德文能源 (DVN) 2008 Q2 法說會逐字稿

Good day, ladies and gentlemen and welcome to Devon Energy's second quarter 2008 earnings conference call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. This call is being recorded.

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

Thank you, operator. Good morning, everyone, and welcome to Devon's second quarter 2008 conference call and webcast. Our Chairman and CEO Larry Nichols will not participate in today's call due to the death last Sunday of his father, John Nichols.

Instead, our President, John Richels, will begin with his perspective on the quarter, then Steve Hadden, Senior Vice President of Exploration and Production, will review operating highlights, then John will return and conclude with a financial review. At that point we'll open the call up to your questions, and as usual we'll ask that you hold your questions to one with one follow-up per participant. We'll try to keep the call to about an hour and a replay will be available today through our link on the home page.

During the call today, we're going to update some of our 2008 forecast and estimates based on actual results for the first half of the year and our current outlook for the second half of the year. In addition to the updates that we're going to give in today's call, we will be filing an 8-K later today that will provide the details of our completed updated estimates for 2008.

Please note that all references in today's call to plans, forecasts, expectations and estimates are forward-looking statements under US securities law. And while we always attempt to be as accurate as possible, there are numerous factors that could cause our actual results to differ from estimates, and therefore we encourage you to review the discussion of risk factors and uncertainties that is provided with the Form 8-K that we will file today.

One other compliance note. We'll 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. These disclosures are available on our website. That address is DevonEnergy.com.

I also want to point out that as a result of our decision to sell our assets in Africa and terminate our operations there, the accounting rules require us to exclude oil and gas produced from our African assets from reported production volumes. That's true for all periods that we're presenting.

Revenues and expenses for the discontinued operations are summarized in the discontinued operations line item at the end of the statement of operations. But we've also provided for your reference an additional table in today's release that gives a detailed statement of operations as well as production volumes attributable to the properties that we're divesting.

On a reported basis, discontinued operations this quarter includes a $647 million after-tax gain on the divested African properties.

As it has for several quarters, accounting for discontinued operations impacted the comparability of analyst earnings estimates this quarter. Most analysts chose to report to First Call numbers that exclude discontinued operations. The mean estimate of those analysts that excluded discontinued operations was $3.23 a share for the quarter. That compares to our non-GAAP earnings from continued operations of $3.28, so we came in a nickel over the consensus or mean estimate.

Also want to point out one usual item that reduced cash flow. There was a $295 million current tax charge that was attributable to the repatriation of cash from foreign subsidiaries during the quarter. The net proceeds from Devon's African divestitures, combined with repatriated cash from foreign subsidiaries, totaled approximately $3 billion in the second quarter.

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

Thanks Vince, and good morning, everyone. As Vince mentioned, John W. Nichols passed away last Sunday. John and Larry cofounded Devon, and John served most recently as the Company's Chairman Emeritus. The oil and gas industry was John's passion, and there are many things for which he will be remembered.

In 1950 he registered the nation's first public and oil and gas drilling fund with the U.S. Securities and Exchange Commission, which became an important funding vehicle for the industry for many years. He and his partners in the Blackwood & Nichols Company discovered the Northeast Blanco unit in the San Juan Basin in New Mexico, a field that is still producing 58 years later, with Devon as operator. His pioneering spirit continued in 1971 when he asked Larry to join him in the creation of Devon Energy Corporation with just four employees and no oil and gas assets.

In 1995, at an event honoring Devon, Larry made these comments about his father -- Devon has come a long way, and yet Devon is still exactly where we started. It still has all the characteristics John Nichols gave it. We're optimistic about our future, creative in solving our problems, resourceful in exploiting our opportunities, and above all else, honest in our dealings with everyone, and so the legacy of John W. Nichols lives on.

These words are as true today as they were when Larry said them more than a decade ago, and John Nichols will truly be missed.

Now, moving to the business of the quarter, beginning with the second quarter highlights, this was another quarter of outstanding financial performance. The results were fueled by our continuing production growth and the strength of oil, natural gas and NGL prices.

Second quarter reported earnings reached $1.3 billion or $2.88 per share, and as Vince has indicated, our non-GAAP earnings of $1.5 billion or $3.39 per share set an all-time record. Cash flow before balance sheet changes reached a record $2.7 billion in the second quarter, or $3 billion if you exclude the tax impact of the repatriation of foreign cash.

We grew our production of oil, natural gas and natural gas liquids from retained properties to 58.5 million oil equivalent barrels. That marks our ninth consecutive quarter of production growth. Our marketing and midstream business also delivered all-time record results, with quarterly operating profit exceeding $200 million.

And during the second quarter, we redeemed all of our outstanding preferred stock, thereby simplifying our balance sheet and eliminating about $10 million of annual preferred dividends.

With the sale of our assets in Equatorial Guinea closing for $2.2 billion during the quarter, we have substantially completed the African divestiture program. We expect to complete the remaining roughly $250 million of African divestitures later this year.

When we first announced our plans to exit Africa in January of 2007, we outlined our intentions for deployment of the proceeds. We indicated that we would allocate the proceeds to debt reduction and share repurchases, and we are doing just that. Upon receipt of the proceeds from the sales and repatriation of other international cash balances we repaid all commercial paper and other short-term debt balances. This brought our ratio of net debt to total capitalization to its lowest level in more than a decade, only 11% at June 30th.

Later this month we will eliminate the remaining debentures exchangeable into Chevron common stock that we inherited when we acquired PenzzEnergy in 1999. These securities mature on August 15th, and upon maturity, the indenture provides that the holders may receive either Chevron shares held by Devon or the cash equivalent, at Devon's option.

We intend to redeem all of the debentures with cash and are exploring the best ways to maximize the value of our 14.2 million Chevron common shares. These shares currently have a market value of about $1.2 billion.

As of June 30th, we had redeemed about 18% of the debentures at a total cost of $214 million, and so far in the third quarter we've redeemed another 10% of the debentures at a cost of $122 million. Redemption of the remaining debentures will require about $837 million in additional cash, assuming the current price of Chevron stock for those yet to be redeemed.

Even after the debt repayments that I've discussed, we'll have a substantial amount of additional cash to deploy in the second half of the year. As we have stated in the past, our priority is to allocate capital in such a way that maximizes growth in reserves, production, earnings and cash flow on a per debt adjusted share basis.

We have been and will continue to be in the market repurchasing Devon common stock. Our Board has authorized us to repurchase approximately 54 million shares or 12% of shares outstanding. During the first half of 2008, we deployed $302 million repurchasing 2.8 million shares of Devon stock. So far in the third quarter, we've purchased more than 3 million additional shares, bringing the total shares repurchased year-to-date to 5.9 million.

I will remind you that based on yesterday's closing price for Devon shares and a modest allocation of value to our marketing and midstream business of 8 times the trailing 12-months EBITDA, the purchase of Devon shares represents the acquisition of our proved reserves at a price of less than $16 per barrel.

And this analysis attributes no value to our thousands of unproved locations in the Barnett; no value to our four discoveries and 21 untested prospects in the Lower Tertiary; no value to our 483,000 net acres in the Haynesville Shale; no value to the continued expansion of our Jackfish SAGD complex; no value to the millions of unproven acres that we have established in other North American plays; and no value to our international exploration inventory.

It's hard for us to imagine an acquisition opportunity in today's market that would represent a more compelling value to us than Devon shares.

In addition to repaying $2.6 billion of debt and preferred shares and restarting our substantial share repurchase program, optimizing the value of Devon on a debt adjusted share basis calls for investing an incremental $1.7 billion in 2008 exploration and production projects.

This will result in full year E&P capital expenditures of $7.3 billion to $7.6 billion. A significant portion of this incremental capital is directed to additional acreage capture in North America, and increased investment in the Lower Tertiary trend to build upon our long-term opportunity set.

Steve Hadden will speak to these additional capital projects in his operations review, and I'll discuss the expected production impact later in the call. With that, I'll now turn the call over to Steve Hadden.

Thanks, John and good morning to everyone. I'll begin with a quick recap of Company-wide drilling activity. We drilled 494 wells in the second quarter. Of these, 16 were classified as exploratory and 81% were successful. The remaining 478 wells were classified as development, of which 98% were successful.

Our rig count averaged 130 rigs during the second quarter, and we peaked at the end of June with 143 rigs running, 92 of them drilling Devon-operated wells.

Capital expenditures for exploration and development were $1.7 billion for the quarter. This brought total exploration and development capital for the first six months to $3.5 billion.

As John mentioned, we've elected to leverage a portion of our robust cash flow and increase 2008 E&P capital spending. With our increased budget, we expect total reserve additions for the year to come in between 450 and 480 million barrels of oil equivalent. So the outlook for 2008 is once again to deliver very competitive finding and development costs with proved reserve additions far exceeding the year's production.

About $700 million, or roughly half of the increase is directed towards acreage capture and testing of emerging plays that will have little impact on 2008 production or reserve additions. This acreage, however, will provide additional opportunities to fuel future growth.

In our resource update in March, we disclosed that we held some 950,000 net acres in various emerging plays with unrisked resource potential of a little over 2.1 billion barrels of oil. Since that time, we've continued to acquire land and gain additional information allowing us to significantly derisk these emerging plays. Today we hold over 1.3 million net acres in these plays, with unrisked resource potential net to Devon of more than 8.5 billion barrels of oil equivalent.

This includes a significant position in the Haynesville Shale that I'll talk more about in just a minute and also includes more than 100,000 net acres in Canada's Horn River basin and nearly 600,000 net acres across two new unconventional gas plays in the Rocky Mountains.

We initially elected to refrain from saying much about Devon's position in the Haynesville Shale when it became a hot topic a few months ago. Instead, we continued to expand our knowledge of the play through drilling, coring, and testing activities. Our approach was to combine our local knowledge of East Texas, where we already produce more than 350 million cubic feet of gas equivalent a day, with our understanding of unconventional reservoirs. We've acquired this knowledge by drilling thousands of tight gas wells including more than 3,000 wells in the Barnett Shale.

Although we're not ready to share everything we've learned today, we will answer some of your questions about Devon's Haynesville position. We've been successful in adding acreage and today have approximately 483,000 net acres in the Haynesville Shale play area in Texas and Louisiana with more to come. This gives Devon the largest position announced to date.

Much of our Haynesville acreage is held by production from other zones that we're developing in the area. We have supplemented this with additional leasing. Enhancing the economics of our 483,000 net acres is a low royalty burden, averaging less than 20%. Much like our approach to the Barnett Shale, we're carefully assessing results and characterizing the shale to define and derisk the play, based on economics and repeatability.

Based on our mapping work to date, early estimates put the resource under our net acreage at almost 73 Tcf of gas in place. We are obviously very early in the life of this play, and more drilling and testing is needed to fully characterize this potential.

We expect to drill our first Haynesville horizontal in the third quarter. However, we have 14 vertical Haynesville penetrations, including three wells with full cores, four wells currently on production, and one well in the completion phase. During the second half of 2008, we will continue to evaluate our acreage, work to optimize location selection and accelerate development.

Now moving on to North America's most significant and best-established shale play, the Barnett Shale field in North Texas. There have been some recent comments by other operators that field life production might be nearing a top. We can't speak for those other producers, but this is certainly not Devon's view.

We believe our net Barnett production will nearly double over the next several years to as much as 2 billion cubic feet equivalent per day. And with 7,500 risked drilling locations, we have more than 10 years of drilling inventory in the Barnett.

We're currently running 32 Devon-operated rigs in the Barnett. In the second quarter, we brought 189 wells online at an average rate of 2.2 million cubic feet of gas per day. In select areas of the play, we've begun drilling long lateral horizontals, with outstanding results. For example, two Johnson County wells came online during the second quarter, each with IP rates in excess of 5.5 million cubic feet a day. These longer laterals are ranging from 3,500 to 4,000 feet, and typically require between 8 and 10 frac stages, with total well costs of about $3.7 million per well.

Our total net Barnett shale production averaged almost 1.1 billion cubic feet of gas equivalent per day in the second quarter, a record, and up over 7% from just the first quarter and up 34% year over year. We now expect to drill between 630 to 660 wells this year. We expect our net production to top 1.2 billion cubic feet of gas equivalent per day by year end and expect our net production to continue to grow for the foreseeable future.

Moving east, and shifting to our Cotton Valley drilling programs in the Carthage area in East Texas, in the second quarter we drilled 39 new wells as part of our 7 rig vertical well program. In addition, we recompleted 6 wells in the second quarter. We also continued to see good results from our horizontal drilling program in the Carthage area, with 4 rigs now drilling horizontal wells.

We completed 6 Cotton Valley horizontal wells during the second quarter, including the Swift 13H that IPed at 8 million cubic feet of gas per day. We plan to drill 12 additional horizontal wells this year at Carthage. In total, our Carthage production averaged a record 273 million cubic feet of gas equivalent per day in the second quarter, up 9% over last year.

Southwest of Carthage, at Groesbeck, we continued three outstanding 100% owned wells in the Nan-Su-Gail field in the second quarter. The Crenshaw 19H IPed at 20 million a day, the Crenshaw 15H at 15 million a day, and the Hill 12H at 13.5 million cubic feet a day. These wells helped drive our net Groesbeck production to a record 90 million cubic feet of gas equivalent per day. That's up 5% from the first quarter and 26% compared with the second quarter of 2007. East Texas is a powerful part of Devon's North American growth strategy, and with the addition of the Haynesville program, it should push us to a whole new level.

We're also generating new excitement in the Woodford Shale. We're achieving excellent results from the Devon-operated 4,000-foot lateral horizontals. As a result, our typical well in the Woodford now yields recoverable reserves between 3.5 and 4.5 Bcf with drilling costs in the $6 million to $6.5 million range.

Long lateral horizontals and our move to full scale development are starting to drive up our production. Our net Woodford production averaged 38 million cubic feet of gas equivalent per day in the second quarter, up 41% from the first quarter average and up 131% compared with the second quarter of 2007. We now have 6 operated rigs running and we brought a total of eight new operated wells online during the second quarter with initial production rates as high as 7.1 million cubic feet a day.

Moving to the Rockies, in the Powder River Basin in Wyoming we have three rigs currently running, including two Devon-operated rigs drilling in the Big George formation. We expect to drill more than 110 wells by year-end. Our net Powder River production averaged 88 million cubic feet of gas a day in the second quarter, up 12% from the first quarter average and up 46% compared with the second quarter of 2007.

We're on track to set an all time production record in the Powder during the third quarter and to exit 2008 above our previously announced target of 100 million cubic feet a day. The Powder River Basin produces natural gas from coal seams, and is another example of Devon's deep inventory of unconventional resources. We have more than 250,000 net acres in the basin.

Also in the Rockies, in the Washakie basin in Wyoming we had two rigs running for a good part of the quarter and drilled a total of 6 operated wells. We initiated drilling on our first horizontal well in the field during the second quarter. The well's currently nearing its total depth. We'll begin fracing the first of seven stages over the next few weeks and should have results for our third quarter call. Our net Washakie production averaged 111 million cubic feet of gas equivalent per day in the second quarter, up 16% from the first quarter average.

Now shifting into the Gulf of Mexico, I'll give you a quick update on our Lower Tertiary trend program. Appraisal operations continued at Jack and St. Malo, on both the Jack number 3 and the St. Malo number four appraisal wells. The owners in these two Lower Tertiary projects continue to work towards the selection of a final development concept, and expect to sanction development around year end 2009. Devon has a 25% working interest in Jack and a 22.5% working interest in St. Malo.

Also in the Lower Tertiary, in the second quarter we successfully completed appraisal operations on a sidetrack well on the Kaskida prospect at Keathley Canyon block 292. This was a re-entry in a sidetrack of the initial 2006 discovery well. We also plan to begin drilling another appraisal well at a new location late this year. BP is the operator of Kaskida with a 73.3% working interest, and Devon has a remaining 26.7% working interest.

At Cascade, our 50/50 Lower Tertiary project with Petrobras, we plan to begin drilling the Cascade number 3 well in the fourth quarter. This will be one of two initial producing wells at Cascade. The design and construction of the production facilities is progressing well. We expect to install the risers and an FPSO mooring system in 2009 as well as flowlines and gas export pipeline. First production from Cascade is planned for just two years from now in mid 2010.

In our deepwater exploration program, we have two additional Lower Tertiary exploration wells planned for this year. The Bass prospect, which is operated by Devon which a 50% working interest, is on Keathley Canyon 596 and is now drilling. We're also participating in a well expected to spud later this month on the Damascus prospect on Walker Ridge 581. This Lower Tertiary exploratory well is operated by Chevron, and Devon is participating with a 28.3% working interest. Both Bass and Damascus will likely be drilling through year end.

And finally, in the deepwater Miocene, after some mechanical challenges, we're drilling ahead on the North Sturgis well in Atwater Valley block 138. Devon has a 25% working interest in Sturgis North which is operated by Chevron.

Moving to Canada, in our Lloydminster oil play in Alberta we continue to be active with a five rig program. In the second quarter, we drilled 55 new wells. Total net production from Lloydminster averaged more than 42,000 barrels a day in the second quarter, up 12% over the second quarter of 2007. We remain on schedule for startup of our second 10,000-barrel a day expansion at our Manatokan plant in the fourth quarter to handle our growing production volumes.

At our 100% owned Jackfish thermal heavy oil project in Eastern Alberta, production continued to climb in the second quarter to 14,500 barrels a day at June 30. Production will continue to ramp up throughout the remainder of the year and we expect to exit 2008 producing around 25,000 barrels a day. We expect to achieve our sustainable peak rate of 35,000 barrels per day in the first half of 2009. With both the plant and the reservoir demonstrating top quartile performance, we're very pleased with the results to date.

At our Jackfish 2 project we anticipate receiving regulatory approval later this month, and hope to begin site work shortly thereafter. Jackfish 2 will essentially double the size of our Jackfish operations, adding 300 million barrels of reserves and another 35,000 barrels a day of oil production. Evaluation of Jackfish 3 is under way with additional drilling slating for this winter to further delineate the resources under our acreage.

We're quite pleased with the overall performance of our exploration and development portfolio and exceeded our production estimate for the second quarter. However our Polvo development, offshore Brazil, is one project that continued to face significant challenges. Because of mechanical issues including drilling problems and submersible pump failures, Polvo remains behind schedule. Based on the reservoir data we've seen, we believe our reservoir estimates for Polvo are sound and that we'll get all of the planned wells on production, but not until next year.

In spite of the setback at Polvo, our large and diverse property portfolio continues to provide consistent, reliable and highly profitable growth in reserves and productions.

That concludes the operations update. Now I'll turn the call back over to John to review our financial results for the second quarter. John?

Thanks Steve. I plan to take you through a quick analysis of the key drivers that shaped our second quarter financial results and review how these factors impact our outlook for the second half of the year. As a reminder, we have reclassified the assets, liabilities, and results of operations in Africa as discontinued operations for all accounting periods presented. I will focus my comments on our continuing operations, which will exclude the results attributable to Africa.

So beginning with production, as I indicated during the opening comments, in the second quarter we've produced 58.5 million equivalent barrels or approximately 643,000 barrels equivalent per day.

In the first quarter conference call we told you that due to a contractual increase in the Azeri government's share of production on the ACG unit we expected our Company-wide second quarter production to be flat with the first quarter. However the second quarter outperformance of our North American onshore properties resulted in production coming in about 0.5 million barrels better than our forecast. This gave us our ninth consecutive quarter of production growth. The payout at ACG also impacted the comparison to the year-ago quarter. Comparing second quarter 2008 results (technical difficulty).

Once again US onshore segment produced the strongest growth, led by the Barnett Shale in East Texas, US onshore production grew by 16% or 55,000 barrels per day over the second quarter of last year. Canadian production also strengthened, up approximately 4% over the second quarter of 2007 due to the ramp up of production from our Jackfish SAGD and Lloydminster projects.

The growth we delivered in the first half of 2008 is significantly less than the growth that we expect for the full year. Based upon our year-to-date results and the 2008 impact of the incremental capital that Steve mentioned, we are increasing our production outlook for the year and narrowing the range to between 240 to 244 million oil equivalent barrels.

This implies about a 2 million barrel increase compared with the guidance we offered in May. We expect our production to grow to approximately 61 million barrels in the third quarter and roughly 64 million barrels in the fourth quarter.

Looking ahead to next year, we believe we're on track to deliver top line production growth of 10% or more. For 2009, we now expect to deliver between 265 and 280 million equivalent barrels. This represents an increase of approximately 6 million barrels over the midpoint of our previous 2009 forecast of 259 to 274 million barrels. Our 2009 growth will be driven largely by continued strong performance of our US onshore properties and an increase in production from Jackfish.

Moving on to price realizations, starting with oil. During the second quarter, the WTI benchmark average rose to a record-setting $124.28 per barrel, up 91% over the second quarter of 2007. In addition to the higher benchmark prices, oil price differentials for all geographic regions remained narrow and better than the top end of our guidance ranges. Our Company-wide realized price averaged $110.55 per barrel or roughly 89% of the WTI Index.

Looking at the remainder of the year, we expect our average oil differential to widen slightly as Jackfish and Polvo volumes become a larger part of our oil production mix.

On the natural gas side, the benchmark Henry Hub Index rose to $10.94 per Mcf in the second quarter. This was 45% higher than the second quarter of 2007 and 36% above last quarter. Our Company-wide gas price realizations before the impact of hedges came in a touch above the midpoint of our guidance at approximately 88% of Henry Hub.

In the second quarter, cash settlements on hedges reduced our realizations by $1.32 per Mcf giving us a realized price, including cash hedging settlements, of $8.29 per Mcf. Updates to our full year differential guidance will be provided in today's 8-K.

Turning now to our marketing and midstream business, Devon's marketing and midstream operations once again delivered outstanding results. Operating profit reached $204 million in the second quarter, exceeding our previous quarterly record by nearly 20%. In total our marketing and midstream operating profit for the first half of the year climbed to $377 million. That's nearly $150 million higher than in the first half of last year.

Our record-setting operating profit was once again driven by increased throughput and strong commodity prices. Based on the impressive results in the first half of the year, we expect full year marketing and midstream operating profit to be in the range of $700 million to $760 million. This represents an increase of $200 million from the midpoint of our previous guidance.

The final item I want to cover before we move to expenses is the $1.2 billion loss on oil and gas derivative instruments that we recorded in the second quarter. $912 million of this charge, or $584 million after tax, is an unrealized noncash loss from a mark-to-market accounting adjustment related to our natural gas and oil hedging positions.

As most of you know, mark-to-market accounting requires us to record the unrealized gains and losses relating to the fair value of the remaining life of the derivative instruments. To illustrate the effects of oil and gas price volatility, based upon the current price environment, this noncash accounting loss would have been completely eliminated. In today's earnings release, you'll find a table that provides the before and after tax impact of this and other items that are generally excluded from analyst estimates.

Moving to expenses, second quarter lease operating expenses were right in line with our guidance, coming in at $537 million or $9.18 per Boe. For the remainder of 2008, we anticipate higher unit LOE due to upward pressure on industry costs and a higher level of workover activity. However we expect our full year LOE expenses to remain within our previous guidance range, but near the high end.

Second quarter DD&A expense for oil and gas properties came in at $13.03 per barrel. This result is right at the midpoint of our full year guidance range. For the third quarter and fourth quarters we expect our DD&A rate to be between $13.30 and $13.40 per equivalent barrel of production.

Our second quarter G&A expense was $180 million. That's a $32 million increase over the first quarter 2008 results. $27 million of the increase resulted from a one-time noncash cumulative charge related to a modification of stock vesting requirements to better reflect industry practices. If you exclude this noncash charge, second quarter G&A expense is $5 million above the first quarter level.

When we issue our annual stock grants in the fourth quarter, the new policy will result in a $15 million to $20 million noncash increase in G&A expense. Accordingly, we expect third quarter 2008 G&A costs to decline to somewhere between $150 million to $160 million, and then increase again in the fourth quarter to between $180 million and $190 million. That gives full year expected G&A expense of $660 million to $680 million.

Shifting to interest expense, interest expense for the second quarter was $90 million. When compared to the second quarter of 2007, interest expense decreased by $17 million or 17%. The most significant driver was our lower debt levels brought about by the repayment of debt balances in early June.

In the second half of the year, lower debt levels will also reflect the retirement of the Chevron exchangeable debentures in August. We expect interest expense to continue to decline to about $75 million in the third quarter and $65 million in the fourth quarter.

Now let's move to income taxes, which were impacted by a lot of unusual items this quarter. Starting with the reported income tax expense from continued operations. This came in at $667 million with $414 million classified as current taxes and $253 million being deferred. This implies a 53% tax rate on $1.3 billion of pretax income from continuing operations. However, our reported taxes were affected by some unusual items that require some explanation.

In aggregate, we received $306 million in deferred tax benefits driven by unrealized losses on oil and natural gas derivatives. The benefits, however, were offset by a $295 million current tax charge attributable to the repatriation of foreign cash to the United States and the affects of some related tax policy elections. We made the tax elections to minimize the taxes on repatriated cash and on gains associated with the African asset divestitures.

After excluding all of the noise of these unusual items, you arrive at an adjusted pretax income from continued operations of nearly $2.2 billion and an adjusted total tax expense of $678 million. This comprises an adjusted current tax rate of just 6% and a deferred tax rate of 26% for a combined rate of 32%.

So in summary Devon continues to deliver solid financial and operating results. During the second quarter, we exceeded expectations for both production and earnings and generated free cash flow of $695 million over and above our very robust exploration and development program. We ended the quarter with $1.8 billion in cash on hand and net debt to adjusted cap ratio of 11%.

Looking to the remainder of 2008, we expect cash flow from operations to fund our capital expenditure budget, leaving us with a sizable cash balance and available free cash flow to retire the Chevron exchangeable debentures and to continue our share repurchase program. With that, at this point I'm going to turn the call back over to Vince to open it up for Q&A.

Thanks John. Operator we're ready for the first question.

(OPERATOR INSTRUCTIONS). And your first question will come from the line of Tom Gardner from Simmons Company. Please proceed.

Good morning everyone. Over in the Groesbeck area, given the success you've had there to date, are you still looking at 6 Bcf ultimate recovery and 150 locations, or do you see that opportunity getting bigger over time?

Tom, we are seeing relatively better performance than that planned number in these more recent wells. We haven't really adjusted our model upwards yet; but if we continue to see those results we probably would. We also -- in the Bossier wells that we're drilling, we'll drill about 15 this year, and probably about the same number next year.

And we're also doing some work on some -- there is some significant Bossier line potential in Personville Field that has significant running room. Well over 100 locations, and we are just working through those pieces. So we think we'll see those results continue this year; next year we are optimistic about that model moving up. But we haven't adjusted it up yet.

Thanks for that. One other question, on the Lower Tertiary. My understanding is that the completion technology needs to improve to make the economics attractive. I think it has something to do with being able to complete the entire section. Can you give us an update on how that effort to improve technology is progressing and what Devon's involvement in it has been?

Tom, I won't speak specifically about some of the specific prospects because obviously we're keeping some of that technology and that development proprietary and within the partnership.

But I will tell you that the current view we have on the completions still put all of our discoveries in the solid economic window with solid finding and development costs. And we think we'll get good production response and economic development, and we're moving forward with those developments, starting with Cascade. With Cascade, we're going to start drilling that second producing -- or the first producing well here very soon.

Devon is working actively with a few different vendors and with some technology folks in order to optimize. It's more of an optimization of those completions as opposed to a hurdle that says they're currently uneconomic and we need to make them economic. So yes, we are working with some of the major service providers both at Cascade, but also with our partnership at Jack and St. Malo and the other discoveries that we have to move those forward.

Our view is not that it's uneconomic at this point and there is a threshold we have to clear in order to make it economic. Our desire, as I think most of our partners is, is to optimize it to get the best economics moving forward.

Thank you. Appreciate the detail.

Your next question will come from the line of David Heikkinen from Tudor Pickering Holt. Please proceed.

Good morning guys. A lot of good information on the call. Thanks for that. When you think about the Haynesville and 73 Tcf of gas in place and increasing your resource potential from 2.1 billion barrels to 8.5 billion barrels, I want to make sure first I got those number right. That's a big increase.

Yes. That's correct.

How do you think about then --- you know, 11% debt to cap, how aggressive can you get with your share repurchase program moving forward? What is the optimal debt balance versus buying your stock with that much resource?

Dave, this is John. I think on that point, we're -- obviously we're buying some of the stock back today with something other than just our free cash flow, because we repatriated a lot of funds and brought the proceeds of the disposition from the African divestures back. So there's room for us to do some of each, frankly.

As we move forward -- and Steve can speak better to the pace or acceleration of that program going forward -- it will ramp up in an orderly fashion. We won't suddenly increase that a dramatic amount because you have got a lot of other issues that you have to deal with from an operational point of view as we bring that up.

So we've been in a fortunate position over the last few years of being able to fund our capital programs, to increase our dividend every year for the last five years, pay down our debt, and buy back stock; and we remain able to do that.

As far as the appropriate debt level is concerned, we've always thought that what is important to us is to be a good investment-grade credit. When we're investment-grade credit, we would rather be a midlevel investment-grade credit than a bottom level investment-grade credit, because there are enough things to concern yourself about in this business you do not want to be one step away from dropping off that investment-grade ladder. So it's important for us to be investment grade.

In kind of a mid cycle, on a mid cycle basis, or in a mid cycle context, that probably means a debt to cap in the 30s somewhere. So we certainly have a lot of room to not only deploy the funds that we brought back, the free cash flow that we are going to generate, but we have got a lot of capacity on the balance sheet and a lot of balance sheet strength to help us out over the next few years as we develop our portfolio.

David, this is Vince. I might add to that that as we optimize growth on a debt adjusted share basis, we are dealing with a constantly evolving view of both --- well, of course, our share price is an unknown as we go forward. But also we're constantly updating our view of what our portfolio can do with incremental capital or by reducing capital. And so it's hard to point to a specific debt level that makes sense under all circumstances.

What do you think a reasonable or optimized growth level on a debt adjusted basis is for Devon now, with the increased guidance that you just put out?

It's entirely dependent upon the commodity price environment. And we showed that in our March call, that even under a commodity price outlook that is significantly below the current strip, we could deliver growth on a compound annual basis in the low to mid-teens on a debt adjusted share basis. And so that remains within our grasp.

And obviously we're looking at 10% growth or better for next year based on the numbers we just gave. That's top line growth. You add in the share repurchases that we're able to make with free cash flow and it will move the needle up.

Okay. And then just one specific question. On the 483,000 acres, how much of that is held by production already, in the Haynesville?

There is -- a majority of it is held by production.

Or fee acreage.

Or fee acreage, right. We have held by production acreage; of course we have got significant position in East Texas; and then we have fee acreage. So we're not feeling too much under the pressure of the clock as far as lease terms.

We also are pushing hard to continue to lease in the area. That's why we're keeping information relatively tight to the vest here. And a goal we have is to add something probably in the neighborhood of as much as another 100,000 acres to that number that we just put out. And I'll point out that 483,000 acres is only about 64% of Devon's total acreage in East Texas and North Louisiana.

Okay. Thanks, guys.

Thanks, David.

Your next question will come from the line of Brian Singer from Sachs.

Good morning. Let me, following up on one of David's questions, and you just spoke to this to some extent, but I guess when you think about commodity prices in oil, Rockies gas, North American natural gas, your stock price level, you can put any numbers to it where you could say at X level of gas price and Y level of oil price you would shift capital more into oil versus natural gas, or more into share repurchase versus drilling?

David, that's a very, very tough question to answer. As you know, we have got a large portfolio of opportunities; and I think we have talked before about the fact that we have got a fairly sophisticated portfolio modeling process so that we can ensure that every time we spend another dollar, we're putting it to -- we're allocating it on the basis it is going to create the most value and create the most growth on a per debt adjusted share basis.

So it's very specific to the areas. I couldn't -- I don't think we can really point it a specific commodity price. But let me give you an example. When Canada got as expensive as it did and the foreign exchange rate went against us as much as it did, the Lloydminster prospect was still one of the prospects that gave us the highest rates of return, notwithstanding that it was within that kind of cost environment. And that would not have been the case on some other oil projects necessarily, so it's very prospect dependent and really tough to answer that question.

Okay. Thanks. Secondly there's been various commentary on the pace of growth industry-wide in the Barnett Shale and various areas within that seeing either plateauing or potentially peaking. Can you speak to, regionally within Devon's acreage position in the Barnett, how you see the growth trajectory over the next few years?

Well we mentioned earlier, Brian that we have got 7,500 risked locations. And the great thing about the Barnett Shale is that not only does it deliver great economics, it is very repeatable. And when we look at that inventory we see a 10-year repeatable inventory of growth for Devon, or inventory of drillable opportunities for Devon. And we see growth continuing well into -- around the middle of the next decade. So.

And we see more of a slowing of growth than we see a peak or a plateau as you look out even for the next three to five years.

Brian, this is Vince, I might add that it really comes as no surprise to us -- and in fact you may have heard us say over the last year -- that we were expecting Devon to demonstrate differential performance in the Barnett Shale relative to our peers. And that's really related to the fact that as the first mover we were able to get the largest and best acreage position in the play.

Some of the fringe areas that we decided not to participate in, I think some of the other players in the Barnett have decided that that doesn't compete well with other capital opportunities. In Devon's case, the vast majority of the 7,500 risked locations that Steve mentioned are in the very best parts of the play. So we'll continue to grow our production while others may not be able to.

Great. Thank you.

Your next question will come from the line of Joe Allman from JPMorgan.

Yes, good morning everybody. Could you comment on takeaway issues that you are preparing for related to the Barnett Shale and in competition with takeaway capacity with the Haynesville Shale and other East Texas and other regional plays?

Yes, Joe, this is Darryl Smette. As it relates to the Barnett, we have in place a number of firm transportation agreements and are currently working on more that will allow us to move all of our production as we now see it, including the forecast that Steve's people have provided us about how they can drill that production. So we continually work that.

As you know we also have our own midstream business, so we feel very comfortable we'll be able to move our gas from the wellhead to the main market centers. And beyond the market centers we think we have enough firm transportation already lined up or that we are in the final stages of putting together that we'll be able to move that gas all the way to the end use markets.

As it relates to the Haynesville, obviously as you've heard Steve say and John say, this is an emerging play. We have high hopes for the Haynesville. We think it has some really good characteristics but it's still emerging. There is a lot of unknowns there yet.

What we can tell you is we, as an industry, have about 8 Bcf of pipeline takeaway capacity. Now I'm not talking gathering, I'm talking mainline capacity to take gas to market. There is about 7 Bcf of that that is subscribed, so there is about a Bcf of available capacity that is unsubscribed.

In talking with the pipelines, our current numbers suggest that we could add additional capacity of about 1.5 Bcf over the next two years, so that's about 2.5 Bcf of available capacity within 24 months.

Once that occurs, if the industry is successful and Devon is successful, you would have to look at some greenfield projects out of that area. Most of those greenfield projects in our estimation would take anywhere from 24 months to 48 months to complete. We're actively looking at some of those projects right now. But at least in the Barnett we feel we're covered. We feel pretty good about what is going on in the Haynesville in terms of industry takeaway capacity. But there is a lot to happen in the Haynesville yet. But right now we feel pretty good about the position we're in.

Even though you guys are covered, you think in a couple years there could be some bottlenecks for some different players with these competing plays; is that right?

Well I don't know that there will be bottlenecks, We know what the existing capacity is, and we know what the existing capacity would be with the projects that could come on in the next, say, 18 months. What we don't know is how fast things are going to ramp up.

As we have said, it's very early in this play; and the results that we have seen and the results that other parties in the Haynesville area have put forth suggest that this is going to be a very robust area. But there is still a lot of work yet to do, as Steve indicated.

Our people are constantly looking at this project and so we just have a lot of work yet to do as an industry. But assuming that that work is successful there probably are going to have to be some additional greenfield projects two and three years down the road.

That's helpful. Darryl, while I have you. I have noticed that the Rockies differentials have narrowed recently. Can you comment on that?

Well that kind of depends on where you start and where you end up. They're pretty volatile as you know. But yes, if you compared to last year at this time we were trading at about a $4.50 differential; yesterday, we were trading at about a $2.50 differential. So they have narrowed. A lot of that is directly dependent upon, of course, the REX pipeline that went into service in January. There is other pipeline projects that are going on now.

And of course relating to the shoulder month we are going to see some more pipeline repairs going on, so we could see those differentials widen a little bit. But over the course of the last year, definitely we've seen differentials narrow out there; and we expect it is going to remain volatile. But they should -- our hope is and based on our analysis, we don't think we'll over a long period of time see the $4 and $5 differentials we saw last year.

Okay. Very helpful. And then a different topic, Haynesville Shale you mentioned you have got some production on line. Can you comment on what you're seeing so far?

We're really keeping that relatively quiet. We do have wells on production and we're completing additional wells as we speak. We've got the 12 penetrations I talked about. We've got quite a bit of whole core material.

And we're going through very methodically, as we did in the Barnett Shale, and looking at our position, looking at opportunities to acquire additional acreage, and categorizing it much like we did in the Barnett Shale as far as primary position or some of the better positions in the play; the emerging positions that are good but not proven; and then the speculative areas that we think may or may not have some potential but are willing to put some capital at risk to acquire some of those leases at reasonable cost and reasonable in our eyes. So it's really an accumulation of things. And because we are still actively acquiring leaseholds, we're not talking about the production rates.

Got you. And then Steve, are you willing to give any details on the Rocky Mountain shale plays, the two that you have got under way?

No. Not at this point. I will tell you though, we continue to get wells down. And again it's a bit of the same story as that we've gotten additional wells down. We've gotten core, the geology is looking very good and that's why you see our unrisked potential continuing to increase there.

Okay. Very helpful.

And obviously Joe, we're still accumulating acreage positions there and we would be shooting ourselves in the foot if we talked about that too much at this point.

Understood. Thanks, John. Thanks everybody.

Operator can we have the next question?

Yes. Your next question will come from the line of Eric Hagen from Merrill Lynch.

Hey, guys. All mine have been answered. Sorry about that.

Okay. Thanks, Eric.

And your next question will come from Mark Gilman from Benchmark Company.

Good morning, guys. Can you give us an idea of what the per acre cost was on your recent acquisitions in the Haynesville and Horn River?

Actually, I'll tell you that it's very competitive and relatively low to some of the other numbers you've heard out there. Again because we're still actively leasing and there are still additional lease sales to come in Canada, we're not really talking about those numbers specifically.

Okay. Steve, let me try another one. There seems to be increasing industry talk about what I guess would be a unitized St. Malo-Jack development scheme. Can you give me your thoughts on that and comment on the distance between the two?

Yes, absolutely. St. Malo and Jack are within about 20 miles of each other and we're going through a very disciplined process with partners at St. Malo and Jack where we look at the options that optimize the economics and efficiency of that operation. One of the leading options there is a combined development between the two. And obviously with that kind of proximity, there are synergies on these very large capital projects that could deliver some very good value.

So the teams are working together, the joint development teams are working together to go through those options and make sure we understand all the technical issues and the costs and performance issues and come up with the optimized development scenario. But one of the leading scenarios is a combined development of Jack and St. Malo.

And Mark, just to remind you and show you how far along those integrated project teams are in doing this evaluation, we're still hoping that we're going to bring this forward in 2009 for sanctioning. And that will keep us on schedule with the first production that we talked about previously in probably 2013 or something like that. So they're well along in terms of doing a lot of this analysis.

All right. John, Steve, does this say anything about freestanding potential of the two?

No. It doesn't. It really is driven exclusively by efficiency, by both capital efficiency and economic efficiency. It doesn't say anything as it relates to what we see relative to what we expected to find initially.

Just one more if I could, for John. I'm not sure I understand the logic with respect to the exchangeable debentures on the Chevron stock and the comment I think you want to optimize the value of the position. Would you elaborate on your thinking a little bit on that?

Sure. You might remember, Mark, that that wasn't code language we were giving you there at all. It is just that if we were to just give the stock back to the debenture holders, because we inherited this from PenzzEnergy in 1999, we have a very low basis in that stock.

So what we're trying to do -- and that would trigger a tax obligation or a tax liability; and we have talked about that in the past. But we're also working on some other alternatives that hopefully are a little bit more inventive. And so in the interim we're going to redeem those debentures with cash.

Okay, guys, thanks a lot.

Okay. Operator, we'll take one more question.

Your last question will come from the line of Fletcher Sturm from [Diamondback] Company.

Everybody hear me okay? I was having phone problems earlier. Okay. Just curious on the natural gas and the crude oil derivative positions. You say you had a -- was it $1.2 billion adjustment which partially was realized, some as mark-to-market. I'm curious what the mark-to-market exposure was again.

Yes, the mark to market --

912 --

$970 million or something like that as of June 30th. If you were to mark-to-market as of the close of business yesterday there would be no exposure.

Right. It actually would be a gain.

It actually would be a gain.

Okay, yes. That's where I'm leading with this. Current strip price like for example, just the calendar [9] Henry Hub nat gas strip was roughly $12.50 and a month later now it's down 25% at $9.50. Are you entertaining any -- the idea of securing, unwinding some of those hedges given the pretty dramatic move down, and specifically in natural gas?

I don't know what the mixture in your mark-to-market set aside is there between natural gas and crude oil, but crude oil has had a modest decline relative to natural gas. I'm curious if you could comment on potential unwinding of hedges.

Yes. This is Darryl again. Just to put it in perspective, we have relatively little oil that is hedged. It's about 20,000 barrels a day and it's only through the end of cal year 2008.

On our natural gas hedges again, we only have four months to go there. We do have discussions now and then about unwinding them. So far we have made the decision not to unwind the 2008 hedges; and we've made the decision not to unwind the 2009 hedges that are in place which are about 300 million a day and they're all collars.

So while we continue to have discussions about that -- which is not unusual, we have those discussions every week when we have our weekly executive committee meetings -- so far we have not made the decision to unwind any of those positions. And with only four months left to go in the year, I would have to say that the chance that we would unwind a majority of those would be pretty small.

Okay. Thank you very much.

John, do you have any closing comments?

Just a few closing comments. Thanks for being here this morning. And I would just like to summarize our second quarter 2008 and reiterate the fact this was one of the best in Devon's history.

We had another quarter of record earnings and cash flow, we increased production for the ninth consecutive quarter and expect additional growth for the foreseeable quarter. We also increased our production outlook for the second half of 2008 and fairly significantly for 2009. We completed the bulk of our African divestitures and eliminated $2.6 billion in debt and preferred stock. We recommenced our share repurchase program, and we unveiled the leading position in the Haynesville Shale play.

So with that, thanks again for being here and we'll talk to you again in a few months.

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