德文能源 (DVN) 2006 Q1 法說會逐字稿

Welcome to Devon Energy Corporation's first-quarter earnings conference call. At this time, all participants are in a listen-only mode. (OPERATOR INSTRUCTIONS). At the request of Devon Energy, this conference is being recorded. If you have any objections, you may disconnect at this time.

I would like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. Good morning, and welcome everyone to Devon's first quarter 2006 conference call and webcast. As usual, I will lead off with some compliance and housekeeping items. Then our Chairman and CEO, Larry Nichols, will give you his thoughts on the quarter and the year ahead. Following Larry, our President, John Richels, will review operating highlights. And then our CFO, Brian Jennings, will cover the financial results and our outlook.

Following Brian's comments, we'll open the call for your questions. And as is our practice, we'll limit the call to one hour. However, feel free to phone us with any questions that we may not get to during the call.

I'm sure that by now, almost all of you know that yesterday, we announced that we had entered into an agreement to acquire the E&P assets of Chief. The transaction is essentially a $2.2 billion tuck-in asset purchase, and we expect to close it at the end of the second quarter. The Chief assets are located entirely in the Barnett shale of North Texas, and we had a conference call yesterday where we provided a very thorough update on the Barnett shale. We will summarize that today. But if you were unable to participate in the call and would like the more detailed discussion, a replay is available through a link on Devon's homepage at DevonEnergy.com.

We plan to file a form 8-K later today that will reflect adjustments to our guidance that include the impact of the Chief transaction. In today's call, we will make reference to some of those forecasted items. The 8-K provides additional detail. And we will send that out to those of you that are on our contact list later today once it is filed with the SEC. It will also be available on our website.

During the call today, we're going to make references to our plans, forecasts, and estimates. These are considered forward-looking statements as defined by securities law. There are of course a number of factors that could cause our actual results to differ from these estimates. And I would encourage you to review the risk factors that we provide with the forecasts and our filings with the SEC.

One file compliance item -- we will use metrics in our call today that are non-GAAP performance measures. When we use these, we are required to provide certain disclosures about those metrics. And we have made those available to you on our website.

With those items out of the way, I'll turn the call over to Larry.

Thanks, and good morning, everyone. While we did sort of upstage this call with our announcement yesterday on the Chief acquisition, Devon did enjoy a strong start to 2006 -- a very good first quarter. As we announced yesterday, we are increasing our long-term production forecasts for the 2007 through 9 timeframe, and now expect to deliver a compound annual growth rate of 11%, up from 8%, our previous estimate.

We reported first quarter net earnings of the 700 million, 24% ahead of last year. We reported earnings per share at an even higher percentage increase, 37% ahead of 2005, at $1.56 per diluted share. The greater increase in per-share earnings demonstrates the effect of the significant share repurchases that we carried out.

Since our last update, we repurchased 4.2 million shares at a cost of 253 million. This brings our total repurchases to over 56 million shares, which is about 11% of our outstanding shares.

First-quarter earnings per share were $1.76 when adjusted for items excluded in First Call estimates. And this puts us just about $0.04 under the First Call mean of $1.80.

Cash flow before balance sheet changes reached 1.5 billion in the first quarter of 2006. This is a 40% increase from last year. And we also increased Devon's quarterly dividend by 50% during the first quarter. This follows a 100% dividend increase in 2004, and a 50% increase last year.

Turning back to the significant increase in our growth forecast, this reflects the improving outlook we have for the performance of our overall property base. The strong reserve replacement performance that we delivered last year in 2005 and that we forecast again for 2006 -- that of course is beginning to translate itself into long-term production growth.

Even before the Chief acquisition, we were preparing to increase our production growth guidance for 2006 through 9 from our previous 8% compound annual growth to 9.5%. Since the Chief transaction added significantly to one of our premier assets, the Barnett shale, this further improves our growth outlook. Including the Chief assets, we now expect production growth to grow at 11%.

The production gains we expect in 2007 are being driven by three very specific high-impact projects [which are] on top of the continued strong performance from our dependable North American onshore core properties. The new projects coming onstream during 2007 are the ACG field in Azerbaijan, the Polvo prospect in Brazil, and Merganser in the eastern Gulf of Mexico. These three projects will come online at different times in 2007, but in aggregate [at peat] rates that will contribute more than 60,000 equivalent barrels per day of new production net to Devon. In 2008, we will have the advantage that each of these projects will be onstream for the entire year.

In addition, we will get production growth throughout the year from our 100%-Devon-owned Jackfish oil sand project in Canada. This double-digit production growth is a result of the investment strategy that Devon has steadfastly followed. We have continued to invest in building our low-risk North American asset base, and we have supplemented this with low-risk but measured meaningful investments in longer-cycle-time, higher-impact projects. Our organic growth outlook results from a demonstrable success in each of these areas.

For more details, I'll turn that over to John Richels. John?

Thank you, Larry. In the first quarter of 2006, Devon drilled 656 wells, with 90 wells classified as exploration, and 566 classified as development. Our success rate was 93% for the exploratory wells and 99% for the development group.

The first quarter is typically a busy drilling period for Devon. We had more than 150 rigs drilling on Devon wells during the peak of activity in the quarter, and finished March with 119 rigs at work.

Capital expenditures for exploration and development reflecting the disproportionately high level of activity in the first quarter were $1.4 billion versus our full-year forecast before the Chief acquisition of 4.3 to $4.5 billion. Canada accounted for more than half of our first quarter drilling activity with 339 wells drilled. About 99% were successful. This is fewer wells than we drilled in Canada last winter, reflecting our efforts to better balance our Canadian drilling program throughout the year.

This accomplishes two objectives. It allows us to more evenly and efficiently utilize our resources. And it also allows us to more effectively respond to stiff competition for drilling rigs and crews in the winter drilling season.

Our Lloydminster oil play in eastern Alberta is one of the areas where we are shifting to year-round drilling. In our first-quarter Lloydminster program we drilled 30 wells at Iron River and 45 wells in the Manatokan and [East Lake] fields. We expect to drill a total of 350 wells in the Lloydminster region this year.

Also in Canada, construction and welfare drilling at the Jackfish oil sands project in eastern Alberta and construction of the related access pipeline project between Jackfish and Edmonton continues on schedule. We have about 300 workers on site at Jackfish, and expect the workforce to peak at about 450 in the future.

We're continuing to evaluate our acreage just west of Jackfish as we move towards a commercial decision on a second SAGD project, Jackfish 2. To date, we have drilled 79 stratigraphic wells, and we're encouraged by what we've seen. Should we decide to go forward with Jackfish 2, we would expect to apply for regulatory approval later this year.

In Canada's far north in the Beaufort Sea, we completed drilling and testing of the Paktoa exploration well in March. The well encountered hydrocarbons, but not to the trillions of cubic feet of natural gas that we were looking for. However, we will be filing for a significant discovery license so that we can hold the mineral rights in the area in perpetuity.

Paktoa is the first well drilled in the Beaufort in more than 15 years. And we gather a large amount of data from the well. And we will evaluate this information to determine where to go with our far north exploration efforts.

I'll now review some of our onshore U.S. operations. As Vince mentioned, we held the conference call covering the Chief acquisition yesterday during which we provided an extensive update on the Barnett shale.

For those of you who might have missed the call, I will provide a quick recap of the Barnett shale update. Firstly, we have revised upward our outlook for the Barnett shale independent of the Chief acquisition. A major driver for that upward revision was the excellent results that we have seen from our 20-acre horizontal infill program. While other companies have drilled wells on 20-acre spacing in new areas, Devon is the only company with experience drilling horizontal infill wells in the mature producing area of the Barnett. This allows us to evaluate the effects of well interference on rates and recoveries.

Based upon the success of our infill pilot program, we have raised our estimated per-well recoveries from 1.8 BCF to 2 BCF. We now expect to ultimately drill infill wells on large portions of our acreage, both within and outside of the core.

Also, we're integrating our extensive knowledge and experience in the Barnett shale with advanced technology to improve well performance. The advanced technology that we are employing includes proprietary seismic interpretation technology developed in conjunction with a leading university which allows us to better select well locations, thereby avoiding geologic hazards and improving gas recoveries.

The positive results of those interpretation methods are clearly reflected in our well results, with Devon being the undisputed leader in the Barnett, having drilled 22 of the best 50 horizontal wells drilled in the field to date. This is more than three times the number drilled by the next closest competitor. Through the use of artificial lift and gathering system enhancements, we have also significantly improved field recovery in several areas.

While at the time of the Mitchell acquisition, we expected to ultimately recover 9 to 10% of the gas in place in the core Barnett, we increased this to 10 to 12% in 2004. And presently, we estimate our recoveries will be in be 16% of the gas in place.

That equates to an increase of more than 1.25 trillion cubic feet net to Devon's interest in the core area alone since 2004. We plan to apply those same technologies and efforts to our noncore areas, as well as to the leases that we have acquired from Chief.

Our extensive experience in the Barnett shale is being reflected not only improved well performance, but also in improved drilling efficiency. By way of example, we have reduced our average drilling time in Johnson County from 33 days in 2005 to 18 days this year. Following the close of the Chief acquisition, Devon will hold over 3 trillion cubic feet of proved reserves in the Barnett and over 700,000 net acres. With our existing knowledge and acreage base, we expect to book a minimum of an additional 5.6 trillion cubic feet in the upcoming years. And ultimately, with further infill drilling and additional experience in the play, we believe that we could nearly double the additional bookings to over 10 trillion cubic feet.

If you missed our call yesterday and would like a more thorough update on the Barnett, I would encourage you to listen to the replay that Vince mentioned is available on our website at DevonEnergy.com.

Looking now at our new shale play in the Arkoma Basin in eastern Oklahoma, competition for land is intense, but we've increased our holdings to almost 90,000 net acres. We now have five rigs drilling, including three operated by Devon, on our Woodford acreage in the Arkoma. We have spudded 10 horizontal Woodford wells year to date.

As we previously mentioned, our economic target for Woodford wells assumes initial production of 2.1 million cubic feet of gas per day and an average well cost of $3 million. However, one of our working interest wells recently came on at more than 5 million cubic feet per day. Although we're still in the data gathering stage with this play, we're becoming increasingly optimistic about it.

Moving to East Texas and North Louisiana, we have five rigs running in the Carthage area. And at the end of the first quarter, we were drilling the 23rd well in the current program. Our production at Carthage continues to climb and average nearly 225 million cubic feet equivalent of gas per day net to Devon's interest in the first quarter.

We have another good story developing in the Groesbeck area of East Texas, where we are drilling horizontal wells in the [Nansugale] field. We drilled two 100% working interest Devon wells that [IP'd] at impressive rates, one at 11.5 million cubic feet per day, and the other at 13 million per day. These rates are more than 4 times that of a typical vertical well in the field, but cost just 2.5 times as much as a vertical well to drill and complete. We expect to recover over 5 BCF of gas from each of these wells, and we have plans to drill a five-well program. We also have additional acreage with development potential in the area.

We also have encouraging results to report on the North Louisiana Bossier play, where we hold 200,000 net acres. We continue follow-up drilling to our Devon-Donner [1 1] discovery well on the Vixen prospect in the first quarter. This discovery well encountered a thick, gas-bearing Bossier section. But the key to productivity in these wells is finding the right combination of porosity and permeability. We're working with our recently acquired 3-D seismic data at Vixen to try to find that sweet spot.

On another of our seven identified Bossier prospects, we drilled a discovery at East Vernon in the first quarter that looks very promising. The [Spillers 18-1] well logged pay in several Bossier intervals, and the first three frac intervals tested at a combined rate of more than 20 million cubic feet of gas --

(technical difficulty)

-- both sidetrack wells have been drilled on the Merganser field in the Atwater Valley area.

Construction of the Independence Hub is ongoing and on schedule, with flowline installations slated to begin by the end of the second quarter. We expect first production early in 2007. Merganser will produce, as I said, into the Independence Hub at about 50 million cubic feet of gas per day net to our interest.

At Magnolia -- you might recall, this is our deepwater development project with ConocoPhillips on [Garden Bank 783]. We completed the seventh producing well in the first quarter. Operations to sidetrack and deepen the eighth producer are currently underway. Magnolia is now producing over 10,000 barrels of oil equivalent net to Devon's 25% working interest share.

Moving to deepwater Gulf exploration, the much anticipated production test on our Jack lower Tertiary discovery is currently underway. Completion operations began in March, and the production test will likely continue into June or July. Because this is the first production test of a deepwater Gulf of Mexico well drilled to the lower Tertiary formation, the results of the Jack test have far-reaching implications beyond this one discovery, and are of intense interest to the industry.

Given the significance of the results, Chevron, the operator, and the other Jack partners are keeping this well data tight. Consequently, we have no results on Jack to share with you today. I will remind you that Devon has a 25% working interest in Jack, one of three Devon discoveries in the lower Tertiary trend.

We are currently participating in another wildcat well called Kaskida. This well is operated by BP, and is located in the Keathley Canyon area on block 292. Keathley Canyon is west of the Walker Ridge deepwater area where our three lower Tertiary discoveries, Jack, St. Malo, and Cascade, are located. Devon has several prospects in Keathley Canyon, so success with this well could have positive implications for future exploration. Devon is earning a 20% working interest in the Kaskida well, which is also designated as a tight [hold].

In our deepwater Miocene program, drilling of the Caterpillar well that we mentioned in February conference call has been delayed until June or July due to rig availability. Caterpillar, you might recall, is a 28,000 foot subsalt Miocene test on Mississippi Canyon 782. Caterpillar is operated by Chevron, and offset Chevron's Blind Faith discovery. Devon has a 25% working interest in the well.

On the Gulf of Mexico shelf, the Mamba well on West Cameron 537 that we mentioned in our previous call was unsuccessful, and was abandoned.

Moving now to international, production remains constrained at our Panyu field, offshore China. Repairs to the production riser that we mentioned in February should be completed this month, allowing us to increase net production by about 5,000 barrels of oil per day over the next few months. We also drilled two new wells in the first quarter at Panyu that again extends the proven limits of the field.

The Panyu field has already exceeded our original expectations, producing more than 55 million barrels of oil since 2003. Proved estimated ultimate recoverable reserves at Panyu have increased more than 50% since this project was sanctioned.

In the first quarter of 2006, Devon determined that the Pina exploration well on block 256 offshore in Nigeria was not commercial. This resulted in the $85 million impairment charge that we announced last month.

We plan to continue our Nigerian offshore exploration program. Block 256 is a very large offshore block, and Devon has several additional prospects on block 256. We expect to drill another test well on the block late this year or early in 2007. In addition, we are conducting seismic evaluations on offshore block 242 this year, and plan to drill an exploratory well on that block in late 2006 or early in 2007.

In Brazil, our Polvo development project on offshore block BM-C-8 is moving ahead on schedule towards first production midyear 2007. Ongoing work on the project includes conversion of the FPSO, fabrication of the jacket and deck, and refurbishment of the platform drilling rig. In addition, pile fabrication is progressing in Brazil, and selection of the pipeline installation contractor has been completed.

Also in Brazil, the exploratory well on block BM-C-30 that we mentioned last quarter was noncommercial. Devon had a 25% working interest in that well. The same rig is preparing to drill another exploratory well on block BM-C-32. Devon will operate this well with a 40% interest, and it has an estimated 500 million barrel reserve target.

So that concludes the operations update. I will turn the call now over to Brian Jennings to review our financial results and outlook. Brian?

Thanks, John. We will take a brief look this morning at our first quarter results and our outlook for the remainder of the year. The announcement yesterday of our acquisition of Chief will impact our revenue and expense outlook going forward. However, given Chief's size relative to Devon, and the large amount of the value we attributed to undeveloped acreage, the expected financial impact of the Chief acquisition to our 2006 outlook is de minimis. As Vince mentioned, we will be issuing an 8-K later today that will provide a detailed update.

Let's begin with production. Devon reported first-quarter 2006 production of 51.1 million barrels of oil equivalent or approximately 568,000 barrels per day. That was 1.1 million barrels greater than our recently revised first quarter forecast. Favorable royalty rates in Canada and strong production in the Gulf Coast region contributed to the improvement.

For those of you comparing this result to last year's first quarter, our first quarter 2005 results did include volumes from properties we later divested. It is important to note that during the quarter, we deferred 3 million barrels of oil production. The primary drivers were hurricane downtime in the Gulf, which accounted for 2.3 million barrels of the total, and repairs to the production riser at Panyu, which accounted for about 0.5 million barrels.

As a consequence to the 3 million barrel deferral, first-quarter production from our retained property declined 2% on a year-over-year basis. Had it not been for the curtailments, our retained property base would have delivered 3% year-over-year organic production growth driven by our North American onshore assets, which delivered 4% organic growth in the period.

First-quarter production did decline 2% on a sequential quarter basis. The biggest driver was a 12% decrease in our international production due principally to problems at the Panyu field as well as some downtime we experienced at the Exxon-operated Zafiro field in Equatorial Guinea.

Looking forward to the second quarter and the remainder of the year, we expect production to build as Gulf of Mexico volumes come online, Panyu repairs are completed, and North American onshore volumes continue to increase. We forecast second quarter production to come in at 52 to 53 million barrels, and remain confident that we will deliver the increased 217 million barrel full-year guidance we disclosed yesterday.

Reflecting the Chief acquisition, we now expect 2007 production to total 241 million equivalent barrels, up from our previous guidance of 234 million barrels. That's 11% year over year.

Shifting to price realizations, during the first quarter, the WT benchmark price averaged $63.41 per barrel. As a result of the higher WTI price and the exploration of our oil hedges at year-end 2005, Devon's realized oil price for the first quarter increased 55% over the first quarter of 2005 to $53.35 per barrel.

Overall, our companywide oil price realizations came in at about 84% of WTI, just above the midpoint of our guidance. Prices were especially strong in the Gulf of Mexico and international segments.

Weaker price realizations in Canada, coming in at only about 60% of WTI, partially offset these strong realizations. Lower Canadian realizations resulted primarily from temporary restrictions in regional refining capacity. Canadian price realizations have improved with the restoration of this capacity.

Moving now to natural gas prices, the benchmark Henry Hub price averaged $9.01 per Mcfe in the first quarter. This is 31% lower than the fourth quarter of 2005.

For the quarter, companywide price realizations were 79% of Henry Hub, which was at the bottom half of our guidance range. U.S. onshore and certain Gulf of Mexico realizations were especially low relative to Henry Hub, coming in at the bottom of our forecasted range. This wide differential in the first quarter in the U.S. resulted from strong Henry Hub prices due to lower natural gas supply from the Gulf of Mexico combined with warm winter weather in many of our producing regions.

Producing regions west of Henry Hub without transportation access to eastern U.S. markets did not experience the same price increase. Consequently, differentials for these regions widened.

Looking forward, we believe our full-year price realizations will still be in line with the guidance we previously provided for oil and gas price differentials. For the second quarter, we now expect natural gas price realizations to approximate 104% of NYMEX for the Gulf, 81% of NYMEX for the U.S. onshore, and 85% of NYMEX for Canada.

Before we move to expenses, I want to briefly cover our marketing and midstream results. Driven principally by increased gas throughput, we reported first quarter marketing and midstream operating profit of $123 million. That is a 45% increase compared to the same period a year ago.

For the full year, we had previously forecast marketing and midstream operating profit of 360 to $400 million. Based on our first quarter performance, we look to be ahead of that guidance. However, we are not at this time going to revise our full-year guidance.

Turning to expenses, our first-quarter lease operating expenses were in line with our guidance, coming in at $6.83 per equivalent barrel. Higher ad valorem taxes, the consequence of higher commodity prices, and upward pressure on oilfield supplies and services are not new stories. Additionally, Devon's reported costs are being impacted by the continued strengthening of the Canadian dollar and hurricane downtime.

Looking ahead, we will increase our full-year 2006 LOE guidance by approximate $10 million, reflecting the impact of the Chief acquisition. That's an increase of less than 1% over our previous outlook.

For the quarter, our DD&A expense came in at $9.92 per barrel, which was above our guidance. This variance is primarily attributable to the impact of cost inflation on our estimated future development expenditures. Consequently, we are increasing our full-year guidance range for DD&A to $9.90 to $10.30 per barrel. The revision does include an increase in the DD&A rate of $0.20 to $0.30 per barrel for the last half of the year as a result of the Chief acquisition.

Our reported G&A expenses for the quarter were in-line with our guidance at $90 million. Of this total, approximately 6 million is related to stock option expenses that pertain to the new FAS 123 accounting rules. If you exclude this non-cash expense, G&A was essentially flat to our fourth-quarter 2005 expense. Looking forward, we do expect the Chief acquisition to add approximately 10 million to our second-half G&A expenses.

First-quarter interest expense came in at $101 million, right in line with our expectations. We expect our second-quarter interest expense to be essentially flat to the first quarter. Looking forward, borrowings used to finance to the Chief acquisition, partially offset the August retirement of 675 million of maturing debt, will result in an increase in interest expense in the second half of the year. We now forecast interest expense in the second half of 2006 to come in at approximately $115 million per quarter.

Income tax expense for the quarter increased to 38% of our reported pretax income. During the quarter, we recognized an $85 million non-cash impairment related to our Nigerian exploration activities. The tax rate was higher than the midpoint guidance because this impairment was not deductible for tax purposes. Backing out this non-cash item, we would've reported an adjusted current rate of 25% and a deferred rate of 10% for a total tax rate of 35%. This was right in line with our full-year guidance. As is customary, we are providing a reconciliation table in today's earnings release that shows the effects of these items that are generally excluded from analyst estimates.

And with that, I'm going to turn the call back over to Vince and open up the call to Q&A. Thank you.

Operator, before we go to Q&A, we have become aware that our webcast provider had an interruption of service for about five minutes. I just want to remind those that are on the call via the webcast that there will be a replay available later today through a link on Devon's website. And with that, operator, we're ready to take the first question.

(OPERATOR INSTRUCTIONS) Benjamin Dell, Bernstein.

My question is really just focused on the free cash flow generation. Obviously, CapEx was relatively high looking at your full-year guidance. And free cash generation was about 120 million. You mentioned yesterday your ambition [sort of by] to reduce debt. If the current commodity prices continued, would you see your debt staying flat? And if so, would we have to wait until 2007 to see any sort of resumption of buybacks from here? And part of that is do you see your CapEx sort of being pushed up to the upper end of your range.

You know, Ben, yesterday in our call we announced our intention to suspend until later in the fall our buyback program. Obviously, our decision to invest in the Chief acquisition -- making that decision, we felt it was a greater way to deliver shareholder value to our shareholders than repurchasing stock.

In the near term, obviously, commodity prices are going to drive that free cash flow capacity of the Company. You asked whether we would be repaying debt, and the pace at which we would be repaying debt. We've got 675 million that matures in the summer. We will be retiring that. We expect to conclude the year as we indicated yesterday with a net debt to cap ratio back down around 20%.

Our decision to finance the transaction using shorter-maturity debt, floating-rate debt evidences our commitment to get the debt repaid as fast as we can. We think that creates a tremendous amount of value to shareholders too. But as you point out, we have got obviously volatility to commodity prices -- in particular, natural gas. And we have -- 60% of our production is natural gas. So that commodity and the movement of that commodity and ultimately realizations will dictate the pace of debt repayment, and whether we will restart the buyback at some point later this year.

Okay, and just to follow-up on an old point. On the international business, obviously production was relatively light there. And the history has been somewhat checkered. Have you had any further thoughts with regard to your ambitions for that -- expanding it, contracting it, or reducing the overall exposure you have [between] countries?

Ben, this is Larry. If you look at it going forward, as we said in the call, as John said, we see growth coming out as Azerbaijan next year. That is on target. We see Panyu coming back onstream, and those problems getting solved -- and Polvo, of course, our project in Brazil. So we look at those and see growth coming out of the international plays going forward.

With regard to the role that they play, that any country plays internationally in our overall portfolio, is going to be driven by success. If we have success in an area -- we have had two discoveries that are indicated in Equatorial Guinea. If we follow-up those and those prove to be large and commercial, then we will pursue them. In other areas like Angola where we had some dry holes, we got out.

So we're neither driven to get into or get out of international. We have a very solid core in North America. And if we can find areas internationally that will add to that, we will pursue them. If they don't, we won't.

David Khani, FBR.

My question is on ACG. If I remember correctly, it's about 30,000 barrels a day of that 60,000 number that you threw on is coming from ACG? Is that correct?

The exact amount depends on when it pays out. But we're estimating 30 to 35,000 barrels a day net to Devon's interest at payout sometime early in '07.

Right. So I guess the question is I guess of the full year -- and then when does that grow, or is that sort of net net 30 to 35?

Actually, due to the structure of the contract, the initial production will be the peak rate. And then the contractor's share will go down as we reach volumetric targets.

To the next split, okay. Could you talk a little bit about pricing of that oil -- and then also, maybe cash costs, so we can sort of try to figure out the back end of what the net margins are to you?

This is Darryl Smette. And it relates to the price of oil, of course, the oil out there as you may know is a sweet crude, about a 38 degree gravity crude. Typically, that has traded between $0.35 cents and $1.25 under WTI. I would also point out there are different ways to move the oil out of that area. And those costs usually are between $4 and $6 dollars a barrel. With the BTC pipeline being complete, we think the cost on that is going to be around 3 50. So 3 50 for transportation and another $1 for differential will give you a pretty good number off WTI.

And then because it's an override, you don't really have much cost beyond that?

Do not.

(OPERATOR INSTRUCTIONS) Van Levy, Dahlman Rose.

Yes, thank you. I just wanted to follow-up on the Bakken shale call yesterday. Out of the 169,000 acres acquired, what portion of that are purely undeveloped?

The portion of the 169 developed and undeveloped, Steve?

Van, when we look at that -- one way to look at it is that in 83% of the --most of the production comes from the core area right now. Now recognize that when you try and calculate developed and undeveloped acreage in a play like the Barnett, when we look at, for instance, 20-acre infills, they're in a developed -- what some may call the developed area of the field. But they also provide significant potential as we move to downspacing.

Generally speaking, most of the production from Chief was in the near-core or core area. We acquired additional acreage, over 107,000 acres in the noncore, which mostly was undeveloped acreage. And we also acquired some additional acreage out in the far west. That was about 49,000 acres. So that may be one way to look at it. But the classification on developed and undeveloped acreage gets a little bit more complex as you get into the infill drilling program.

Yes, in this field, there are some of the acres that are partially developed. There are none of them that are really fully developed in the sense that you mean. There are some that are more developed than others, but none of them are really coming anywhere close to being fully developed.

Okay. And in terms of your 20-acre downspacing, is this a program such that essentially, you're splitting up -- the shale there, I know, is -- you may tell me how many feet it is, but it's big and thick. And you're essentially just drilling layers of the shale?

Is that what's going on?

Van, real quickly -- the Barnett shale ranges from about 200 feet generally on average in the noncore to as much as 430 feet in the core area. We are actually drilling -- we drill 40s in the core, for instance -- 40-acre spacing units in the core. When we downspace, we drill in between those spacing units. So we're not drilling layers. We are actually drilling additional area within the Barnett shale.

(technical difficulty), Citigroup.

This is probably a question for Steve. You mentioned that the Jack test is underway, but they are tight holding the data. Are you privy to that data? And the second question is how would you change your project pipeline depending on the outcome of the Jack test?

Well, as John had mentioned in the call, that's a tight hold, so we won't comment on it. We do have direct access to all the information on the test, since we are a working interest partner in the well.

Relative to our lower Tertiary portfolio, we are very optimistic with our work to date with the three discoveries that we have. We also have a good inventory of prospects. We think -- we are relatively confident with a good result from the Jack test, we will be moving towards pushing them towards commercial development.

Now, recognize that the lower Tertiary spans quite a distance in the Gulf. And the results on one test in and of itself won't necessarily give us an indication of confirmation or not on the entire play. But we are confident. We're hoping for good results from the test. And that's the way we view the portfolio right now.

Is your current drilling program based on a successful Jack test or not?

No, our current drilling program is based on the risk profile -- you know, we look at our exploration program broadly, look at the portfolio of opportunities we have. We don't just focus on the lower Tertiary. And we try and drill a portfolio that is risk balanced and risk managed in order to deliver commercial results over a longer-term period. So we manage our portfolio that way, and not necessarily the results of one prospect.

Okay. And in terms of the inventory, can give us an idea of the prospects in those pipelines that are lower Tertiary additional wells that you're going to drill in the next couple of years?

Could you repeat the question?

Could you give us an idea of the pipeline of lower Tertiary prospects that you are going to drill in the next couple of years?

Well, we're continuing to [develop] -- I will tell you that we have beyond the three discoveries we currently have, we now have an inventory of about 18 prospects that we're continuing to move forward in the commercial pipeline. We are also bringing on a deepwater rig in the late part of this year, early next year. And some of those lower tertiary prospects will be mature to a point to where we will be drilling them over the next few years.

So the pipeline is going to move around a bit. But we think lower Tertiary will make up a complementary part of that pipeline. And certainly those 18 prospects -- we're continuing to work those to get them to a decision point on drillable status, probably beginning next year.

[Brian Tuslow], RBC Capital Markets.

Just on the East Vernon field, I was wondering if you could elaborate as to what your current acreage position is in that area -- thinking more long-term there?

In the East Vernon area -- I don't have the specific acreage number here. We have about 200,000 net acres in the area. East Vernon is the one of about seven prospects we have identified to date within there. We think the targets are ranging as high as around 200 BCF for the East Vernon prospect. And as John had mentioned earlier, a follow-on to this well would be probably as many as about six other wells in the development, and there will be dozens -- with success, there could be dozens of other developmental locations in the play. But I don't have the specific acreage numbers for that individual prospect at hand here for the call.

You might recall as well that of that 200,000 acres that we have, we have the mineral interests on about 75% of those acres. So that greatly increases our net revenue interests as well. So this is very profitable acreage for us.

Okay, and just one quick clarification -- all the forecasts you guys put together for production -- that excludes any type of acquisitions other than Chief, right?

No.

Well, yes, it does exclude any other acquisition --

Oh, I didn't quite hear -- we're having difficultly hearing that question. There were no acquisitions at all involved in the forecast.

(OPERATOR INSTRUCTIONS) Marshall Carver, Pickering Energy.

A couple of brief questions. I missed a couple of minutes of the call. Did you mentioned anything about 20-acre downspacing in Carthage? And could you give me an update their?

No, we did not discuss that.

Any updates on that? I know you're going to be doing some tests this year.

Yes, we're continuing to drill at Carthage. And we are moving forward with some of plans on 20-acre downspacing. And we're continuing to see some good growth from Carthage. We will see the results from the work that we're doing on the pilots and then apply those across the field and move forward with our developments.

Okay, and when would the timing of those pilots be?

I would expect over the next six months to a year, we'll have those results and be moving forward with the program or not based on those results.

And then on increased development costs assumption that's driving up DD&A, would that be since the 10-K was filed, or was that between in your reported year end results in the 10-K? I'm just trying to get a feel for whether I can use the future development costs in the 10-K in my NAV evaluation.

Those are the costs in the 10-K.

Tom Covington, AG Edwards.

In the Woodford shale play of the Arkoma Basin, can you tell me what sort of per-well recoveries you're expecting based on the 10 horizontal wells you have drilled to date?

You know, the most recent wells we have drilled in the quarter, we have seen per-well recoveries that could range from 3 to 5 BCF a well on the last two that we have been involved in in the last quarter. We drilled 10 wells in the play. And remember, we still believe it's relatively early in the play. We are accelerating into the play based on our results. We've moved up to three rigs. We're seeing initial production from some of the wells as high as 5 million cubic feet a day.

When we look at our economics going forward, to have a good solid play, we're targeting about 2.1 million cubic feet today as an average IP, and average well costs of about 3 million a well. So that's what we're moving toward. We think those will be good, solid results for a commercial play. And so far, we have had good, positive results that make us believe we can get there.

And the $3 million per well is a fairly stable number or is it rising, or is it --?

Actually, our experience in drilling -- as you can imagine, initially going into the well, we do a lot of science and experimentation both on formation evaluation and completion as we move into these plays. So the wells we have drilled to date have been a bit more expensive. But as we have moved forward with this drilling program, the well costs continues to drop. We haven't dropped below the 3 million number yet, but that is the target. We think we're going to be able to get down to that 3 million number and hold that relatively stable as we move into a development plan.

(technical difficulty) -- questions, I'll give you a sort of a brief -- what we think are the headlines. We think we're off to a good start here in 2006. Obviously, with first-quarter earnings growing 24%, topping 700 million -- earnings per share up 37%, those are good results. Barnett shale continues to improve both on what we have and what we are acquiring from Chief. Our major growth projects -- Canadian oil sands, Brazil, Azerbaijan, deepwater Gulf -- are all on track. Lower Tertiary deepwater test is underway.

And finally, based on the improving outlook that we have for our historical assets coupled with Chief, we're able to [bump] with some degree of real confidence that our compound annual growth rate will be 11% next year and for several years thereafter.

All in all, we think we're off to a very good start this year. And we thank you very much. Take care.