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Devon Energy Corporation (NYSE:DVN)

Q4 2009 Earnings Call Transcript

February 17, 2010 11:00 am ET

Executives

Vince White – SVP, IR

Larry Nichols – Chairman and CEO

John Richels – President

Dave Hager – EVP, Exploration and Production

Darryl Smette – EVP, Marketing and Midstream

Analysts

Doug Leggate – Merrill Lynch

David Heikkinen – Tudor Pickering

Mark Gilman – Benchmark

Brian Singer – Goldman Sachs

Bob Morris – Citigroup

Robert Christensen – Buckingham Research Group

John Abbott [ph] – Richard Capital [ph]

Operator

Good day, ladies and gentlemen, and welcome to the Devon Energy’s fourth quarter and year-end 2009 earnings conference call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. This call is being recorded. At this time, I’d like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Vince White

Good morning, everyone, and welcome to our call. I’m going to start with – start the call with a few preliminary comments, and then turn it over to our Chairman and CEO, Larry Nichols. Larry’s going to provide an overview of 2009 and recap our reserves performance for the year. Following Larry’s remarks, our President, John Richels will review 2009 financial results and update our 2010 outlook. And then our Executive Vice President of Exploration and Production, Dave Hager, will cover fourth quarter operating highlights.

We’ll conclude the call in about an hour. So if we don’t get to your questions in the Q&A period, please feel free to follow-up with us later in the day. A replay of this call will be available later today through a link on our homepage. That’s www.devonenergy.com.

In November of 2009, we filed a Form 8-K with detailed guidance for 2010. During the call today, we’re going to update some of that guidance, and those updates will be posted to our Web site under the Estimates link in the Investor Relations area of the Web site. In addition, the 2009 Form 10-K, we expect to file that on February 26th, and it will reflect this updated guidance.

Before we get to the business of the call, we’re obligated to remind you that the discussion of our expectations, plans, forecasts, and estimates are all considered forward-looking statements under US Securities Law. And while we always make every effort to give you the very best data possible, there are many factors that could cause our actual results to differ from our estimates. For a discussion of those risk factors, please refer to our Form 8-K filed in November 16th, 2009.

One final compliance item, we will make reference today in the call the various non-GAAP performance measures. When we refer to these measures, we’re required to provide certain disclosures under Securities Law. If you would like to review those disclosures, they are also available on the Devon Web site.

Finally, I want to remind everyone that in November of 2009, we announced plans to divest all of our international and Gulf of Mexico assets. And as a result of these plans, accounting rules require our financial reporting to be somewhat illogical. The oil and gas production from the international operations that we are divesting are excluded for all periods presented, while the production from the Gulf of Mexico assets we are selling are included in our reported volumes and financials. Similarly, revenues, expenses for the international assets are collapsed into a single line item at the end of the statement of operations, and that line item is titled Discontinued Operations, while the revenues and expenses for the Gulf divestiture assets remain imbedded in our Continuing Operations.

In providing increased transparency in today’s press release, you’ll find additional tables that provide a detailed statement of operations as well as production and reserve data and cost incurred figures attributable to the operations classified as discontinued. And again, that’s only the international operations. Our comments today on the financial statements will generally conform to the presentation for continued operations. But when it’s practical, we will provide commentaries specifically targeting the North American onshore operations that represent the go-forward Devon.

The accounting treatment of the divestiture properties also muddies the water for Devon’s fourth quarter comparison to consensus estimates. We pulled the cell site analyst that report estimates the first call, and learned that about half the analysts included international operations, while the other half excluded the impact of these operations. The mean estimate for the analyst who included discontinued operations was $1.29 per share. This compares to our non-GAAP diluted earnings per share of $1.60 for the fourth quarter. The mean estimate for the analyst who excluded discontinued operations was $1.20 per share. And that figure compares to our adjusted earnings from continuing operations of $1.33 per diluted share.

The reconciling items are included in our press release today. In either case, with or without the contribution of our international assets, our fourth quarter results significantly exceeded expectations. With those items out of the way, I’m going to turn the call over to Devon’s CEO, Larry Nichols.

Larry Nichols

Thanks, Vince, and good morning, everyone. This year, 2010, is a transition for Devon. A very much of a transition year as we divest our onshore international assets, and refocused all of our efforts on Devon’s very powerful North American onshore growth engine. Our philosophy of focusing on optimizing returns and refusing to get caught up in that growth at any cause mentality is reflected in the very solid 2009 results that we reported today. We have achieved solid production growth while significantly reducing operating costs and delivering industry-leading finding and development costs.

Including the properties we are divesting, we increased company-wide oil and gas production to a record 682,000 Boe per day. Production from our North American onshore properties also grew to a record 603,000 Boe per day, which is up 6.5% over 2008 production. At the same time, we drove unit operating costs from those North American onshore operations from our continued operations down 14% to just $7.16 per equivalent Bo per barrel.

We generated $4.7 billion of cash flow from operations, funding most of our $5.1 billion in capital expenditures. With that capital, we drilled more than 1,100 successful wells, driving proved reserves to the highest level in our company’s history and delivering outstanding reserve replacement results. Our marketing and midstream business delivered yet another year of better than forecasted results reaching $512 million in operating profit. And finally, we maintained a very strong financial position, ending the year with a net debt to capitalization ratio of 29%, and unused credit lines and cash on hand totaling $2.8 billion.

In today’s news release, we provided a summary reserve report data for continuing operations in accordance with accounting standards. Although the results from those continuing operations are in press today, what I wanted to talk a little bit about are Devon’s North American onshore properties, which delivered even stronger reserve growth reflecting the strength of Devon’s property base going forward.

Drill-bit reserve additions from North American onshore, and by drill-bit I’m referring to discoveries, extensions, and performance revisions, came in 492 million Boe. These drill-bit additions were well over 200% of our 2009 onshore production. With drill-bit capital of $3.2 billion, including capitalized G&A and interest, our organic North American onshore finding and development costs were an industry-leading $6.59 per Boe. It is important to realize that one year F&D costs can be somewhat arbitrary because capital expenditures and reserved bucket are often misaligned. And we’re going to see that in 2008 and 2009.

In 2009, we expect North American onshore reserves to add a total of about 320 million Boe to 340 million Boe, with associated drill-bit capital of roughly $4.4 billion. This will give us F&D of a little over $13 per barrel for 2010. This variance comes primarily from the timing of bookings at reserves at Jackfish relative to the capital outlay. If you combine our 2009 results and our 2010 forecast, you’ll come up with an average F&D for those two years of a little over $9 a barrel. And we think this is more indicative of our go-forward expectations. And it’s still a number that will compare very favorably to our peer group.

Price revisions, again for North American onshore properties only, gave us a net positive boost in 2009 adding another $176 million barrels. Positive oil price related revisions, mainly coming from our Jackfish properties in Canada, more than offset negative gas price revisions. These results underscore the importance of having a reserve and production base with a balance between natural gas and liquids. In fact, oil and natural gas liquids made up more than 40% of our total North American onshore reserves at the end of 2009. While some of our peers now aspire to achieve this kind of liquid gas balance, Devon’s already there.

Looking at all sources F&D, in other words, including both drill-bit additions and net price revisions, we added 669 million Boe onshore in North America, which is more than three times our production, and it’s to the cost of $3.3 billion. As with drill-bit only F&D, our all sources F&D for 2009 is a little less than $5 of Boe, which is also industry-leading.

It is notable that Devon achieved these results without taking our proved undeveloped reserves to aggressive levels. While some companies have booked undeveloped reserves – prudent undeveloped reserves approaching 50%, and in fact in some cases even more than 50% of total reserves, Devon’s company-wide proved undeveloped reserves are only 30% of total proved. Likewise, pro forma for the divestitures, in other words, looking at only North American onshore, PUD is only 29% of total reserves. There have been a lot of talk recently about PUD additions as a result of SEC rule changes and the resulting impact on reported F&D cost. As a result, some analysts are computing F&D on a proved developed only basis, or in other words, excluding PUD reserves. Devon’s 2009 F&D on a proved developed basis is roughly $11.50 per Boe, again, very, very strong performance.

In summary, for our North American onshore, we added in 2009 $2.6 billion equivalent barrels of proved reserves, which represents 20% growth over year-end 2008 North American reserves. In fact, our year-end 2009 North American onshore reserves are almost 9% more than company-wide proved reserves at the end of 2008 including the assets that we’re divesting. Said another way, if we had sold all of our Gulf and international reserves at the very beginning of 2009, our activity in 2009 would not only have replaced the reserves that we sold and replaced our production for the year, but would also have given us growth for the company by 9%. That demonstrates the strength of our North American onshore portfolio. This result also increases Devon’s reserve life index to 12 years.

Before I turn the call over to John, I want to update you on the status of our Gulf and international divestitures. We announced our first step in December with our agreement to sell our interest in three of our prospects at Cascade, St. Malo, and Jack to Maersk. Subsequent to that announcement, partners in Cascade and St. Malo exercised their preferential rights. Maersk recently closed on the purchase of Jack as originally announced. This keeps the aggregate sale price for Devon’s interest in these projects at $1.3 billion or $1.1 billion after tax.

Because we prepared our 2010 capital budget on the assumption that we would own the divestiture assets for the full year, the sale of those three assets reduces our 2010 capital budget by some $400 million. We now have data rooms opened for all the international and all the deep-water Gulf of Mexico assets. And we’re in the process of preparing the remaining data room for our remaining Gulf properties. The level of interest is high. And we remain confident in the previously provided range of net after tax proceeds of $4.5 billion to $7.5 billion. We expect to receive the bids for all the assets by mid-year, and to close the sales throughout the year.

With that, I’ll turn the call over to John Richels for a financial review and outlook. John?

John Richels

Thank you, Larry, and good morning, everyone. Today, I’ll take you through a brief review of the key events and drivers that shaped our 2009 financial results, and also take you through our outlook for 2010. As Vince mentioned earlier, we have reclassified the assets, liabilities, and results of operations for our international assets into discontinued operations for all accounting periods presented. As a result, I’ll focus most of my comments on our reported continuing operations. And just to reiterate, our reported results from continuing operations include both the North American onshore assets that we are keeping and the Gulf of Mexico assets that we plan to divest.

Let’s with start production. Total 2009 company-wide production, including international, came in at $249 million equivalent barrels, or some $11 million Boe greater than our beginning of the year forecast. Looking at continuing operations alone, and again, under accounting rules that includes the production from the Gulf properties that we’re divesting, 2009 production was $233 million oil equivalent barrels or approximately 639,000 Boes per day. That’s 10 million barrels higher than our 2008 production from continuing operations, and more than 1 million barrels above the guidance we’ve provided in our most recent update.

When you examine just the North American onshore assets as the assets that we will be retaining in the repositioned company, you’ll see that 2009 production increased 36,600 equivalent barrels per day or about 6.5% over the full year 2008. This growth was achieved in spite the voluntarily reducing production in the second half of the year. The primary drivers of our onshore production growth in 2009 include our Jackfish SAGD Project as well as our Barnett, Cana, and Arkoma Woodford Shale plays.

Reported production was also supplemented by lower crown royalty rates in Canada. Fourth quarter production from continuing operations came in at 56.1 million equivalent barrels or approximately 609,000 barrels per day. This result was about 22,000 equivalent barrels per day lower than the third quarter of 2009. The decline is almost entirely attributable to the impact of reduced drilling during the year and the voluntary volume reductions that we announced in mid-2009.

In 2010, we expect production from continuing operations to range between 231 million and 235 million barrels. It's important to note that this estimate assumes that all of our producing Gulf of Mexico assets are sold on the last day of 2010. Since we actually expect to sell the properties throughout the year, we’ll provide updated guidance as we announce those sales.

Looking specifically at our retained asset base that’s the North American onshore region, we’re raising our production guidance to some 221 million equivalent barrels of production or about 2 million Boes more than we have previously forecasted. For the first quarter of 2010, we expect to produce between 55 million and 56 million barrels from continuing operations, including approximately 53 million barrels from our North American onshore portfolio. In response to higher activity levels, we expect to grow North American onshore production in each subsequent quarter of 2010. And beyond 2010, as we said when we’re announcing the repositioning, we expect to continue to deliver significant economic growth without the need to issue incremental debt or equity.

Moving to price realizations beginning with oil, in the fourth quarter of 2009, Devon’s oil price realizations came in at the top end of our guidance range at approximately 84% of WTI or $63.84 per barrel. Once again, Canadian realizations were above our expectations due to a favorable supply-demand balance for heavier Canadian crudes. Looking at full-year 2010, we have hedged 79,000 barrels of oil per day, and that’s about two-thirds of our expected oil production from continuing operations. We utilized callers for those hedges with an average floor of about $67 per barrel and a ceiling of about $96 per barrel.

On the natural gas side, the benchmark Henry Hub gas price improved to an average of $4.16 per Mcf during the fourth quarter. In addition to the higher indexed price, differentials for all of our major operating regions narrowed during the fourth quarter. Price realizations were especially strong for our Canadian gas production, averaging nearly 100% of Henry Hub. In total, our company-wide realized price, before the impact of hedges, came in at $3.80 per Mcf or 91% of Henry Hub. That’s a 34% increase in realized price over the last quarter.

For the fourth quarter cash settlements from the hedges, increased Devon’s company-wide realizations by $0.65 per Mcf to an all-in price including hedges of $4.45 per Mcf. We have approximately 1.4 Bcf per day of gas hedged throughout 2010 with swaps and callers protecting a weighted average floor of $6.12 per Mcf. In aggregate, our hedged position represents about 53% of our estimated natural gas production for the year. We also have a regional basis hedges on 150 million cubic feet a day of Canadian production and 70 million a day of Rockies gas. The average basis differential we locked in is $0.33 per MMBtu in Canada and $0.37 per MMBtu on the Rockies.

Turning to our marketing and midstream operations, driven by higher commodity prices and strong cost control, Devon’s fourth quarter operating profit climbed to $133 million and brought our full year marketing and midstream profit up to $512 million. Looking ahead to 2010, we expect another solid year with an expected full year operating profit of $450 million to $525 million.

Before we move into discussions of specific expenses, I just want to point out a change to the presentation of a few expense categories in our income statement. To bring us in line with most of our peers and to provide more clarity into our recurring operating cost trends, we’re now reporting ad valorem taxes for all periods presented on the new line item on the income statement entitled, “Taxes other than Income Taxes”. This new line item also contains production taxes and a few miscellaneous business taxes. Looking at that expense, which is the “Taxes other than Income Taxes” line that totaled $314 million in 2009. That’s a $162 million decrease when compared to 2009 results. This decline is entirely due to lower commodity prices throughout 2009 resulting in decreased production taxes. In the upcoming year, we expect “Taxes other than Income Taxes” to range between 4.5% and 5.5% of total oil, gas, and NGL revenues.

Turning to operating expenses, for 2009, our lease operating expenses came in at $1.7 billion or $7.16 per equivalent barrel produced. This represents the unit cost decrease of $1.13 per equivalent barrel or about 14%. The decrease reflects lower energy cost and downward price pressure for oilfield services and supplies. It’s really across the board. Looking forward, we expect 2010 LOE per Boe to be in the range of $7.50 to $8.15 per barrel of production. For our North American onshore assets, we expect 2010 LOE rates to be in the bottom half of that guidance range.

Devon’s full year 2009 DD&A expense for oil and gas properties totaled $1.8 billion or $7.86 per barrel. This result was within the guidance range we provided last November. For 2010, we anticipate our depletion rate to be between $7.60 and $8.10 per barrel of production.

Moving on to G&A expenditures, our reported G&A expense for 2009 came in at $648 million, which is essentially flat with 2008. Looking ahead, we expect to achieve additional efficiencies in 2010 reducing G&A costs by about $50 million. Our decision to sell our Gulf and international assets required us to recognize $153 million of restructuring expenses in the fourth quarter. Of this amount, $105 million was recorded on the expense line item titled “Restructuring Costs”, while the remaining $48 million of the restructuring expenses are included in the “Discontinued Operations” line. In 2010, we expect to recognize between $50 million and $120 million of additional restructuring charges.

Shifting to interest expense, interest expense for 2009 was $349 million, right in line with our expectations. For 2010, we expect interest expense to be roughly flat, somewhere between $325 million and $365 million.

The final expense item I want to touch on is income taxes. Devon’s reported income tax expense for the fourth quarter was 36% of pretax income. The most significant item affecting our tax rate during the quarter was the decision to divest our international assets. This event triggered the recognition of $55 million of additional income tax expense during the quarter. When you back out the impact of the non-recurring items, Devon’s adjusted fourth quarter tax rate came in at 29%, with 13% being current and 16% deferred. For 2010, we expect our total income tax rate to be roughly30%, split evenly between current and deferred taxes. In today’s news release we’ve provided a table that reconciles the effects of items that are typically excluded from analysts’ estimates.

Moving to the bottom line, fourth quarter earnings from continued operations adjusted for special items came in at $596 million or $1.33 per diluted share. If you include results from our discontinued operations, the total adjusted earnings for the quarter came to $1.60 per diluted share. This result exceeded last quarter’s earnings by 45%, and as Vince pointed already out earlier, far surpassed the street estimates.

For the full year 2009, Devon’s cash flow before balance sheet changes totaled $4.7 billion. We utilized this cash flow, along with cash-on-hand in short term borrowings, to fund $4.6 billion of drill-bit capital, and approximately $500 million corporate and midstream expense. We exited 2009 with $2.8 billion of cash on-hand and unused credit facilities. In addition to our strong liquidity, our balance sheet continues to improve and remains one of the strongest in the industry.

At December 31st, Devon’s net debt to capitalization ratio decreased to 29%. That’s actually about 21% as calculated under the terms of our bank credit agreement. Looking to 2010, we expect our overall balance sheet strength to improve even further as we begin to receive as we begin to receive proceeds from the asset sales. In order to sustain growth in production, reserves, and cash flow on a debt adjusted share basis, one must optimize results through the entire value chain. That means owning high quality assets at low entry cost, with reasonable royalty burdens while continually striving to drive costs from the system. Our 2009 results reflect the quality of our property portfolio and our focus on controlling costs.

At this point, I’m going to turn the call over to Dave Hager for an update on operations. Dave?

Dave Hager

Thanks, John, and good morning, everyone. Our growth in oil and gas reserves and production has already been covered in this call and reflects the outstanding results achieved with our 2009 capital budget. We drilled 1,130 wells onshore in North America, included 1,077 development wells and 53 exploration wells. Essentially, all of the development wells were successful, and all but a couple of exploratory wells were successful. 2009 capital expenditures for exploration and development projects from our North America onshore operations totaled $3 billion, including $840 million in the fourth quarter. To reach the $3.2 billion of drill-bit capital that Larry referred to, you would add capitalized G&A and interests to the EMP total.

From only 23 operated rigs running in late August, we gradually ramped up activity over the last four months of 2009, and we exited the year with 64 operated rigs running. We currently have 80 operated rigs running. On the oil side, at our 100% Devon-owned Jackfish thermal oil project in Eastern Alberta, our daily production reached 33,700 barrels per day in late December, a little shy of 35,000 barrels per day facility capacity. The contribution from four new in-fill well pairs that are currently steaming should allow us to hit the 35,000 barrel per day capacity in the near future. Jackfish continues to be one of the best performing SAGD projects in the industry as measured by both production for well and steam oil ratio.

Construction of our Jackfish 2 Project is now roughly two-thirds complete, with costs continuing to trend under budget. Jackfish 2 remains on schedule for first oil in 2011. Last quarter, we told you about our decision to move forward with our Jackfish 3 project. During the fourth quarter, we submitted a project summary document, the first step in the regulatory process. We anticipate filing the actual regulatory application in the third quarter of 2010. Pending regulatory approval and formal sanctioning, we could begin site work by late 2011 with plants startup targeted for 2014. Devon has a 100% working interest in each of the three Jackfish projects.

In our Lloydminster oil play in Alberta we drilled 75 new wells, which brought our full year total to 239. Lloydminster production average 41,000 barrels equivalent per day in the fourth quarter, up 5% from the third quarter. This activity maintained full year production from Lloydminster equal to that of 2008. In 2010, we plan to spend $82 million running a two-rig program and drill approximately 140 wells in the Lloydminster area to roughly maintain current production levels.

Moving to the Permian Basin and our Wolfberry oil play in West Texas, we have more than 140,000 prospective net acres. This play provides repeatable low risk, high return drilling opportunities. We currently have three rigs running, and plan to dill at 80 wells this year. We have significant running room here with more than 1,000 remained risk locations.

On the gas side of the business, we began ramping up activity in the Barnett Shale field in North Texas during the fourth quarter. And we’re currently running 16 Devon-operated rigs there. Our net production in the Barnett averaged just over one Bcf equivalent per day for the quarter. With our increased drilling activity and approximately 225 wells awaiting completion at year-end, we expect our Barnett production to gradually begin trending up.

As we showed you in our resource update in November, we have no shortage of drilling opportunities in the Barnett. We recently completed our 2,000th horizontal well on the Barnett, and yet we still over 7,000 remaining un-drilled locations on our acreage. In 2010, we plan to invest about $1 billion of capital in the Barnett drilling, drilling 350 operated wells and participating in about 20 non-operated wells. We plan to add one additional operated rig during the first quarter, taking us to a 17-rig program that we expect to maintain for most of the year. We expect Devon’s Barnett to be back up to its previous record production of 1.2 Bcf equivalent per day during the third quarter.

From a reserves performance perspective, the Barnett Shale was a leading growth area for the company again in 2009. Extensions, discoveries, and performance revisions in the Barnett accounted for 251 million Boe of additions, of which just 63 million barrels were related to the new SEC rule changes. These drill-bit additions replaced more than three times our Barnett production of 69 million equivalent barrels for the year. Related drill-bit capital was $820 million. At year-end, we had over six trillion cubic feet equivalent booked in the Barnett, with 78% developed and 22% proved undeveloped.

Moving to the Woodford Shale in Eastern Oklahoma’s Arkoma basin, we added three rigs in the fourth quarter, and now have a total of five operated rigs running. We brought five new operated wells on line during the quarter. Our net Arkoma-Woodford production averaged just over 70 million cubic feet per day for the fourth quarter. We plan to continue to grow production in the Arkoma-Woodford in 2010, investing $140 million of capital and drilling 51 operated wells. Our activity will focus on drilling 600 foot offset in-fill wells. Our technical evaluation of the Woodford continues to indicate that the optimum well configuration for maximum economic return calls for a lateral length of 4,000 to 5,000 feet. In the Cana-Woodford Shale in Western Oklahoma, we recently added about 9,000 net acres to our position, including 4,500 that we purchased through a bankruptcy proceeding.

Devon continues to be the largest risk holder in the play, now at 118,000 net acres. We added one rig during the fourth quarter, and are currently running seven operated rigs. We also plan to add two additional rigs in the second quarter. The additional rigs will allow us to further accelerate the process of de-risking and securing our acreage.

We continue to see outstanding results from Cana. In the fourth quarter, we brought six wells on line with average 24-hour IP rates of 4.7 million cubic feet equivalent per day. Production history from our 22 long lateral-horizontal wells drilled in the core of the play continued to improve, and now support a tight curve approaching 11 Bcf equivalent per well, including 3 Bcf equivalent of natural gas liquids. At roughly $8 million to drill and complete in light of our low royalty burden and cost of entry, these are some of the most economic shale wells in North America from a full-cycle return perspective.

We grew fourth quarter net production from Cana to 45 million cubic feet of gas equivalent per day, up 200% from the fourth quarter of 2008. We had a drill-bit reserve addition to Cana totaling 55 million Boe, with related drill-bit capital of $235 million. We increased total proved reserves in the play to almost one-half Tcf equivalent at year-end. With some 7 Tcf of risk resource potential, we expect many years of highly economic production and reserve growths from Cana. In 2010, we plan to invest about $300 million of capital and drill 43 operated Cana wells, and exit the year with Devon’s net production at over 100 million cubic feet equivalent per day. Construction will continue on our processing facility, which remains unscheduled for startup in early 2011.

Moving to the Haynesville Shale, in the fourth quarter, we drilled our first Haynesville well in the southern acreage in San Agustine County. As we announced in early November, the Kardell 1H well averaged a 24-hour continuous flow rate of 30.7 million cubic feet per day. After the first 90 days, the well has produced almost one Bcf equivalent, and is currently producing a little over three million cubic feet per day. Although the Kardell is experiencing high decline, keep in mind that this is our first well in our southern portion of the play.

On our Haynesville acreage in the greater Carthage area, we recently finished drilling operations on three wells in Shelby and Nacadoshous [ph] Counties. These three wells are currently being completed, and we expect to have results for you in the next quarter. This year, we plan to invest about $250 of capital to further de-risk primary term acreage in both the southern and greater Carthage areas. We will run a five-rig program, drilling approximately 24 operated wells with both Haynesville Shale and Bossier Shale targets. We are currently drilling our first two Bossier Shale wells, one on our southern acreage, and the other in the greater Carthage acreage. In addition, we will anticipate a numerous non-operated wells focused primary on our southern acreage where our working interests are much lower as a result of formation of drilling units with multiple partners.

Southwest of the Carthage area at Groesbeck, we’ve had a very successful development program over the last few years in the Nan-Su-Gail field. In the fourth quarter, we brought two high – two additional high rate Bossier sand horizontal wells on line at Nan-Su-Gail. The Patent Hill 2H [ph], high (inaudible) at 18 million cubic feet of gas a day, and the IBB6H [ph] high (inaudible) at 12 million a day.

Shifting to the Horne River Basin at Northern British Columbia, at a lease sale held this past December, we acquired an additional 17,000 net acres in the play, much of which is adjacent to our existing lease-hold position. This increases our total position in the play to approximately 170,000 net acres. We are running one rig in the Horne River, and plan to drill seven horizontal wells and four vertical strat wells in 2010. We also expect to complete four of those horizontal wells this summer, and expect to provide you with results later this year.

And finally, although we intend to sell our Brazil position, I’d like to update you on our most recent success there. In addition to our Wahoo discovery and successful appraisal well on block BMC 30, we also made a significant pre-salt find on block BMC 32 during the fourth quarter. As we announced in mid-December, the initial Itaipu discovery well, located approximately six miles southeast to the giant Jubarte Field, encountered at least 90 feet of net pre-salt pay with no oil water contact. We subsequently sidetracked the well to take a bypass core. This core is confirmed net light oil pay of 145 feet, significantly above the 90 feet we originally reported. Our preliminary mapping suggests Itaipu has up to 1 billion barrels of potential. Devon operates Itaipu with a 40% working interest. Addition appraisal work will provide more clarity, but early indications are very encouraging.

At this point I’m going to turn the call back over to Vince to open it up for Q&A.

Vince White

Thanks, Dave. Operator, we’re ready for the first question. I will remind everybody that we will ask you to limit your questions to one question and one follow-up per call.

Question-and-Answer Session

Operator

Yes, sir. (Operator Instructions). Your first question comes after the line of Doug Leggate of Merill Lynch. Please proceed.

Doug Leggate – Merrill Lynch

Well, thanks. Good morning everybody. The question really relates to what you’re going to do post the disposal program. If looking at our numbers, and arguably we’ve got a big oil price assumption for this year, will we see a lot of cash flow and obviously a lot of incoming cash from disposals. Can you just talk a little bit about – looking at your own asset base that are some major basins and some major place where you’re not involved. The Marcellus is probably one at the jump site. How are you thinking about potentially redeploying net cash and consolidation opportunities? That’s the broad first question, and I have a follow-up.

Larry Nichols

Well, this is Larry. As we said in previous calls, the reason for the sale of these assets is that we have reviewed our North American on-trail [ph] portfolio, all aspects of it. We see a lot of opportunities in every single one of those areas where we are, that can consume our cash flow for a long time to come. If you just look the number of unreal locations that we’ve already talked about proved or certainly de-risked under real locations, we have a lot of growth potential in the assets we already have. We’re always looking for new areas within that area to expand, both by leasing or supplemental small acquisitions of acreage. So there’s a lot of opportunity we see, both on the oil side and on the gas side, both on the shale gas in the US and in Canada as well as the heavy oil up in Canada. John, you want to – or Dave, you want to add anything?

John Richels

I have a whole lot of – yes, as Larry said, Doug, I think we have so much opportunity. While we always have to keep looking at new opportunities to supplement what we have, there’s no compelling reason to do that. If we see something that really fits very well, then we always need to look at that. That may mean that we take something else and push it out the backdoor, frankly, if it comes into our portfolio and competes better per capital. But as Larry said several times, we don't see any real holes in our asset base at this time. We have chosen not to move into the Marcellus because we have a lot of other opportunities to go to that specific question. But we know that not only with regard to the plays that we've already identified on our acreage, but we’re going to find a lot more opportunity on this huge asset base the we have that’s mostly held by production as we continue to look through all of horizons in our asset base.

Doug Leggate – Merrill Lynch

Perfect. Thanks, John. My follow-up is actually related to the disposal, the assets that you’re planning to dispose of. The capital program, John, you had given us some indication before as to what you’re expected allocation of capital to assets that were for sale would be. Could you update that number and maybe comment on whether or not you’re actually going to be able delay additional capital in places like Brazil given that obviously this things are for sale. Are you going to try to fill some of that and wait until bio-phase takes that over?

John Richels

All right. Just give me those numbers again. When we gave our guidance in November, we said that we’re going to spend about $1.5 billion on the properties that we were disposing. And that was about $600 million more than the revenues that were attributable to those properties at that time using the price deck. As Larry mentioned earlier, we sold the Cascade, St. Malo, and Jack. That accounts for about $400 million. So that’s about $1.1 billion that we’re going to spend on the disposal of properties – on distribution properties in 2010.

Now that’s not going to happen. We’ve done that. We’ve assumed, as I said earlier, that we're going to own this properties until the end of the year just – because we had to put a pin on a date somewhere. And that’s the only reasonable thing to assume. But as we go through the year, we will sell those properties, which will defray some of the additional capital costs. We’re not going to slow down our programs, frankly, on the properties that we have. We’ve got programs laid out. And we’re proceeding with them. And we’ll do that notwithstanding the fact that these are going to be sold.

Dave Hager

I might just add, particularly on Brazil, I think the activities we’ve been undertaking have been value adding. When you look, we’ve had a discovery at Wahoo. We’ve successfully appraised that discovery. We’ve had a new discovery recently at the Itaipu well, and we have some very exiting exploration prospects. We’re going to be drilling in block BMC 34 this year. So we think this is a capital that’s well spent and it’s just going to help out with the value of the assets.

Doug Leggate – Merrill Lynch

All right . Terrific. Thank you very much.

Operator

Your next question comes from the line of David Heikkinen of Tudor Pickering of Tudor Pickering. Please proceed.

David Heikkinen – Tudor Pickering

Good morning. You all disclosed your risk locations with the Wolfberry, Barnett, and Cana. And one of the things we’ve been trying to segregate is the number of locations that are booked as PUD interest locations. I’m just making sure that we’re not double counting. Can you go through the Wolfberry, the Barnett, and the Cana, and just disclose the number of PUDs that you have – PUD locations you have and then what the risk locations are, and if there’s any other areas that have high PUDs or risk locations that we ought to be thinking about with that as well?

Vince White

Dave, this is Vince. I’ve got some of the answers to the questions you’re asking. In the Barnett, we have – at 12/31/2009, we had 707 PUD locations booked. That compares to the north of 7,000 risk locations in the Barnett. And in the Cana, we had 68 PUD booked, compares to some 3,500 risk locations that we’ve identified in the Cana. In the Wolfberry, we estimate we have 1,100 risk locations. I think we’ve got very few PUD locations booked there, less than 20 is my recollection. I don't have the exact number in front of me. Was there another area you asked about?

David Heikkinen – Tudor Pickering

No. those are the primary ones. And just to make sure I’m comparing apples and apples of that acreage and locations, are those gross locations or are they net?

Vince White

Those are gross locations. Of course, in the Barnett, we can have very high working interests, and in the Cana and Wolfberry as well. All three of those places are high working interest plays, probably 80% or better.

Dave Hager

And Dave I might just add in the Barnett, for instance, so even though Vince said we have over 700 PUD locations, the PUDs are only 22% of the proved, and we have over 4,300 PDP locations booked there.

Vince White

Yes, we’re only – total proved reserves in the Barnett were only 22% PED at this point.

David Heikkinen – Tudor Pickering

Yes. You didn’t book very many PUDs as a relative ratio to the peers for sure. The other question just – since you hinted on BMC 34 additional exploration, can you just talk about the prospects from the timing, just so we will know what you’re doing there?

Dave Hager

Yes. We have a – in BMC 34, we plan to drill four wells this year. We have just – three of those wells will be post-salt wells, above the salt. And one of the wells will be a pre-salt well. We have just Spud the first of the post-salt wells called Itaipu and is currently drilling. And then we just have one rig down there. We're just going to be drilling those wells back to back. We may add a second rig to make sure that we get all of the wells drilled this year. We may add a second rig for some activity later in the year because we also would have some activity up in BMC 32 because obviously, we have a nice discovery there. But basically, it’s a four-well program throughout 2010.

David Heikkinen – Tudor Pickering

Those are commitment wells for the Bakken.

Vince White

Yes. Those are commitment wells, and we have a deadline facing in some time in January of 2011 to have those wells down. So that’s why we may add a second rig to make sure we get that done.

David Heikkinen – Tudor Pickering

Okay. Thank you.

Operator

Your next question comes – your next question comes – yes, sir?

Larry Nichols

No, go ahead with the next question.

Operator

All right. Your next question comes from the line of Mark Gilman of Benchmark. Please proceed.

Mark Gilman – Benchmark

Hi, guys. Good morning. Dave, I wonder if you could just address – and I’ve got a follow-up question afterwards. What kind of spacing the 2010 program the Barnett’s going to focus on?

Dave Hager

Well, the bulk of our locations are on 40-acre spacing. That’s where the 500-foot spacing, we call them, but they’re essentially 40-acre spacing. That’s where the bulk of them are located. We will have some that we’re doing on a 250-foot spacing or 20-acre spacing.

Mark Gilman – Benchmark

Okay. And then just shifting to a slightly different gear, I’m curious as to getting a better understanding of the logic in terms of carving out Cascade, Jack, and St. Malo in the divestment program. And I’m wondering in particular, does that imply that you did not receive as what you would consider to be an attractive and satisfactory offer for a much broader swap of the package, if not the entire offshore package in the US?

John Richels

Mark? Mark, it’s, John. That doesn’t imply anything. We had that data room open. And as you'll recall, we had some additional activities on Cascade that we’re continuing well into December. And so we have results coming in. We’ve made those results available to the folks that were in the data room. And so they were looking at that. And we got the bid from Maersk initially. I think it was early in December. So it was just – it just reflected the activity levels and the maturation of the programs on those assets. So we’ll just continue ahead now with the sale of Cascade in conjunction with our (inaudible) Maersk scene and all of the exploration blocks we have in both the (inaudible) and the Maersk scene.

Mark Gilman – Benchmark

Okay, John. Thank you.

Operator

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

Brian Singer – Goldman Sachs

Thank you. Good morning.

John Richels

Good morning, Brian.

Brian Singer – Goldman Sachs

I’m fully recognizing that I may have asked a similar the questioning on the previous calls. Can you talk more on the type curve and decline rates in the Cana-Woodford. Last quarter, I think, your wells had IPs of about 6.5 million a day, and you’ve got it to EURs of around 10 Bcfs. It seems like the wells drilled in the fourth quarter had slightly lowered at least initial IP rates. Do you feel more comfortable with the slightly higher EUR. What’s changing in the pressure tube, decline rate, and the new or existing wells that’s giving you more confidence in the EUR improvement? And if I could follow-up after that, thanks.

Dave Hager

Yes. It may not have been real clear for my prepared comments there. But we’re really talking about two different areas within Cana. The wells that we drilled in the most recent quarter were outside the core area. And so that’s one reason they – the IPs were a little bit less. The other reason is, frankly, that we tend to choke these wells back pretty good. We find that that leads to better EUR overall by not bringing those out-wells on at a high rate. So a combination of those two things, the fact that they were not located in the core, plus the fact we choke them back a little bit, why those IPs are a little bit less, the 11 Bcf equivalent per day that we’re talking about, per well – 11 Bcf per well as it relates specifically to the core area of Cana. Overall in Cana, we’re saying 8 Bcf equivalent per well for all of Cana.

John Richels

That’s the type curve brand that we presented in our November update. It’s the 8 Bcf type curve that we said was representative of our overall acreage position as opposed to the high liquid square area.

Brian Singer – Goldman Sachs

Great. Thanks. Your comments about choking I think are a good segue to the follow-up, which is with regards to the Haynesville where the initial well in San Augustine County, it looks like you’re really at the well fluid as fast as it could. How do you think about doing the benefits of tracing back the wells in Haynesville as you look to drill more in the next couple of quarters versus letting them flow all out and then seeing a higher decline rate? Did you think there’s any difference in the EUR and one strategy versus the other?

Dave Hager

The one thing, the comment there, I guess you’d say, we were not obviously going through any sort maximum IP rate for any reason. We were just – the well itself appeared to be capable with very little drawdown of a very high rate. What we're seeing obviously is the Haynesville down there is thinner. And so, although it had a very high initial rate that the overall EUR may not be as substantial as you might think from the initial rates. So it's not – I don't think it's clear at all that bringing the well on at a higher rate had anything to do with the ultimate EUR. It's just fact that the Haynesville is thinner down there.

Now, we are currently drilling two Bossier shale wells down there. The Bossier shale is thicker in this area. And obviously, you know there have been some very nice Bossier shale wells announced here recently. And so we're still optimistic for the overall area. So it's just – I think it's more of a product of the geology, really, rather than a strategy about how strong we bring those wells on.

Brian Singer – Goldman Sachs

Thank you.

Operator

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

Bob Morris – Citigroup

Good morning. My first question's on the Barnett. You mentioned that the uncompleted well inventory at year-end was 225, but at the end of the last quarter was 159, and the total number of wells you're going to drill for the year was 210. So it appeared you didn't complete any other wells that you drilled in the period in the Barnett. So first question is, is that true? And if not, then why was the uncompleted well inventory at 50% over what it was in the last quarter?

Dave Hager

Now that's essentially true. As we announced previously, we were curtailing our production in the last part of 2009. And so we've completed very few of our Barnett wells. And then we have now started completing those wells. And we're drawing down the completion inventory as we speak.

Bob Morris – Citigroup

Okay. Thank you. Second question was on the Haynesville, on the well that (inaudible) 30 million a day. And just overall on the Haynesville, what do you expect the EURs there to be now?

Dave Hager

Well, we're still learning on this southern area to be quite frank. So we've just drilled one well down there. We're going to have some additional wells that we're going to drill down there, as I mentioned, targeting the Bossier. So I think we'll know a lot more after a few wells and we – than we would know right now in the southern part of the play.

Now in the greater Carthage area, I think some very positive story that we're very confident in this greater Carthage area up in Panola and Shelby counties. So we'll be – have EURs on the order of 6 Bcf equivalent per well. And when you couple that with your uncompleted costs, around $8 million, we think that play is very economic. And we have a net resource potential up there of about 4 Bcf. And so we're very encouraged with about 1,000 locations up there. So we're very encouraged by the greater Carthage area up in Panola and Shelby counties. But we have a lot to learn yet, I think, as we go to the south. And so, we need to drill some more wells to see if that's where – how well that's going to work.

Bob Morris – Citigroup

Okay. Thank you.

Operator

Your next question comes from the line of Robert Christensen of Buckingham Research Group. Please proceed.

Robert Christensen – Buckingham Research Group

Can you update us on your plans for the South China Sea, the exploratory well in light of the three great discoveries that Husky had? Do you have an obligation to drill there before it's sold?

Dave Hager

Yes. We do have an obligation. That is part of the divestment program overall that we're doing with international. And we have been working on that divestment program. We don't have any announcement at this point. But obviously, there are – we have to well commitments essentially for this year. And we're working through that as part of the divestment process.

Robert Christensen – Buckingham Research Group

Do you have a rig in line to go drill them? Have you lined that up yet? I mean what's your thinking in terms of you building as opposed to someone just selling it to?

Dave Hager

Well, we have identified a rig that could potentially drill those wells. It depends a little bit on the purchase here and their plans. It can go into additional phase also and if they choose to do so. And so, we're talking through all those options with the potential purchasers of the assets.

Robert Christensen – Buckingham Research Group

Swinging back to the Barnett, I mean is there an easier solution as opposed to drilling more wells to resurrect production a little bit deeper with a series of maybe gas compression additions on your end? Or you've done that once before, I think pretty successfully where you picked up the horsepower to get more outlet? Is that cheaper? Will you do that?

Darryl Smette

This is Darryl Smette. Yes. You're right, Bob. We have, in the past, certain areas lowered compression increased deliverability out there, and that has been successful. Some places have been more successful than others. But in all of our places that's been successful. We continue to do some, I'd call it, pilot projects on some of these areas to see whether the costs will support increased productions. But we will continue to look at that as we continue to drill wells out there. And so that could be an option in the future. We'll continue to lower line pressure, both on our existing wells, but on some of the new wells, we're bringing on stream also.

Robert Christensen – Buckingham Research Group

On that (inaudible) question in the refract opportunities out there, I mean that was a big part of the Devon story a while back. Is that still – we should–

Vince White

Bob, I'm going to have to – a couple of follow-ups. We're going to have to move to the next caller.

Operator

Your next question comes from the line of John Abbott [ph] of Richard Capital [ph]. Please proceed.

John Abbott – Richard Capital

Yes. Hi. I was just curious on the follow-up to Brian's question. Did you mention on the Cana where well costs are and how many fracs you've – you're using per well at this point.

Dave Hager

Yes. The overall Cana well costs are on the order of about $8 million or so. Number of fracs, I don't think I have that data handy right here. If we go to another, maybe I'll come back and get it to you real quick. I don't have exactly how many fracs I have.

John Abbott – Richard Capital

And I guess if you looked at it on a relative basis, do you think that the Cana has the possibility to be as incremental from a rate or return or NTV [ph] standpoint? As for Barnett, do you think that Barnett's going to be better?

Dave Hager

We think that Cana is as strong, if not better than the Barnett from a rate of return. It's very strong, particularly in the area that has a high liquids content.

John Abbott – Richard Capital

Got it. Great.

Dave Hager

I just found that we're doing about nine frac stages here per well, so to answer your question.

John Abbott – Richard Capital

Superb. Thanks very much.

Dave Hager

Thank you.

Vince White

That ends the Q&A session. Do we have any closing remarks?

Larry Nichols

Yes. As we've discussed, 2010 is going to be something of a transition year with some confusing numbers with continuing or none – discontinued operations. But when you look through that, our 2009 results confirm that we have one of the best asset portfolios in North America onshore. And we expect to emerge from our repositioning in 2010 we have a very deep inventory of low risk growth opportunities and outstanding balance between natural gas and oil, one of the lowest overall cost structures in the industry, and extensive midstream business that allows us to capture additional capital, and one of the strongest balance sheets in our peer group.

With that, we believe that this positions Devon to deliver per share growth that is second to none, without the need for external financing for a long time to come. Thank you very much for the call.

Vince White

That ends today's call.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.

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Source: Devon Energy Corporation Q4 2009 Earnings Call Transcript
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