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'd like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.
Vince White – Vice President of Communication and Investor Relations
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 todays 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 and Steve Hadden, Senior Vice President of Exploration & Production will review the operating highlights and John will return and conclude with the financial review. At that point, we will open the call up to your questions, and as usual we will ask that you hold your questions to one with one followup per participants. We will try to keep the call to about an hour and a replay will be available later today through our link on the hompage.
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 update that we’re going to give on todays call we would 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 our 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 risk factors and uncertainties that is provided with the Form 8-K that we will file today.
One other compliance note, we will refer today to several non-GAAP performance measures and we make reference to these measures, we will require to make certain disclosures on the Securities Law these disclosures are available on our website that addresses Devonenergy.com.
And 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 requires to excludes 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 operation, but we have 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 are divesting. On a reported basis discontinued operation this quarter includes a 647 million after tax gain on the divested African properties.
As enhanced for several quarters, accounting for discontinued operations impacted the comparability of analyst earnings estimate this quarter. Most analysts chose to report the first call and that exclude discontinued operation, the mean estimate of those are analyst that excluded discontinued operations was 323 a share for the quarter. That compares to our non-GAAP earnings from continued operations of 328, so we came in nickel over the consensus or mean estimate.
Also I want point out one unusual 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 divestiture combined with repatriation cash from foreign subsidiaries totaled approximately $3 billion in the second quarter. With those items out of the way, I will turn the call over to John Richels.
John Richels – President
Thanks Vince and good morning everyone. As Vince mentioned John W. Nichols passed away last Sunday. John and Larry co-founded Devon and John served most recently as the company’s 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 oil and gas drilling fund with the US 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 Blonco unit and the San Juan Basin in New Mexico, a field that is still producing 58 years later with Devon as operator.
This pioneering continued in 1971 when he ask Larry to join them in the creation of Devon Energy Corporation with just four employees and no oil and gas assets. In 1995 and an event honoring Devon Larry made these comment 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 are optimistic about our future creative and solving our problems, resource full in exploiting our opportunities and above all else honest in our dealings with everyone, we console the legacy of John W. Nichols lives on. These words are as true today as they were when Larry said more than decade ago, and John Nichols will truly be missed.
Now moving to the business of the quarter, beginning with the second quarter highlights this is another quarter of outstanding financial performance. The results were fueled by our continuing product growth and the strength of our oil and natural gas in NGL prices. Second quarter reported earnings reached $1.3 billion or $2.88 per share, and as news is 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 and gas natural gas and natural gas liquids from retained properties to 58.5 million oil equivalent barrel. So that marks a ninth consecutive quarter of production growth.
Our marketing and midstream business also delivered all time record results where quarterly operating profits 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 asset in Equatorial Guinea are closing for $2.2billion during the quarter, we have substantially completed the African divesture program. We expect to complete the remaining roughly $250 million of African divestiture later this year. When we first announced our plans to exit Africa in January 2007 we outlined our intentions for deploying another proceeds. We indicated that we would allocate the proceeds of debt reduction and share repurchases and we are doing just that. Upon receive the proceeds from the sales and repatriation about the international cash balances we repaid all commercial paper and other short term debt balances. This brought ratio of mid-debt to total capitalization to its lowest level in more than the decade only 11% at June 30.
Later this month we will eliminate the remaining debentures exchangeable into Chevron common stock that we inherited when we required PennZenergy in 1999. These securities mature on August 15, and upon maturity the intention provides of the holders may receive either Chevron shares help by Devon or the cash equivalents 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 30, we had redeemed about 18% of the debentures at a total cost of $214 million. And so far in the third quarter we have 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 prices of Chevron stock for those yet to be redeemed.
Even after the debt repayment so that discussed will have a substantial amount of additional cash to deploy in the second half of the year. As we stated in the past our priority is to allocate capital in such a way that maximizes growth and 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 thus repurchases 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 agree to repurchase more than 3 million additional shares bringing the total shares repurchases year-to-date to 5.9 million.
I will remind you that based on yesterdays closing prize for Devon shares and a modest allocation of value to our marketing and mid-stream business of 8 times the trailing top months EBITDA. The purchase of Devon shares represents the acquisition of our proof results at a price of less than $16 per barrel, and this analysis attribute no value to a thousands of unproofed 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 o expansion of our Jackfish SAGD complex, no value to the millions of un proven acrid – acres that we have established another North American plays and no value to our international exploration inventory. Its hard for us to imagine an acquisition opportunity in today’s market that would represent a more compelling value to us in Devon shares.
In addition repaying $2.6 billion of debt in prepared shares and restarting our substantial share repurchase program optimizing the value of Devon on a day suggested share basis calls for investing an incremental $1.7 billion in 2008 exploration and production projects. This would result in full year EMP capital expenditures of 7.3 to $7.6 billion. A significant portion of this income and of capital is directed to additional acreage capture in North America and increased investment in the Lower Tertiary trend to build up on our long term opportunities set. Steve Hadden will peak to these additional capital projects in his operations review and I will discuss the expected production impact later in the call.
With that now turn the call over to Steve Hadden.
Stephen Hadden - Senior VP of Exploration & Production
Thanks John and good morning everyone. I will begin with the quick recap of company wide drilling activity. We drilled 494 wells in a second quarter. Of these 16 were classified as exploratory and 81% were successful. Remaining 478 wells were classified as development of which 98% were successful. Our recount average to 130 rigs during the second quarter and repeat at the end of June with a 143 rigs running with two of them drilling Devon operated wells. Capital expenditures for exploration development were 1.7 billion for the quarter, despite total exploration and development capital for the six months to $3.5 billion. As John mentioned, we have elected to leverage a portion of our robust cash-flow and increase 2008 EMP 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 equipment. So the outlook for 2008 is once again to deliver very competitive funding and development cost with prove reserve additions far exceeding the year’s production.
About 700 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 updated March we disclose that we held some 950,000 net acres in various emerging place with earnest resources potential of little over 2.1 billion barrels of the oil. Since that time we’ve continued to acquire land and gain additional information allowing us to significantly de-risk these emerging plays. Today we hold over 1.3 million net acres in these place with unrisked potential net to Devon of more than 8.5 billion barrels of oil equivalent.
This includes a significant position in Haynesville Shale that I will talk more about in just a minute and also includes more than a 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 Mount.
We initially elected to referring and saying much about Devon’s position in Haynesville Shale when it became hot topic of few months ago. Instead, we continue to expand our knowledge of the play to drilling and testing activities. Our approach was to combine our local knowledge of East Texas where we already produced more than 350 million cubic feet of gas equivalent a day with our understanding of unconventional reservoirs. We have acquired this knowledge by drilling thousands of tight gas wells including more than 3000 wells in Barnett Shale. Although we are not ready to share anything we’ve learnt today, we really have to summit your question about Devon’s Haynesville position. We’ve been successful in adding acreage and today we have approximately 483,000 net acres in Haynesville Shale play area in Texas and Louisiana with more to come. This gives Devon a largest position announced today. Much of our Haynesville acreage is held by production form others zone that we’re developing in area and we have supplemented this with additional leasing. Enhancing the economics of a 483,000 net acres is little royalty burden averaging less than 25%.
Much like our approach to Barnett Shale, we’re carefully assisting results and characterizing the shale to define and derisk the play based on economics and repeatability. Based on our mapping work to date early estimate put the resource under our net acreage that almost 73 PCS of gas in place. We are obviously very early in the life of this play and more drilling and testing it immediate to fully characterize this potential.
We expect to drill our first Haynesville horizontal in the third quarter. However, we have 14 vertical Haynesville penetration including three wells before course, 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 to optimize location selection and accelerate development.
Now moving on to North America’s most significant and best established shale play, the Barnett Shale fuel in North Texas. There have been some recent comments by other operators that few like reduction might be nearing the top, in case big for those other producers but this is certainly not Devon’s view. We believe our net Barnett Shale production will nearly double over the next several years to as much as 2 billion cubic feet equivalent per day and were 75,000 rest drilling locations, we have more than 10 use of drilling inventory in Barnett.
We are currently running 32 Devon operated rigs in the Barnett. In the second quarter we bought a 189 wells on Maine in an average rate of 2.2 million cubic feet gas per day. In select areas of the play we began drilling long lateral horizontals of outstanding results. For example two 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 3500 to 4000 feet and typically required between 8 and 10 flat stages which total our cost of about $3.7 million per well.
Our total net Barnett Shale production on average 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 Carthage area, East and East Taxes, in the second quarter we drilled 39 new wells as part of our 7 rig vertical well program. In addition we completed 6 wells or we completed 6 wells in the second quarter. We also continued to see good results from our horizontal drilling program in the Carthage area, with four rigs now drilling horizontal wells.
We completed six Cotton Valley horizontal wells during the second quarter, including the Swiss 13 H the 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 completed three outstanding 100% owned wells in the Nan-Su-Gail field in the second quarter. The Crenshaw 19H IP to 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 help drive our net Groesbeck production to a record 90 million cubic feet of gas equivalent per day. That’s a 5% from the first quarter and 26% compared with the second quarter of 2007. East Texas is a powerful part of North America growth strategy and with the addition of the infill program it should push us to a homely level.
We are also generating new excitement in the Woodford Shale. We are achieving excellent results from the Devon operated 4000 foot lateral horizontals. As a result, our typical well Woodford now yields recoverable reserves between 3.5 and 4.5 bcf with drilling costs in the 6 to $6.5 million range. Long run over horizontals and are now into 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 bought a total of 8 new operated wells during the second quarter with the 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 had three rigs currently running and including two Devon operated rigs drilling in the Big George Formation. We expect to drill more than 110 new 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 are on track to set an all time production record in the Powder doing 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 Cole Scenes 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 is currently nearing its total depth. We will begin refracting the first of 7 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 will give you a quick update on our Lower Tertiary trend program. Appraisal operations continued at Jack St. Malo on both the Jack No. 3 and St. Malo No. 4 appraisal wells. The owners in these two Lower Tertiary projects continue work towards the selection of a final development concept and expect a 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 reentry to sidetrack of the initial discovery2006 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 73.3% working interest and Devon has the remaining 26.7% working interest. At Cascade, our 50-50 Lower Tertiary project with Petrobras. We plan to begin drilling the Cascade #3 well in the fourth quarter. This will be one of two initial producer wells at Cascade. The design and construction of the production facilities is progressing well.
We expect to install ri prers in FPSO marine system in 2009 as well as flowlines in 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 with 50% working interest is on Keathley Canyon 596 and is now drilling.
We are also participating in a well expected to spud 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 are 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 30th. 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 are 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 underway with additional drilling slated for this winter to further delineate the resources under our acreage.
We are 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 have seen, we believe our reservoirs estimates for Polvo are and we will get all 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 production.
That concludes the operations update. Now, I will turn the call back over to John to review our financial results for the second quarter. John?
John Richels - President
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 reclassify 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 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 our contractual increase in the Azeri government share of production on the ACG unit, we expect that our companywide 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 ECG also impacted the comparison to the year ago quarter. Comparing second quarter 2008 results and the second quarter 2007 (audio gap) once again that onshore segment produce 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 Side B 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 as 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 approximately 61 million barrels in the third quarter and roughly 64 million barrels in the fourth quarter.
Looking at the next year, we believe we are on track to deliver top line production growth of 10% of more. For 2009 we now expect to deliver between 265 and 280 million equivalent barrel. 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 onto price realization 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 a higher benchmark prices oil price differentials for all geographic regions remains narrow and better than the top end of our guidance ranges.
Our company wide realized price average $110.55 per barrel or roughly 89% of the WTI index. Looking at the remainder of the year we expect our average oil differentials 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 realization by a $1.32 per mcf getting us a realized price including cash hedging settlements of $8.29 per mcf. Updates to our full year differential guidance will be provided in todays 8-K.
Turning now to our marketing and midstream business, Devon’s marketing and midstream operation 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 declined 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 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 non-cash 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 non-cash accounting loss would have been completely eliminated. In today's earnings releases, you will find a table that provides the before and after-tax impact of this and other items that are generally excluded from analysts' estimates.
Moving to expenses. Second quarter lease operating expenses were right inline 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 work over 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 in at the midpoint of our full year guidance range. For the third and fourth quarters, we expect our DD&A rate to be between $13.30 and $13.40 for 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 non-cash cumulative charge related to a modification of stock vesting requirements to better reflect industry practices. If we exclude this non-cash 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 to $20 million non-cash increase in G&A expense. Accordingly, we expect third quarter 2008 G&A cost to decline to somewhere 150 to $160 million and then increase again in the fourth quarter to between 180 and $190 million. That gives full year expected G&A expense of 660 to $680 million.
Shifting to interest expense, interest expense for the second 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 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 receive $306 million in deferred tax benefits driven by unrealized losses on oil and natural gas derivatives. The benefits, however, were offset almost entirely by $295 million current tax charge attributable to the repatriation of foreign cash to the United States and the effects 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, we 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 an above our very robust exploration 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 fee cash flow to retire the Chevron exchangeable debentures and to continue our share repurchase program.
So with that, at this point I am going to turn the call back over to Vince to open it up for Q&A.
Vince White - VP of Communications & IR
Thanks John. Operator, we are 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.
Hey over in the Groesbeck area, are you still -- you know, given the success you had there to date, are you still looking at 6 bcf ultimate recovery and 150 locations, I already see that opportunity getting bigger overtime?
You know, Tom, we are seeing a relatively better performance that 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 are also in the Boseyer wells that we are drilling, we will drill about 15 this year and probably about the same number next year, and we are also doing some work on some -- there is some Boseyer line potential, significant Boseyer line potential in first horizontal field that has significant running room well over a 100 locations and we are just working through those pieces. So we think we will see those results continue this year and next year we are optimistic about that model moving up, but we haven’t adjusted it up yet.
Thanks for that. And 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 progression and what Devon's involvement in it has been?
Yeah Tom, I won't speak specifically about some of the specific prospects, because obviously we are keeping some of that technology and that development proprietary, but and within the partnership, but I will tell you that the current view we have on the completion still put all of our discoveries in the solid economic window with solid finding and development costs and we think we will get good production response in economic development. And we are moving forward with those developments starting with Cascade. With Cascade we are going to start drilling that second producing or the first producing well very soon. Devon is working actively that we have a few different vendors and we have some technology folks in order to optimize. It’s more of an optimization of those completions as opposed to a hurdle which shows they are currently uneconomic and we need to make them economic. So we are working with some of the major service providers, both with Cascade, but also with our partnership at Jack and St. Malo and the other discoveries that we have to move those forward. So 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 or desire as I think most of our partners is to optimize to get the best economics moving forward.
Thank you. I appreciate the detail.
Your next question will come from the line of David Heikkinen from Tudor Pickering Holt. Please proceed.
Good morning guys and 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 the resource the potential from 2.1 billion barrels to 8.5 billion barrels, I want to make sure, first I got those numbers right that’s a big increase?
Yes, that’s correct.
How do you think about then 11% of that’s cap, how aggressive can you get with your share repurchase program moving forward? What's the optimal debt balance versus buying a stock with that much resource?
Dave, its John. I think on that point -- obviously, we are 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 proceed to disposition from the African divestitures back. As we ramp up our -- and so there is 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 the kind of an orderly fashion. We won't suddenly increase that to a dramatic amount because you have got a lot of other issues that you have to deal with from operational point of view as we bring that up. We have been in a fortunate position over the last few years to being able to fund our capital program to a) increase our dividend every year for the last five years, pay down our debt and buyback stock and we remain and able to do that.
As far as the appropriate debt level is concerned, we always thought that what's important to us to be a good investment grade credit and when our investment grade credit, we would rather be kind of a midlevel investment grade credit than a bottom level investment grade credit because there are enough things to concern yourself about in this business that we don't want to be one step away from dropping off that investment grade latter. So it's important for us to be investment grade and in kind of a mid cycle on a mid cycle basis or a in a mid cycle context that probably means a debt to cap in the 30 somewhere. So we certainly have a lot of room to not only deploy the funds that we have brought back, the free cash flow that we are going to generate, but we 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.
Dave, 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 what of course our share prices are unknown as we go forward, but also we are 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 make 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 have just put out?
Well, it's entirely dependent upon the commodity price environment and we show that in our March call that even under 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 and on a debt adjusted share basis and so that remains within our grasp. And obviously we are looking at 10% growth or better for next year based on the numbers we just gave. That's top line growth. You are adding the share of repurchases that we are 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 it is held by production.
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 are 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 are keeping information relatively tight to the best here and a goal we have is to add something probably in the neighborhood of another -- as much as another 100,000 acres to that number that we just put out. And I will point out that 483,000 acres is only about 64% of Devon's total acreage in East Texas and North Louisiana.
Okay. Thanks guys.
Your next question will come from the line of Brian Singer from Sachs.
Thank you and good morning.
Good morning Brian.
Following up on one of the questions. You just spoke to some extent but I guess when you think about commodity prices and oil, Rockies gas, North American natural gas, your stock price level, can you put any numbers to where you could say 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. We got as you know, we got large portfolio opportunities and I think we have talked before about the fact that we have – and we got fairly sophisticated portfolio modeling process so that we can ensure that every time we spend another dollar we’re putting at to – were reallocating at on the basis that’s going to create the most value and create the most growth on a per debt adjusted share basis. So its very specific to the areas I couldn’t – I don’t think really point to a specific commodity price, but let me give an example, when Canada got its expensive as of debt and foreign exchange rate went against thus as much as a bit that Lyoldminster prospect was still one of the prospect that gave us the highest rates of the return notwithstanding that was in that kind of cost environment and that wouldn’t have been the case on some other oil projects necessarily. So its very prospect dependent and really talk to answer that question.
Okay, thanks. Secondly there is been various commentary on the pace of growth industry wide in the Barnett Shale, and various areas within that seeing either plate owing or potentially taking. Can you speak to regionally within Devon’s acreage this in the Barnett how you see the growth trajectory over the next few years?
Well, we mentioned earlier Barnett that we got 7500 risk locations, and the great thing about the Barnett Shale is that is 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. There are e inventory of durable opportunities for Devon and we see growth continuing well into the around the middle of the next decade. So – and we see more of a slowing of growth than we see a peak or plateau as you lookout even for the next three to five years.
Brian this is Vince. I am going to add that – it really comes as now surprised us and in fact you may have heard to 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 is the first we were able to get the largest invest acreage position in the play you know, some of the fringe areas that we decided not to participate and I think some of the other players in the Barnett have decided that doesn’t compete well with other capital opportunities, in Devon’s case the vast majority of the 7500 gross locations that Steve mentioned or in the very best parts of the place. So we will 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 J.P. Morgan.
Yes, good morning everybody. Could you comment on a takeaway issues that you are preparing for related to the Barnett Shale and in competition with the takeaway to passive with the Haynesville Shale another East Texas and other regional place?
Yeah Joe this is Darryl Smette, as it relates to the Barnett we haven’t place a number of film transportation agreements that – and we are currently working on more that will allow us to move all about production as we now see it including the forecast these people have provided just how they can drill that production. So we continually worked that, as you know we also have around midstream business. So we feel very comfortable, we are able to move our gas in well ahead to the main market centers, and beyond the market centers we think we have an upfront transportation already lined up that we are in the final stages of putting together we will be able to move that gas all the way to end use market.
As it relates to the Haynesville obviously, as you’ve heard Steve say and John say, this is an emerging play, I mean, we have high hopes for the Haynesville, we think that has some really good characteristics, but its still emerging. There is a lot of unknown there yet. What we can tell you as we have about. We as an industry have about 8 bcf of pipeline takeaway capacity and I am not talking gathering, I am talking mainline capacity take gas to market. There is about 7 bcf about that the subscribes, and there is about a bcf of available capacity is on subscribe. In talking with the pipelines our current number suggest that t 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 project area 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 and feel good about what is going on in the Haynesville in terms of industry takeaway capacity, but there is a lot that happened 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 of years there could be some bottlenecks for some different players with these competing plays; is that right?
Well I don't think 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. But we don't know that how fast things are going to ramp up. As we 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 look forward suggest that this is going to be a very robust area. But there is still a lot of work yet to is, as Steve indicated, I mean, 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.
It’s helpful. And Darryl while I have you – I have noticed that the Rockies differentials have narrowed recently. Can you comment on that?
Well, it kind of depends on where you start and where you end up. I mean, they're pretty volatile as you know. But yes, if you compared to last year at this time we were trading at about a 450 differential yesterday, we’re trading at about 250 differentials that they have in the road, a lot of that is directly dependent upon of course the rest pipeline that went into service in January. There is other pipeline projects that are going on now and of course we're waiting to the shoulder month we're 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 its 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 see the $4 and $5 differential we saw last year.
Okay. Very helpful. And then different topic Haynesville Shale you mentioned you got some production online, can you comment on what you're seeing so far?
We're really keeping that relatively queue. 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 really to looking at our position, looking at our opportunities to acquire additional acreage and categorizing it much like we did in the Barnett Shale as far as primary position and 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 reasonable cost and reasonable NRIs. And so it's really an accumulation things and because we are still actively acquiring leaseholds, we're not talking about the production range.
Got it. 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 though we continue to get wells down. And again it's the same -- a bit of the same story as we've gotten additional wells down. We've gotten core geology is looking very good and that’s why you see our unrisk potential continuing to increase there.
Okay. Very Helpful.
And obviously Joe, we're still accumulating acreage positions there and we would shoot ourselves in the foot if we talked about that too much at this point.
Understood thank you 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 of mine have been answered. Sorry about that.
Okay Thanks Eric.
And your next question will come from the line of 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 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 with the unitize St. Malo and Jack developments scheme. Can you give me your thoughts on that and comments on the distance between the two?
Yeah absolutely it is a St Malo and Jack within about 20 miles of each other and we are going to a very discipline process with partners at St. Malo and Jack where we look at the options in it optimize the economic efficiency about operation. One other 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 to joint – development teams are working together to go through those options make sure you understand all the technical issues in the cost and performance issues and come up with the optimized development scenario but little leading scenarios is a combined development of Jack and St. Malo.
And Mark just to remind you and then show you how far along those integrated project teams are in doing this evaluation. We are still hoping that we are going to bring this forward in 2009 for sanctioning and that will keep us on schedule with the first production of we talked about previously and probably 2013 or something like that. So we well along in terms of doing a lot of this analysis.
John, Steve does this saying anything about free standing 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 expect to define initially.
Just to want one more if I could for John I am not sure I understand the logic with respect to the extendable debentures on the Chevron side and you – they comment at I think we want to optimize the evaluated position. Would you elaborated on your thinking a little bit on that?
Sure you might remember Mark that – that wasn’t code language you give me there that all its just that if you would give the just give the stock back to the debenture holders you know we have very – because we inherited these from PennZenergy in 1999 we have a very low basis in that stock and so we are trying to do and that would trigger a tax obligation or tax liability and we talked about that in the past, but we are also working on some other alternatives that hope we are little bit more inventive and so, in the interim we are going to redeem those debentures with cash.
Okay guys thanks a lot.
Okay operator we got – we take one more question.
Your last question will come from a line of Fletcher Stern from Diamondback Company.
Good morning guys.
Everybody hear me okay.
I was having phone problems early. 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 and some as mark-to-market. Curious what the mark-to-market exposure was again?
Yes, the market to market –
970 million ore something like that as a June 30. If you were to mark-to-market as of the close of business yesterday there would be no exposure.
It would actually be a gain.
It would actually be a gain.
Okay. That's where I'm leading with this. Current strip price for example just the calendar, 9 Henry hub net gas strip was roughly 1250 and a month later now it's down 25% at 950. 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 just curious if you could comment on potential unwinding of ledges?
Yeah this is Darryl again. We just to put perspective. We have relatively little oil hedges its about 20,000 barrels a day, and it’s only to the end of carrier 2008. On our natural gas hedges again we only have four months to go there. We do have discussions now then above on lining them. So far we have made the decision not to online the 2008 hedges and we’ve made the decision not to online the 2009 hedges that are in place which are about 300 million a day and they’re all collars. So we continue to have discussions about that which is not unusual, we have discussion every week when we have our weekly executive committee meeting, so far we have not made the decision on any of those of positions, and with only four months we have to go in the year, you know, I would have to say that the chance that we are online and majority on lined and 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. I would just like to summarize our second quarter 2008 and reiterate the fact this is one of the best in Devon’s history. We had another quarter of record earnings and cash flow. We increase production for the ninth consecutive quarter and expect additional growth for the foreseeable future. We also increase our production outlook for the second half of 2008 and fairly, significantly for 2009. We completed the bulk of our efforts and divestitures and eliminated $2.6 billion in debt in 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 will talk to you again in the few months.
Thank you for your participation in todays. This concludes the presentation and you may now disconnect. Have a wonderful day.
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