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Devon Energy Corp. (NYSE:DVN)

Q2 2007 Earnings Call

August 1, 2007 11:00 am ET

Executives

Larry Nichols - Chairman of the Board, Chief Executive Officer

John Richels - President, Director

Danny J. Heatly - Acting Chief Financial Officer, Chief Accounting Officer, Vice President - Accounting

Stephen J. Hadden - Senior Vice President - Exploration and Production

Vincent White - Vice President of Communications and Investor Relations

Analysts

Thomas Gardner - Simmons & Company

Ben Dell - Bernstein & Co.

Ray Deacon - BMO Capital Markets

Rehan Rashid - Friedman, Billings & Ramsey

John Herrlin - Merrill Lynch

David Heikkinen - Pickering Energy Partners

Mark Gilman - The Benchmark Company

TRANSCRIPT SPONSOR
Wall Street Breakfast

Operator

After the prepared remarks, we will conduct a question and answer session. (Operator Instructions) I’d like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Vince White

Thank you, operator. Good morning everyone and welcome to Devon’s second quarter 2007 conference call on web cast. I will begin with a few remarks and then our Chairman and CEO, Larry Nichols, will review the highlight of the quarter and bring you up to date on some of our recent initiatives. Following Larry’s remarks, Steve Hadden, he’s our senior Vice President of Exploration and Production, and he will cover the operating highlights. And then finally, Devon’s President, John Richels will conclude with a financial review. We’ll follow that with a Q and A session. As is our practice, we’ll try to hold the call to about an hour, so if we don’t get to your question, please give us a call this afternoon.

A replay of today’s call will be available later today through a link on devonenergy.com. We will also be posting to our website a new issue of Devon Direct. This is an electronic report that included highlights from the web cast and also includes links to additional supplementary information.

During the call today, we’re going to update some of the estimates for the year that are based on the actual results that we saw for the first six months of the year and our current outlook for the second half of the year.

In addition to the updates that we’re going to provide in today’s call, we’re going to file an A-K later today and that document will give all the details of our updated guidance.

Please note that in today’s call, we’ll talk about plans, forecasts, and estimates. These are all forward-looking statements under U.S. securities law. While we always strive to provide you the very best estimates possible, there are many factors that can cause our actual results to differ from these estimates. Because of these uncertainties, we encourage you to review the discussion of risk factors that we provide with our form A-K accompanying the forecast. One other compliance note. We will make reference today to certain non-GAAP performance measures. When we use these measures, we’re required to provide related disclosures and those disclosures are available on our website at devonenergy.com. We encourage you to review those disclosures.

Finally, I want to remind you that our decision to sell our assets in Africa and terminate of operations there triggered the accounting rules for discontinued operations. Under those rules, we exclude oil and gas produced from the divestiture assets from our report in production volumes for all periods presented. The related revenues and expenses for the discontinued operations are collapsed into a single line item at the end if our statement of operations. However, in today’s release we’re providing an additional table that gives you a detailed statement of operations as well as production items for the properties that we are divesting.

You will note that for the quarter we reported net earnings for the discontinued operations of $80 million. That’s in the second quarter. However, that does not mean that the discontinued operations would have generated earning of $80 million, had we not decided to sell them. The discrepancy occurs principally because the accounting rules require us to stop recording depletion on the sale properties once they are designated for divestiture. Has we not chosen to exit Africa, we would have had net income of associated with the divestiture properties of $50 million. Or $30 million less than the $80 million of income we reported from discontinued operations.

Discontinued operations also complicate the process of estimating earnings and that’s what we did last quarter. We polled the analysts that report their estimates the first call and determined that some had included African operations but this quarter, the majority excluded the impact of the African operations.

The mean estimate for the analysts that we contacted that included discontinued operations was $1.50 per share. This compares to our non-GAAP diluted earnings of $1.87 per share for the second quarter. The mean estimate from the analysts that we were able to contact that excluded discontinued operations was $1.45 per share and that compares to our non-GAAP earnings from discontinued operations of $1.73 per share.

So, any way you look at it, with or without the contribution of the second quarter was a blowout quarter. With those items out of the way, I’ll turn the call over to Larry.

Larry Nichols

(inaudible) is not usually inclined to such exuberant language, but it clearly was a terrific quarter that extends the momentum that we’ve been building for some time. We’re particularly pleased with the increase in production from continuing operations which was 16% better than the second quarter 2006, and 5% ahead of the first quarter 2007, demonstrating very solid organic growth. The second quarter of 2007 was our fifth consecutive quarter of production growth, and about 300 million barrels in our target for the quarter. There are several reasons for this out performance, they’re really across the board of our portfolio, and later in this call John Richels will explain those reasons and give a production outlook for the remaining two quarters.

With regard to our second quarter financial results, they were also very strong. As Vince described, the second quarter earnings and the earnings per share came in better than analysts expectations. If you look at the numbers that Vince just gave you, whether you exclude or include discontinued operations, our earnings exceeded the estimates of analysts by 19%, and they were also the second highest quarterly earnings per share in Devon’s history.

The cash flow before balance sheet changes was a record $1.8 billion, bringing the year-to-date total to $3.3 billion. Importantly, the 56.2 million equivalent barrels that we’ve produced in the second quarter puts us well on the way to producing at the upper end of our full year 2007 forecasts of 219-220 million BOE from continuing operations. That would be more than a 10% growth for 2007 over 2006.

We’re very pleased about our performance at this halfway point in the year, and remain confident in the continued success for our long-term growth strategy that combines our predictable near term developmental projects with the higher impact longer-term growth opportunities that we’ve been building.

Now concerning our Africa divesture program, I’ll give you a brief status update on that. We expect to close the sale of our Egyptian operations near the end of August. This is the transaction with Dana Petroleum that we announced earlier in the second quarter. The sales price was $375 million, which includes $67 million working capital. That works out to about $38.50 per barrel of crude reserves so we’re pleased with that transaction.

The West Africa divestiture program began a few months later than the Egyptian program. The interest level has been quite high, and we have received more than 30 bids on those assets. As we expected we received bids for various combinations of properties, and we’re still in the process of determining the most favorable combination of bids. And we will not announce those sales until we’ve actually signed the purchase and sale agreements in hand.

One element of our growth strategy over time has always been to regularly evaluate our property portfolio and make changes when necessary to realize the greatest value from our broad set of opportunities. That decision to divest our operations in Africa and re-deploy the people and capital to other projects is of course a result of that evaluation.

As we said when we announced the divestiture plans, in addition to funding our capital spending program, we expect to use the proceeds to repay commercial paper balances, and to resume share repurchase program that was suspended last year when we made the acquisition of the chief Barnett Shale properties. This repurchase program is in addition to the recently announced 10b5 share repurchase plan that is intended to offset to the dilution of option exercises, and grants a restricted stock.

Finally I want to mention an announcement we made a week or so ago, on July 18, concerning the creation of a marketing and midstream Master Limited Partnership. Under the SEC’s pre-registration rules, which are known as the “gun-jumping” rules, we’re not allowed to provide any new information on that project that was not already included in our news release. To recap that news release, we plan to form an MLP that will initially own a minority interest in Devon's U.S. onshore marketing and midstream business. The purpose of creating the MLP is of course to allow the marketplace to establish an independent value for our midstream business that is currently embedded in Devon’s overall corporate evaluations. A Devon subsidiary will serve as the general partner of the MLP, and Devon will own a majority interest following the initial public offering. Because of the gun-jumping rules, we request that you refrain from asking any questions about the MLP today.

A Devon subsidiary will serve as the general partner of the MLP and Devon will own a majority interest on the initial public offering. Because of the rules we will request that you refrain from asking any questions about the MLP today. Registration should provide you with most of the answers when it becomes available.

With that I will turn it over to Steve Hadden who will give you a more in-depth review of the exploration and production operations, Steve.

Stephen Hadden

Thanks Larry and good morning to everyone. We had an active second quarter drilling 434 wells company-wide. 14 of these wells were classified as exploration of which 79% were successful. The remaining 420 were development wells and about 99% of those were successful. We had 141 rigs drilling in June of which 88 were drilling Devon operated wells.

Capital expenditures for explorations and development on our routine properties, and this excludes operations in Africa, were $1.2 billion in the quarter. This brought total exploration and development capital for the first six months to $2.5 billion.

Now let’s move to the quarterly operational highlights beginning with the Barnett Shale field in North Texas where we continue to enjoy excellent success in production growth ahead of our plans. We are currently running 30 Devon operated rigs of which 13 are in the core area and 17 are drilling outside the core, including 11 in Johnson County.

During the second quarter we completed a total of 147 Barnett wells of which 56 were in the core area and 91 outside the core. At the current pace we would drill about 500 wells in the Barnett Shale this year compared with our previous forecast of 385 wells. With this additional activity, we expect company-wide exploration and development capital to come in at the upper end of our forecast range of $4.9 billion - $5.3 billion.

From an execution perspective, the new more automated rigs are enabling us to buck the trend and reduce drilling costs in the Barnett. Average drilling costs have decreased in 2007 versus 2006. This is largely due to a 10% decline in average drilling days per well down from 18.3 days in 2006 to 16.5 days in 2007. This is saving us about $190,000 per well in drilling costs and helping offset higher completion and fracturing costs and is holding our total well costs flat year-over-year in the Barnett.

We continue to see solid results from Johnson County where during the second quarter we put 24 new wells on line at an average rate of about 3.1 million cubic feet a day. 2 particularly strong wells in Johnson County each had 24 hours sustained initial production rates in excess of 5 million cubic feet a day.

In addition, we bought 17 new horizontal wells online in portions of Southwestern Tarrant and Southeastern Parker Counties at an average rate of about 1.8 million cubic feet a day.

We also continue to see solid economic results from our core area 20-acre infill-drilling program. Through the end of the second quarter we’ve completed a total of 128 infill wells, a 105 of which were horizontal. A total of 124 infill wells have been connected to the production grid and 101 of those are horizontal that came on line at an average rate of 2.1million cubic feet a day.

Our net Barnett Shale production averaged a record 797 million cubic feet of gas per day in the second quarter. The second quarter average was up 9% from the first quarter and up 37% compared with the second quarter of 2006.

We previously announced a target rate of 800 million cubic feet a day by year-end 2007. Having essentially reached that target already we have revised our year-end expectations to 857 million cubic feet equivalent per day.

We also set a long-term target of 1 Bcf per day by the end of 2009. Given our progress to date we’d expect to set a more aggressive target when we update our long-term projections later this year.

Because the Barnett Shale was so dominant we seldom highlight our conventional gas operations in Fort Worth Basin. However, in the second quarter we also increased conventional Fort Worth Basin production by 7% compared to the second quarter of 2006 to 70 million cubic feet a day.

Moving onto the Wood ford Shale in Eastern Oklahoma we currently have five operated rigs drilling in the play. We bought a total of seven new operated wells online during the second quarter with individual well production rates as high as 4 million cubic feet of gas per day bringing our total operated well count to 38. (Eddings) gross operated production was about 35 million cubic feet a day from the field. Our total net Wood ford Shale production averaged over 16 million cubic feet of gas a day in the second quarter and we plan to grow that volume to between 25 and 30 million cubic feet a day by year-end. We believe that Devon’s network resource potential in the Wood ford could be as much as 1 Bcf.

To accommodate our growth and that of others in the area, we are constructing a $30 million gas processing plant located about 20 miles west of McAllister, Oklahoma. The plant will have the capacity to process up to 200 million cubic feet in natural gas per day and produce about 18,000 barrels a day of natural gas liquids. The plant is scheduled to be operational in May of 2008.

Shifting to east Texas, we continue with a seven-rig vertical cotton valley drilling program in the Carthage area. In the second quarter we drilled 22 vertical wells and continued an active recompilation program. At the end of the quarter we were drilling the 44th well in the 88th well vertical program we have planned for this year. We also continue to have success with our horizontal drilling program in the Carthage area. We added a third horizontal rig during the second quarter and drilled two new wells, including our first cotton valley horizontal in the central part of the Carthage field. The 98% working interest Hancock 15H well averaged 6.7 million cubic feet in gas a day for the first 30 days of production. Two additional cotton valley sand wells were drilled during the quarter and are awaiting completion. In total, we expect to drill 15 horizontal wells in Carthage this year.

Our net Carthage production averaged 249 million cubic feet of gas equivalent per day in the second quarter, up 7% from the first quarter and up 6% from a year ago. Also in east Texas, we continue to peruse to horizontal drilling program in the Gross-Back area. However we scaled back this year’s plans from 22 wells to 17wells.

The reservoir performance we’ve seen from the wells in this area is very encouraging, but the drilling and completion options we’re evaluating are very complex and we’re working towards refining our approach before moving into full development in the area. This is very similar to our approach that we have taken in the non-core baronage hail where we thoroughly evaluated our position before moving into wide scaled development. We still believe we have as many as 200 potential horizontal drilling locations in the Gross-Back area.

Moving to the Rockies and the Powder River Base and then in Wyoming, we have eight rigs currently running including four Devon operating rigs drilling in the big George formation in the West Pine Tree and Juniper Draw areas. We expect to drill more than 200 new wells by year- end.

Our net-powder river production averaged 61 million cubic feet of gas per day in the second quarter, up 9% from the first quarter average and up 11% compared with the second quarter of 2006. We expect to exit 2007 producing over 70 million cubic feet a day and ultimately expect to bring Powder River Productions to more than 100 million cubic feel per day in late 2008.

Now shifting to the Gulf of Mexico, we are pleased with our continued progress in the quarter end in our deepwater lower area trend. First, at our 2006 discovery called Cascada, the MMS approved expansion of the Cascada unit to the west with the addition of Keytha Canyon blocks 244 and 245 in June. As a result the Keytha Canyon 244 number one well, previously known as the Cortez Bank prospect, was included in the unit. The well, some 12 miles away from the discovery well, sits in 5500 feet of water and is currently drilling below 30,000 feet. SQ is operated by BP and Devon has a 20% working interest.

The second lower tertiary well we are drilling is on our Chuck Prospect located in Walker Ridge 278. This exploratory well targets a large sub-salt structure in about 6500 feet of water. The wells currently drilling below 8000 feet with the ocean endeavor, the deep water-drilling rig that we have under long-term contract. Devon is the operative chuck with 39½% working interest.

Also in our lower tertiary exploration program during the second quarter we completed an agreement to acquire 23% interest in the Green Bay Prospect located on Walker Ridge 372, approximately 20 miles north of St. Mallow discovery and about 18 miles east of our Chuck Prospect. This are has seen many lower tertiary discoveries to date and we expect to begin drilling an exploratory well on Green Bay Prospect in the fourth quarter.

Our Gulf team continues to work with our partners towards the commercial development decisions on each of our lower tertiary discoveries. At Cascade, our 50% working interest project with Petra Bross in the Walker Ridge area, we expect to sanction the project and award FPSO and development contracts later this year.

And Jack, also in the Walker Ridge deep water lease area Devon and our co-owners are preparing to initiate drilling on a second delineation well, the Jack number three, later this year, with the results expected in early 2008. The well will be operated by Devon and drilled with the ocean endeavor when drilling is complete on the Jack exploratory well. The co-owners are evaluating various development options for Jack and Devon has a 25% working interest in that prospect.

And finally in St. Mallow, also in the Walker Ridge deep-water area we expect to drill delineation well during the fourth quarter. We have a 22½% working interest in St. Mallow.

In the eastern Gulf of Mexico the Marganza field was ready for production to the independent’s hub in the second quarter. Devon has a 50% interest in the two Marganza wells, which should commence production later this month. We expect our share of production to be about 50 million cubic feet of natural gas per day. Shipping to the Gulf of Mexico to -- on the shelf, again this quarter we had success in both exploration and development projects. We've made a discovery at our lime prospect on Eugene Island 354; the well was drilled to about 10,600 feet and penetrated the Atlantic sands where we found approximately 140 feet of net pay. We expect to bring the lime discovery on line in the third quarter at an expected rate of about 8 million cubic feet of natural gas per day. Devon has a 50% working interest in this discovery.

On the development side, we drilled a third offset to our very successful 2005 Chopin discovery. The B-12 development well located on Eugene Island 333 was completed in June and came on line at 25 million cubic feet of natural gas per day. All four wells are currently producing at a combined rate of 75 million cubic feet of natural gas per day, and Devon has 100% working interest in the four wells.

Our Gulf team now has largely completed the planned 2007 shelf capital program with 100% success rate, a job very well done.

Moving north to Canada, we drilled just 63 wells in Canada in the second quarter due in part to the extremely rainy spring. The wet and muddy conditions delayed our drilling in the first two months of the quarter at our Lloyd Minister Oil Play in eastern Alberta. However in June we ramped activity back up to five rigs, and were able to drill 36 wells in Lloyd Minister. We plan to maintain a five-rig program for the remainder of 2007.

Our net production from the Lloyd Minister area averaged 33,000 barrels of oil a day in the second quarter, up 48% when compared with the second quarter of 2006. We’ve also begun to prepare for our next expansion of the Mannetoken plant. An additional 10,000 barrels a day of processing capacity will be added to bring our total processing capacity at the facility to 27,500 barrels a day in anticipation of our growing oil volumes.

At our 100% Devon owned Jackfish Heavy Oil Project in eastern Alberta pre-commissioning activities were completed in June, and was achieved on July 16. As we've indicated before, we expect production from Jackfish to begin around the end of this year. Production will then ramp up to a suspected sustainable rate of 35,000 barrels a day by the end of 2008.

At our Jackfish 2 Project, engineering and budgeting work continues and we expect to receive regulatory approval around mid 2008. At that point we expect to make a formal decision about the project. Jackfish 2 would essentially double the size of the Jackfish Project, adding another 35,000 barrels a day of oil production.

Moving to the international arena, development drilling on the Devon operated Palvo oil project on DNC8 in n Brazil continued during the second quarter. As we announced on Monday, we have now begun producing into the FPSO from the first of ten development wells. The additional wells will be drilled and tied in throughout the remainder of this year and into 2008 as we ramp our production up to 26,000 barrels a day net to Devon's 60% working interest.

Now to [Abidjan], where Devon has a 5.6% in the ACG oil filed, gross oil production exceeded 750,000 barrels of oil a day in early May. Devon's share of ACG production averaged more than 40,000 barrels a day in the second quarter. This was above forecasts because of favorable timings of [lithnics]. We do not expect that situation to repeat in the third quarter, in fact we expect two to three weeks of planned down-time at ACG in September to tie in new facilities and do some maintenance work.

And finally, in China, we will be replacing the production riser at the Panyu field during the third quarter. Accordingly we anticipate up to two weeks of downtime at the Panyu Field. This work was originally scheduled for the second quarter, but was delayed awaiting delivery of the replacement equipment. In summary, the second quarter delivered strong operational results, demonstrated good organic growth, and advanced our high impact projects, adding both near term and long-term value. Now, I'll turn the call over to John Richels, to review our financial results for the second quarter.

John.

John Richels

Thanks Steve, and Good Morning. This morning I want to take you through a brief preview of the key drivers that impacted our second quarter financial results. In addition, I will review with you how these factors are likely to affect our outlook for the remainder of the year. Events mentioned, we're issuing an 8k today, will provide further details of our updated 2007 forecast. As a reminder, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. As a result, I'll focus my comments on our continuing operations, which exclude the results attributable to Africa.

Let's begin with production. In the second quarter we produced 56.2 million equivalent barrels for approximately 618,000 barrels per day. These results exceeded our guidance by over three million barrels or about 6%. Approximately half of three million barrel out-performance is attributed to better than expected performance from our core North American properties. The other half of the out-performance is attributable to favorable royalty adjustments in Canada, the timing of oil sales from the ACG field in Azerbaijan, and the rescheduling of expected downtime at our Panyu project in China.

When you compare second quarter results of the same quarter a year ago, you’ll find that company-wide production increased by 84,000 barrels per day or roughly 16%. This strong year-over-year growth was driven primarily by our U.S. onshore and international segments.

Production by the U.S. onshore grew by over 40,000 barrels per day, or 15%. When compared to the second quarter of last year, once again the leading contributor to our U.S. onshore performance was grossed in the Barnett Shell production. In addition we also experienced significant growth from our international sector, up nearly 45,000 barrels per day over the same quarter last year.

This was primarily attributable to the ACG field in Azerbaijan. In Canada, despite significantly scaling back conventional gas drilling activity, second quarter production remained relatively flat year-over-year, and actually increased by 4% over the first quarter of 2007.

We had strong performance from our Lloyd Minster area projects and net performance was also aided by reduced royalties.

Based on first half results, we expect production to come in at the top end of our full year 2007 forecast range of 219-221 million oil equivalent barrels. Looking to the second half, we expect our productions to total approximately 55 million barrels in the third quarter, and 57 million barrels in the fourth.

Third quarter estimate reflects a slight decrease in production from second quarter. This is driven by the timing of oil sales and the scheduled field downtime in Azerbaijan, as Steve mentioned. Also, it reflects scheduled downtime for the equipment replacement in China and an anticipated drop in production from Canada.

Fourth quarter growth will be fueled by our U.S. onshore properties and the ramped up production from the Mergancer field in the deepwater gulf, and the Palvo field, offshore Brazil.

Moving on the price realizations and starting with oil. In the second quarter, the benchmark WTI oil price averaged $65.08 that was 8% below the second quarter of 2006, but a 12% increase from the first quarter of 2007. In addition to the strong oil price environment this year, regional differentials narrowed and price realizations in virtually all of our producing regions were in or above the top half of our guidance range.

The leading driver of our higher oil price realizations was the robust international oil market and this is reflected in the premium pricing that we received for our light, sweet oil in Azerbaijan. As a result, our company-wide price realizations rose to 92% of WTI, or $60.01 per barrel for the quarter. That’s a 15% improvement in realized pricing when compared to the first quarter 2007.

We will be updating our full year oil price differential guidance in today’s AK to reflect the improvements in pricing.

On the natural gas side, the benchmark Henry Hub index averaged $7.55 per MCF in the second quarter. And this was 11% higher than in the second quarter of 2006 and 12% higher than the first quarter of 2007.

Our company-wide gas price realizations came in near the midpoint of our guidance at approximately 86% of Henry Hub. Price realizations remain strong in Canada and in the Gulf of Mexico. However, this regional strength was offset by weak gas price realizations in the Rocky Mountains. As many of you know, price differentials in the Rockies, have widened significantly over the past few months due to increased productions and constrained take-away capacity.

As a result of this short-term issue, we continue to expect soft pricing to persist in the Rockies for the remainder of 2007.

Looking into the third quarter, we now expect natural gas price realizations to approximate 100% of NYMEX to the Gulf, 80% of NYMEX to the U.S. onshore, and 90% of NYMEX for Canada. Updates to our full year differential guidance will be provided in today’s A-K.

Turning now to our marketing and midstream business, in addition to the terrific upstream performance in the second quarter, Devon’s marketing and midstream operation once again delivered impressive results.

Marketing and midstream operating profit for the second quarter totaled $119 million that was $14 million greater than the second quarter of 2006 and $10 million sequential quarterly increase. This solid performance was driven by increased gas processing revenues combined with higher natural gas pipeline throughput. Based on our strong showing in the first half of the year we now expect our marketing and midstream full year operating profit to come in between $420 million and $460 million, which represents an increase of $30 million from our previous guidance.

Moving to expenses, second quarter lease operating expenses was near the midpoint of our guidance coming in at $439 million or $7.81 per barrel produced. Unit LOE costs were 4% lower than the $8.13 per barrel we reported in the first quarter of 2007. However, we still anticipate a rise in LOE during the second half of the year. This increase will be driven by scheduled maintenance in our international and Canadian operating regions along with higher unit costs incurred while our new development projects ramp up production. We now expect our full year lease operating expense to be in the range of $8.00 and $8.30 per equivalent barrel.

Our second quarter DD&A expense for Oil and Gas properties came in within our guidance range at $11.48 per barrel. Looking forward we expect our third and fourth quarter DD&A rates to rise to between $11.50 and $12.25 per equivalent barrel. Based on this we are now forecasting our full year 2007 DD&A rate to come in between $11.40 and $11.80 per equivalent barrel.

Moving onto G&A expense, G&A expense for the second quarter was $113 million right in line with our guidance and $6 million less spend than the previous quarter of this year. At this time we are not making any changes to our full year G&A guidance range of $460 - $480 million.

Second quarter interest expense came in at $107 million right in line with our expectations. Of total interest expense for the quarter $20 million was related to commercial paper balances, which we expect to pay down following the close of the African divestitures. As Larry mentioned earlier we expect to close the sale of Egypt during the third quarter and we’re expecting to close on the West African sale near year- end. Based on these expectations and the related timing of commercial paper balances we now expect full year 2007 interest expense to be in the range of $430-$440 million.

The final expense item that I want to touch on is income taxes. Income tax expense for the second quarter came in at 29% of pretax income. When you back out the impact of items that are generally excluded from analyst’s estimates, you get an adjusted current tax rate of 15% and a differed tax rate of 16% for a total income tax rate of 31%. We remain comfortable with our full year guidance ranges for income taxes. In today’s earnings release we provided a table that reconciles the tax effects of items that are usually excluded from analysts estimates.

Moving to the bottom line reported earnings from continued operations were an impressive $824 million or $1.82 per diluted share in the second quarter of 2007. That’s a 43% increase in earnings from continuing operations over the first quarter of this year. Earnings from discontinued operations came in at $80 million or $0.18 per diluted share. In aggregate after backing out items that are typically excluded from analysts estimates, our total net earnings for the second quarter were $845 million $1.87 per diluted share. As we said earlier, the results far exceeded our expectations as well as those of the street.

Cash flow before balance sheet changes reached a record $1.8 billion up 24% from the last quarter and up 18% from the second quarter of 2006. Year-to-date our operating cash flow before balance sheet changes totaled $3.3 billion comfortably funding $3 billion of capital investments and leaving us with nearly $300 million of free cash flow.

In addition to our strong cash flow in the month of June, a healthy cash balance of $1.4 billion while our net debt to capitalization ration reached a 12 month low of 20%. Looking to the remainder of 2007 we expect cash flow from operations to generally cover our total capital demands. That will leave us with the after tax proceeds from the African divestitures available to reduce debt and resume repurchasing shares. To summarize, DVN’s second quarter performance was a strong one in almost every way.

With that I am going to turn the call back over to Vince to open it up for Q and A.

Vince White

Thanks John and operator we are ready for the first question.

Question-and-Answer Session

Operator

We will now begin the question and answer session. (Operator Instructions) Our first question comes from Tom Gardner, Simmons & Company.

Tom Gardner - Simmons & Company

Good Morning guys, could you comment on the potential for an additional offset wells to the two wells you have at Merganser and any additional comments you care to make on opportunities for additional gas development around the independent’s hub?

Stephen Hadden

Yeah Tom this is Steve. Right now we don’t have any near term plans for future development around Merganser, which is essentially two wells 50% working interest and that will come out about 50 million cubic feet a day. We continue to work a prospect inventory in the eastern Gulf and as they come up and rank competitively where we can move them forward to drill we will do that, but right now we don’t have any specific plans to drill additional prospects in that area.

Tom Gardner - Simmons & Company

Thanks for that. And regarding Palvo, how rapidly do you see production ramping up to your 26,000 barrels a day net and can you give us an idea of the crude quality and likely price realizations from that oil?

Stephen Hadden

Yeah, this is Steve again. Relative to the Palvo development we started our production already. We’ve got two wells drilled. We’ll drill a total of ten and that includes a couple of injection wells. I anticipate that we would be ramped up to that 26,000 barrels a day net probably sometime around the middle of 2008.

Tom Gardner - Simmons & Company

Thanks guys.

Operator

Our next question comes from Ben Dell, Bernstein and Co.

Ben Dell - Bernstein and Co.

Hi Guys. I have one macro question and one specific one. Firstly the specific one on Cascade: You talked about, if I heard you right, sanction to end at 2007, previously you talked about production in 2009. Would that still be the case?

Stephen Hadden

Yeah, our current target is still around the end of 2009 for first production, sanction decision would probably happen sometime this year.

Ben Dell - Bernstein and Co.

Ok, and I know it’s a long way off on Jack, but Chevron has sort of made comment that they didn’t expect Jack to start off for (inaudible-Gorgon?) which puts it in the sort of 2014 plus range, is that sort of where you are looking, or the early part of next decade?

Stephen Hadden

Well we’re working together with the partnership and I think our plans for the MMS say somewhere in that range of 2014, but it’s still very early as it relates to putting together the final production configuration and what the commercial sanctioning project or commercially sanctioned project would be going forward. So to speculate any more than that on timing would be a little bit premature from our perspective.

Ben Dell - Bernstein and Co.

Ok, and lastly on the Macro side, you along with a number of other gas buyers have recorded pretty good volume growth, both year on year, a lot of it coming from the on shore which still appears to be out 5% despite the rate count flattening up. Do you think this is a trend you expect to see continuing on the Macro? And if so do you believe that its’ got any implications of future gas prices?

Stephen Hadden

Well a couple observations Ben, we are going to see a lot of incremental gas demand coming out of the Canadian oil sans over the next couple of years. Certainly production growth does have implications on shore as well as bringing on the independent’s hub will be a significant increase and Golf production, but we remain long-term pretty bullish on the North American natural gas market.

Unidentified Company Representative

Yeah Ben, I might add while DVN and a few other independents are achieving production growth, the majors have not chosen to put a lot of their capitol into U.S. onshore gas production and their production has generally been declining for many years. That could of course change, but while some independents have been achieving growth and DVN is pleased to be at the top of that list or at the top, don’t know exactly but compared to all that certainly a contender for that. Overall there's a lot of production in the

decline and the U.S. and Canada, with imports from Canada declining, so there are a lot of moving pieces there.

Ben Dell - Bernstein and Co.

Ok, great. Thank you for your time.

Operator

Our next question comes from John Herrlin, Merrill Lynch. Mr. Herrlin, your line is open. (Operator Instructions)

John Herrlin – Merrill Lynch

Oh, Sorry about that. Good quarter. I don't normally say that.

Stephen Hadden

Well, we appreciate it, John.

John Herrlin – Merrill Lynch

Sure. Regarding your free cash, why not roll the commercial paper and shrink the denominator?

You know, buying stock.

Stephen Hadden

At the moment, since we have a registration statement on file, for our MLP, the company and all the officers are precluded from doing anything in the marketplace, so from a legal standpoint that is not an option to us at the time. Once that registration statement is filed, in approximately a month or so, then the use of free cash is something we can consider.

John Herrlin – Merrill Lynch

Ok, that's fine. Would Steve – [would Chuck even mention] kind of a target size, or I missed it?

Stephen Hadden

I didn't mention it, but I will tell you, we generally say the slower tertiary prospects are in the 3-500 million barrel range or bigger and this is in that range.

John Herrlin – Merrill Lynch

Ok, Last one for me is on [Fratt] costs and the [front ad] you had good efficiencies with fit for purpose equipment. Are you seeing any drop in your [Fratt] costs at all?

Stephen Hadden

No, we've seen some deceleration of the cost escalations if that makes sense, and we're just going through, we're getting into the period of time now to where we'll start looking at our contracts for 2008 and looking at pricing there, so we're just getting into that window where we're going to get a good look at the go-forward pricing here, but we have seen some flattening in the escalation rates.

John Herrlin – Merrill Lynch

Do you plan to lock in any equipment longer term, like rigs?

Stephen Hadden

We, as a matter of fact, we have kind of a blended portfolio, when you look at those 30 rigs, we have some of those rigs under a long term contract, some on much shorter terms, and we kind of just manage our risk that way, so some of those rigs are longer term contracts, some aren't. Some are shorter term.

John Herrlin – Merrill Lynch

Ok, thank you.

Operator

Our next question comes from Mark Gilman, the Benchmark Company.

Mark Gilman – The Benchmark Company

Hi Guys. Good morning. I have a couple of things. Steve, I wonder if you could just put a little more color on the scale back at [gross Beckett]. Is that a low cost issue that you're responding to?

Unidentified Company Representative

No actually, when we looked at it, Mark, when we drill these wells, we're getting relatively good reservoir performance, and we go through and drill these long reach horizontal wells and do multiple stages along a horizontal section that are along these spacing units, sometimes 40-acre spacing units. Every time we do a stage, or generally on average, we're seeing the reservoir performance from each stage that we have. We're simply working through some execution issues as it relates to the type of drilling we want to do, the type of mechanical completion we want to do, in other words, the type of jewelry we want to put in the hole, and then the interplay with that, with the completion to try and optimize all that before we go into full blown development. We're simply not comfortable yet to really start ramping up our drilling activity until we're comfortable that we can deliver very good, solid consistent results.

Mark Gilman – The Benchmark Company

Steve, what have the drilling costs been, per well?

Stephen Hadden

Oh, they can range from about 6.5 million, to as much as $11 million depending on where we're drilling, how deep it is, and how far we try and reach out with that horizontal section.

Mark Gilman – The Benchmark Company

That's drill completed?

Stephen Hadden

Yes.

Mark Gilman – The Benchmark Company

Ok. In the Lloyd Minister area. I wonder if you could talk a little bit about whether or not the production increases are associated with new areas, whether it's in-fill, and whether you’ve got a number of locations identified?

Stephen Hadden

You know, it's a combination of those things. We continue to grow the Lloyd area, and the Lloyd Minister area. We did acquire

the Iron River properties back in, I believe it was back in 2004, or 2005, and that had a lot of running room on it. That's adjacent to our Mannetoken field that we've had and developed for quite some time, and it was relatively undeveloped, so we're getting pretty good kick from the Iron River side, as well as other drilling in the Lloyd Minister area.

Mark Gilman – The Benchmark Company

Ok. And just one final one from me. I assume that with the incorporation of Cortazian to the [casketing] unit that your interest in the unit, given that the percent in Cortez will still be 20%.

Stephen Hadden

Okay.

Mark Gilman – The Benchmark Company

Thanks a lot.

Stephen Hadden

You’re welcome.

Operator

Our next question comes from (ph.) Raheen Fabji, UBS.

Raheen Fabji – UBS

Good morning. This is a question on the convertible bond or exchangeable bond that you guys have upstanding on the balance sheet, convertible at Chevron stock, I guess. I’ve been told that some of the holders might be converting it before the Chevron dividend in August or later this month. Just wondering, what are the tax implications for that on your bottom line?

Stephen Hadden

It must be a good question—we’re all looking at each other. It’s certainly their option to exchange at any time. As far as the tax implications—

John Richels

One thing you have to recall is that we have the option of paying back either in stock or in equivalent amount of cash. And if we pay an equivalent amount of cash for anything redeemed, there’s no tax consequence. It only becomes a tax consequence for us at the time that we liquidate the underlying stock.

Raheen Fabji – UBS

Right.

John Richels

--because of the cost basis in that. We have a lot of flexibility there and particularly with our pre-cash position, today, we have a lot of flexibility determining how we might do that.

Raheen Fabji – UBS

Okay. Has there been any thought or discussion on restructuring the convertible, or exchanging it to defer the tax implications?

John Richels

There are a lot different opportunities available, and we have a lot of flexibility in terms of what we might do with is, something that we’ve looked at continually over the past few years, and we will continue to as we get closer to the maturity date which I think is August 2008. We’re continuing to look at that.

Raheen Fabji – UBS

Okay. Thank you.

Operator

Our next question comes from Ray Deacon, BMO Capital.

Ray Deacon – BMO Capital

Hey, John, I guess I had a question on jackfish and what the thought process is as far as second phase there, and maybe if you can speak to what the cost increases have been since you took on this first project, and/or if there’s any technologies that could help you mitigate some of those cost increases. And then maybe a quick comment on the foreign end—it sounded as though you were saying your well cost looks to be flat over year over year, so I guess is the implication that besides the drilling costs, completion costs have been trending up. Is that a fair way to look at it?

John Richels

Well, let me take a crack at the first one, and then I’ll turn the Barnett question over to Steve, Ray. On Jackfish Two, we’re still—as Steve indicated—we’re still doing a lot of work right now on budgeting. There’s no doubt that Jackfish Two is going to be come in a little higher than Jackfish One, just because of the cost pressures that we’re all aware of in the oil patch and in particular in and around the fort McMurray area. However, we did some things when we built Jackfish One, that anticipated that we might upsize to a second project, and as you know, we also built the access pipeline and some blending and other facilities that Jackfish Two will get the benefit of because we really absorbed that capital costs and in the first phase.

So we’re not quite sure yet exactly what the budget for Jackfish Two will look like, still working on that. We are really encouraged though, by what we’ve seen on the technical side. Jackfish two looks to be, from a reservoir point of view and from a quality point of view, every bit as good as Jackfish One which we believe is a top docile lease in the province. So we’re pretty positive about it and we’ll likely make a sanctioned decision on that sometime in and around the time that we expect to get regulatory approval, which should be about mid-2008.

Ray Deacon – BMO Capital

Got it.

Stephen Hadden

And because that is a year off, you know, the questions are not what the costs are now, but what they’ll be then, as you’ve seen from some of our other reports today, and things like the Barnett where we actually brought some costs down and held others flat. Ultimately the cost in Canada got to come down because of the pullback that Devon and other companies have done in the conventional drilling. So the cost a year from now may be up, they may be down. So we’ll see.

John Richels

And what allows us to do too, Ray, is—you had asked if there were going to be different technology—we’re really looking at this as a look-alike to Jackfish One, taking advantage of the knowledge that we got from that rolling over some of the crude’s and the time period allows to do a lot of engineering, so we thought to go into it with a great deal of certainty. Let me turn that over to Steve now on your Barnett Shale question.

Stephen Hadden

In regards to the Barnett, I think you had it spot on. Essentially, we saw that $190 thousand per well improvement on the drilling sides as for drilling only. When you look at the other costs for a total completed well, that improvement essentially offset those cost escalations year-over-year, so you end up with a flat well cost ’06-’07.

Ray Deacon – BMO Capital

Got it thanks.

John Richels

Which is a great result for such a major part of our capital expenditures.

Ray Deacon – BMO Capital

Thanks very much.

Operator

Our next question is coming from Rehan Rashid of Friedman, Billings, Ramsey.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

Morning. Sticking with Barnett for a second, how should we think about future reserve growth? I know you guys talked about 3 TCF approved, 13 and change, [3P] potential, what could be some of the technology drivers or results, and just some sort of a timeline if you could, please?

Stephen Hadden

Rehan, you mentioned the 13.5 TCF total resource potential that we’ve out before, and that’s on a risk basis. We’re very comfortable around that number right now as far as the total resource potential. Obviously, stepping up from 385 wells this year to 500 wells is going to have a positive impact on both our recovery and, ultimately, on our reserves. And we think we will continue to realize good, strong reserve additions from the Barnett for the foreseeable future, as we go through.

So it’s just a continuous process of driving towards getting that ultimate recovery to 13.5 TCF or better. Some of things we’re doing are continuing to down space. We talked about the 20-acre in-fill program that we’ve done both in the core area and expanded a bit to the non-core. We have another 400 locations or so, plus or minus, that we’ve identified as far as 20-acre in-fill opportunities. There could be more, but right now we’re looking at about something in the range of 400.

We also have opportunities with our refract programs. We do refracts when the well performance dictates that it’s time to do that. We’ve only done maybe about 40 or so this year, but we’re continuing to get very good results that give us additional recoveries as high as 0.7 BCF per frac, and so that’s another tool, or technology, that we’re using to continue to claw away at that total resource potential.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

What recovery factor did you assume when you talked about the 13.5 TCF risk potential there?

Stephen Hadden

If you look at the 13.5 TCF, and you look at it, it’s a risk number. And if you look at the acreage under Devon’s control, and you look at our estimate of gas-in-place in that acreage under Devon control, it’s about 11-13% of the gas-in-place.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

Okay, and then do we need, once again, maybe [simul] fracs or trifacs to work for us to progress down this recovery factor path, or simply down spacing and marginal stuff like that would work?

Stephen Hadden

We think the majority of it’s going to be with existing technology and continued improvements in our exploitation work as we move out into the non-core, and then look at the down spacing areas. There could be some additional potential with even smaller down spacing, or other technologies, but that’s not fully baked in or reflected in the 13.5 TCF.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

Okay, perfect. One more question, but on the deep water site, so it’s Cortez and it’s Chuck, what else from the deep water sub-salt for this year in terms of exploration?

Stephen Hadden

I think we mentioned the Green Bay prospect that we just picked up 23% interest in. That should spud some time probably in the first quarter of this year. So that will probably be the last sub-salt exploration well that we’ll be drilling this year.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

Got it. And how will that program look like next year?

Stephen Hadden

We haven’t finalized that program yet. As I mentioned before, we have appraisal work going on. The exploration work, we’re still working on finalizing that. We’re just going in. As we come out of August and go into September we’ll go through our budgeting process and really firm up those plans going forward.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

I guess a better way to phrase it would be, will it be dependant upon results from Chuck or Cortez, or not?

Stephen Hadden

No, I don’t think on the exploration side it’ll be materially affected by those two. Generally, what you’ll see us do is we’ll probably drill a couple of deepwater exploratory wells in the lower tertiary each year, on average, going forward. And we may pick up a few deepwater Miocene opportunities to compliment that as we go forward. But generally, you’ll see us in the one to three range as it relates to our opportunities on average over about a four-five year period.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

One last question, on the deepwater side we’ve seen quite a bit of activity in the Walker Ridge side. Any particular thoughts why so much on the Walker Ridge and not maybe as much, although you’ve seen some good success, in the Keathley canyon or some other place?

Stephen Hadden

I’m sorry, could you repeat that Rehan? I didn’t hear it all.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

So the bulk of the activity on the sub salt side seems like an industry that’s focused on Walker Ridge. Any technological, geological explanation for that versus not being focused somewhere else within the deeper waters?

Stephen J. Hadden

We just continue to work the portfolio and identify the best opportunities for us to drill going forward and we stay pretty tight lipped about everything else.

Rehan Rashid – Friedman, Billings, Ramsey, & Co.

Ok thank you.

Operator

Our final question is coming from David Heikkinen with Pickering Energy Partners.

David Heikkinen - Pickering Energy Partners

Good morning. I have a question on the Woodford, the net acreage for the 1 TCF potential.

Stephen Hadden

The net acreage is about 70,000 acres

David Heikkinen - Pickering Energy Partners

Ok, and have you the Woodford and the Ardmore Basin at all?

Stephen Hadden

We’re currently looking at a couple of different areas and we haven’t announced any tests in the Ardmore Basin.

David Heikkinen - Pickering Energy Partners

Ok, and then thinking about the corporate target of 350-370 million barrels of oil at (inaudible) and reserve as this year (inaudible) goal and then adding 115 wells to the Barnett seems like you could have some upside to that target. Is that a reasonable thought process?

Stephen Hadden

You know there are always pluses and minuses, that’s why we give a range and we aren’t updating our reserve target range for this year. If there were some risk barrels in that range for lower turf sharing which we now think we will not book this year and so I just don’t think we’re prepared to move the range.

David Heikkinen - Pickering Energy Partners

Ok, that’s cool, so still on target though for the original range, no concerns..

Stephen Hadden

Absolutely, we’re comfortable in that range.

David Heikkinen - Pickering Energy Partners

I’m not trying to get too much into the weeds but now you’re drilling some offset wells to Questar in the Vermillion Basin. Any idea of how we should think about that from a Devon standpoint of how meaningful that could be?

Stephen Hadden

It’s just too early to tell at this point.

David Heikkinen - Pickering Energy Partners

That’s perfect, thanks a lot guys

Stephen Hadden

Ok, we’re at the top of the hour so Larry do you have any closing remarks for the call?

Larry Nichols

Well yeah I hate to summarize because I’d just like to repeat every sentence we’ve gone over but clearly we had a very strong financial result for this quarter and it was driven by production growth really throughout the Company which is exciting not only of itself but we’re clearly solid in position to reach the upper end as we said of our full year production target of 221 million BOE, through our organic growth at the same time that we’re keeping expenses under control across the board.

Outstanding performance at Barnett Shale with 36% over last year as well as all our other projects that will be supplemented in the second half of the year with (ph.) Morganza and Palvo, those longer term projects start to come on-stream. Continue to advance our projects in the high impact portfolio in the oil turf sharing.

All in all very pleased with the first half results and look forward to a great second half. For those that we didn’t have time to answer questions we’ll be here this afternoon so thank you and I’ll look forward to talking to you again in November. Take Care.

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Source: Devon Energy Corp. Q2 2007 Earnings Call Transcript
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