德文能源 (DVN) 2009 Q3 法說會逐字稿

Good day ladies and gentlemen. Welcome to the Devon Energy third quarter 2009 earnings conference call. At this time, all participants are in a listen-only mode. After the prepared remarks, we conduct a question-and-answer session. This call is being recorded.

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

Thank you. Good morning everyone, and welcome to Devon's third quarter earnings call. As usual, I will begin with some housekeeping items and then turn the call over to our Chairman and CEO, Larry Nichols for his overview. Following Larry's remarks, our President, John Richels, will provide a financial review, and then finally, after John's comments, Dave Hager, Executive VP of Exploration and Production, will provide an operations update. We'll follow that with a Q&A.

We generally try to hold the call to about an hour, so if we don't get your question, we'll be in later today to get to your call. And as always, we ask the Q&A participants to limit their question to one question and one follow-up. A replay of this call will be available through a link on our home page later today.

During the call, we're going to provide updates of some of our 2009 forecasts based on actual results for the first nine months of the year and our expectations for the fourth quarter; however we will not be issuing a revised 8-K today,. That's because most of the estimates remain within the updated ranges that we provided in the Form 8-K that we filed on August 5th of 2009. That 8-K is posted to the Estimates page of the Investor Relations section of Devonenergy.com, and the refinements that we provide to those estimates today will also be posted to the Estimates page of our website.

Please note that our references in today's call to our plans, forecasts, expectations, and estimates are all forward-looking statements, as described under U.S. Securities Law, and while we always strive to give you the very best information possible, there are many factors beyond our control that could cause our actual results to differ from the estimates we provide. Therefore, we urge you to review the discussion of risk factors and uncertainties provided in the August Form 8-K. One final compliance item, we will refer today to various non-GAAP performance measures, and when we make reference to such measures, we're required to make certain disclosures under U.S. Securities Law. Those disclosures are available on the Devon Energy website at Devonenergy.com.

Before I turn the call over to Larry, I want to give you a quick update on our lower tertiary sell down. This process has attracted a very broad interest, and we've had a strong showing in the data room. We've said all along that we will not ask for bids until the Kaskida delineation well results are in, and we are confident that we will complete those operations on Kaskida this month. That schedule would put us with bids due by the end of December. Now I'll turn the call over to Devon's Board Chairman and CEO, Larry Nichols.

Thanks, Vince. Good morning, everyone. The third quarter was another outstanding one for Devon. We continue the trend that we've had for several quarters now, quite a few of exceeding expectations for oil and gas production, while at the same time driving costs lower.

The third quarter production for oil, gas, and MGLs totaled 61.9 million barrels, exceeding our guidance by about 900,000 BOE. This represents a 6% increase over third quarter of 2008, and this is in spite of voluntary curtailments that we had during the third quarter of about a million equivalent barrels. We drove LOE per equivalent barrel down by 19% from a year-ago quarter to quarter, fueled by higher than expected production, improving cost and strong oil prices.

We generated net earnings of $499 million for the third quarter. After we exclude those items that we and analysts generally do not forecast, we earned $491 million or $1.10 per share, far exceeding the first call mean estimate of $0.90 per share. We had cash flow operations from operations of $1.2 billion for the quarter, which more than funded our total capital expenditures for the period and generated free cash of $168 million. We exited September with cash and equivalent credit lines of $2.8 billion and a healthy net debt to cap ratio of just over 31%.

While natural gas prices declined from the second quarter of this year, prices for oil and natural gas liquid strengthened, which drive our sequential increases in third quarter sales and earnings. Oil and gas liquids accounted for 60% of Devon's oil and gas revenues in the third quarter, which underscores again the importance of Devon's balance portfolio, the balance between oil and gas that we've talked about so much in the past really paid off for us this quarter.

While natural gas prices are still weak today, as we look ahead, we do see improving economics in the North American natural gas business. Costs have come down considerably from the peaks of last year, and based on our own internal forecast, as well as the future strip, our key development gas projects all deliver attractive rates of return that are well above our cost to capital. With the improving outlook for natural gas prices, with the impact of the sale-down of our lower tertiary, and with lower overall industry cost structure, this should allow us to step up activity next year.

With superior acreage positions in many of the best shale plays, we have no shortage of opportunities. We have currently adding drilling rigs in our major shale development plays, and will continue to do so in 2010. The step-up in activity for the remainder of the year will move us outside the range of our previous 2009 ENP capital guidance. For 2010, we're currently working through the budgeting process and expect to finalize the 2010 budget by year end.

Based on our better than expected third quarter production and the impact of higher activity levels in fourth quarter, we are increasing our full-year 2009 production forecast by three million barrels, to a range of 247 million to 249 million BOE. The midpoint of that range, which is 248 million equivalent barrels, represents a 4% increase of 2009 over full-year 2008 production. [In separate areas] to add more predictability to 2010 price realizations, and to ensure sufficient cash flow to support the increased level of activity, we have already hedged a significant portion of our oil and gas production for the year.

We have entered into swap contracts for the full-year 2010, covering about 1.1 BCF of gas per day, at a weighted average NYMEX price of $6.18 per MMBTU. We have also protected the price of about 68,000 barrels per day of our 2010 oil production with costless collars. The weighted average of the floor for the oil collars is $67.05 per barrel, with a weighted average ceiling of $96.07 per barrel. To put this in perspective, the 2010 oil and gas hedges cover volumes equal to about 37% of our current production.

In recent months, we have also added hedge positions for the fourth quarter of 2009. We have now about 1.1 BCF per day protected at a weighted average gas price of $5.65 per MCF. This represents 45% of our estimated fourth quarter natural gas production. So we enter the final months of 2009 with an improving outlook for our core North American business, and with an eye to a much more active 2010. With that I'll turn the call over to John Richels for the financial review and further outlook. John?

Thanks, Larry, and good morning, everyone. I'll 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 fourth quarter. Let's begin with production. In the third quarter, Devon's production totaled 61.9 million equivalent barrels, or approximately 673,000 barrels per day. As Larry said, this exceeded our guidance by approximately 900,000 barrels. The lack of hurricane downtime in the Gulf of Mexico and lower royalty rates on Canadian natural gas production drove most of that out performance.

When compared to the third quarter of 2008, Devon's Companywide production increased by 36,000 barrels per day or 6%. The U.S. on-shore segment continued to deliver growth in spite of voluntarily reducing production by approximately one million equivalent barrels during the quarter. Led by growth from our [Coleman], Woodford, and Cana shale plays, U.S. on-shore production grew by 12,000 barrels per day or 3% over the third quarter of 2008.

In Canada, third quarter volumes climbed by more than 6% year over year. Growing production from our Jackfish Sag D oil project and lower crown royalty rates on Canadian gas production were the primary growth drivers. Production from our international properties increased by 36% or 11,000 barrels per day over last year's third quarter. Greater production from our Polvo field in Brazil and higher output from the ACG field in Azerbaijan accounted for the increase.

As Larry mentioned earlier based on our strong year to date results and our outlook for the fourth quarter, we are once again increasing our 2009 production outlook. We now expect full-year production to be between 247 million and 249 million barrels. This revised forecast implies a fourth quarter production range of 58 million to 60 million barrels, which is up about two million barrels from our previous guidance for Q4.

You'll recall that last quarter, we mentioned that we were deferring well completions and reducing incremental compression resulting in a voluntary reduction in fourth quarter production of about 12 BCFE or about two million equivalent barrels. So the 58 million to 60 million barrel fourth quarter production forecast is in spite of that reduction.

Moving on to price realizations starting with oil, in the third quarter, the WTI benchmark price averaged $68.25 a barrel. That's about a 14% improvement over the last quarter. In addition the higher index prices, oil differentials, improved for most of our geographic regions. The most notable regional out performance occurred in Canada. For the second quarter in a row, heavy oil differentials were tight, resulting in a third quarter realized oil price in Canada of about 81% of WTI. Company-wide, our realized oil price in the third quarter averaged $61.12, or 90% of the WTI index, about $9.00 per barrel higher than last quarter.

Looking to the fourth quarter, we expect differentials to widen somewhat in Canada as we move beyond the summer high-demand months, and as a result, we anticipate fourth quarter realized prices in Canada to come in around 65% of WTI. Company-wide, we expect fourth quarter oil price realizations to average about 80% of WTI.

On the natural gas side, the third quarter Henry Hub Index averaged $3.39 per MCF. Our Company-wide gas price realizations, before the impact of hedges, came in at 84% of Henry Hub or $2.84 per MCF. In the third quarter, we had hedges totaling 347 MMBTU a day, with a weighted average floor of $7.25. Cash settlements from that hedging position increased our Company-wide realizations by $0.53 per MCF, to an all-in price, including hedges, of $3.37 per MCF.

Turning now to marketing and midstream, our third quarter marketing and midstream operating profit came in right in line with our expectations at a $100 million, and for the fourth quarter, we expect a similar level of marketing and midstream profit. Before we move to expenses, please note the $96 million of other income reported in Q3. Most of this amount, approximately $84 million, is attributable to a favorable legal decision associated with deep water royalties. With a final ruling having been received, we have now reversed the contingent liability that we had previously recorded.

Moving now to expenses, our third quarter lease operating expenses totaled $505 million. This result marks the fourth consecutive quarter that Devon's lease operating expenses have declined. On a per-unit basis our third quarter LOE came in at $8.16 per barrel, about $2.00 a barrel lower than the year-ago quarter. The reduction in LOE reflects declines in virtually every expense category across all of Devon's major producing regions. Looking ahead ,we expect to continue to achieve cost savings on oil-field services and supplies, and for the fourth quarter, we are now forecasting LOE to decline to a range of $485 million to $500 million.

Our third quarter DD&A expense for oil and gas properties came in at $480 million, or $7.75 per barrel. That's near the bottom of the guidance range provided during our conference call last quarter. For the fourth quarter, we're forecasting our DD&A rate to be between $7.50 and $8.00 per barrel of production.

Shifting to G&A expense, Devon's third quarter G&A expenditures totaled $137 million. That's about a $9 million decrease in G&A costs when compared to the third quarter of 2008. This decline in G&A is due to a Company-wide focus on reducing costs. Looking ahead, the fourth quarter of 2009 will include approximately $20 million of non-cash expense due to the issuance of annual equity compensation, and when you include this non-cash expense, we expect fourth quarter G&A expenditures to increase to a range of $150 million to $170 million.

The final expense item I want to touch on is income taxes. For the third quarter, we reported income tax expense of $93 million or 16% of pre-tax income. However, this number has some unusual items that require explanation.

First, we received a $59 million benefit in the third quarter, due to income tax accrual adjustments that were recorded in conjunction with the filing of current and amended prior-year returns. Additionally, we recognized about $22 million of current tax benefits associated with international exploration and $40 million of deferred tax benefits due to the fair value changes of derivatives. When you back out of the impact of these items, our adjusted tax rate for the quarter would have been just over 30%, or right in line with our guidance.

In today's earnings release, we provided a table that reconciles the income tax effects of items that are typically excluded from analyst estimates. Cutting all the way to the bottom line, adjusting for items that most analysts don't include, reduces reported earnings slightly to $491 million or $1.10 per diluted share. While well below earnings in the year-ago quarter due, of course, to much lower natural gas prices, it marks a 29% increase in adjusted earnings per share on a sequential quarterly basis. As Larry mentioned earlier, these results exceeded the first call consensus by about $0.20 per share.

Before I turn the call over to Dave, I want to conclude with a quick review of our financial position. We generated a free cash flow of $168 million in Q3, and as a result, we ended the quarter with $905 million of cash on hand and $1.9 billion of unused credit facilities. The reduction in net debt during the quarter, combined with the net earnings, brought our net debt to capitalization ratio down to 31%, or that's about 21% as we calculated under the terms of our bank credit agreements. So we continue to maintain a very strong balance sheet, with plenty of available resources, giving us significant financial flexibility.

So at this point, I'm going to turn the call over to Dave for an update on operations. Dave?

Thanks, John. Good morning. Our oil and gas properties continued to perform very well during the third quarter, and despite much lower activity levels, we delivered some very positive results. We invested $832 million of exploration and development capital in the third quarter, and ended September with 30 Devon operated rigs running. Total exploration and development capital for the first nine months was just under $3 billion.

During the third quarter, we drilled 233 wells, including 225 development wells and eight exploration wells. All but three of the development wells were successful, and three of the exploratory wells were successful. In the Barnett shale field in north Texas, we moved one rig to the Cana field in the third quarter, exiting the quarter with seven Devon operated rigs in the Barnett.

Devon's net production in the Barnett averaged 1.1 BCF equivalent per day for the quarter, 7% below the second quarter this year. This decrease is consistent with our reduced activity in the field and the decision to both reduce incremental compression and push completions back to late in the year, and as we reported in August, we expect to exit the year producing about one BCF equivalent per day from the Barnett net to Devon.

By the end of 2009, we expect to have drilled a total of about the 210 operated Barnett wells for the year. At September 30, we had 159 Barnett wells awaiting completion. In addition, we plan to drill 48 wells in the fourth quarter. By picking up completion activity late in the fourth quarter, we now expect to work that inventory down to approximately 150 wells awaiting completion by year end.

As Larry mentioned earlier we are ramping activity up going into 2010 on most of our major gas plays. We expect to have 16 operated rigs running in the Barnett as we enter 2010. In addition to the rig we moved from the Barnett to the Cana, we also recently moved one of our rigs from the Woodford shale in the Arcoma basin to the Cana play.

We have continued with a two operated rig program in the Arcoma Woodford and brought 13 additional wells online in the third quarter. Our net Arcoma Woodford production averaged 74 million cubic feet of gas equivalent per day for the third quarter, a 55% increase over the third quarter of 2008. Between now and year end, we will add three additional operated rigs as we prepare for increased activity in 2010.

Moving to the Cana Woodford shale in western Oklahoma, we increased our operated rig count to six during the third quarter, following the relocation of the rigs from the Barnett and Arcoma Woodford that I mentioned. The additional rigs in the Cana enable us to accelerate the process of derisking and securing the 109,000 acres we have in the play area.

We continue to see outstanding results from Cana, and believe the core Cana to be one of the most economic shale plays in North America. In the third quarter, we brought eight wells online, with average 24-hour IP rates of 6.5 million cubic feet equivalent per day. Production history from our 26 long lateral horizontal wells drilled in the core area of the play now support a tight curve approaching 10 BCF equivalent per well, including two BCF equivalent of NGLs. Third quarter net production from Cana averaged 53 million cubic feet of gas equivalent per day, more than seven times that of the third quarter of 2008, and up 55% on a sequential quarter basis. We plan to add an additional rig in Cana by year end.

Shifting to the Haynesville shale in east Texas, I will remind you that Devon has about 570,000 net acres in the greater Haynesville trend equally divided between Texas and Louisiana. More than a year ago, we began evaluating our position around Carthage, where we have 110,000 prospective net acres and over 1,800 conventional producing wells.

We continued our Haynesville derisking efforts in the are during the third quarter and brought our eighth well online. The Jernigan A4-H in Panola County achieved a 24-hour IP rate of eight million cubic feet per day, with numerous cores, 3-D seismic, geologic mapping and correlation with our wells drilled to date, we have now identified about 1,000 risked Haynesville drilling locations and four TCF of net risked resource potential to Devon in the greater Carthage area. We expect EURs in this part of the play to average roughly six BCF equivalent per well.

After drilling our eighth well in the greater Carthage area, we shifted our focus to derisking our 47,000 net acre position south of Carthage. This is primary term acreage located mostly in San Augustine and Sabine Counties in Texas and Sabine Parish in Louisiana. Our first Haynesville horizontal test of the area was drilled in the San Augustine County and yielded some very impressive results.

The Cardell 1-H achieved an average continuous 24-hour flow rate of 30.7 million cubic feet per day. We believe that this is the highest IP rate of any Haynesville shale well ever drilled. The well was drilled to a vertical depth of 13,850 feet, with a horizontal section of 4,500 feet. Devon operates the well with a 48% working interest. Although the Cardell well is our first in the area, it is a strong indicator of the potential of our southern Haynesville acreage.

In the fourth quarter, we will ramp up drilling activity in the Haynesville for a five-rig program for most of 2010. This additional activity, combined with our non-operated drilling activity, will enable us to begin securing our term acreage in the southern portion of the play. We estimate that about 105 wells will need to be drilled over the next two years for us to adequately secure the acreage we are derisking in the southern portion of the Haynesville.

Having drilled fewer than 10 Haynesville wells to date, we still have considerable work to do. We will continue to systematically derisk our position, just as we have done in the Barnett shale and are currently doing in the Cana Woodford.

Moving to the Permian Basin, it is worth noting that while our production mix is weighted in natural gas, we also have a deep portfolio of growth opportunities on the oil side. Our Wolfberry oil play in west Texas, where Devon has more than 98,000 net acres is one example. The Wolfberry is a repeatable play that generates outstanding rates of return with low geologic risk. With the current value proposition for oil versus gas, Wolfberry wells can have a positive impact on cash flow.

We currently have two rigs running and plan to add a third rig later this month. This will allow us to bring our 2009 drilling program up to 45 wells. We have significant running room into Wolfberry, with as many as 2,500 locations on an unrisked basis, for an estimated 1,100 risked locations.

Now shifting to the Gulf of Mexico, we continue appraisal and development work on our deep water discoveries in the lower tertiary trend in the third quarter. Our 50% owned Cascade Development Project is progressing well, and we are preparing to move the West [Serius] rig to Cascade this month to complete operations of the first of two producing wells. This well was drilled earlier in the year and encountered 500 feet of net pay. Construction of the FPSO is approximately 95% complete, and it should arrive in the Gulf of Mexico in January. The project remains on schedule for first production in mid-2010.

At Kaskida, we are drilling an appraisal well five miles west of the original discovery. This appraisal well would test a second structural feature on the Kaskida prospect, and has the potential to increase the size of a resource that we believe is already the largest of Devon's four lower tertiary discoveries. We said in our quarterly conference call in August that we expect to finish operations on the well in September. While drilling in the Wilcox section, we encountered an encouraging oil column and are now evaluating options to side track the well [bur] for further delineation information. Devon has a 30% working interest in Kaskida, and BP owns 70%.

Moving now to Canada, at our 100% Devon-owned Jackfish Thermal Oil Project in eastern Alberta, we completed two weeks of scheduled downtime for plant maintenance in the third quarter. To this end, we have steadily been ramping Jackfish production back up, sustaining a daily rate of 31,000 barrels per day. We remain on track to reach the facility capacity of 35,000 barrels a day before year end.

We continue to see outstanding well and reservoir performance at Jackfish. Our steamed oil ratios have improved to 2.4 ,and the cumulative ratio is below 3.0. This top-tier performance validates our front-end geologic work done to identify and delineate the high-quality Jackfish reservoir.

Based on the performance of Jackfish, we are excited about the Jackfish Two project. Jackfish Two construction is advancing on schedule, and is now over 50% complete. In July, we began drilling the initial well pairs. Like our Jackfish project, Jackfish Two is expect to produce 35,000 barrels per day and recover 300 million barrels. Jackfish Two remains on schedule first oil in late 2011.

Over the last couple of years, we have been in the process of evaluating the potential for a third phase of Jackfish development. This involves drilling a number of stratographic core wells, analyzing the cores, and performing a detailed geologic study to determine the location and quality of the reservoir. We have now completed this evaluation process, and will seek approval for the regulatory authorities and our Board of Directors for Jackfish Three.

This is a look-alike project to Jackfish One and Two, with 300 million barrels recoverable, and production capacity of 35,000 barrels per day. Pending regulatory approval and formal sanctioning, we would begin site work by late 2011, with plant startup targeted for 2014. Devon has a 100% working interest in each of the three Jackfish projects.

Shifting to the Horn River Basin in British Columbia, Devon has 153,000 net acres under lease. During the third quarter, we completed and tied in three horizontal wells from our 2008, 2009 winter drilling program. Initial production rates from these wells are averaging about 900,000 cubic feet of gas per day for each FRAC stage. This is consistent with the better wells drilled to date in the Horn River play.

Production history is limited, but early indications suggest first-year decline rates could be as low as 50%. With only three producing wells in the play, it is still in the early stages, but we are very encouraged with these result. Going forward, we will continue to fine-tune our completion techniques in order to achieve the best economics at Horn River. Over time, we expect to achieve drilling and completion costs of about $8 million per well, with average recoveries between seven and eight BCF per well. We will continue to derisk and secure our acreage with eight horizontal wells planned for 2010.

Finally, in Brazil in the third quarter, we wrapped up exploratory drilling on the Petrobras operated [Aracaju] prospect located on the block BM-BAR-1 in the Barreirinhas Basin. That well was unsuccessful and has been plugged and abandoned. The rig is now on location and just spud our [pre-salt Atypu] prospect, located block BMC-32 in the Campos basin. This prospect is 16 miles north of our Wahoo discovery and adjacent to Petrobras [Japarti] field and the pre-salt oil park discoveries. Devon will operate the well with a 40% interest.

We are also currently drilling an appraisal well to the Wahoo discovery on block BMC-30. Wahoo is operated by Anadarko and Devon has a 25% interest.

So in summary, the quarter brought very encouraging results from all of our major shale plays, and exciting news about the Jackfish project. We are now in the process of ramping up activity for a more robust drilling program in 2010. I'll now turn the call back over to Vince to open it up for Q&A.

Operator, we're ready for the first question.

(Operator Instructions) Your first question comes from the line of Ben Dell of Bernstein LLC. Please proceed.

Good morning.

Good morning Ben.

I just had one question. Obviously your debt to cap has come down significantly. It sounded, from your commentary, as if you are considering or looking at acquisitions. Did I get that I mean impression correctly, or is that incorrect?

Ben, this is Larry Nichols. I have no idea you got the notion we were looking at acquisitions. The debt is coming down, because the cash is building up with our oil revenues that are coming in. There's no change on our attitude toward acquisitions that we've had over the last five or six years. It's difficult to see any change in certainly, in a major transaction. We continue to look for small add-ons here are and there, that are consistent with our leasing position, but if you look at the acreage portfolio that we have around the Company, we are awash in opportunities and don't see any holes that we need to fill with any acquisitions, which is what we've said for a long time.

Okay. And just the second question, on the cost deflation side, obviously there's been a huge amount of cost deflation in the industry from service costs, drilling costs, [de-fracing] costs. Now that the service industry's earnings at [our] operating margin, it doesn't appear to be able to take those any lower, where do you see the real opportunities of continuing to drive down costs ?

I think the major opportunities we have, I think we are very effective when we have repeatable play types like we have in the shale plays, that we can continue to drive down the drilling cost by just continued improvement opportunities, and we've certainly done an outstanding job of that in the Barnett, decreasing the drilling time from 30 days to 15 days, in some cases even less than 10 days on these wells. We're continuing that type of activity also in the other shale plays, the Haynesville, the Cana, the Woodford, where we haven't drilled as many wells, we're continuing to drive down those costs and use the experience we had in the Barnett and import that to the other shale plays.

So I see that as probably the biggest opportunity we have. To add one point as well, you'll recall that, in 2009, we were essentially drilling with committed rigs that were not at the spot price, and we talked earlier about the fact that we had acquired and contracted for a lot of tubulars at the end of 2008, when tubulars were in short supply, and with our reduced program this year we are still working that off. So we ought to see a reduction in cost going forward just on that basis as well, in addition what Dave has said.

Okay, and just to clarify, can you confirm what percentage of your caps (inaudible) on well are actually day rate in drilling costs on, say, your Haynesville well?

He asked for a percentage. A percentage of the total. I think it's about 20%. About 20%, we're saying.

Okay. Great. Thank you.

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

Hi. Thank you, good morning everybody. A couple of questions. So on your [sales], I guess the hedging policy, are we going to see this get a little more aggressive as we move forward into 2010. Because I guess you have around about a third of your total production hedged. Just kind of outline how you're thinking about that right now.

Well Doug, we talked before, in the past, we tended to take the view that there are a lot of ways to manage risk, and we have managed that risk by keeping a very strong balance sheet and then remaining a low-cost operator. However, as we get into more plays that have a lot of momentum that you can't turn on and off regularly or easily, having a little larger hedge position is a good thing. I think you see we're already a little more active than we have been in the past, so as we go forward, we're going to monitor our view of prices, our view of capital costs, and our view of the industry direction carefully and make that call, but I think you could see us do it on a bit more regular basis.

Maybe I'm reading too much into it, John, but you're covered about a BCF a day for next year, and you're producing about a BCF a day from the Barnett, which is probably arguably one of your biggest decline issues in the Company. Is there any relationship between those two; is the implication that we're now going to stabilize and start to grow again in the Barnett.

No, not at all, Doug. As a matter of fact, we still, notwithstanding discussion around the Barnett, the Barnett is still a terrific play. We have almost 7,500 locations in the Barnett, and while we have seen a rollover in our production as a result of reduced activity levels, as we ramp up our activity levels, we're going to increase that production again, and we think there's a lot of running room for us there. So there's absolutely no correlation.

Okay. I'm going to guess that wasn't my follow-up, so if I could risk my follow-up. In the Cana, I don't think Dave mentioned anything by way of how much running room you might have there, obviously with the economics and the NGO portion and so on, I imagine that's screening well. What kind of activity levels can we expect, and what kind of location [light load] do you have there? If you could widen the discussion a little bit on the Cana, that would be great. Thanks.

Yes. We currently have 109,000 net acres in the play. The play is essentially lease stop. It's essentially held by two companies, ourselves and Cimarex.

When you look at it, we think that we have up to about 1,600 risk locations there, and we give it a total potential on the order of five to six TCF, and so you can see it's essentially a billion-barrel oil-field net to Devon. So it's a very substantial opportunity with very strong economics, particularly because of the liquids content.

What are those wells costing to drill, David?

On average, the most recent wells we've been drilling are on the order of around $8 million.

All right. And you think there's any down side to that, or is that pretty much as good as it gets?

We're always improving. So we have drilled a number of wells out there, but we're continuing to drive those costs down. So I wouldn't say there's a huge amount of improvement, but I think we'll continue to improve on that number.

Okay. I appreciate your comments. Thanks.

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

Thank you. Good morning.

Good morning.

When we look at your comment on Kaskida, I know you highlighted this has the potential to be resource additive. But because it was an appraisal well, can you perhaps add a little bit more color on what was encouraging about the oil column versus what might have been expected, and what you need to see to deem the result to be commercial?

Brian, obviously, BP is the operator here, and they've indicated that they don't want to do a release on this well until the operations are through. They have approved us to say what we've said. But when you consider that this well is something like five miles away from the discovery well at Kaskida and has a separate geographical feature, or a second high, just the fact that it's oil-charged is a very positive indicator to us, and when you ask why that is encouraging is that there were a couple of possibilities. One was that it was also oil charged and the other was that it was not. So the fact that is is full of oil we view as encouraging.

Great. Thank you. And secondly, on Cana Woodford, I think we may have discussed this in the past, but the 6.5 million cubic feet a day IPs compared to an EUR of 10 BCF a day, the IPs tend to be a little bit less relative to the UR versus other plays, and I wondered, given that it seems like some of the well results that you've drilled in the past as well as the IPs coming in are better than expected. If you can talk about the decline profile that you expect and what you're seeing?

Yes. And we have found that really we feel to maximize the EUR on the wells out here, that it's better from a completion standpoint to bring them on a little bit slower than we do some of our other plays to minimize the migration of finds and things like that. So we're just doing that from a prudency standpoint to maximize the EUR. You made a good observation on that, I agree, that the IPs are a little bit lower in relation to our other plays. But we're very confident that what we will have then are somewhat lower declines in the first year, because we're bringing them on at lower rates and we'll achieve the type of EURs that I described.

So I guess if you weren't, it seems like choking back the wells, what do you think they could be producing, or I guess the other side of the question is, how long can that 6.5 million a day rate be such as sustained before you do see it declining?

Well, you know, Brian, it's hard to say exactly. It would obviously be a little bit higher. The other thing is with these wells they have the other component that Dave was talking about of having that high liquids content. So that influences to some extent the way we bring them on as well. So I'm not sure that we have a good answer for what kind of a hypothetical IP would be if we opened up that choke a little faster.

Great. And, I guess, one last one, and I know you haven't put out official guidance for 2010, but how are you thinking about just overall growth when we think about the inventory that's scheduled to come on. Do you expect overall production, both oil and gas, to be up next year?

Oh, Brian you're asking us to get out in front of our forecast for next year, and we're in the process of finalizing our budget. We're not going to answer that specifically, but we do think Devon has the opportunity and the resources to be a long-term grower.

Thank you.

Your next question comes from the line of Joe Allman with JPMorgan. Please proceed.

Thank you. Good morning, everybody.

Hi, Joe.

In terms of the ramp-up in the shale plays, I know in the release you put out the other day, you said that the Haynesville, you're going to have a five-rig program in that southern part of east Texas. What's your intention elsewhere in east Texas, or in Louisiana in the Haynesville? And in the Barnett you have seven rigs running now. What's the plan for 2010, and any kind of estimate about what kind of production you might be seeing in the Barnett shale as you exit 2010 or go out to 2011 or any period in the future?

Yes. We do have the five-rig program in the Haynesville that's directed towards the primary term acreage in the southern part of the play. We also, as I mentioned, have a lot of opportunities in the greater Carthage area, on the order of 950 to 1,000 identified locations. We're evaluating whether we want to - - those are essentially held by production, so we don't have an urgency to move on those. So we're really finalizing our capital plans right now to decide how much if any rig activity we want to put on that versus focusing on the primary term acreage and securing that acreage.

In the Barnett, we do have seven rigs we're going to be ramping up to 16 by year end, and be having probably around 17 rigs working for most of next year. That's our currently plan in the Barnett. We think that with that level of activity, that, as John mentioned earlier, that we will not be declining the Barnett. It will be flat to starting to grow again in the Barnett with that level of activity.

And if you could just step back, industry-wide, I mean, do you think that Barnett has basically flattened out here, or do you think the whole play can grow based on your activity and the activity of others?

Well, I think it's hard for us to judge other people's position very well. I know that the bulk of our acreage is really located right in the core of the play, in Denton, Tarren, Johnson[wide], eastern part of Parker County, and so the vast majority of our acreage is located there. That's where the best wells have been drilled, and we still see that we have a lot of running room on that acreage, and we've look at maps comparing our position relative to other companies in that area. We can see that our well density is not nearly as great as others have. So I can't comment overall about other companies, but I do know that when we look and what we think is the best art of the play, we have a lot of running room to go.

Okay. Very helpful. Thank you.

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

Hey, guys. Regarding your recent Haynesville well in San Augustine County, can you give us a little color on the completion design of that well, and I also noticed that the choke size was about 3764, and that looks to be a little wider than other chokes. So if you could give some other detail on that as well.

Sure. It's about 2,000 feet deeper, so much of the Haynesville has been up in the Carthage area. So we're dealing with a little bit higher pressures, which, of course, helps out on the deliverability side. It gives you higher rates as well.

I know there have been some questions about this higher choke size. I think anybody with some engineering knowledge understands that what you're really trying to do here is to monitor, you're looking at the flowing casing pressure, and that's the most important thing. I can tell you that every time we increase the choke size, our production rate increased significantly, and our flowing pacing pressure remained very high.

The only reason we kept increasing the choke size is we're trying to get back some of the FRAC fluid. We've still only recovered 12% of the FRAC fluid as we speak, and so we're just trying to get the well to unload and we got a very high production rate. So I can tell you this is an extremely strong well. I wouldn't focus on the choke size. The more important thing is what kind of pressure are you flowing the well at, with this larger choke size, and I think you can see that our pressure of over 6800 psi is a very high pressure that we're flowing this well at.

And how many FRAC stages did you guys complete this well with?

I may be off, but I think it was about a 12-stage FRAC.

That's right, it was 12.

Okay. And then how has the production held up?

Well, we just increased it. And we hadn't shut the well in here briefly, because we go south, had a shut-in, we had a little bit higher than pipe-line spec on CO2. So we shut that in until we get some equipment modifications and then we'll be opening the well back up very soon.

Okay. And then moving to Horn River, can you guys mention the completion designs there and the activity level for 2010?

Yes. Our idea in the Horn River was that, what we were really focusing on is what kind of productivity we could get per FRAC stage. So we recognize that if we wanted to go out there and put a 10 or 12 stage FRAC, we could do that. But just didn't feel it was necessary at this point of the play to do that.

We recognize there is essentially a linear relationship, we believe, of about 0.9 million cubic feet per day per FRAC stage, and we proved that, so we put on the order of four to six FRAC stages on these wells, and we verified that ratio. And so we're comfortable, once we move into full development of the field, that we can increase the number of FRACS and get much higher rates, and then we'll optimize the trade-off between the cost of additional FRAC stages and the additional production you get the that. So that's all we were trying to prove with this year's activity, is that ratio held up, and it did.

Regarding future activity, we do have plans to use two rigs; we're going to drill about eight wells. Actually, after the breakup next summer, we'll be drilling about eight wells to just continue to evaluate our acreage, to hold the acreage that we have out there, although those are very long-term leases, and just increase our understanding. So this is a resource that, again, we talk about the Company being very opportunity-rich, and you can see, when you put together something like this, that we're not really pushing too hard at this point, but these results are certainly as good as anybody else is having out in the industry. We think we have a lot of future growth opportunity here.

Okay. Thanks. That's all I have.

Your next question comes from the line of Bob Morris of Citigroup. Please proceed.

Good morning.

Good morning, Bob. Welcome back.

Thank you. Larry, a question on your spending here. I noticed what you spent in the third quarter, and with all of the rigs you plan to add by year end. Can you tell us what sort of run rate that is on CapEx? In other words once you ramp up to that activity level that you're going to get to by all the rigs you're adding by year end, what sort of annualized CapEx rate is that?

I'm going to jump in here, Bob. This is Vince. We misspoke. We do not expect this ramp-up of activity in the fourth quarter to push us outside our previous guidance range. So we'll probably be near the top of our previous guidance, which is a little over $4 billion of EMP expenditures. The top end of the range was 4.1, and we still expect to be there for the full year.

Okay. Let me ask you, then, I know obviously your cash flow depends on commodity prices next year, but do you plan to spend within cash flow, or do you anticipate, or are you willing to supplement that with the proceeds from your lower tertiary sale, when you look at your capital budget for 2010?

Well, one of the reasons that we are doing the sale of the lower tertiary is to bring our sales back in line, as we said in past calls, so we're not spending as large a percentage in the gulf. We're spending more of it on our core on shore properties.

So we certainly do intend, as long as oil and gas prices continue the way that we think they will, to ramp up our spending in 2010. We haven't put out an official amount for that yet, because we haven't finalized the budget, because we want to get all of the data before we get there. But we certainly do intend to spend, and cash flow from lower tertiary is cash flow. Whether we use that for - - I imagine it is more likely we will use that for drilling activity, based on the assumption that we see the economy recovering and oil and gas prices, or oil prices continuing to be strong and gas prices continuing to improve.

Okay. The second question, on the Wilcox section you saw in the Kaskida appraisal well, did you expect that to be part of the continuous reservoir from the discovery well, or was that something that you anticipated might be fault separated, or I know BP is the operator. You can't say a whole lot . But in drilling that well, was it as you anticipated, or now that you're drilling a side track how did that differ from what you mapped out prior to doing

I think you just said the key phrase. BP is the operator of this. So we have an agreement on what we will say here and what we won't say. And so I don't know if I can add a whole lot more color to it than what we've already said other than that we have found an encouraging column, and again, it is five miles away, and it's essentially on a separate culmination from the original discovery well.

Okay. Thank you.

Your next question comes from the line of Joe Magner of Macquarie. Please proceed.

Good morning, thank you. I just wondering if you could - - I know there have been some questions around Kaskida, but just clarify the timing. Sounds like you have the information in hand to move ahead with the bid process, but there is comment made in the release that a side track is being considered. Is that something that will be pursued once the sell-down has closed, or how does that factor into your - - ?

No. We're actually completing the side track right now, and we anticipate - - it's at 30,000 feet, so you never know for sure, but we anticipate that this could probably take on the order of a couple of weeks or so to finish this side track. After that we will finish with the operations at Kaskida; we'll take the west [Serius] rig over to cascade to begin the completion operations there.

And so we think that once all of that information is given, then all of the data will be completed and available. The final data will be completed and available in the data room, including the side track. Everybody has seen everything except the side track already. And then we will be able to complete the sale process, which we said would be done by the end of December.

Okay, that's helpful. And then one quick question, I know you haven't completed the 2010 planning process yet, but at one point, up until the middle of 2008, Devon was talking about a five-year growth potential that was in the 7% to 9% range. Is that a range we can expect to see again now that you're more confident about the outlook and planning to ramp up development of some of your on shore plays?. If so, what sort of capital do you think will be required to drive that sort of annual growth going forward?

You know Joe, or Mark, there were some - - who am I speaking with?

Joe.

Excuse me. There were some price assumptions for oil and gas behind those forecasts, and our resource base has the potential to deliver that kind of growth and actually higher growth rates than 7%, and long-term, we live within cash flow. We have not been willing to shovel debt or equity out the door to support growth, and so it's highly dependent on the future of commodity prices. Everybody has a view on that; but assuming kind of strip pricing, I think you can expect Devon to move back into the high single digit growth rate over time.

Okay. Great. Last quick one on the Haynesville, what is your EUR expectations in that southern area, and then, with the deeper depths, what sort of completed well costs are you expecting, or did you have on that first well ?

Yes. It's a little bit hard to say what the EUR expectations are. We think up in the Carthage area, we're probably on the five to six BCF per well range, probably 5.5 to six, realistically. We obviously think it may be somewhat better down here, but again, we just brought this well online, and we have just such very limited production data that it is a little bit hard to say. So I would expect it would be a little higher than we're seeing to the north. But we just need to get more data to say for sure.

As far as the well costs go, we anticipate that future well costs in this order will probably be on the order of around $10 million or so. We spent a little more on this well because it was the first well we drilled down there. We did some extra work on this well. But we anticipate around $10 million going forward. Again, a little bit deeper, a little bit higher pressure, requires different casing design, et cetera, and that's why it's a little higher well cost.

Okay. Thank you.

Operator, we have time for one more question.

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

Thanks guys, good morning. Just a couple quick things if I could. Do you have a cost estimate yet for Jackfish Two?

Yes, we've said, Mark, that Jackfish Two is going to come in in the neighborhood of $1 billion US.

Okay.

So it continues, to, with the 300 million barrels, that continues to have obviously a very, very low F&D cost, and that's up a bit from where we were on Jackfish One, just with the cost inflation. But frankly, with the reduction in activity in the oil patch, and in particular, in the heavy oil sector in Canada, we're getting better services and being able to bring it in faster and within budget, and within schedule.

Okay, could you talk just for a second about what kind of facility sharing agreement regarding Cascade Chinook you have, and what that would mean in terms of your share of the facility production?

Mark, I don't have all those details in front of me. We do have obviously an arrangement to share the facilities. I believe it's on the order of a 50/50 sharing arrangement that we have with the Chinook development. And we basically have our half of around 85,000 BOE per day on the facility.

Okay, thanks. Just one more quick on if I could. Per your stats, there were, I guess, four unproductive wells drilled in the international arena, exploratory wells, in the quarter. Dave, you talked about one of them, what were the other three?

There were some very minor interest wells outside of our core areas that were actually counted in those stats, so I think actually a couple of wells that we never even talk about over in Russia that were included in those stats. The other area is the Angola wells. We also had some dry holes in the Angola wells in the Angola block that we have.

I might also mention, we're currently drilling an appraisal to our previous discovery in Angola, the [Chachonga] well over, and don't have results on that yet.

Just to remind you, we've got a 15% working interest in those wells, so that's why Dave said they're really low interest wells where we had the dry holes.

Thanks Dave.

That ends today's call. Thanks everybody for joining us.

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