德文能源 (DVN) 2009 Q1 法說會逐字稿

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

At this time I would like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. You may begin, sir.

Good morning everyone, and welcome to our call. I'm going to begin with some preliminary comments about our first quarter results and then I'll turn the call over to our Chairman and CEO Larry Nichols for his thoughts on the quarter and the outlook for the future. Following Larry's remarks, our President John Richels will provide a financial overview of the quarter. And then Devon 's new Executive Vice President of Exploration and Production Dave Hager will review operations. We will conclude the call in about an hour, so if we don't get to your question during the Q&A period please feel to follow-up with us after the call. And as always we will ask everyone to -- that asks a question to limit it to one question and one follow-up. A replay of this call will be available later today through a link on our home page. And during the call today we're going to update some of our 2009 forecast and estimates based on actual results for the first quarter. Since the revisions are pretty minor we are not issuing a new 8-K, but we will post those changes to our guidance on our website. If you want to find those just click on the estimates link found in the investor relation section of the Devon website.

Please note that all references in today's call to our plans, forecast, expectations, and estimates are forward-looking statements under U.S. Securities law and while we always attempt to be as accurate as possible there are many factors that could cause our actual results to differ from our estimates. And so we would urge you to review the discussion of risk factors and uncertainties that we provide in the Form 8 K with the forecast, the last one was issued on February 4.

One other compliance note, we will refer today to several non-GAAP performance measures. When we make reference to these measures we're required to make certain disclosures under securities law. Those disclosures are available on our website at Devonenergy.com.

Before I turn over the call to Larry I want to comment on the noncash impairment charge that led to the quarterly loss that we reported today. We went through in in detail in the February call, but because deteriorating natural gas prices in the first quarter triggered another ceiling test writedown it probably merits a repetition of that discussion.

The SEC requires companies that utilize the full cost method of accounting and that's the one that Devon follows to implement a stringent impairment test at the end of each quarter. The test consists of comparing the net book value of our oil and gas properties less the related deferred income taxes to a calculated maximum carrying value or ceiling. The ceiling is the estimated present value of the after tax future net cash flows from our proved oil and gas properties plus the book value of any unevaluated properties. The ceiling is calculated using oil and gas prices and costs in effect on the last day of the quarter but held flat and discounted at 10% per annum. We then compare the net book value of our oil and gas properties less deferred income taxes to the ceiling. Any excess is written off as expense.

Based on the first quarter 2009 ceiling test calculation we took an after tax charge of $4.2 billion in the first quarter. This charge is almost entirely attributable to lower U.S. natural gas prices while oil prices improved slightly during the first quarter, natural gas prices slid significantly and our U.S. production is roughly 75% natural gas. I'll remind you that this charge has no impact upon cash flow or cash balances and is unrelated to the intrinsic value of Devon's oil and natural gas reserves. A misconception about the full cost ceiling test adjustment is that it results in writing off oil and gas reserves, this is not the case.

The reserves estimate is independent of the ceiling test. The ceiling test adjustment is purely a financial statement event and has no impact on oil and gas reserves in the ground. The main criticism of the full cost ceiling test has always been that it's based on oil and gas prices in effect at a single point in time. And because of that, price volatility can result in anomalies at the end of an accounting period that lead to an impairment charge that is not indicative of fair value. These issues have been recognized by the SEC with a recent change in the rules. Under the new rules full cost companies will use a 12 month trailing average oil and natural gas price rather than the prices on a single day at the end of the accounting period. Unfortunately those rules don't take effect until the end of 2009. Had we had the new rules at the end of the first quarter we would not have taken this noncash charge.

Unlike the test for companies using successful efforts the full cost ceiling test uses discounted future net cash flows based on the end of the quarter prices. This makes the test for full cost companies more severe than the test for successful effort companies that can use undiscounted cash flows based on expected oil and gas prices. Consequently the full cost accounting method often results in a more conservative carrying value for oil and gas properties. While the write down impacts our balance sheet it does not impact liquidity or compliance with our banking agreements. Devon's bank credit agreements have only one significant covenant and that is a maximum debt to capitalization ratio of 65%. Under the terms of our credit agreements noncash charges such as the ceiling adjustment are added back to capitalization reflecting the fact that our banks agree that these accounting adjustments do not impact the underlying value of our business. Accordingly for purposes of our credit agreements our debt to cap ratio was 21% at March 31. With those items out of the way I'll turn the call over to CEO Larry Nichols.

Thanks Vince, ad good morning everyone. The first quarter of 2009 as we all know continued to present a very challenging environment for our industry. While oil prices did stabilize and improve somewhat realized natural gas prices in most of North America were weak the entire quarter. In spite of these challenges Devon had a very good quarter. Total oil and gas production was up both on a sequential quarter basis and on a year over year basis. And based on our first quarter results we are reconfirming our production guidance of somewhere between 235 million and 241 million BOE for the full year. That's the number we gave you earlier.

Our production growth was driven by record production from several fields that included the Barnett shale, the Arkoma Woodford shale, the Powder River Basin, all of those had record production and we continued to ramp up the Jackfish as planned up in Canada. The earnings before the impairment charge were well above expectations due to higher than forecasted overall production, lower than expected operating costs, better than expected performance from marketing and and Midstream and a lower than expected overall tax rate. As a result, excluding those items that analysts do not forecast we earn $216 million or $0.48 per share in the quarter. This is about 20%, -- $0.20 above the First Call estimates. And finally, in spite of dramatically lower oil and gas prices we generated roughly $1 billion in cash flow from operations.

Now, looking ahead the challenging commodity price environment will likely persist through the remainder of 2009, that's been our view for sometime. In spite of significantly reducing our rig count in the first quarter of this year Devon actually increased natural gas production as a carryover from our robust activity levels in 2008. While we're confident that lower activity levels will eventually correct the oversupply situation that exists for natural gas in the United States now, and the cost will decline further, it does take time for these effects to fully manifest themselves. We have seen costs begin to decline, however at current natural gas prices if you hold those flat forever almost all domestic gas drilling is still sub economic.

In light of this we are continuing to execute the strategy we outlined at the beginning of the year. That is to decrease our activity over near term developmental projects in North America, to continue to advance our longer term development projects like our second Jackfish SAGD project in Canada as well as our tertiary developments in the Gulf of Mexico, and to continue to drive costs lower and to maintain our strong liquidity position until we see signs of the recovery in the hydrocarbon markets.

The success that we have had in the deep water lower tertiary as well as the Jackfish SAGD projects in Canada have resulted in growing long-term development commitments. While these long-term projects provide tremendous opportunity even for a Company of Devon's size and scale the increasing share of our budget directed to these longer term projects effectively reduces capital available to develop our near term portfolio and thus limits our flexibility to adjust capital expenditures to changes in cash flow particularly in these times of low commodity prices. For example, our current capital budget for exploration and development projects is somewhere between 3.5 billion and $4.1 billion. While we have historically devoted 10 to 15% of our capital to longer cycle time projects today more than a third of our 2009 E&P budget is dedicated to those longer term projects. In many ways we're victims of our own success.

We believe that it is prudent not only for current budget considerations but for future years as well to limit our capital allocation to these long-term projects. Accordingly, we're announcing today a plan to pursue a partner to participate in the lower tertiary projects in the Gulf of Mexico. We are one of the larger independent acreage holders in the play and in fact our average interest in the exploration blocks is over 50%. The benefits to a potential partner would be to obtain an interest in four significant oil discoveries plus a share of our exploration prospect and leased inventories. Our share of the four discoveries alone represents up to a 100 million barrels of net resource -- 900 million barrels of net resource, didn't mean to scare the whole team and everyone in one fell swoop, let's go back to 900, the number we've given you for a long time. This is a very valuable package.

We believe that this opportunity will have appeal to large companies around the world. For Devon our share of the ongoing capital commitments would be reduced while we would of course maintain and keep a meaningful interest in the play. We expect to open a data room to potential partners within the next several weeks and we will see what kind of interest that generates. Fortunately we are under no pressure to execute a transaction and will not part with these valuable assets in any kind of a discount. With that I'll turn it over to John Richels. John.

Thanks Larry, good morning everyone. I'll begin by looking at some of the key events and drivers that shaped our first quarter financial results and review how these factors impact our outlook for the remainder of the year.

Let's begin with production. In the first quarter we produced 61.6 million equivalent barrels or approximately 685,000 barrels per day. This exceeded the top end of our guidance range by over 2% or nearly 15,000 barrels per day. Better than expected results from Barnett shale, lower royalty rates in Canada and restored volumes in the Gulf of Mexico provided the upside to our first quarter performance.

When you compare our production results to the first quarter of 2008 you will find that Companywide volumes increased by 45,000 barrels per day or about 7%. Led by the Barnett shale the U.S. onshore region grew production by 17% or 63,000 barrels per day over the same quarter a year ago. Canada also contributed significant growth of 14% year over year due mostly to the rampup of production from the Jackfish SAGD project. In aggregate Devon's North American onshore assets delivered growth of over 16% over the first quarter of 2008. The onshore growth was partially offset by lower production from the Gulf of Mexico with natural declines and curtail MTHS due to hurricane Ike both contributing.

Our international production declined by 19,000 barrels per day when compared to last year's first quarter and that's due almost entirely to a contractual reduction last year in Devon's share of production from the ACG field in Azerbaijan.

Looking ahead to the second quarter we expect to produce between 61 million and 62 million barrels equivalent essentially flat with first quarter production. Given the way our assets are performing we feel very good about our full year production forecast.

Moving on to price realizations, during the first quarter the benchmark WTI price averaged $43.18 per barrel, that's a 26% decline from the fourth quarter average. Our Companywide first quarter realized oil price average $33.61 or 78% of WTI which is right in the middle of our guidance range. That's an improvement from last quarter's average realization of 72% WTI. The most meaningful improvement to differentials was in Canada. After Canadian oil prices bottomed out at year end the unusually wide differentials at December 31, improved steadily through the first quarter.

On the natural gas side, the benchmark Henry Hub index declined to an average $4.91 per MCF during the first quarter. Our Companywide gas price realizations before hedges came in below the low end of our guidance range at approximately 76% of Henry Hub or $3.73 per MCF. Price realization during the quarter were especially weak in the U.S. Rockies and Mid Continent regions. In the first quarter our hedges protected 277 million cubic feet per day with a weighted average floor of $8.25. Cash settlements from most hedges increased our Companywide realizations by $0.48 per MCF giving us an all in price including hedges of $4.21 per MCF.

Looking to the remainder of the year we're not making any changes to our full year guidance. This reflects our expectation for U.S. onshore differentials to tighten somewhat as the year proceeds.

Turning now to our marketing and mid-stream division once again it delivered solid results generating $142 million of operating profit in the first quarter. Increased throughput and lower operating costs contributed to the first quarter performance. For now we're sticking with our guidance for full year operating profit of 375 million to $425 million.

Moving now to expenses, the first quarter lease operating expenses came in the bottom half of our guidance range at $524 million or $8.50 per barrel produced. Our first quarter unit LOE rate decreased by 9% when compared to the fourth quarter of 2008. During the first quarter we saw costs soften across many expense categories in most geographic regions. For the remainder of 2009 we anticipate continued downward pressure. Based on our first quarter results we're obviously off to a good start in meeting our full year guidance of $8.10 to $9.55 per BOE.

Moving to production taxes for the first quarter our production taxes as a percentage of oil and gas revenues came in at 2.8%, therefore we expect the full year production tax rate to be in the bottom half of our guidance range of 3.25 to 3.75%. Devon's first quarter DD&A expense for oil and gas properties totaled $599 million or $9.72 per barrel. This was a little more than $0.50 per barrel below the low end of our forecast range. The lower than expected DD&A rate was the result of recovering reserves at our Jackfish project in Canada. You may recall that these reserves were temporarily written off at year end due to unusually wide oil price differentials. As oil price differentials began to normalize during the first quarter these barrels came back on the books. Of course increasing the size of the proved reserve base without additional cost reduces unit DD&A. Looking ahead, the effects of our first quarter asset impairment will reduce our DD&A rate even further and we now expect our full year depletion rate to be between $7.50 and $8.50 per barrel equivalent produced.

Moving on to G&A expense Devon reported first quarter G&A expense of $166 million, that's 7% decline from the fourth quarter of 2008. Looking to the remaining three quarters of the year, we will continue to focus on curtailing G&A expenditures and expect costs to decline throughout the year. For 2008 we're targeting a 10% reduction in full year G&A. Shifting to interest expense, the first quarter came in at $83 million right in line with our expectations. When compared to the first quarter of 2008 reported interest expense decreased by 19%. Lower interest rates in decreased long-term debt balances drove our positive year over year comparison.

The final item I want to touch on is income taxes. After backing out the impact of the special items our adjusted first quarter income tax rate was 18% of pretax earnings which is composed of a 1% current tax rate and a 17% deferred tax rate. This was well below the guidance because of two main drivers. First, jurisdictions with tax rates lower than the U.S. primarily Canada, contributed a higher than anticipated portion of total first quarter earnings. And second, we recognized a $24 million reduction to current tax expense when a contingent tax liability was resolved to our benefit during the first quarter. Without the $24 million tax benefit our adjusted tax rate would have been 27%. So we anticipate income tax rates to be within our full year guidance ranges for the remainder of 2009.

Before I turn the call over to Dave I want to conclude with a quick review of cash flow and liquidity. In the first quarter of 2009 Devon's cash flow before balance sheet changes totaled $988 million. During the quarter we funded approximately $1.3 billion of exploration and production capital or about one third of our total E&P capital budget for 2009. This is right in line with our expectations as we wound down operation in the field throughout the quarter and completed our winter drilling program in capital. Non-E&P capital demands and payment of dividends brought total first quarter capital demands to about $1.6 billion or roughly $600 million in excess the first quarter cash flow. However, total debt increased by about $1.1 billion reflecting a significant reduction in other current liabilities during the quarter.

When we outlined our full year 2009 capital budget we were assuming full year average benchmark prices of $45 for oil and $5.50 for natural gas yielding cash flow of about $1 billion less than our 2009 capital demands. If natural gas prices remain at sub $4 levels that shortfall will grow. In this uncertain economic environment we believe that maintaining liquidity is paramount and we have many options at our disposal. These include reducing our exposure to long-term projects as Larry already mentioned, divesting noncore properties or given that we have one of the strongest balance sheets in our peer group as a last resort we could access public debt markets.

Despite the challenging business conditions we exited March with a very strong liquidity position of $2.7 billion of available cash and unused credit facilities. With a debt to cap ratio of only 21% as calculated under the terms of our bank credit agreements with total debt per proven BOE of just $2.85 and with our commitment to maintaining a conservative financial profile we continue to operate our business from a position of considerable financial strength.

At this point I'll introduce Dave Hager, Executive Vice President of Exploration and Production. Dave has more than 25 years of industry experience and I know that many of you already know him. Dave is not a newcomer to Devon, he's been a member of our Board of Directors, and we're delighted that he agreed to join the management team to head up our Exploration and Production activities. So with that I'll turn the call over to Dave for an update on operations. Dave.

Thanks, John. And good morning, everyone. Before I begin my part of the review I'd just like to comment how pleased I am to be part of the Devon team. This is an outstanding Company with high quality people, strong values and great assets. I will begin with a quick recap of Companywide drilling activity. Throughout the first quarter we tapered our rig count and by the end of March we had just 30 Devon operated rigs running. This is about the level of activity we expect to maintain for the remainder of 2009. In the first quarter we drilled 451 wells. Of those 30 were classified as exploratory of which 93% were successful. The remaining 421 wells were classified as development of which 99% were successful.

As John mentioned, capital expenditures for exploration production were $1.3 billion in the first quarter. We gradually reduced activity during the first quarter so our first quarter capital does not fully reflect the extent of the reduced activity. On the cost side of the equation we have seen deflation across many of our operating areas in the range of 10 to 15% since the beginning of the year. The amount of cost reduction we are able to realize varies by operating area and the extent of any preexisting contracts for goods and services. For example, in the Barnett despite having long-term contracts for rigs and pipe significant reductions in frac costs have still allowed us to realize a 15 to 20% savings and a total cost of drilling and completing a Barnett well. Companywide we expect to see our costs fall another 10 to 20% on average by the end of the year, as service costs continue to respond to lower commodity prices.

Moving now to our quarterly operations highlights we will start with the Barnett shale field in north Texas, where we're currently running eight Devon operated rigs compared with a peak of 39 rigs in the fourth quarter. During the first quarter we brought 122 Barnett wells on line. Our net production in the Barnett reached an all time high of 1.2 BCF equivalent per day in the first quarter, a 1% increase over the fourth quarter of 2008. This reflects the lag between reduced drilling activity and lower production. We now expect our net Barnett production to crest sometime during the second quarter before beginning an anticipated decline. However, when it makes sense to resume a high level of activity we expect to continue production growth.

In the Woodford shale and eastern Oklahoma Arkoma basin we are running three operated rigs and will continue at that pace for the remainder of 2009. We are achieving outstanding per well recoveries from our long lateral horizontals. In the first quarter we brought 11 operated wells on line with an average IP rate of 7.4 million cubic feet per day. These IP's point out how our results in the Woodford have improved over time. In late 2007 for comparison we're achieving per well IPs of about 2 million to 4 million per day.

Devon's net production climbed to an average of 79 million cubic feet of gas equivalent per day in the first quarter up 23% from the fourth quarter average and nearly triple the first quarter 2008 rate. In our recently announced Canaan Woodford shale play in western Oklahoma Devon has established the industry's largest lease position with 109,000 net acres. We currently have four operated rigs running. Much like we did in the early days of the Barnett we are focused on drilling wells across our Canaan acreage to fully evaluate and to derisk the resource. Production history from our 28 long lateral horizontals drilled to date indicate ultimate recoveries of between 5.5 and 9 bcf per well.

Also impressive is an early indication that initial decline rates could be as low as 50% in the first year. We need more drilling and production history, but early results look outstanding. Our first quarter net production from Canaan averaged 24 million cubic feet of gas equivalent per day.

Another objective in the Canaan is to establish production to hold key acreage with 5 TCF equivalent of net risk resource potential on our existing Canaan acreage we're eager to continue evaluating the play so that when natural gas prices rebound we are well positioned to move into full scale development. Canaan economics are enhanced by its liquid rich gas with as much as 1300 MMBTU per MCF in some areas. To capture this additional value we are building a 200 million cubic feet per day processing facility scheduled for startup in early 2011.

Shifting to the Haynesville shale I'll remind you that Devon has about 570,000 net acres in the greater Haynesville trend roughly equally divided between Texas and Louisiana. The highest rate wells drilled to date by the industry have been in an apparent sweet spot in Louisiana near the intersection of Red River, Bossier, and Desoto parishes. These wells tend to come on at high rates, some more than 20 million per day and then decline very quickly, as much as 85% in the first year with reported recoveries of approximately 7.5 BCF per well. We own the minerals under most of our acreage in eastern Louisiana and much of the acreage in Texas is held by production. So for the majority of our acreage we don't face near term lease expiration issues. The order of attack in evaluating our Haynesville position is dependent upon a variety of factors including where we have existing infrastructure where we have lease expiration issues and where acreage we view as most perspective. To date we have drilled five Haynesville shale horizontal wells all in our Carthage area of east Texas.

As we previously reported the first two wells suffered casing failures but we solved those problems in the next three wells which we completed during the first quarter. These three wells had average IP's of about 5 million a day. We brought these wells on very cautiously choking them back to avoid the casing problems we encountered in the first two wells. While we're not implying these wells could have the IPs that the rates encountered in the Louisiana sweet spot we believe these lower IPs are conservative. In addition, based upon early production data we believe these wells have shallower decline rates. Ultimate recoveries in the Carthage area are expected to range from 5 to 8 BCF per well. It is in the early days in the evaluation of the play and we expect our results to improve as we gain additional experience as they did in the Barnett and Woodford. However, the results in this area indicate that we have a repeatable, economically attractive play under a normalized price environment on our 110,000 net acres in this part of the Carthage acreage position.

We also have a very good acreage position in the southern part of the play which lies south of where most wells have been drilled to date. We have 47,000 net acres in the Sabine parish, Louisiana and the contiguous counties of Sabine, St. Augustine and Nacogdoches in Texas. While Devon has not yet drilled in this part of the play the technical data indicates this could be a very perspective area. We plan to drill up to five additional Haynesville shale wells in the remainder of 2009 including at least one well to test our acreage south of Carthage. Southwest of Carthage at Groesbeck we brought four high rate Bossier sand horizontal wells in the Nan-Su-Gail field in the first quarter. All four wells IPd at rates in excess of 10 million cubic feet of gas per day. Most notably is the Neil B 14H that IPd at 23 million a day and the Hale 17H at 19 million cubic feet per day. These wells helped drive our net first quarter production at Groesbeck to a record 107 million cubic feet of gas equivalent per day, up 24% from the first quarter of 2008.

Moving to the Rockies in the Washakie basin in Wyoming our net production averaged a record 118 million cubic feet of natural gas equivalent per day in the first quarter, up 23% year over year. We ran two rigs throughout the first quarter and drilled 10 operated wells. Both of these high efficiency rigs are under long-term contract and will continue to drill in the Washakie area this year.

In the Powder River Basin of Wyoming our net production averaged a record 114 million cubic feet of natural gas equivalent per day in the first quarter up 44% compared to the first quarter of 2008. Because coal bed methane natural gas production increases as the wells dewater we are now seeing the production ramp up from aggressive Big George drilling program in 2008.

Now shifting to the Gulf of Mexico, we continued appraisal and development work on four deep water discoveries in the deep water lower tertiary trend in the first quarter. At Jack and St. Malo, appraisal drilling carried out in the second half of 2008 provided valuable data for our resource estimates and facility designs. Partners are considering approval of a joint development concept for the two discoveries and have begun front end engineering design -- engineering and design work for the development in anticipation of a sanctioning decision next year. Devon has 25% working interest in both Jack and St. Malo.

At Cascade our 50% owned development with Petrobras, the project is progressing well. In the first quarter we drilled a Cascade number three well on the upside of a known fault and off structure to test the reservoir limits and further refine our resource estimate. The Cascade number three successfully encountered good quality sands with a thickness consistent with expectations but without economically recoverable hydrocarbons. The well was designed to penetrate an oil water contact but then be sidetracked up structure for a producing take point. Although the updrilling fault block continues to have up structure potential we changed directions and are now drilling a lower risk well in close proximity to the existing well bore on the down thrown side of the fault. Cascade number four is currently drilling and will be completed as a first producing well with a second producing well to follow shortly thereafter.

The FPSO is on track to arrive in the Gulf from Singapore in the first quarter of 2010. Installation work for the sub sea equipment has begun and remain on schedule for first production from Cascade in mid-2010. At Kaskida, the largest of our four lower tertiary discoveries appraisal drilling operations on the Keathley Canyon 291 number one well continued on after a brief drilling delay for rig modifications. Devon and co-owner BP are considering drilling an additional appraisal well next year with a possible production test to follow. Devon has a 30% working interest in Kaskida.

Moving now to Canada, at our 100% Devon owned Jack based thermal oil project in eastern Alberta well and reservoir performance continues to lead the industry. In March we were injecting steam in all 24 well pairs and our daily production hit a peak rate of 28,000 barrels per day. For the first quarter production averaged 21,000 barrels per day up 29% over the fourth quarter of 2008. We remain on track to hit 35,000 barrels per day later this year.

At our look alike project Jackfish two construction continues on schedule. During the second quarter we will focus on completing the construction camp and transporting plant modules to the site. In the Horn River Basin of northern Columbia we drilled the first of two planned horizontal wells in the first quarter as we continue to evaluate this play. A second horizontal well has reached total depth now and these wells will be completed later this year.

Moving to Brazil late last year we took possession of the deep water discovery drill ship under a long-term contract. The rig's first stop for us was in the Barreirinhas space in the northern coast of Brazil to drill an exploratory prospect on the BM Bar three block. Although the well encountered hydrocarbons it was noncommercial and has been plugged and abandoned. The rig has now moved 80 miles to the southeast to the [Arikogi] prospect located on block BM Bar one. Like the Bar three this prospect is also high risk. Petrobras is the operator and Devon has a 25% working interest. Following the Bar one well the rig will drill one well for another operator before moving to the Campos basin in the fourth quarter to drill a very exciting presale prospect on block BMC 32. Devon will operate the well with a 40% interest. We will also be participating later this year in well in a presalt well in the Campos Basin on block BMC 35. Devon will have a 35% working interest and is Petrobras operated prospect.

This concludes the operations update. At this point I'm going to turn the call back over to Vince to open it up for Q&A.

Thanks Dave. Operator, we're ready for the first question. We will remind you that we are asking you to hold your questions to one question and one follow-up.

(Operator Instructions) The first question comes from the line of Brian Singer from Goldman Sachs, please proceed.

Thank you, good morning.

Morning.

When you considered selling long lead time projects or doing a joint venture seeking a partner how were you thinking or do you think about the returns of risks of the lower tertiary versus the oil sands or Jackfish as a potential alternative source of proceeds? Are you explicitly choosing one over the other, should we read anything into that?

Well, first, we are not selling. It is, we're looking for a partner. It's not a sale per se. We want to maintain a -- we will maintain a continuing interest in that project. It's -- the problem is just the scope. Both of those projects are very successful, but the amount of capital that's required in the lower tertiary is significantly larger over the next several years than the capital required in Jackfish. We as the sole operator and sole owner of Jackfish we have greater capacity to control the timing of that. So they're both very good projects. They obviously have very different characteristics, but they're both very attractive projects.

Really Brian it really is not a question of a -- this isn't a return related question. As Larry said when you look at the capital profile in the deep water projects, we're in the fortunate position of having had a lot of success there. Those capital demands just continue to increase in 2010, 2011, 2012, so it's more related to that.

That's helpful, thank you.

And in essence Jackfish one is funding the cash flow requirements for Jackfish two. So we have already primed the pump so to speak up there.

That's helpful, thank you. My follow-up, I appreciate the color on the various plays and drilling results, could you speak to the well costs you're seeing, specifically in your various Haynesville areas as well in the Woodford.

Yes, I can address that. Currently on the Haynesville wells our first wells cost up on order of 11 million to $12 million, our most recent well is down around $9 million. We believe that we're going to be able to continue to drive those well costs down just as we have historically in the Barnett and other resource type plays. If you look up in the Northridge area our average drill and complete there is somewhere on the order of 6 million to $7 million, Canaan on the order of 8 million to $10 million, of course Barnett we're down around the $3 million or so drill to complete costs.

For those of you that don't know the Northridge area is our area of focus in the Arkoma Woodford shale.

Yes, thank you.

Thank you.

The next question comes from the line of Ellen Hannan from Needham and Company, please proceed.

Thank you. In terms of the costs on your Jackfish two project, with the declines in costs that we have seen across construction industries commodities et cetera, has that -- the cost to develop that second project come down materially was my first question? My second, my follow-on if you will is getting back to the Gulf of Mexico, how much of the percentage would you be comfortable selling down and do you give up any operatorship there?

Ellen, let me, on the first question on Jackfish two, we are seeing those costs come down somewhat. And but there's a good chunk of that that was committed, last year already as you can appreciate, long lead time items like the boilers and the turbines are things that we ordered early on even some of the steel. So some of that was locked in. What we're really seeing is that the cost of some of the services that we're contracting are coming down and of course we're getting a lot better access to labor. And we're building a project that we're pretty sure is going to come on on schedule and with the highest quality services. So it is coming down a bit. We had talked about the fact that that was going to be about a $1 billion project for us and we're still kind of in that range.

We are I might also add we're benefiting from the Canadian U.S. dollar exchange rate which has improved.

Right, that exchange rate has come down from about parity a year ago to somewhere, it's been fluctuating a little over $0.80.

The second part of her question was percentage we would be willing to sell down in the deep water Gulf and would we give up any operatorship?

Yes, in some of those projects obviously there already is an operator, BP or Chevron, so that probably wouldn't affect operatorship at all. Going forward on some of the undeveloped projects we own over 50% of those, so I really don't see that affecting operatorship. In terms of how much we might negotiate in -- that's really hard to tell, it depends on what the terms are. I certainly don't see us giving up any more than 50% as an absolute maximum. It's a hard number, I almost hesitate to say that because the headline is Devon to sell 50%, it probably won't be that much.

Great, thank you.

The next question comes from the line of Ben Dell from Bernstein, please proceed.

Morning guys.

Morning.

I guess my first question was around some of the commentary you made on the Haynesville. When you look sort of further out five, ten years time what do you believe the Haynesville could contribute to your volumes? I guess the second question I had was on the AUR that you mentioned, what sort of second year, third year, fourth year decline would you need to see to make that number achievable?

Well, as far as how much it's going to contribute over the long term, we're so early on in the evaluation of the play we have five wells across our 570,000 acres that we have in the play that it is really difficult to give a characteristic. We know that we have a very large resource in place underneath our acreage. We really need to get more penetrations across the larger span of our acreage before we really feel confident saying too much on how much can ultimately contribute. We're excited with what we have seen so far, but it's way early on to say how much it may ultimately contain.

We are, regarding the declines we are seeing some, as I mentioned in the remarks, we are seeing somewhat flatter declines we think in the area that we are at and you may see areas where there have been higher IP's on wells. And those declines then we anticipate will continue to shallow out in years two three, and four. I don't have an exact number for you. Frankly it's very early for us to be able to determine. Most of our wells have only been on on the order of 30 to 90 days. Our early indications are as I said we're confident ultimately in the 5 to 8 BCF is achievable in the Carthage area.

Okay. And I guess I'm not sure this counts as a follow-up, but if you do sell down in the lower tertiary as you plan what would you do with your rig commitments? Do you have plans to reduce your rig commitments or are you looking to sell those with the acreage or with the positions?

Well, we're evaluating our rig position right now. As most of you know we do have two deep water rigs in the Gulf of Mexico and one is working for us in Brazil. We do think that there's a possibility that we may need one less of those rigs and so we're in discussions with various companies out there about possible farm out arrangements on one of the rigs. It's not an absolute necessity that we do this, but we think from a cost management standpoint and able to control our -- not be obliged to force our exploration program to move quicker than we would be comfortable, it would probably be better to move one of those rigs out. So we're in discussion with various companies on that issue right now.

I'll remind you Ben that we talked before about the fact that we have fortunately have these rigs very advantageous day rates compared to many of the rigs that have been on the market. So we don't really see any issue if we decide to move that way.

Okay, great, thank you.

Your next question comes from Joe Allman from JPMorgan, please proceed.

Thank you, good morning everybody.

Morning Joe.

Just clarification on the CapEx could you just again state what your CapEx right now and has that changed from the prior CapEx?

We have not changed our estimate on CapEx for the year. We had talked range of CapEx 3.5 billion to $4.1 billion so.

That's for the E&P piece. Mid stream and corporate capital and dividends that will also present capital demands but they're all currently in line with our previous forecast, Joe. No changes.

Okay, got you. And then just in the Gulf of Mexico besides the lower tertiary activity was there anything else that went on in the first quarter?

No significant activity outside of the lower tertiary. So we, no.

Okay . All right, very helpful, thank

Thanks Joe.

Our next question comes from the line of Rehan Rashid from FBR Capital Markets, please proceed.

Morning. On your take away capacity from the Barnett shale area could you talk about kind of where we are in terms of incremental FT capacity and how that's going to play out for the rest of the quarter?

Yes, this is Darryl Smette, I'll answer that. As we said we currently have about 1.2 BCF of production that's coming out of the Barnett. Devon has a substantial amount of gathering capacity there along with two gas processing plants. And so between the gathering capacity that we have and plus the gathering capacity we have under contract with third parties, we have about 1.4, 1.5 BCF of gathering capacity out of there now without impression or additional line hooks. As we take gas away from the Barnett, we currently have in place about 1.2 BCF a day of firm transport. About another 300 million a day of contracts with end use consumers that have firm transport. So right now we're at about 1.5 BCF take away capacity out of the Barnett.

And just one point to your firm transport Darryl what was it at the beginning of the year and are you taking this to Transco all the way?

We do have a long-term commitment on Gulf crossing that will move gas Transco 85. That pipeline while its operational now it's not up to maximum capacity. Currently we're moving about 350 million a day on that pipeline. We have firm transportation on that system of 700 million a day. The total capacity available to Devon up to 700 million should be available we think mid-June to maybe mid-July.

Okay, thank you.

I might just add that on that Gulf South we also have the ability to move gas from Woodford shale area and our Carthage Haynesville play too. So we could use that firm capacity for all three of those plays.

So we should see good material improvement and realized prices.

I think you will see, you will see differentials capacities available and we see the additional pipelines being built out there. Once that capacity is available not only from Gulf Crossing but some of the other, the Kinder-Morgan line I think you will see start to see differential shrink and shrink substantially. You've already seen it if you look at the first quarter of this year differentials about $0.80 and the Carthage area the last two months that's been down to about $0.35 to $0.40. You already seen differential strength to 40% there -- or $0.40, $040, $0.50.

Thank you.

Yes.

The next question comes from the line of Doug Leggate from Howard Weil, please proceed.

Good morning guys.

Hi Doug.

Hi. A couple things. First of all on production guidance when you last spoke to us you suggested flat versus last year. But the first half was, the guidance was 660 to 670. You're now suggesting I guess 685 or thereabouts as the average for the first half of the year. So are we really expecting that much of a decline in the second half or are you thinking that things are looking a little better relative to 2008 at this point?

Doug, this is Vince. Obviously the first quarter was a little better than we expected so the assets are performing well. Still a lot of the year in front of us and as Dave mentioned we're winding down drilling activity in the first quarter. We want to see another quarter of history before we draw any concludes about where in the range we have put out we will be or consider changing the range.

Okay. Related question Vine, on the mid-stream guidance a pretty strong quarter in Q1 relative to the guidance for the year, so again same kind of question are we looking to move that guidance higher or how are you feeling about that right now?

Yes, this is Darryl, I'll take that one. Right now we're keeping our guidance where we have had it previously. Kind of echoing what Vince said, one of the things we're looking to see is how our wells continue to perform. If our wells continue to perform above expectation then we would probably increase that range in terms of what mid-stream will do. But since a lot of our gas goes through facilities that are mid-stream known, if that production would decline then the range we gave you are probably a pretty good number.

If I could risk just a quick follow-up on the Gulf of Mexico, on the lower tertiary sales are the any preemption rights with your partners there? That's it for me.

No, the answer to that's no

Okay, thanks.

And the next question comes from the line of Mark Gilman, from The Benchmark Company, please proceed.

Guys, good morning. Just a point of clarification on the partner issue if you would. Can I assume that the middle, lower Miocene properties are not included Larry in your stated intent here?

No, it's the lower tertiary, that's where the capital requirements are and as we have said in the early part the goal is to rebalance our capital expenditures, our long-term goal has been to have 10 to 15% of our capital budget in these long-term projects. That's where we have been for a very long time, many many years, we think that's the right place for us to be, we want to get back to that.

If I could just follow-up with respect to the Barnett, Dave traditionally companies utilize about a 20% in place assumed over life recovery rate. I'm wondering about your thoughts on that in the context of the number, potential number of 10 acre locations that you have defined up to this point?

This is Vince, I'll take a stab at that. It's not really an easy question, because our recovery rates across our expansive acreage position vary a lot depending on the specific local area that you're in. And so we have used a risk approach, there's large portions of our acreage that we think can be down spaced significantly and in fact we drilled a lot of infill wells during the first quarter with very good results. But, to draw a different conclusion about our overall respected expected recovery of the gas in place over a vast position I just don't think we're there.

Mark, another way to answer your question is last year I think last on March 28, of 2008, we gave an overall resource evaluation of the Barnett shale and I think if you look back at that or get with Vince I think it will give you a pretty good handle on how we are evaluating the potential of the various down spacing opportunities and the overall Barnett shale. Our evaluation has not changed significantly since that presentation.

Dave, maybe I could just ask how many 10 acre locations do you have at this point being identified?

I actually think we provided some detail on that in that resource update. I'll get with you offline on that Mark, we can--.

I don't think so, but please do.

Okay.

Yes, the thrust of your question is really important, and that is while we did hit a record peak in the first quarter for the Barnett with only eight rigs running we expect that to flatten and decline a little bit. But the resource we have there is still there. Once we get back to being really active we're by no means finished with our drilling in the Barnett shale.

In fact Mark you might remember that we when we provided our resource update we indicated that we have 7500 identified undrilled locations in the Barnett shale, so to go to Larry's point there's a lot of drilling potential there. Those are a variety of different types of wells, not all 10 acre infill wells obviously. There's many many years of drilling left for us on our acreage.

Not to beat it to death here, but in some acres 10 acres will work, in other areas 10 acres may not work as well. I think you need to look at it as an overall resource evaluation. I think that we gave a pretty good evaluation on that March 28, report. Again, get with Vince if you need more details.

Okay, thanks guys.

Next question comes from the line of David Heikkinen with Tudor, Pickering, Holt, please proceed.

Morning guys. Had a question on your future development cost $9.3 billion that has $2 billion of abandonment. How much that is for the lower tertiary?

We don't have at our fingertips, that's not something that we would mind disclosing at all, we just don't have details of abandonment cost in front of us.

Not abandonment cost, the development costs. Just trying to get an idea of what type of capital commitment you have in your four discoveries already?

I can give you an idea David on for the next few years we're seeing capital needs on the order of $800 million to $1 billion or so per year. For the four lower tertiary discoveries that we currently have. That's just over the next three to four year type timeframe. I don't have total numbers, an exact total number for you, David. But that will give you an idea of what we're looking at.

So a significant percentage of your total then, that's useful.

Yes.

The other question is an assumption it seems like on the call that you're going to sell for cash or joint venture for cash. Would you swap prospects, are you looking to do anything along those lines or is it just purely reducing interest and trying to garner some dollars?

We would certainly consider swaps, those are exceedingly difficult to do. But consistent with what we said the objective is. And the objective is not to generate short-term immediate cash, we have no real pressure there. The objective is really to reduce the long-term capital commitment and get it back in line with the overall budget. We really just had more success there than we have the cash flow to go forward with. So we would certainly consider a swap. Or just a pure farmout.

Okay, thanks.

The next question comes from the line of Tom Gardner from Simmons and Company.

This will be the last question that we have time for in the call.

And the final question comes from the line of Tom Gardner from Simmons and Company, please proceed.

Yes, I just wanted to get some more resolution on your ceiling test write down was the reduction all allocated to the U.S. calculation or was it spread across additional countries in which you operate?

It was substantially all in the U.S.

Okay. And just following up with some well economic questions if you will. Specifically the Canaan Woodford shale. Can can you give us an idea of what is going on with respect to the fact that the initial rate to AUR seems to be a little atypical for shale? What are you seeing there, what sort of long-term gags price do you need to make this attractive development for Devon?

Well, again, we are seeing strong overall AUR's on this, a little bit shallower decline on the Canaan than we have seen in some of the other areas. In general we feel a break even gas price on an NPV 10 basis is approximately $4 per MCF for the Canaan.

Okay. Thank you very much.

We have no further questions at this time. I would now like to turn the call back over to management for closing remarks.

Thank you. It's the appointed hour and we try to limit this to one hour, so thank you very much. We think we had a good quarter, looking forward to the rest of this year, take care

This concludes the presentation for today ladies and gentlemen you may now disconnect have a wonderful day.