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Executives

Vince White - VP of Communications & IR

Larry Nichols - Chairman & CEO

Steve Hadden - SVP of E&P

John Richels - President

Darryl Smette - SVP of Marketing and Midstream

Analysts

Stacy Nieuwoudt - Tudor Pickering

Tom Gardner - Simmons & Company

Ronnie Eisman - JP Morgan

Mark Gilman - Benchmark

Eric Hagen - Merrill Lynch

Brian Singer - Goldman Sachs

Ellen Hannan with Bear Stearns

Harry Mader - Lehman Brothers

Eric Goldman - GB Capital Partners

Devon Energy Corporation (DVN) Q1 2008 Earnings Call May 7, 2008 11:00 AM ET

Operator

Welcome to the Devon Energy's first the quarter 2008 Earnings Call.

(Operator Instructions) At this time 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, and good morning and welcome to everyone. This is Devon's first quarter 2008 conference call and webcast. Today's call will follow our usual format. We'll start with our Chairman and CEO Larry Nichols, who will provide his perspective on the quarter. Then Steve Hadden, our Senior Vice President of Exploration and Production will follow Larry covering operating highlights, and finally our President, John Richels will conclude with a financial review. At that point we'll open up the call to questions. We'll ask each of you to hold your questions to one and one follow-up and we'll try to hold the call to about an hour.

A replay of the call will be available later today through a link on our homepage. Please note that all references in today's call to our plans, forecasts, expectations and estimates are forward-looking statements under US Securities law, and while we always attempt to provide you the very best estimates possible, there are many factors that could cause our actual results to differ from those estimates. So we encourage you to review the discussion of risk factors and uncertainties provided with our Form 8-K forecast.

One other compliance note, we will make reference today in the call to certain non-GAAP performance measures when we use these measures we're required to provide certain related disclosures. Those disclosures are available on the Devon website.

Additionally, I want to point out that as a result of our decision to sell our assets in Africa and terminate operations there, accounting rules require us to exclude oil and gas produced from the divestiture assets from the reported production volumes for all the periods we present. The related revenues and expenses for these discontinued operations are summarized in the discontinued operations line item at the end of the statement of operations. We have provided for your reference an additional table in today's news release that gives a detailed statement of operations and the production volumes attributable to the properties that we are divesting.

As it has for the last several quarters, accounting for the discontinued operations impacted the compare ability of earnings estimates. Most of the analysts that report their estimates to first call excluded the contribution from the African operations. The mean estimate of earnings per share from these analysts was $2.30 a share. This compares to our non-GAAP earnings from continuing operations of $2.56 per share that is reported number.

The mean estimate for the analysts that included discontinued operations was $2.43 per share that compares to our non-GAAP diluted earnings of $2.74 per share for the first quarter including discontinued operations. You can see that in either case, with or without West Africa, our first quarter results were significant beat over street expectations. With those items out of the way I'll turn the call over to Larry Nichols.

Larry Nichols

Thanks and good morning, everyone. Let me start by reminding everybody that 2007, last year, was the best year in Devon's history, and if you look at the first quarter of this year, 2008 promises to be another outstanding year. The robust pricing environment for both oil and natural gas, combined with the effective execution of our capital programs is leading to record setting financial results and operating milestones.

First quarter earnings before mark-to-market hedging losses rose to an all-time company record of $1.2 billion. Cash flow before balance sheet changes also climbed to a record $2.6 billion for the quarter, on pace to significantly exceed the annual cash flow record we set in 2007 of $7.3 billion. First quarter cash flow exceeded our capital expenditures by a very comfortable $600 million.

Production of oil and natural gas and natural gas liquids climbed to 58.3 million barrels equivalent, marking the eighth consecutive quarter of production growth, and a 9% increase over the year ago quarter. We also reached significant milestones in our Barnett Shale natural gas field in North Texas. In April, we topped 1 billion cubic feet a day, net to our interest.

We achieved this goal of 1 Bcf a day net to Devon, a full 21 months ahead of our original target. In the first quarter, we also announced a 14% increase in cash dividends on the common stock. This is the fifth year in a row that we raised our quarterly dividend payment. In total during that period, that five year period we have increased Devon's dividend by more than 600%.

We also made notable progress in the first quarter with our African divestiture program. In March, we announced an agreement to sell our assets in Cote d'Ivoire for $200 million and in April, we announced an agreement to sell our position in Equatorial Guinea for $2.2 billion. We now have signed contracts to sell substantially all of our African properties for over $3 billion in aggregate.

The contracts we executed for all of our African properties represent a very attractive sales price of more than $36 per barrel of proved reserves or approximately $90,000 per flowing barrel. We are optimistic that we can close the remaining divestiture packages around mid-year and are extremely pleased with the results. They exceed the forecast that we and the street had earlier this year and last year.

Once these transactions are completed, and the proceeds are combined with our internal cash balances, we anticipate having approximately $4 billion after-tax for deployment. As we previously indicated, we will be seeking a combination of share repurchases, capital investments and debt retirement that will optimize our growth in earnings, in production, in cash flow, all on a per debt adjusted share. On that high note I'll turn the call over to Steve Hadden.

Steve Hadden

Thanks Larry, and good morning to everyone. I will begin with a quick recap of the companywide drilling activity. We drilled 646 wells in the first quarter. Of these 646 wells, 66 were classified as exploratory, of which 82% were successful. The remaining 580 wells were classified as development of which 99% were successful.

Our recount peaked at 155 rigs during the first quarter, and we ended March with 120 rigs running, 76 of them drilling Devon operated wells. Capital expenditures for exploration and development on our retained properties were $1.7 billion. Our first quarter capital spend exceeded one-fourth of the full year budget of $5.6 billion to $5.9 billion.

Several factors contributed to this outcome. First, recall that our Canadian capital budget is weighted towards the first quarter of the year because many areas in Canada are limited to winter only drilling access. In addition, we've accelerated activity in several areas of the US Onshore including the Barnett.

Given the robust opportunity set embedded in our property portfolio and the current strong commodity price outlook, we will continue to look for ways to accelerate the development of these opportunities.

Moving now to our quarterly operations highlights for the Barnett Shale field in North Texas I'm going to keep my comments brief because we provided a comprehensive Barnett update in the webcast on March 28. For those that missed that presentation, a replay and copies of the slides are available on the Devon website.

In the Barnett, we're currently running 34 Devon operated rigs and we now have drilled more than 1,280 operated horizontal Barnett Shale wells. We continue to be very active in Johnson County with seven rigs now running. In the first quarter, we bought 45 new operated wells online in Johnson County at an average rate of 2.1 million cubic feet a day, including the Light Foot 1 H that IP'd at 7.1 million a day.

In addition, we completed Phase II of our West Johnson County plant, gas plant. Plant capacity was boosted to 130 million cubic feet of gas per day, with throughput currently running above 100 million cubic feet a day. This additional capacity has allowed us to continue to grow our production in Johnson County where we averaged to 195 million cubic feet a day in the first quarter.

For the entire Barnett play, we exited the first quarter producing just shy of 1 billion cubic feet of gas equivalent per day net to Devon. In the first quarter our net Barnett Shale production averaged a record 995 million cubic feet of gas a day, up 7% from the fourth quarter and up 36% year-over-year.

As Larry mentioned, we're now producing in excess of 1 Bcf a day net to Devon or roughly 2% of total US daily gas production. With over 7,500 risks to drilling locations at our current drilling pace we have about 13 years of drilling inventory in the Barnett Shale. This translates to continuing production growth in months and years ahead with the potential to reach between 1.6 Bcf and 2 Bcf equivalent on a net basis.

In the Woodford Shale in Eastern Oklahoma, we added one rig late in the first quarter and we now have six operated rigs running. We bought a total of 13 new operated wells online during the quarter with initial production rates as high as 4.2 million cubic feet a day. Much like we did in the early days of expansion of the Barnett play, we've been drilling wells across our Woodford acreage to better evaluate the position. We're now moving to full scale development, and expect to ramp up production significantly over the next year.

Moving to the Rockies, in the Washakie Basin in Wyoming, we had four rigs running for a good part of the quarter prior to the start of the wildlife stipulation season, and drilled a total of 34 wells during quarter. In the second quarter we plan to drill our first horizontal well in the field. Given our track record with horizontal drilling and the Barnett Shale in East Texas, we're eager to evaluate these results. Horizontal drilling could open up another leg of activity on Devon's 150,000 plus net acres at Washakie.

Shifting to East Texas, we drilled 30 wells in the first quarter. Our seven rig vertical Cotton Valley drilling program in the Carthage area. In total, we plan to drill about 100 vertical wells in 2008, a third of which will be infill wells. Also in the first quarter we recompleted eight wells.

In addition, we continue to see good results from our horizontal drilling program in the Carthage area. We're currently running three rigs drilling horizontal wells, and completed four Cotton Valley horizontal wells during the first quarter, with average IP's of 2.9 million cubic feet of gas a day. We plan to drill over 20 additional horizontal wells this year at Carthage. In total, our Carthage net production averaged 273 million cubic feet of gas equivalent per day for the first quarter, up 17% over the same quarter just a year ago.

Southwest of Carthage at Groesbeck, we're improving our ability to deliver consistent repeatable results across our acreage position, as we indicated in our year-end call we've been refining our drilling and completion techniques. As a result, we've been able to reduce the number of days to drill a Groesbeck horizontal well from 76 days to 66 days. These improvements in execution are most apparent in our Nan-Su-Gail field where during the first quarter we completed three very successful wells.

The Hill 19 H and Nail-B 12H, each IP'd at 24 million a day and Crenshaw 17 H IP'd at 10 million a day. Four additional Nan-Su-Gail horizontal wells were in various stages of drilling or completion at the end of the first quarter. Although, we've seen the best results to-date at Nan-Su-Gail, we're hopeful that we can extend this success to other neighboring fields in our Groesbeck area. The net Groesbeck production averaged 86 million cubic feet a day gas equivalent for the first quarter, also up 17% over the first quarter of 2007.

Now shifting to the deepwater Gulf of Mexico, we continue to be impacted by the production suspension at the Independence Hub. The Merganser field remained shut-in due to a leak in the third party operated export line. This is currently curtailing our net Gulf volumes by about 50 million cubic feet of gas a day. Repairs are underway, and we hope to see production resume around the middle of May.

Elsewhere in the deepwater Gulf of Mexico in Lower Tertiary trend, we are continuing to move towards sanctioning its Jack and St. Malo. The working interest owners in these two Lower Tertiary projects have moved farther along toward the selection of the final development concept and expect to begin front-end engineering and design work in 2009. Appraisal operations continue on both discoveries. Devon has a 25% working interest in Jack and a 22.5% working interest in St. Malo.

Also in the Lower Tertiary, we are currently at work on a sidetrack operation on the Kaskida Prospect in Keathley Canyon block 292. This is a reentry of the initial discovery well we drilled in 2006 and the objective is to extract additional whole core samples and down hole data. The co-owners also plan to drill another appraisal well at a new location in 2009.

I will remind you that Devon recently increased its ownership in Kaskida by exercising our preferential purchase right. BP is the operator with 73.3% working interest and Devon now has the remaining 26.7% interest. At Cascade, this is our 50-50 Lower Tertiary project with Petrobras. We plan to set surface casing on the Cascade 3 and the Cascade 4 wells in the third quarter of 2008.

The partners are planning to develop Cascade jointly with the Chinook project. We expect Cascade to be the first of Devon's four existing Lower Tertiary discoveries to begin commercial production. Our plans call for utilization of the first FPSO in the Gulf of Mexico when production commences just two years from now in mid 2010.

In our deepwater operated Gulf of Mexico exploration program, the test on the Chuck Prospect on Walker Ridge 278 has been plugged and abandoned. Although the well was P&Aed, the partners continue to evaluate the results for further potential on the unit. Devon operated the Chuck well with a 39.5% working interest.

We have two additional Lower Tertiary exploratory wells planned for this year. We plan to spud a well in June. Devon currently holds a 50% working interest and operates the Bass Prospect at Keathley Canyon 596. In addition, we plan to participate with a 28.3% working interest in an exploratory well on the Chevron-operated Damascus prospect on Walker Ridge 581. This well is expected to begin drilling in the third quarter of this year.

And finally in the deepwater Miocene, we are now drilling ahead at about 23,000 feet on the Sturgis North exploratory well in Atwater Valley block 138. Devon has a 25% working interest in Sturgis North which is operated by Chevron.

Now, moving to Canada, we drilled 249 wells in the first quarter despite challenges presented by colder than normal weather. In our Lloydminster oil play in Alberta, we have increased our production 30% over the past 12 months to nearly 42,000 barrels a day. We continue an active five rig program in the first quarter as we drilled 121 new Lloydminster wells. The second 10,000 barrel a day expansion at our Manatokan plant is under construction. We expect to complete that work by the fourth quarter of this year bringing the total capacity of the Manatokan plant to 27,500 barrels a day.

At our 100% Devon-owned Jackfish Thermal Heavy Oil Project in Eastern Alberta, production continued to climb during the first quarter up to 10,000 barrels a day by March 31st. Production will continue to ramp up throughout 2008 as we head toward a sustainable peak rate of 35,000 barrels a day in early 2009.

At our Jackfish 2 project, the front-end engineering and design work is substantially complete. We drilled 35 stratigraphic wells in the Jackfish area during the first quarter. All of these wells met or exceeded our expectations. We hope to receive regulatory approval and formal sanctioning of the project this summer, and could begin site construction in the fall. Jackfish 2 will essentially double the size of our Jackfish operations, adding 300 million barrels of reserves and another 35,000 barrels a day of oil production.

Moving to Brazil, during the first quarter we continued development drilling in the Devon-operated Polvo Oil Project on block BM-C-8. We worked through the mechanical issues and the delays with the carbonate wells that mentioned last quarter. We now have drilled the first cretaceous sand well, and it is currently being completed. While we are behind schedule relative to our original plan, we expect Polvo production to continue to ramp up during the remainder of the year as we drill and complete the additional wells.

In China, the Panyu exploratory well located on block 42/05 in the South China Sea was determined to be non-commercial. Although this well fulfills our contractual commitment for evaluating several other high-potential prospects on this 1.7 million acre block. Also, in China, at our Panyu project in the South China Sea we achieved a significant milestone in the first quarter reaching 100 million barrels of cumulative production. Panyu continues to outperform 4-1/2 years after its first production. Devon's net production from Panyu averaged nearly 15,000 barrels a day during the first quarter, roughly the same level as the first quarter of last year.

That concludes our operations update. Now, I will turn the call over to John Richels to review our financial results for the first quarter. John?

John Richels

Thanks, Steve. This morning I want to take you through a brief review of the key drivers that impacted our first quarter financial results, and review how those factors impact our outlook for the remainder of the year.

As Vince mentioned, we have classified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. As a result, I will focus my comments on our continuing operations which will exclude results attributable to Africa.

Let's begin with production. In the first quarter of 2008, we produced 58.3 million equivalent barrels or approximately 640,000 barrels per day. That is right in line with the guidance provided in the fourth quarter conference call, and marks Devon's eighth consecutive quarter of production growth.

During the first quarter, Devon's core North American assets lead by the Barnett Shale, exceeded budget by nearly 1 million barrels, offsetting the delays at Polvo that Steve referred to. When you compare the first quarter of 2008 to the first quarter of 2007, you will find production increased by 52,000 barrels per day or roughly 9%. The US onshore grew by 53,000 equivalent barrels per day over the year-ago quarter, an increase of 17%.

Even though we scaled back significantly on conventional gas drilling in Canada, total first quarter production from our assets in Canada climbed 2% over the first quarter of 2007. This growth was principally driven by our Lloydminster oil properties.

Our first quarter international production decreased by 5000 barrels per day from the first quarter of 2007, driven by a decrease in our volumes from the ACG field offshore Azerbaijan. Given the very strong production performance of the ACG field and the robust oil price environment, the ACG field reached an economic threshold which triggered an increase in the government share of production.

Also, our production outlook for the remainder of 2008 has been impacted by a reduction of our profit oil split from the field. We have previously forecasted this to occur around the end of 2008; however, due to higher than expected oil prices, coupled with a clarification of contract terms, our share of ACG oil production was reduced as of April 1. Fortunately, this is the final crunch, so our percentage of ACG production will be stable from this point forward.

In aggregate, this early payout reduces Devon's expected 2008 production by about 3 million barrels and as a result of that reduction we now expect companywide full year 2008 production to come in at the low end of our previous guidance range of 240 million to 247 million Boe. In the second quarter, companywide production should be essentially flat with the first quarter at about 58 million barrels of oil equivalent with sequential quarterly growth expected in both the third and fourth quarters.

Moving on to price realization starting with oil. During the first quarter the WTI benchmark price rose to $97.67. That is a 67% increase over the first quarter of last year. In addition to higher benchmark prices, regional differential as a percentage of WTI narrowed pushing price realizations in all of our producing regions above the top end of our guidance ranges.

Our companywide realized price came in at $88.23 per barrel or just over 90% of WTI. Our oil price hedges had no effect on first quarter prices. I will just remind you, for the full year we have approximately 12% of our oil production hedged through price callers with a weighted average for $70 per barrel and a ceiling of $140 per barrel.

On the natural gas side, the benchmark Henry Hub index averaged $8.03 per Mcf for the first quarter, a 19% increase over the first quarter of last year. In addition, Devon's gas price realizations increased to 91% of Henry Hub before the impact of hedges. Hedges reduced companywide realization by only $0.04 per Mcf giving us an average realized price of $7.27 per Mcf for the first quarter.

Turning now to our Marketing and midstream business, Devon's Marketing and midstream operations again had an excellent quarter. Operating profit increased to $173 million in the first the quarter, driven by increased throughput and strong natural gas liquids prices. For the full year, we had previously forecast Marketing and midstream operating profit of $510 million to $550 million and based on our strong first quarter performance and the favorable commodity outlook for the rest of the year, we're obviously off to a good start in meeting that objective.

The final item I want to cover before we move to expenses, is the net loss on oil and gas derivative instruments that we recorded in the first quarter. We recorded a non-cash loss of $780 million pre-tax or $500 million after-tax from a mark-to-market accounting adjustment related to our natural gas price hedges. Mark-to-market accounting requires us to record the unrealized gains and losses related to the fair value of the remaining life of the derivative instruments. In our earnings releases, we provide a table that identifies items that are generally excluded from analyst estimates and this unrealized non-cash loss from our hedges is included in that table.

Moving to expenses. First quarter lease operating general and administrative and DD&A expenses all came in at or below the bottom end of our full year forecast ranges. While we're pleased with our first quarter performance, we still expect to be within the forecast ranges for the full year.

Shifting now to interest expense, interest expense for the first quarter decreased to $102 million. Looking to the second quarter, we expect a decline in variable interest rates to reduce our interest expense to around $90 million to $95 million. We also expect interest expense to decline in the second half of the year as the divestiture proceeds are initially applied to reduce short-term borrowings. Of total first quarter interest expense approximately $28 million was related to commercial paper and credit facility balances which we expect to repay from the African divestiture proceeds around mid-year.

A final item I want to touch on is income taxes. Reported income tax expense for the first quarter came in at 27% of pre-tax income; however, when you back out the income of the non-cash mark-to-market hedging adjustment you get a current tax rate of 6% of adjusted pre-tax earnings and a deferred rate of 26% of pre-tax earnings for a total income tax rate of 32%.

Moving to the bottom line, reported earnings were $749 million or $1.66 per diluted share in the first quarter. After backing out the items typically excluded by securities, analysts and the published estimates, earnings for the first quarter were $1.2 billion or $2.74 per diluted share. As Vince indicated earlier these first quarter results were significantly better than speed estimates.

Cash flow before balance sheet changes climbed to a record high of $2.6 billion. That's a 74% increase over the first quarter of 2007 and a 13% sequential quarterly growth. This record cash flow comfortably funded $2 billion of capital investments while leaving us with a $600 million cushion of free cash flow.

Looking to the remainder of 2008, we expect cash flow from operations to significantly exceed our total capital demands. That cash flow, along with the after-tax proceeds from the African divestitures and our existing cash balances will be available to buyback shares and make incremental capital investments, reduce debt, or do all three. And at this point, we'll open up the call for Q&A.

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Stacy Nieuwoudt with Tudor Pickering. Please proceed.

Stacy Nieuwoudt - Tudor Pickering

Good morning, guys. Can you please provide an update on your Brazilian activity plans for '08 and '09 and any update on the pre-salt?

Steve Hadden

Yeah. Stacy, this is Steve Hadden. In Brazil, activity wise we're moving forward as I mentioned earlier with the development work at Polvo, we plan to drill or have a total of nine wells on production by the end of the year there and two of those wells will be new sand wells that we'll drill between now and the end of the year and there will be a couple of other of the carbonate wells there so that's the development work we're doing on Polvo.

From an exploration standpoint, of course we have a good portfolio of exploration blocks there. We do have a well that will be spudded about the middle of the year which will be in the Campos Basin, on one of our blocks in the Campos, that does have some pre-salt potential, some sub-salt potential and we're looking forward to that drilling operation. Anadarko is the operator, they're bringing the rig in again as I said about the middle of the year.

In addition to that, we're doing seismic evaluation and advancing other prospects to drill ready status for the arrival of our deepwater drill ship that's going to come in just about the end of the year, just about the beginning of 2009 and we'll start drilling that exploration program with that rig that we have under contract for several years. And so we'll drill a few wells as we get into 2009, 10, and 11, drilling through that portfolio.

Stacy Nieuwoudt - Tudor Pickering

That's very helpful. Thanks, guys.

Operator

Your next question comes from the line of Tom Gardner with Simmons & Company. Please proceed. Tom Gardner with Simmons & Company, please proceed.

Tom Gardner - Simmons & Company

Yes. Good morning, everyone. With respect to Canada, can you give us an update on what you're observing with respect to service cost trends?

Steve Hadden

Yeah, Tom, when we look at the more recent activity and what we saw in the first quarter during this winter program, we saw costs come off maybe about another 10% from drilling and completion from where we were last year. We're seeing some indication that that may be bottoming out and may start going the other way. We're not quite sure yet. The drilling activity was still down below the five year average in Canada over the winter program, but with gas prices where they are, we'll see what happens relative to activity and keep in mind too that while we maybe down as much as 30% from the peak, the peak was awfully high up there.

Tom Gardner - Simmons & Company

That's helpful. Just as a follow-up with respect to Alberta royalty changes, is that impacting your Canadian budget going forward? Can you give us an update on what's happening there so to speak?

John Richels

Tom, it's John. It's really not affecting it particularly. We now have all of the changes in as the additional rules that came out on some of the deep gas drilling came out recently. We had already shifted around our capital expenditures in Canada to some extent. As we focus a lot more on our Lloydminster project, which has been just a terrific project for us because of the significant upside that we have there and the expertise that we've developed over the years.

In fact, I think year-over-year we were up close to 50 % in our production from that area, so we've already done some shifting around and we're in the fortunate position in Canada of not having the types of properties that are most affected by the royalty changes that occurred. So as much as anything, our capital expenditure focus in Canada has been affected by things like the cost structure and foreign exchange rates and that type of thing that you're all familiar with.

Tom Gardner - Simmons & Company

Thank you, guys.

Operator

Your next question comes from the line of Ronnie Eisman with J. P. Morgan. Please proceed.

Ronnie Eisman - J. P. Morgan

Good morning, guys. I had a question with regard to the differentials you mentioned that they narrowed tighter than you previously guided. Do you have any or can you comment and provide color as to why you think that happened and the expectations going forward?

Darryl Smette

Yeah, this is Darryl Smette. On the oil side, it's just a matter, quite frankly, of demand still being fairly strong in various parts of the world and supply being somewhat off because of OPEC's willingness to manage production, and so what we have found is that that has kept the differentials at a fairly narrow rate compared to what our previous forecast was. On the gas side, differential has been fairly narrow compared to our forecast and that has primarily been driven by the 4% to 5% colder than normal weather experienced throughout the United States, and so during the first quarter those differentials were narrow. We are starting to see those differentials widen now as we get out of the winter season into the summer season and before we get to the air-conditioning season. So, those differentials have widened but the cold weather was the primary driver for gas in the first quarter.

Ronnie Eisman - J. P. Morgan

Thank you. And then in terms of the Woodford, you said you are moving on to full scale development. What are you seeing in terms of cost trends for drilling and completion?

Steve Hadden

Well, in the Woodford and the North Ridge area in Southeastern Oklahoma, we're seeing some of the well costs go up but part of that is driven by our optimization of the drilling program. In other words, we're drilling some longer laterals on a per well basis but we're also getting much better production. The last couple of wells that we've completed have IP'd well in excess of 4 million cubic feet a day and our well costs were running about $4 million or about $4.1 million and some of these are up to about $5 million but that's mainly because we're extending the horizontal reach of those wells and we think that's going to make good sense economically.

Ronnie Eisman - J. P. Morgan

What percentage of the wells going forward do you think will be these longer lateral wells?

Steve Hadden

Well, probably a higher percentage. Probably the majority of the wells will be a bit longer as we go through the program, yeah. We'll evaluate each one based on the position of the well and the reservoir and some of the other factors that go into that decision-making, but I would just say that the majority of the wells would probably have a bit longer horizontal reach.

Ronnie Eisman - J. P. Morgan

Okay and just going back to capital cost in general, you mentioned in Canada, you see them flattening and potentially going up. How about in other areas that you operate in?

Steve Hadden

Generally in the other areas that we operate in, we have essentially seen a stabilization of rates. We've offset some of the increases that we've seen previously in the pumping services side with improvements in our drilling performance. There is some pressure on steel prices that we see and could have an impact relative to the tubulars that we run into the wells, so we may see some increased pressure there as we move into the second half of the year.

Ronnie Eisman - J. P. Morgan

All right, thank you.

Operator

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

Mark Gilman - Benchmark

Good morning, guys. Steve, I got a question with respect to Polvo that I guess has two parts. First, I guess I wasn't aware there were both carbonate as well as conventional sand potential. Could you elaborate a little bit on that, and can I correctly assume that the dry development well drilled in the first quarter was at Polvo?

Steve Hadden

No, there was not a dry development well drilled at Polvo. If I can remember, we did have one well, Mark, these wells are extended reach wells, in particular when we're going for the sand structure, there's a sand structure that is a bit of a distance from the main platform and we have to do extended reach wells there which have some drilling challenges there. We had one of those wells where a piece of equipment that we run in on our casing had failed and caused us to have to re-drill the well, and that put us behind a one-well slot or one well relative to the development.

Relative to the sand itself, it is sand that was actually discovered and identified a few years ago. We came along a little bit later and discovered the shoal production, the carbonate production and it's just a combination of those two that are coming online. We think there's good production to come out of the sand wells. We just got the first sand well down and are in the process of running the pumping equipment into the well, and we'll see what that well produces. We're very interested in that well of course because it's the first sand well that we'll be producing.

Mark Gilman - Benchmark

Steve, by way of a follow-up regarding what's going on at ACG. Other members of the consortium have indicated that the reduction in profit split occurred in the earlier part of the year and I guess I'm confused by your saying April 1. I also don't know what you mean by clarifications in contract terms. Can you elaborate a little bit on this?

Steve Hadden

Yeah. I can give you a little bit more elaboration. You know, there are a couple of things going on at ACG. There were two traunches that were going to occur between, I think, about the last quarter of last year and then coming through to the end of this year, the end of 2008. We passed the first one and that resulted in a reduction at that point just on profit. I'm not talking about the cost oil component yet, and then there was some clarification that was required as to exactly when the second traunch would occur.

From our perspective we thought in looking at the contract terms and the agreements in place, it was most likely to occur in I think the beginning of the fourth quarter of this year and after extensive discussions of the partnership lead by the operator BP with the government, it was determined that that traunch actually occurred, that last traunch was actually going to occur April 1, and that's what we're now realizing and that's what we've reflected in our forecast going forward for the year.

Mark Gilman - Benchmark

So the first traunch was effective at the first part of the year and it's another step down in profit oil as of April 1?

Steve Hadden

Yes, that's right Mark.

Mark Gilman - Benchmark

Okay, thank you very much.

Operator

Your next question comes from the line of Eric Hagen with Merrill Lynch. Please proceed.

Eric Hagen - Merrill Lynch

Hi, good morning. In the Woodford, there's a decent amount of property on the market now. Are you interested in expanding your position there at all?

John Richels

You know, we're very pleased with our position in the Woodford, and obviously, if other acreage is available or when other acreage becomes available, we look at it relative to its position and its quality and of course its pricing as it relates to being able to compete with the other pretty good opportunities we have in our portfolio. So, we'll make that comparison in the Woodford, as we would in other places when these opportunities come up and we'll make a decision on that basis.

Eric Hagen - Merrill Lynch

Great. And the follow-up is Haynesville Shale, any comments on that, the potential for that on your acreage?

John Richels

Well, no comments on that from our standpoint. I will tell you we talked about the emerging positions in our call on the 28th and we're still adding to those positions. And we actually have several wells that will be going down in the second quarter and evaluating several of those positions, but we're going to stay relatively tight lipped on those for competitive reasons and let you know when we have some material results to report.

Eric Hagen - Merrill Lynch

Great. Thank you.

Operator

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

Brian Singer - Goldman Sachs

Thank you. Good morning. Following up on the previous question on the Woodford, if we just take a step back and we look outside of the Barnett, your US onshore portfolio, you are more active in a number of areas. As you continue to drill in some of these areas, should we look for you to bolster your acreage position either in the lease hold acquisition or producing property acquisition, especially considering additional free cash flow and recent asset sales?

Steve Hadden

Yeah, bolster our lease holder acreage position generally or in a specific area?

Brian Singer - Goldman Sachs

I guess when we think about the Rockies and we think about Woodford, which I guess you just answered on that one, and when we think about East Texas, Groesbeck.

Steve Hadden

Yeah, you'll see us continue to add to our acreage position in areas that make good sense economically for us going forward relative to our portfolio. And as I mentioned before, we've, on the 28th call, we talked a little bit about the emerging position and we added several 100,000 acres at that time this year and we've added to that total just for this year’s acreage position, and we're looking for areas and we're adding to areas that are going to be material to our portfolio and have the prospect of delivering good solid economic returns to us. So, you'll see us continue to do that as we move forward quarter to quarter.

Brian Singer - Goldman Sachs

Do you have some sense as to what incremental capital is dedicated towards that and what you think that could mean from a capital perspective?

Steve Hadden

No. That's going to be opportunity driven. That's going to vary and be opportunity driven.

Brian Singer - Goldman Sachs

Great. And lastly in Canada, I apologize if you touched on this earlier, any initial sense on how steam/oil ratios are coming along at Jackfish?

Steve Hadden

Well, we're still ramping up. We're 10,000 barrels a day and ramping up. We've got active steam injection going and bringing production up on, we'll have a total of four pads going here pretty soon, and the reservoir is actually performing a bit better than what we had anticipated but we always thought that Jackfish, that area is really in the top quartile of reservoir quality and our facilities are running very well and the ramp up is going very nicely, so we think, we'll be at least at the steam/oil ratio that we projected. Of course, our ambition is always to improve on that but we're very comfortable with where we are now albeit early in the ramp up until we get to 35,000 barrels a day and we'll see where we are thermally.

Brian Singer - Goldman Sachs

Great. Thank you.

Operator

Your next question comes from the line of Ellen Hannan with Bear Stearns. Please proceed.

Ellen Hannan - Bear Stearns

Good morning. My question, I apologize if you mentioned this, you talk about the sanctioning at Jackfish 2. Did you mention what your capital plans, your expenditure dollars are for that project?

Steve Hadden

No, Ellen, we haven't disclosed that yet. We've gone through and we've essentially completed our FEED work, our front end engineering work. We're moving towards regulatory approval and a sanctioning decision later this year and at that point, we'll have a really good look at the capital costs.

We're very comfortable with where we are with Jackfish 1. We think we really got a very good understanding for what the SAGD projects take to develop from an initial capital standpoint and we'll just take a real close look at it with our Canadian team when we get to the point of making that sanctioning decision.

John Richels

And Ellen, I'll just remind you too that we are now in these SAGD projects. You don't have the same kind of capital out lay as in the mining projects, of course, because there's no upgrade attached or anything, so when you look at the sensitivities on these types of project its still remains more sensitive to things like differential and (inaudible) cost and those other economic factors rather than the capital. Obviously, capital can be higher than Jackfish 1 because of the pressure we've seen but as Steve said we'll nail that down to a final number probably in the third quarter of this year.

Ellen Hannan - Bear Stearns

Thanks, and I just had another question, moving to the Lower Tertiary trend, with the Chuck well that you plugged and abandoned as well as I think it's the Green Bay prospect on the Walker Ridge 372 that was P&A'd, what have you learned or in what way have your thoughts changed in terms of what you've learned on these couple of wells regarding this trend?

Steve Hadden

Well, Ellen, there's a couple of things. First of all, we probably won't disclose a lot of information in our learning simply because it's competitive in that trend. I will tell you that we're still very confident and very optimistic about our position to Lower Tertiary and the trend itself.

In a couple of cases, Green Bay of course was a dry hole. We think we understand that and we understand that outcome relative to our portfolio and have factored that into our thinking going forward. When you look at Chuck, while we were, Chuck was P&A'd, and while we're a bit disappointed with what we saw there, we did find hydrocarbons and the partners are working together to evaluate the remainder of the unit so it's just another step in getting the information on the entire trend. I think as we mentioned, we're going forward with drilling two additional high impact Lower Tertiary opportunities later this year and we look forward to those results.

Ellen Hannan - Bear Stearns

Great. Thank you very much.

Larry Nichols

Ellen, I might go back on Jackfish 2 when you're comparing Jackfish 2 to Jackfish 1, remember we already have in place the pipelines to get the from Edmonton up to the field and when the crew back down to Edmonton so that capital cost is already incurred and there will be no incremental cost with regard to Jackfish 2 and secondly, we already have all of the engineering design work done, so that the plant and the facilities at Jackfish 2 will essentially be a carbon copy of Jackfish 1, so a lot of those up front costs will not need to replicate in Jackfish 2.

Ellen Hannan - Bear Stearns

Great. Thank you.

Operator

(Operator Instructions) Your next question comes from the line of Mark Gilman with Benchmark. Please proceed.

Mark Gilman - Benchmark

Hi, guys, now that the ink is at least relatively dry and can you give a rough estimate of the impact of the Alberta royalty changes on '09 production and potentially reserves?

Steve Hadden

Mark, when we look at the impact of the royalty issue, when you look at our portfolio and you look at the distribution of both well depth and rate on the gas side, we are able to weather those changes relatively well. While we don't have an exact number for you today for 2009 because that's part of our planning process is to work through that and really get those numbers very well developed as we move into the fall.

We think the impact on a barrels per day basis will be relatively small on our operation and as John mentioned earlier, we redeployed capital out of those areas that are impacted in our portfolio to areas that are either minimally or not impacted, in particular the oil side of the business.

So relative to our Canadian performance you're going to see a ramp up in Canada to continue based on Jackfish thermal, the redeployment into the Lloyd area, and some flattening and improvement in the Canadian gas business, so for us as a company, the impact of the Canadian royalty changes, will be relatively small.

Of course, when you look at Alberta itself, it's still moving in the wrong direction relative to providing good solid energy development in Alberta, but from a Devon standpoint that impact is going to be relatively small.

John Richels

Right and it's very hard Mark to give you a comparative number because to give you a comparative number really assumes we would run the same program year-over-year just with the royalty impact. So as Steve said, by moving that around within our portfolio, what we're still doing as you know is we're comparing our opportunities in Canada not only against other opportunities in Canada but opportunities across our entire portfolio and we're only going to proceed with the ones that match up well from a value creation point of view and with our movement now more into the Lloyd field. That’s been a very, very high rate of return project for us because of our economies of scale there and the oil prices and the other factors, so it's tough to quantify that but it's not really slowing down what we're doing in Canada and we're in the fortunate position there too, having a huge asset base which isn't going to go away, so as costs come down, as foreign exchange rates get more to or start to come down a little bit in Canada, we'll be ready to continue to ramp up our programs on our portfolio there.

Mark Gilman - Benchmark

John, with your fairly small comment or inference also apply to year-end 2007 proven Canadian reserves?

John Richels

Yes.

Mark Gilman - Benchmark

Okay. Just one other one if I could. Is there any contingent element to the exercise of the preemption rights on the Cascade interest?

John Richels

Could you repeat that?

Mark Gilman - Benchmark

Is there any contingent payment element to your exercise of the preemption rights on the Cascade interest?

Steve Hadden

No, sir.

John Richels

No.

Mark Gilman - Benchmark

Okay, thanks, guys.

Operator

Your next question comes from the line of Harry [Mader] with Lehman Brothers. Please proceed.

Harry Mader - Lehman Brothers

Hi, guys. Just a quick question. Given the pending asset sales and free cash flow, it looks like you certainly wouldn't need to come to market but you do have a decent amount of short-term debt outstanding and your leverage is already pretty low so any thoughts on whether you're interested coming to the bond market this year for longer-term financing?

Larry Nichols

No. We haven't really addressed that just because our debt is in such good position, terming some of that out is a possibility but we really haven't focused on that yet.

John Richels

And really with the cash that we're going to get from the African divestitures plus the cash balances that we already have and the free cash flow that we're generating we'll pay off that short-term debt. As we've said before, we've got some longer term debt in place and we'll probably just continue to roll that as we go forward because we're at kind of a healthy level of long term debt for a company our size and there is really no compelling reason for us to go to the long-term market right now.

Harry Mader - Lehman Brothers

Okay, thank you.

Operator

Your next question comes from the line of Eric [Goldman] with GB Capital Partners. Please proceed.

Eric Goldman - GB Capital Partners

Good morning. I wondered if you could give us any additional color on your hedging strategy and sort of the pricing scenario and what your cash flow might look like if we maintain this high level of prices for natural gas?

Darryl Smette

Yeah, this is Darryl Smette, and this year, we put into place a number of hedges on the gas side of the equation and historically what we've done is we've put in hedges that support the capital programs that are going forward within Devon. We have so many capital programs now that are longer term in nature, it's hard just to stop and start those capital programs that we thought it was wise towards the end of 2007 and early 2008 with a lot of gas in storage and forecasts suggesting that maybe we were going to have a warmer than normal winter, it would be wise to put some of the hedges on that we did.

So, we'll continue to look as we go out, we still have the capital projects, long-term capital projects and we look at it periodically, but I would say that we would continue to look at all of those options available to us from the financial standpoint both collars and swaps. We do, as you probably noted, have entered into some financial transactions for calendar year 2009, I think 300 million a day. We're projecting at $8.25 price, so we continue to look at that and as the opportunities present themselves to support our capital programs, we will probably do so.

Larry Nichols

But that's only about 10% of our 2009 gas production or so and 0 hedges on oil.

Eric Goldman - GB Capital Partners

Right. Well, I'd see UK gas for winter 09 is up to 16 plus this morning, so what do you see? Do you believe the scenario is real that we're going to be in the 10-plus gas for a while or do you believe like Chesapeake says we probably are going to be in $8 to $10 range or that's where I'm sure they're comfortable, but it seems like that might be backward thinking to think we're going to stay in the $8-$10 range, especially with crude at these levels.

Steve Hadden

Yeah, there are a lot of things that have happened just in the last two or three months really that has made commodity prices on the gas side look very bullish. First of all, as you mentioned, we've had a very high oil price and we've seen a lot of non-commercial people go into the market that has certainly been bullish for the market. In addition to that as I mentioned a little earlier, we had a 4% to 5 % on our population weighted basis – 4% to 5% increase in demand this winter.

We've had Japan now come off the nuclear facility, that went off line the third quarter of last year. They anticipated being on first quarter of this year and now they say it will be at least a year and maybe longer, so that adds about a Bcf of demand globally. The production performance that we've seen out of Mexico has been rather disappointing. So, many people projected you'd actually see some exports out of Mexico a year ago and now it looks like that's imports.

We not only had cold weather in the US this year, we had it in Asia, in Europe, which certainly has kept the LNG volume coming to the United States down. So, we've had a lot of bullish signals to the market over the last two or three months and one could speculate that that would probably raise the spectrum where gas prices will do the $8-$10 barrel range and we wouldn't dispute that. But most of us have been in this business a long time and we know that things can go up in a hurry and go down in a hurry and so right now we're certainly enjoying the prices we're receiving but that's not an indication that they will stay there forever.

John Richels

All right, and this gas environment is not priced into or not modeled in very many cash flow scenarios for you, I'm sure, for 08 and 09 and one other thing, it's still the only component of the energy market where you've got a huge short interest remaining. So there obviously is another bullish indication that at some point the shorts are going to have to capitulate or at least they have in every other part of the energy complex.

All good points.

Eric Goldman - GB Capital Partners

Thank you very much and congratulations on a great performance.

Steve Hadden

Thank you.

Larry Nichols

That ends. That's the last question we had in the queue, so thank you, everyone for participating in today’s call and we look forward to reporting to you next quarter.

Operator

This concludes the presentation. You may all now disconnect. Good day.

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Source: Devon Energy Corporation Q1 2008 Earnings Call Transcript
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