted third-quarter tax rate on earnings from continuing operations came in at 33% of adjusted pretax income. This tax rate consisted of deferred taxes equal to 40% of pretax income and current taxes of a negative 7% for the quarter. This atypical distribution of current and deferred taxes was due to an adjustment related to the filing of our 2009 tax return.

Essentially our 2009 tax return indicated more carryover benefits available for 2010 than we had previously estimated. The cumulative impact for the first nine months of the year was recorded in the third quarter. In spite of the unusual third-quarter tax rate, our adjusted tax rate for the first nine months of 2010 was similar to what we now expect for the full year with a total rate of 33% of pretax earnings composed of a 6% current tax rate and a 27% deferred tax rate.

In today's news release, we have provided a table that reconciles the effects of items that are typically excluded from analysts' estimates. Moving now to the bottom line, non-GAAP earnings from continuing operations totaled $571 million or $1.31 per diluted share. Higher oil and gas revenues along with strong cost controls increased our adjusted earnings from continuing operations by over 40% when compared to the third quarter of 2009. As Vince mentioned earlier, this result also exceeded the comparable First Call mean number by $0.06.

Before we open the call to Q&A, I would like to conclude with a quick review of our financial position. During the third-quarter Devon generated cash flow before balance sheet changes of a $1.8 billion, a 47% increase over the year ago quarter. Additionally, we received $2 billion of cash from the sale of assets in Azerbaijan and China.

After funding our total capital demands for the quarter of $1.8 billion and repurchasing $499 million of common stock, our cash balances increased by over $1 billion during the quarter reaching a total of $4 billion. With that level of cash, and total debt of roughly $5.6 billion, we clearly maintain a great deal of financial strength and flexibility. Over all, we believe our measured approach to the business and our balanced high-quality property base, place Devon in an advantageous position during this period of uncertain gas prices.

Our deep and diverse inventory of oil and liquids opportunities provides us with great flexibility in allocating capital in response to market conditions. We remain committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength and optimizing our growth per debt-adjusted share. At this point I will turn the call back over to Vince for the Q&A.

Operator we're ready for the first question.

Thank you. (Operator Instructions). Your first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Your line is open.

Thank you, good morning guys. Thanks for all the detail this morning.

A couple things from me. On the CapEx guidance for next year that you laid out, can you give us an idea as to whether or not you are anticipating living within cash flow or if you are obviously the strength of your balance sheet would give you more flexibility should you choose to pursue your oil investments a little more aggressively.

And related to that, if you could give us an idea of what you expect your rig count trajectory to look like through the course of 2011. I have one quick follow-up if that is possible.

Doug, let me take a crack at the first part of that.

You recall a year ago when we announced our repositioning we indicated that as a result of the fact that we had kind of starved our North American asset base for a couple of years we would take some portion of the proceeds from our asset sales and invest them in both 2010 and 2011 in our capital programs.

So depending on what kind of a price forecast you look at for next year, that will result in some investment next year that is in addition to our cash flow for the year. And, that was always intended. What the exact level of that turns out to be, as I mentioned, will depend on what commodity prices are next year.

But we clearly have the financial strength to do that and it's an appropriate thing for us to do given that we are investing in very solid return projects.

And then I will ask Dave to maybe answer the question on the ramp-up.

I can give you an idea. And again we have not finalized our Board approval on our budget but we do have some ideas here on what we think the rig count may look like.

It is actually pretty steady through all of our divisions with the exception of Canada where of course you have increased drilling activity in the winter.

So you have a higher rig count in Canada during the winter months. So Canada first quarter will probably have on the order of around 20 rigs working. About 11 or so we're anticipating in the thermal-type activity, primarily at Pike where we will be going strat wells.

And then we'll have a couple of rigs at Lloydminster, and then about seven or eight working on other various plays throughout Canada. Some Cardium oil plays, some Deep Basin plays, etc.

But around 20 and then that will fall off in the second, third, and fourth quarters to around that 8 to 10 range on an overall basis.

The other three divisions we have of central, southern, western will be pretty constant.

Let me just give you some numbers for that. The Cana we mentioned we are going to be up around 21 by year-end. We are actually planning to average around 23 rigs in Cana next year. And we mentioned in Barnett we plan to run about a 12-rig program which would keep production flat there.

We have about three to four rigs working in the Granite Wash area.

Then, down in our southern division, down in Haynesville, we mentioned that we are really going down to essentially no activity there. We will have a total of about five rigs working various opportunities throughout our South Texas area total for the year.

Then we'll have about 20 rigs in what we call our Western division with about 17 of those rigs working the Permian Basin area. About 17 of those and about three of them in the Rockies area. There are a couple working oil opportunities up in the Powder River and one working at Washakie.

If you want a little further breakdown on the 17 rigs in the Permian that we're going to have working there next year, we will probably have about five rigs working in the Wolfberry play, about three working the Avalon, four working Bone Springs and about five working other opportunities we have in the Permian including Delaware, Wolfcamp, Tubb, other conventional plays we have there.

Hopefully that gives you all the details you need on -- a not-yet-approved budget but a kind of a planned-out budget for 2011.

That was pretty thorough. My follow-up is really related to your comments around the Haynesville.

But I guess it applies to the wider portfolio. We haven't seen Devon participate or try to participate in bringing joint venture partners in to pursue some development in areas that might not be a top of the list for your capital right now.

Can you give us some thoughts on why perhaps Devon hasn't chosen to go down that road and maybe what your outlook might be for divesting some acreage that does not fit the portfolio as you go forward and I will leave it there.

This is Vince. I would comment that we have actually brought in some farm-in partners in the Haynesville on our term acreage. And we really have a focus on managing our overall inventory.

So we think that rather than being focused on just maximum acreage capture that we need to manage our inventory to optimize present value, so we are considering outright sales, farm-ins, JVs. Anything that we are not going to get to in the next few years we are looking at a way to bring that value forward.

Great stuff. Thanks, Vince.

Our next question comes from the line of David Heikkinen with Tudor, Pickering, Holt. Your line is open.

Good morning. Thanks for all the details on your capital plans and drilling plans.

As I think about the Granite Wash and your current acreage position, how much of that do you think that is prospective for horizontal development and how much has already been drilled. Just trying to get an idea of real inventory and path forward for that.

Hello David. We think we have roughly 350 locations in the Granite Wash play. About 150 of those would be in the two upper formations where we've targeted our work so far.

In the Cherokee and in the Granite Wash A and about 200 locations in the lower Granite Wash formations where we haven't drilled yet, and frankly, we are not sure the economics will be quite as strong. These wells we are drilling right now are, you can imagine, that these kind of rates we're getting are just incredible rates of returns, in excess of 100%. So, we are not sure these lower Granite Wash locations, these 200, will be quite as good.

But they could be -- we think they are still going to be very, very attractive and we'll probably have a learning curve to go through and we will get good results from those as well.

So I would say overall we are giving it a -- about 350 locations that we think we have. As far as a net resource potential it is still early on. We need to know a little bit more about the lower Granite Wash. I'd say on an unrisked basis it could be as much as 500 million barrels on an unrisked basis, maybe more like 150 million barrels or so on a risked basis.

That is helpful.

As you think about the Lower Granite Wash, that's the Atoka, are you seeing liquids component or is it pretty dry?

We have not actually drilled the Lower Granite Wash.

Okay. Fair enough. I think that was it. Thanks guys.

Your next question comes from the line of Dave Kistler with Simmons & Company. Your line is open.

Good morning guys.

Real quickly, with most of the leasing behind you in terms of capital being spent for picking up additional acreage in the Permian and other plays, can you give us a sense maybe across the Bone Springs, Avalon, Wolfberry what the actual cost is on an acreage basis for you guys?

Well, we are still actively -- most of it's behind us but I think we are still doing a little activity.

I am a little reluctant to say too much on the cost. Overall I can say that on the Texas side of the Avalon play, it has been less because it is more frontier area out there.

Where you get on the New Mexico side of the play, it has been a little bit more expensive. I might also add that we have a huge position out there that is already held by production. So we aren't relying just on spending a lot of money, that we have it on new leases.

We had nearly 1 million acres in the Permian in total. And so we have a lot held by production that's contributing to our resource opportunities there.

And Dave, it's John.

Let me make one other point about our asset base in general. When we're bringing new properties in, we've got -- our asset base has some very common characteristics.

We have tried to stay away, and, gosh, we have not been perfect, but we have tried to stay away from getting into paying really high amounts and giving high royalties in areas of our operations.

So as we're getting into new areas and we are bringing those properties in, we have got to make sure they continue to compete against an asset base that instead of $20,000 an acre tends to have a cost of a couple hundred to a couple of thousand dollars an acre and a 20% or less royalty burden.

So that is one of the considerations that we are taking into account all the time as we go into new areas, make sure that we keep that really low cost economic asset base.

Great, that is helpful.

Then, jumping over to the services side for just a bit.

[Somatically] pressure pumping increasingly and completion services are increasingly getting tighter and tighter. We are seeing people have production delayed as a result of that.

Can you talk a little bit about whether that is impacting you guys at all in terms of are there some delays with wells being tied in? Are you building an inventory of drilled uncompleted wells? And then probably more importantly, how are you planning on managing that and avoiding cost inflation in the upcoming budget?

I don't know that we can totally avoid cost inflation in the upcoming budget. When we look at the cost, what we believe is going to happen, looking at an average of where we were mid-year 2010 versus what we expect to happen for 2011, on a raw service cost increase, we think is going to be probably around 14%, 15% in 2011.

Now, we think that we can have increased efficiencies in our operations that is going to lower that. We are planning in our budgeting process for about a 10% increase cost environment versus 2010.

An important thing to remember is we are a very strong player in the vast majority of the plays where we are active, whether it is the Barnett or the Cana or even out in the Permian Basin.

And so we command, to a large degree, I guess attention you might say, in that we can -- we have had good luck with our -- because we have a strong position of getting good cooperation with the service companies to lock in our -- particularly the pressure pumping side. So in those areas that I mentioned we really aren't having a significant problem.

The only area we have had much of a problem with delays on frac dates I would say would be in the Haynesville where we are not a large player compared to others and we don't want to become a large player because we think the economics are not attractive there compared to the other areas of our portfolio.

So we have had some delays. We do have frac dates locked-in for about our eight remaining wells in the Haynesville between now and the end of the year. But it is just not a big problem for us overall to get frac dates locked in, although we obviously -- as I said, we are planning on about 10% cost increase, '11 versus '10.

Great, thank you so much for those clarifications, guys.

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

Good morning.

Dave, can you give us an idea of what kind of lease expiration picture you are looking at in the East Texas Haynesville, Bossier play -- and the term acreage?

Mark, where we think we have the large repeatable play identified that is -- would be economic under a more normalized gas price environment; we are talking there probably around $5.50 to $6 type prices would be in Panola County. That is all held by production.

We have about 110,000 acres held by production there. We have about 47,000 acres or so just to the south in Shelby and San Augustine counties that we do not think again are meeting our return requirements for investment. That is why we are dropping our rigs.

We are talking to some people whether they might be attractive to someone else and so we are talking to some companies to see if they are interested in pursuing that. That is around 47,000 acres or so with expirations throughout 2011 and 2012.

Dave, my follow-up, per the Barnett program for 2011 that you talk about, at what well spacing will you be drilling on?

We're drilling a lot of our wells primarily on either 80s or 40s.

And that is the basis of the 2011 program as you understand it now?

Yes.

Thanks very much.

Your next question comes from the line of Robert Christensen with Buckingham Research. Your line is open.

Thank you, Jackfish 2, how quick a ramp will we have, or will it be just identical to what we saw in Jackfish 1?

It's going to be very similar to Jackfish 1. It is probably going to take the better part of a year to ramp up to a full production rate.

Okay, thank you.

Or next question comes from the line of Mark Polak with Scotia Capital. Your line is open.

Good morning guys.

A question for you on Jackfish 1. Just curious what kind of steam-oil ratios you guys are seeing in the third quarter?

They continue to come down in our top 10%. John, do you have the number?

I will point out, Mark, that remember in the third quarter we had the turnaround going on. So that is a little bit -- that is not a great quarter to look at from that point of view.

We are trending down to somewhere below 2.5 in our steam-oil ratio. When it comes back up to full production here in the next 30 days, we will expect to get back to that kind of level.

Our cumulative is down around that level as well.

Yes. This quarter won't throw the cum out much, and we'll continue to be in the 2.5 or less range.

Yes, the cum is around 2.5. I think we are actually on a quarter basis, ongoing basis we're probably even better.

Thanks. And Vince already covered all my questions on JVs. Maybe just one more then on Horn River. I was just curious how you are completing those wells, how many stages and what kind of cost structure you are seeing on those wells?

What we are doing right now is we haven't really optimized the number of stages that we think are going to be necessary once we go to full development.

What we are seeing is a recovery of about 1 million cubic feet per day per stage.

That is what we wanted to see. We've been doing them so far with on the order of four to eight stages although we have not really decided what the optimum number of stage will be when we go to full development. Those wells when -- they've been costing on the order of about $8 million per well completed.

Thank you very much.

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

Thanks, good morning. When you consider the 20% liquids growth next year what contribution are your US assets and particularly the Permian contributing to that? Is that the major driver relative to Canada or is it relatively equal?

There are two big pieces on the US side that are really driving the production growth. That is going to be Cana and the Permian assets and they are both going to be growing substantially.

We mentioned that we are going to be doubling our overall production in Cana to about 250 million equivalent per day including 14,000 barrels of liquids there, and we will probably have about a 25% growth or so in the Permian and that will be roughly split equally between gas and oil and liquid. So those are the two big drivers in the US and then, of course, our Jackfish ramp-up in Canada as well.

Although for 2011, since we won't have the second project ramping up for most of the year, most of our oil growth is coming from the US in 2011.

Thanks, and then you mentioned much less acreage acquisitions next year.

Do you think you have the bulk of the acreage you want or need in the Permian and Cana plays and do you see the potential for any new liquids exploration plays to warrant capital to build acreage and then perhaps you could touch on activities in the Powder River Basin oil drilling since you brought it up earlier?

Let me make kind of a general comment first, Brian, on the acreage that we have. We think we have got a very good acreage position.

We constantly have to, in order to deploy our capital really effectively and drive the most value for our shareholders, we have got to constantly balance the notion of acreage capture with resource development.

And so we don't want to just continue to add and frankly we don't subscribe to the idea that the world of leasing is over. We think that there are going to be a lot of plays that come around in the next few years and we are focused on them.

And as I've mentioned to you before, it's not unlikely that you're going to hear us talking about a couple of plays that have not had a lot of publicity over the next while.

So with regard to the Powder River, specifically, I'll maybe let Dave answer that question.

Yes, I would just say, we could have strong production growth, really living within cash flow over the longer term without adding any new acreage.

So, we think it is always important to see if we can optimize, add new opportunities that may even be better and move some of the poorer things at the bottom of the portfolio out.

That is just part of the ongoing process. But it is not out of need so much. We have a very strong acreage position with a lot of opportunities right now.

With regard to the Power River we have got a couple ideas working up there. I just don't want to go into a whole lot of detail about them but we've got some ideas around some deeper oil in there and we are going to be testing out some of those ideas in 2011.

Great, thank you.

Your next question comes from the line of David Cameron with Wells Fargo. Your line is open.

Thanks, a couple questions.

Powder River, can you talk about oil frontier [mallory] what you're seeing there and just give us some more color there?

We just addressed that very quickly.

We see some opportunities in those type and I just prefer not to go into a lot more detail until we have more results. But we are going to be drilling a few wells to test out some of those ideas and those type plays in '11.

Okay. Fair enough.

Same question Canadian Deep Basin?

Yes. Well, we have a lot of running room obviously up in the Canadian Deep Basin.

If you look at it overall, we have about 6 million net acres of land in the Western Canadian Sedimentary Basin and we are looking at plays in the fractured oil shales and the carbonates in Deep Basin. We are looking at tight oil classics in Saskatchewan.

Specifically onto Deep Basin, we have about 600,000 net acres where we are currently evaluating some Cardium light oil plays with horizontal wells.

Additionally we're going to be pursuing a number of other zones horizontally with multi-stage fracturing, targeting liquids-rich oil and liquid-rich gas and light oil. We're also drilling some light oil plays in the Cardium and the Ferrier area of central Alberta.

Testing the Viking light oil play where we have about 900,000 acres of fee lands in Saskatchewan.

We have a large number of oil and liquids-rich plays in Canada that we are pursuing and they are in the early stages most of them but they could grow into something material over the longer term.

Yes, and I heard you reference some of those before, the horizontal oil and the Cardium. Have you guys begun drilling -- you say you are in the early stages of testing. What exactly --

We will be drilling wells on them in 2011.

Okay. That's what I was looking for. Thank you.

We have got time to take one more caller.

Your final question comes from the line of [Phillip Dogue] with CDT Capital. Your line is open.

Came pretty close there.

Good morning everyone.

Good morning.

Could you bring us up-to-date on the sale of the properties in Brazil? As I understand it, you haven't received the money there, whether that looks any closer after the election or some other variable?

You know we have had Phil, we've had no indications through the year that that wasn't moving ahead exactly as planned. We always thought that that was going to take some time given the regulatory process that E&P goes through.

The election, having the election behind us is a positive thing because it adds -- it just created some delays in that whole process but the candidate who was elected is one that has been a supporter of this industry. And we still expect that to close somewhere around year-end. So everything is on schedule and on course the way we expected.

Okay, and unrelated follow-up. You're talking about the expenditures for undeveloped acreage and lease additions this year. I heard you mention $1.2 billion and $700 million. Two figures. My question is just clarification. Is the $700 million included in the $1.2 billion or is it separate?

Yes. Yes, it is.

What it is, the $1.2 billion that we allocated to undeveloped leaseholds this year, included $500 million for the acquisition of the Pike heavy oil lease immediately adjacent to Jackfish.

That was part of our overall deal with BP during the repositioning and the other $700 million was invested in liquids and oil leases primarily in the Permian Basin and also some in the Mid-Continent in our Cana play.

Okay. Thank you very much.

That concludes our call. Thank you for joining us today and as we said earlier, we will be around for the rest of the day to answer any follow-up questions.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.