德文能源 (DVN) 2007 Q2 法說會逐字稿

Welcome to Devon Energy's second quarter 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. (OPERATOR INSTRUCTIONS) This conference is being recorded. If you have any objections, please disconnect 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.

Thank you, operator. Good morning, everyone, and welcome to Devon's second quarter 2007 conference call and webcast. I will begin with a few remarks and then our Chairman and CEO, Larry Nichols will review the highlights the quarter and bring you up to date on some of our recent initiatives. Following Larry's remarks, Stephen Hadden, he's our Senior Vice President of Exploration and Production, and he will cover the operating highlights. And then finally Devon's President John Richels will conclude with a financial review. We'll follow that with Q & A session. As is our practice, we'll try to hold the call to about an hour. So if we don't get to your question, please give us a call this afternoon. A replay of today's call will be available later today through a link on devonenergy.com. We will also be posting to our website a new issue of Devon Direct. This is an electronic report that includes highlights from the webcast and also includes links to additional supplementary information.

During the call today we're going to update some of the estimates for the year that are based on the actual results that we saw for the first six months of the year and our current outlook for the second half of the year. In addition to the updates that we will provide in today's call, we're going to file an 8-K later today and that document will give all the details of our updated guidance. Please note that in today's call we'll talk about plans, forecasts, estimates, these are all forward-looking statements under U.S. securities law. While we always strive to provide you the very best estimates possible, there are many factors that can cause our actual results to differ from these estimates. Because of these uncertainties, we would encourage you to review the discussion of risk factors that we provide with our form 8-K accompanying the forecast. One other compliance note. We will make reference today to certain non-GAAP performance measures. When we use these measures, we're required to provide related disclosures, and those disclosures are available on our website at devonenergy.com and we encourage you to review those disclosures.

Finally, I want to remind you that our decision to sell our assets in Africa and terminate our operations there, triggered the accounting rules for discontinued operations. Under those rules we exclude oil and gas produced from the divestiture assets from our reported production volumes for all periods presented. The related revenues and expenses for the discontinued operations are collapsed into a single line item at the end of our statement of operations. However, in today's release we're providing an additional table that gives you a detailed statement of operations as well as production volumes for the properties we are divesting. You will note that for the quarter we reported net earnings from discontinued operations of $80 million, that is in the second quarter. However, that does not mean that the discontinued operations would have actually generated earnings of $80 million had we decided not to sell them.

The discrepancy occurs principally because accounting rules require us to stop reporting depletion on the sale properties once they are designated for divestiture. Had we not chosen to exit Africa we would have had net income associated with divestiture properties of $50 million or $30 million less than the $80 million of income we reported from discontinued operations. Discontinued operations also compliment --complicates the process of estimating earnings and as we did last quarter, we polled the analysts that report their estimates to First Call and determined that some had included African operations, but this quarter the majority excluded the impact of the African operations. The mean estimate for the analysts that we contacted that included discontinued operations, was $1.50 per share. This compares to our non-GAAP diluted earnings of $1.87 per share for the second quarter. The mean estimate for the analysts that we were able to contact that excluded discontinued operations was $1.45 a share and that compares to our non-GAAP earnings from continuing operations of $1.73 per share. So any way you look at it, with or without the contribution of Africa, the second quarter was a blowout quarter. With those items out of the way I'll turn the call over to Larry.

Thanks. (inaudible) even though he's not usually inclined to such exuberant language, but it clearly was a terrific quarter that extends the momentum that we've been building for some time. We're particularly pleased with increase in production from continuing operations, which was 16% better than the second quarter 2006 and 5% ahead of the first quarter of 2007, demonstrating very solid organic growth. The second quarter of '07 was our 5th consecutive quarter of production growth and about 3 million barrels in our target for the quarter. There are several reasons for this outperformance, they're really across the board of our portfolio, and later in this call John Richels will explain those reasons and give a production outlook for the remaining two quarters.

With regard to our second quarter financial results, they were also very strong. As Vince described, the second quarter earnings and the earnings per share came in better than analysts expectations. If you look at the numbers that Vince just gave you, whether you exclude or include discontinued operations, our earnings exceeded the earnings estimates of analysts by 19% and they were also the second highest quarterly earnings per share in Devon's history. The cash flow before balance sheet changes was a record $1.8 billion, bringing the year-to-date total to $3.3 billion. Importantly, the 56.2 million equivalent barrels that we produced in the second quarter puts us well on the way to producing at the upper end of our full-year of 2007 forecast of 219 to 220 million BOE from continuing operations. That would be more than a 10% growth for 2006 over 2000 -- over 2007, over 2006. We're very pleased about our performance at this half-way point of the year and remain confident in the continued success for long-term growth strategy that combines our predictable near-term developmental projects with the higher impact, longer term growth opportunities that we've been building.

Now, concerning our Africa divestiture program, I'll give you a brief status update on that. We expect to close the sale of our Egyptian operations near the end of August. This is the transaction with Dana Petroleum that we announced earlier in the quarter. The sales price was $375 million which includes $67 million working capital. That works out to $38.50 per barrel of proved reserves so we're pleased with that transaction. The West Africa divestiture program began a few months later than the Egyptian program. The interest level has been quite high and we have received more than 30 bids on those assets. As we expected, we received bids for various combination of properties and we're still in the process of determining the most favorable combination of bids, and we will not announce those sales until we've actually signed the purchase and sale agreements in hand. One element of our growth strategy over time has always been to regulate, evaluate our property portfolio and make changes when necessary to realize the greatest value from our broad set of opportunities. That decision to divest our operations in Africa and redeploy the people in the capital to other projects, is of course a result of that evaluation.

As we said when we announced the divestiture plans, in addition to funding our capital spending program, we expect to use the proceeds to repay commercial paper balances and to resume share repurchase program that was suspended last year when we made the acquisition of the Chief Barnett shale properties. This repurchase program is in addition to the recently announced 10B5 share repurchase plan that is intended to offset the dilution of option exercises and grants a restricted stock. Finally I want to mention an announcement we made a week or so ago on July 18th concerning the creation of a marketing and midstream master limited partnership. Under the SEC's preregistration rules which are known as the gun jumping rules we're not allowed to provide any new information on that project that wasn't already included in our news release. To recap that news release, we plan to form an MLP that will initially own a minority interest in Devon's U.S. on shore marketing and midstream business. The purpose of creating the MLP is, of course, to allow the marketplace to establish an independent value for our midstream business that is currently embedded in Devon's overall corporate valuations.

A Devon subsidiary will serve as a general partner of the MLP and Devon will own a majority interest following the initial public offering. Because of the gun jumping rules we request that you refrain from asking any questions about the MLP today. Registration should provide you with most of the answers when it becomes available. With that I will turn it over to Steve Hadden who will give you a more in-depth review of the exploration and production operations. Steve?

Thanks and good morning to everyone. We had an active second quarter, drilling 434 wells company-wide. 14 of these wells were classified as exploration in which 79% were successful. Remaining 420 were development wells and about 99% of those were successful. We had 141 rigs drilling in June, of which 88 were drilling Devon operated wells. Capital expenditures for exploration and development on our retained properties and this excludes operations in Africa, were $1.2 billion in the quarter. This brought total development and exploration capital in the first six months to $2.5 billion.

Let us move to the quarterly operational highlights beginning with the Barnett shale field in north Texas where we continued to enjoy excellent success in production growth ahead of our plans. We are currently running 30 Devon operated rigs, of which 13 are in the core area and 17 are drilling outside the core including 11 in Johnson County. During the second quarter we completed a total of 147 Barnett wells of which 56 were in the core area and 91 outside the core. At the current pace we would drill about 500 wells in the Barnett shale this year compared with our previous forecast of 385 wells. With this additional activity we expect company-wide exploration and development capital to come in at the upper end of our forecast range at $4.9 billion to $5.3 billion. From an execution perspective, the new more automated rigs are enabling us to buck the trend and reduce drilling costs in the Barnett. Average drilling costs have decreased in 2007 versus 2006. This is largely due to a 10% decline in average drilling days per well down from 18.3 days in 2006 to 16.5 days in 2007. This is saving us about $190,000 per well in drilling costs and helping offset higher completion and fracturing costs and is holding our total well costs flat year-over-year in the Barnett.

We continue to see solid results in Johnson County, where during the second quarter we put 24 new wells on line at an average rate of 3.1 million cubic feet a day. Two particularly strong wells in Johnson County each had 24 hours sustained initial production rates in excess of 5 million cubic feet a day. In addition we brought 17 new horizontal wells on line in portions of southwestern Tarrant and southeastern Parker counties at an average rate of about 1.8 million cubic feet a day. We also continue to see solid economic results from our core area 20 acre infill drilling program. Through the end of the second quarter we completed a total of 128 infill wells, 105 of which were horizontals. A total of 124 infill wells have been connected to production grid and 101 of those are horizontal that came on line at an average rate of 2.1 million cubic feet a day. Our net Barnett shale production averaged a record 797 million cubic feet of gas per day in the second quarter.

The second quarter average was up 9% from the first quarter and up 37% compared with the second quarter of 2006. We previously announced a target rate of 800 million cubic feet a day by year-end 2007. Having essentially reached that target already, we have revised our year end expectation to 875 million cubic feet equivalent per day. We had also set long-term target of 1BCF per day by the end of 2009. Given our progress to date, we expect to set a more aggressive target when we update our long-term projections later this year. Because the Barnett shale is so dominant, we seldom highlight our conventional gas operations in Ft. Worth basin. However in the second quarter we also increased conventional Fort Worth basin production by 7% compared to the second quarter of 2006, to 70 million cubic feet a day.

Moving on to the Woodford shale in eastern Oklahoma, we currently have five operated rigs drilling in the play. We brought a total of seven new operated wells on line during the second quarter, with individual well production rates as high as 4 million cubic feet of gas per day bringing our total operated well count to 38. Devon's gross operated production was about 35 million cubic feet a day from the field. Our total net Woodford shale production averaged over 16 million feet of gas a day in the second quarter and we plan to grow that volume to between 25 and 30 million cubic feet a day by year end. We believe that Devon's net resource potential in the Woodford could be as much as 1 TCF.

To accommodate our growth and that of others in the area, we're constructing a $30 million gas processing plant located about 20 miles west of McAllister, Oklahoma. The plant will have the capacity to process up to 200 million feet of natural gas per day and produce about 18,000 barrels a day of natural gas liquids. The plant is scheduled to be operational in May of 2008.

Shifting to east Texas, we continue with a seven-rig vertical Cotton Valley drilling program in the Carthage area. In the second quarter, we drilled 22 verticals wells and continued an active recompletion program. At the end of the quarter we were drilling the 44th well in the 88-well vertical program we had planned for this year. We also continue to have success with our horizontal drilling program in the Carthage area. We added a third horizontal rig during the second quarter and drilled two new wells including our first Cotton Valley horizontal in the central part of the Carthage field. The 98% working interest, Hancock 15H well averaged 16.7 million cubic feet of gas a day for the first 30 days of production. Two additional Cotton Valley sand wells were drilled during the quarter and are awaiting completion. In total, we expect to drill 15 horizontal wells in Carthage this year. Our net Carthage production averaged 249 million cubic feet of gas equivalent per day in the second quarter, up 7% from the first quarter, and up 6% from a year ago.

Also in east Texas we continued to pursue the horizontal drilling program in the Groesbeck area. However, we scaled back this year's plans from 22 wells to 17 wells. The reservoir performance we have seen from the wells in this area is very encouraging but the drilling and completion options we're evaluating are very complex and we're working towards refining our approach before moving into full development in the area. This is very similar to our approach that we've taken in the non-core Barnett shale, where we thoroughly evaluated our position before moving into wide-scale development. We still believe we have as many as 200 potential horizontal drilling locations in the Groesbeck area.

Moving to the Rockies, in the Powder River basin in Wyoming, we have eight rigs currently running, including four Devon operated rigs drilling in the Big George formation in the West Pine Tree and Juniper draw areas. We expect to drill more than 200 new wells by year end. Our net Powder River production averaged 61 million cubic feet of gas per day in the second quarter, up 9% from the first quarter average and up 11% compared with the second quarter of 2006. We expect to exit 2007 producing over 70 million cubic feet a day and ultimately expect to bring Powder River production to more than 100 million cubic feet per day in late 2008.

Now, shifting to the Gulf of Mexico. We're pleased with our continued progress in the quarter in our deep water lower tertiary trend. First, at our 2006 discovery, called Cascada, the MMS approved expansion of the Cascada unit to the west with the addition of Keithley Canyon blocks 244 and 245 in June. As a result the Keithley Canyon 244 number 1 well previously known as the Cortez Bank Prospect was included in the unit.

The well, some 12 miles away from the discovery well, sits in 5500 feet of water and is currently drilling below 30,000 feet. Cascada is operated by BP and Devon has a 20% working interest. The second lower tertiary well we're drilling is on our Chuck prospect located in Walker Ridge 278. This exploratory well targets a large subcelled structure in about 6500 feet of water. The well is currently drilling below 8,000 feet with the Ocean Endeavor, a deepwater drilling rig that we have under long-term contract. Devon is the operator of Chuck, with 39.5% working interest. Also in our lower tertiary exploration program, during the second quarter we completed an agreement to acquire a 23% interest in the Greenbay prospect located on Walker Ridge 372, approximately 20 miles north of St. Malo discovery and about 18 miles east of our Chuck prospect. This area has seen many lower tertiary discoveries to date and we expect to begin drilling an exploratory well on Greenbay prospect in the fourth quarter. Our Gulf team continues to work with our partners towards the commercial development decisions on each of our lower tertiary discoveries.

At Cascade, our 50% working interest project with Petrobras in the Walker Ridge area, we expect to sanction the project and award FDSO and development contracts later this year. At Jack also in the Walker Ridge deepwater lease area, Devon and our co-owners are preparing to initiate drilling on a second deliniation well, the Jack number 3, later this year, with the results expected in early 2008. The well will be operated by Devon and drilled with the Ocean Endeavor when drilling is complete on the Jack exploratory well. The co-owners are evaluating various development options for Jack and Devon has a 25% working interest in that prospect. Finally at St. Malo, also in the Walker Ridge deepwater area we expect to drill another delineation well during the fourth quarter. We have a 22.5% working interest in St. Malo. In the eastern Gulf of Mexico, the Merganser field was ready for production to the Independence hub in the second quarter. Devon has a 50% interest in the two Merganser wells, which should commence production later this month. We expect our share of production to be about 50 million cubic feet of natural gas per day.

Shifting to the Gulf of Mexico on the shelf, again this quarter we had success in both exploration and development projects. We made a discovery at our lime prospect on Eugene Island 354. The well was drilled to about 10,600 feet and penetrated the lenthic sands where we found approximately 140 feet of net pay. We expect to bring the lime discovery on line in the third quarter, at an expected rate of about 8 million cubic feet of natural gas per day. Devon has a 50% working interest in this discovery. On the development side we drilled a third offset to very successful 2005 Chopin discovery. The B12 development well located on Eugene Island 333 was completed in June and came on line with 25 million cubic feet of natural gas per day. All four wells are currently producing at a combined rate of 75 million cubic feet of natural gas per day and Devon has 100% working interest in the four wells. Our Gulf team now has largely completed the planned 2007 shelf capital program with 100% success rate, a job very well done.

Moving north to Canada, we drilled just 63 wells in Canada in the second quarter due in part to the extremely rainy spring. The wet and muddy conditions delayed our drilling in the first two months of the quarter at our Lloydminster oil play in eastern Alberta. However, in June we ramped activity back up to five rigs and were able to drill 36 wells in Lloydminster. We plan to maintain a five-rig program for the remainder of 2007. Our net production from the Lloydminster area averaged 33,000 barrels of oil a day in the second quarter up 48% compared with the second quarter of 2006. We've also begun to prepare for our next expansion of the Manitokan plant, an additional 10,000 barrels a day of processing capacity will be added to bring our total processing capacity at the facility to 27,500 barrels a day, in anticipation of our growing oil volumes.

At our 100% Devon owned Jackfish thermal heavy oil project in eastern Alberta, precommissioning activities were completed in June and first steam was achieved on July 16th. As we've indicated before, we expect production from Jackfish to begin around the end of this year. Production will then ram up towards an expected sustainable rate of 35,000 barrels a day by the end of 2008. At our Jackfish II project, engineering and budgeting work continues and we expect to receive regulatory approval around mid 2008. At that point, we expect to make a formal decision about the project. Jackfish II would essentially double the size of the Jackfish project adding another 35,000 barrels a day of oil production.

Moving to the international arena, development drilling on the Devon operated Polvo oil project on BMC 8 in Brazil continued during the second quarter. As we announced on Monday, we have now begun producing into the FBSO from the first of ten development wells. The additional wells will be drilled and tied in throughout the remainder of this year and into 2008 as we ramp our production up to 26,000 barrels a day net to Devon's 60% working interest.

In Azerbaijan, where Devon has a 5.6% interest in the ACG oil field, gross oil production exceeded 750,000 barrels of oil a day in early May. Devon's share of ACG production averaged more than 40,000 barrels a day in the second quarter. This was above forecast because of favorable timings of (inaudible). We don't expect that situation to repeat in the third quarter. In fact we expect two to three weeks of planned down time at ACG in September to tie in new facilities and do some maintenance work.

Finally in China, we would be replacing the production riser at the Panyu field during the third quarter. Accordingly we anticipate up to two weeks of down time at the Panyu field. This work was originally scheduled for the second quarter, but was delayed awaiting delivery of the replacement equipment. In summary, in the second -- in summary, the second quarter delivered strong operational results, demonstrated good organic growth and advanced our high impact projects adding both near-term and long-term value.

Now I'll turn the call over to John Richels to review our financial results for the second quarter.

Thanks, Steve. Good morning. This morning I want to take you through a brief review of the key drivers that impacted our second quarter financial results. In addition, I will review with you how these factors are likely to affect our outlook for the remainder of the year. As Vince mentioned, we're issuing an 8-K today that will provide further details of our updated 2007 forecasts. As a reminder, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. As a result, I'll focus my comments on our continuing operations which exclude the results attributable to Africa.

Let's begin with production. In the second quarter we produced 56.2 million equivalent barrels or approximately 618,000 barrels per day. These results exceeded our guidance by over 3 million barrels or about 6%. Approximately half of the 3 million-barrel outperformance is attributable to better than expected performance from our core North American properties. The other half of the outperformance is attributable to favorable royalty adjustments in Canada, the timing of oil sales from the ACG field in Azerbaijan and rescheduling of expected down time at our Panyu project in China.

When you compare our second quarter results to the same quarter a year ago, you will find that company-wide production increased by 84,000 barrels per day or roughly 16%. This strong year-over-year growth was driven primarily by our U.S. on-shore and international segments. Production from the U.S. on-shore grew by over 40,000 barrels per day or 15% when compared to the second quarter of last year. Once again, the leading contributor to our U.S. on-shore performance was growth in the Barnett shale production.

In addition, we also experienced significant growth from our international sector, up nearly 45,000 barrels per day over the same quarter last year. This was primarily attributable to the ACG field in Azerbaijan. In Canada, despite significantly scaling back conventional gas drilling activity, second quarter production remained relatively flat year-over-year, and actually increased by 4% over the first quarter of 2007. We had strong performance from our Lloydminster area projects and that performance was also aided by reduced royalties. Based on first half results, we expect production to come in at the top end of our full-year 2007 forecast range of 219 to 221 million oil equivalent barrels. Looking to the second half, we expect our production to total approximately 55 million equivalent barrels in the third quarter, and 57 million barrels in the fourth.

Third quarter estimate reflects a slight decrease in production from the second quarter. This is driven by the timing of oil sales and the scheduled field down time in Azerbaijan that Steve mentioned. Also it reflects scheduled down time for the equipment replacement in China and an anticipated drop in production from Canada. Fourth quarter growth will be fueled by our U.S. on-shore properties and the ramp up of production from the Merganser field in the deepwater Gulf and the Polvo field offshore Brazil.

Moving on to price realizations and starting with oil. In the second quarter the Benchmark WTI oil price averaged $65.08. That was 8% below the second quarter of 2006, but a 12% increase from the first quarter of 2007. In addition to the strong oil price environment this year, regional differentials narrowed and price realizations in virtually all of our producing regions were in or above the top half of our guidance range.

The leading driver of our higher oil price realizations was the robust international oil market and this is reflected in the premium pricing that we received for our light sweet oil in Azerbaijan. As a result our company-wide price realizations rose to 92% of WTI or $60.01 per barrel for the quarter. That is a 15% improvement in realized pricing when compared to the first quarter of 2007. We will be updating our full-year oil price differential guidance in today's 8-K to reflect the improvements in pricing. On the natural gas side, the benchmark Henry Hub Index averaged $7.55 per MCF in the second quarter. And this was 11% higher than in the second quarter of 2006 and 12% higher than the first quarter of 2007. Our company-wide gas price realizations came in near the midpoint of our guidance at approximately 86% of Henry Hub. Price realizations remain strong in Canada and in the Gulf of Mexico.

However, this regional strength was offset by weak gas price realizations in the Rocky Mountains. As many of you know, price differentials in the Rockies have widened significantly over the past few months due to increased production and constrained take-away capacity. As a result of the short term issue we continue to expect soft pricing to persist in the Rockies for the remainder of 2007. Looking ahead to the third quarter, we now expect natural gas price realizations to approximate 100% of NYMEX for the Gulf, 80% of NYMEX for the U.S. onshore and 90% of the NYMEX for Canada. Updates to our full-year differential guidance will be provided in today's 8-K.

Turning now to our marketing and midstream business. In addition to the terrific upstream performance in the second quarter, Devon's marketing and midstream operations once again delivered impressive results. Marketing and midstream operating profit for the second quarter totaled $119 million, that was $14 million greater than the second quarter of 2006 and $10 million sequential quarterly increase. This solid performance was driven by increased gas processing revenues combined with higher natural gas pipeline through put. Based on our strong showing in the first half of the year, we now expect our marketing and midstream full year operating profit to come in between $420 million and $460 million, which represents an increase of $30 million from our previous guidance.

Moving to expenses, second quarter lease operating expenses were near the midpoint of our guidance coming in at $439 million or $7.81 per barrel produced. Unit LOE costs were 4% lower than the $8.13 per barrel we reported in the first quarter of 2007, however, we still anticipate a rise in LOE during the second half of the year. This increase will be driven by scheduled maintenance in our international and Canadian operating regions, along with higher unit costs incurred while our new development projects ramp up production. We now expect our full year lease operating expense to be in the range of $8.00 to $8.30 per equivalent barrel.

Our second quarter DD&A expense for oil and gas properties came in within our guidance range at $11.48 per barrel. Looking forward we expect our third and fourth quarter DD&A rates to rise to between $11.50 and $12.25 per equivalent barrel. Based on this, we're now forecasting our full-year 2007 DD&A rate to come in between $11.40 and $11.80 per equivalent barrel.

Moving on to G&A expense, G&A expense for the second quarter was $113 million, right in line with our guidance and $6 million less than the previous quarter of this year. At this time we're not making any changes to our full-year G&A guidance range of $460 million to $480 million.

Second quarter interest expense came in at $107 million, right in line with our expectations. Of total interest expense for the quarter, $20 million was related to commercial paper balances which we expect to pay down following the close of the African divestitures. As Larry mentioned earlier, we expect to close the sale of Egypt during the third quarter and we are expecting to close on the West African sales near year end. Based on these expectations and the related timing of commercial paper balances, we now expect full-year 2007 interest expense to be in the range of $430 million to $440 million.

The final expense item that I want to touch on is income taxes. Income tax expense for the second quarter came in at 29% of pretax income. When you back out the impact of items that are generally excluded from analysts' estimates, you get an adjusted current tax rate of 15%, and a deferred tax rate of 16% for a total income tax rate of 31%. We remain comfortable with our full-year guidance ranges for income taxes. In today's earnings release we provided a table that reconciles the tax effects of items that are usually excluded from analysts' estimates.

Moving to the bottom line, reported earnings from continued operations were an impressive $824 million or $1.82 per diluted share in the second quarter of 2007. That is a 43% increase in earnings from continuing operations over the first quarter of this year.

Earnings from discontinued operations came in at $80 million, or $0.18 per diluted share. In aggregate, after backing out items that are typically excluded from analysts' estimates, our total net earnings for the second quarter were $845 million or $1.87 per diluted share. As we said earlier, the results far exceeded our expectations, as well as those of the street.

Cash flow before balance sheet changes reached a record $1.8 billion, up 24% from the last quarter and up 18% from the second quarter of 2006. Year-to-date, our operating cash flow before balance sheet changes totaled $3.3 billion, comfortably funding $3 billion of capital investments and leaving us with nearly $300 million of free cash flow. In addition to our strong cash flow, we exited the month of June with a healthy cash balance of $1.4 billion, while our net debt to capitalization ratio reached a 12-month low of 20%.

Looking to the remainder of 2007, we expect cash flow from operations to generally cover our total capital demands. That will leave us with the after-tax proceeds from the African divestitures available to reduce debt and resume repurchasing shares. To summarize, Devon's second quarter performance was a strong one in almost every way. With that, I'm going to turn the call back over to Vince to open it up for Q&A.

Thanks, John, and operator we're ready for the first question.

We will now begin the question-and-answer session. (OPERATOR INSTRUCTIONS) Our first question comes from Tom Gardner, Simmons & Company.

Good morning, guys. Could you comment -- could you comment on the potential for additional offset wells to the two wells you have at Merganser and any additional comments you care to make on opportunities for additional gas development around the Independence hub?

Yeah, Tom, this is Steve. Right now we don't have any near-term plans for future development around Merganser. It's essentially two wells, 50% working interest and they'll come on about 50 million cubic feet a day. We continue to work a prospect inventory in the eastern Gulf and as they come up and rank competitively where we can move them forward to drill, we'll do that. But right now we don't have any specific plans to drill additional prospects in that area.

Thanks for that. Regarding Polvo, how rapidly do you see production ramping up to net to your 26,000 barrels a day net and can you give us an idea of the crude quality and likely price realizations from that oil?

Yeah, this is Steve, again, relative to the Polvo development we started our production already. We've got two wells drilled. We'll drill a total of ten and that includes a couple of injection wells. I would anticipate we would be ramped up to that 26,000 barrels a day net probably sometime around the middle of 2008.

Thanks, guys.

Our next question comes from Ben Dell, Sanford Bernstein.

Hi, guys.

Hi, Ben.

I have a one macro question and one specific one. Firstly, the specific one on Cascade. You talked, if I heard you rightly, sanction at end 2007, previously you talked about production in 2009. Would that still be the case?

That is still our current target is around the end of 2009 for first production. Sanctioning decision would probably happen sometime this year.

And I know it's a long way off on Jack, but Chevron sort of made comments they didn't expect Jack to start up before [Gorgon] which puts it in the sort of 2014 plus range. Is that sort of where you're looking or is it early part of next decade?

We're working together with the partnership and I think our plans with the MMS say somewhere in that range of 2014, but it is still very early as it relates to putting together the final production configuration and what the commercial sanctioning project -- commercially sanctioned project would be going forward. To speculate any more than that on timing would be a little bit premature from our perspective.

Lastly on the macro side, you along with a number of other gas players, have recorded pretty good volume growth, both year-on-year, a lot of it coming from the onshore which still appears to be up 5% despite the rig count flattening off. Do you think this is a trend you expect to see continuing on the macro? If so, do you believe it has any implications to future gas prices?

Well, a couple of observations, Ben. We're going to see a lot of incremental gas demand coming out of the Canadian oil sands over the next couple of years. Certainly production growth does have implications onshore, as well as bringing on the Independence hub will be a significant increase in Gulf production. But we remain long-term pretty bullish on the North American natural gas market.

Yeah, Ben, I might add while Devon and a few other independents are achieving production growth, the majors have not chosen to put a lot of their capital into U.S. onshore gas production, and their production has generally been declining for many years. That could, of course, change. But while the independents -- some independents have been achieving growth and Devon is pleased to be at the top of that list or near the top or at the top, don't know exactly, haven't compared it all, but certainly a contender for that, overall there is a lot of production in decline in the U.S., and in Canada, with imports from Canada declining. There are a lot of moving pieces there.

Okay. Great. Thank you for your time.

Our next question comes from John Herrlin, Merrill Lynch. Mr. Herrlin, your line is open. You may need to check your mute button.

Sorry about that. Good quarter. I don't normally say that.

We appreciate that, John.

Sure. Regarding your free cash, why not roll the commercial paper and shrink the denominator, buying stock?

At the moment, since we have a registration statement on file, for our MLP, the company and all of the officers are precluded from doing anything in the marketplace. So from a legal standpoint that is not an option to us at the time. Once that registration statement is filed, in approximately a month or so, then the use of free cash is something that we can consider.

Okay. That's fine. Would Steve, with Chuck, you didn't mention kind of a target size or I missed it.

I didn't mention it but I will tell you we generally say these lower tertiary prospects are to 300 to 500 million barrel range or bigger and this is in that range.

Okay. Last one for me is on frac costs in the Barnett, you had good efficiencies with fit-for-purpose equipment. Are you seeing any drop in your frac costs at all?

No, we've seen some deceleration of the cost escalations, if that makes sense, and we're just going through, we're getting into the period of time now to where we'll start looking at our contracts for 2008, and looking at -- looking at pricing there. So we're just getting into that window where we're going to get a good look at the go-forward pricing here. But we've seen some flattening in the escalation rates.

Do you plan to lock in any equipment longer term, like rigs?

As a matter of fact, we currently have -- we have kind of a blended portfolio. When you look at those 30 rigs, we have some of those rigs under a long-term contract, some on much shorter terms and we manage our risks that way. Some of those rigs are longer-term contracts, some aren't. Some are sorter term.

Thank you.

Our next question comes from Mark Gilman, the Benchmark Company.

Good morning. I had a couple things. I wonder if you could just put a little more color on the scale back at Groesbeck. Is that a well cost issue that you're responding to?

No, no, actually when we looked at it, Mark, when we drill these wells, we're getting relatively good reservoir performance, and we go through and drill these long reach horizontal wells and do multiple stages along a horizontal section that are along these spacing units, sometimes 40-acre spacing units. And every time we do a stage or generally on average, we're seeing the reservoir performance from each stage that we have. We're simply working through some execution issues as it relates to the type of drilling we want to do, the type of mechanical completion. In other words, the type of jewelry you want to put in the hole, and then the interplay with that, with the completion, to try to optimize all of that before we go into full-blown development. We're simply not comfortable yet, to really start ramping up our drilling activity until we're comfortable that we can deliver good solid consistent results.

Steve, what have the drilling costs been per well?

Oh, you know they can range from about $6.5 million to as much as $11 million, depending on where we're drilling, how deep it is and how far we try to reach out with that horizontal section.

That's drilled, completed and fraced.

Yes.

Okay. On the Lloydminster area, I wonder if you could talk a little bit about whether or not the production increases are associated with new areas, whether it is infill and whether you've got a number of locations identified?

It is a combination of those things. We continue to grow the Lloyd area and the Lloydminster area. We have -- we did acquire the Iron River properties back in 2004, 2005, and that that had a lot of running room on it. That's adjacent to our Manitokan field that we've had and developed for quite some time and it was relatively undeveloped. So we're getting a pretty good kick from the Iron River side as well as other drilling in Lloydminster area.

Okay. One final one for me. I assume that with the incorporation of Cortez into the Cascada unit that your interest in the unit given 20% in Cortez will still be 20%?

Yes.

Thanks a lot.

You're welcome.

The next question comes [Raheem Sabgee] from UBS.

Good morning, just a question on the convertible bond or exchangeable bond you guys have outstanding on the balance sheet convertible into Chevron stock, I guess. I've been told that some of the holders might be converting it before the Chevron dividend in August or later this month. I'm just wondering what are the tax implications of that on your bottom line?

It must be a good question, we're all looking at each other.

It is certainly their option to exchange that at any time. As far as the tax implications --

One of the things you have to recall is that we have the option of paying that either in stock or an equivalent amount of cash. If we pay an equivalent amount of cash for anything redeemed there is no tax consequence. It is only -- only becomes a tax consequence for us at the time we liquidate the underlying stock because of the cost basis in that. So we have a lot of flexibility there and particularly with our free cash position today we have a lot of flexibility in determining how we might do that.

Okay. Has there been any thought or discussion of restructuring the convertible or exchanging it to defer that tax implication?

There are a lot of different opportunities available and we have a lot of flexibility in terms of what we might do with it. Something that we've looked at continually over the past few years, and we will continue to, as we get closer to the -- to the maturity date which I think is August of 2008. We're continuing to look at that.

Okay. Thank you.

Our next question comes from Ray Deacon, BMO Capital.

Yeah, hey, John, I guess I had a question on Jackfish and what the thought process is as far as the second phase there. And maybe if you can speak to what the cost increases have been since you took on this first project or if there is any technologies that can help you mitigate some of those cost increases and then maybe just a quick comment on the Barnett. It sounded as though you were saying your well cost looks to be flat year-over-year, so I guess is the implication that besides the drilling costs, completion costs have been trending up? Is that a fair way to look at it?

Let me take a crack at the first one and I'll turn the Barnett question over to Steve, Ray, but on Jackfish II we're still -- as Steve indicated, we're still doing a lot of work right now on budgeting. There is no doubt that Jackfish II is going to be -- come in a little higher than Jackfish I just because of the cost pressures we're all aware of in the oil patch, particularly in and around the Fort McMurray area. However, we did some things when we built Jackfish I that anticipated that we might upsize to a second project. And as you know, we also built the access pipeline and some blending and other facilities that Jackfish II will get the benefit of, because we've really absorbed that capital cost into the first phase. So we're not quite sure, yet, exactly what the budget project is to look like. Still working on that. We are really encouraged, though, by what we've seen on the technical side, Jackfish II looks to be, from a reservoir point of view and from a quality point of view, every bit as good as Jackfish I, which we believe is a top decile lease in the province. We're pretty positive about it and we'll likely make a sanction decision on that sometime in and around the time that we expect to get regulatory approval which should be about mid 2008.

Got it.

And because that is a year off, the questions are not what the costs are now, what they'll be then as you have seen from some of our other reports today and things like the Barnett, where we have actually brought some costs down and held others flat. Ultimately the costs in Canada have got to come down as -- because of the pull-back that Devon and other companies have done in the conventional drilling. So, the costs a year from now, they may be up or down. We'll wait and see.

What it allows us to do too, Ray, is you asked if there was going to be different technology, we're really looking at this as a look-alike to Jackfish I, taking advantage of the knowledge that we got from that rolling over some of the crews and the time period allows us to do a lot of engineering, so we ought to go into it with a great deal of certainty. Let me turn that over to Steve now on your Barnett shale question.

In regards to the Barnett, I think you had it spot on. Essentially we saw that $190,000 per well improvement on the drilling side, just for drilling only. When you look at the other costs for a total completed well, that improvement essentially offset those cost escalations year-over-year so you end up with a flat well cost '06 to '07.

Got it.

Which is a great result for such a major part of our capital expenditures.

Right. Thanks very much.

Thanks, Ray.

Our next question is coming from Rahan Rashid, Friedman, Billings and Ramsey.

Morning, sticking with Barnett for a second. How should we think about future reserve growth. I know you guys talked about 3 TCF proved and 13 and change, 3P potential. What could be some of the technology drivers or results, and just some sort of a time line, if you could, please.

I guess to get back to that you mentioned the 13.5 TCF total resource potential that we've put out before and that is on a risk basis. We're very comfortable around that number right now as far as the total resource potential. Obviously, stepping up from 385 wells this year to 500 wells, is going to have a positive impact on both our recovery and ultimately on our reserves. And we think we'll continue to realize good strong reserve additions from the Barnett for the foreseeable future as we go through. So we're -- it is just a continuous process of driving towards -- getting that ultimate recovery at 13.5 TCF or better.

Some of the things we're doing is continuing to downspace. We talked about 20-acre infill program that we had done both in the core area and expanded a bit to the non-core. We have another 400 locations or so, plus or minus, that we've identified as far as 20-acre infill opportunities. There could be more, but right now we're looking at about something in the range of 400. We also have opportunities with our refrac programs. We do refrac when the well performance dictates that it is time to do that. We've only done maybe about 40 or so this year, but we're continuing to get very good results that give us additional recoveries as high as .7 BCF per frac and so that is another tool or technology we're using to use to continue to claw away at that total resource potential.

What recovery factors did you assume when you talked about the 13.5 TCF risk potential?

If you look at the 13.5 TCF and you look at it, it is a risk number. And if you look at the acreage under Devon's control and look at our estimate of gas in place in that acreage under Devon's control, it is about 11 to 13% of the gas in place.

Okay. And then do we need once again on simul-fracs or (inaudible) frac to work for us to progress down this recovery factor path or simply downspacing and marginal stuff like that would work?

We think the majority of it is going to be with existing technology and continued improvements in our exploitation work as we move out into the non-core and then look at the downspacing areas. There could be some additional potential with even smaller downspacing or other technologies, but that is not fully baked in or reflected in the 13.5 TCF.

One more question but on the deepwater side. So it's Cortez and Chuck, and what else from the deepwater subsalt side this year in terms of exploration?

I think we mentioned the Greenbay prospect that we just picked up 23% interest in. That should spud sometime probably in the fourth quarter of this year. So that will probably be the last exploration -- subsalt exploration well we'll be drilling this year.

Got it. And how would the program look like next year?

We haven't finalized that program, yet. As I mentioned before, we have appraisal work going on. The exploration work, we're still working on finalizing that. We're just going in, as we come out of August and go into September we'll go through our budgeting process and really firm up those plans going forward.

I guess a better way to phrase it will be will it be dependent upon results from Chuck or Cortez or not?

I don't think on the exploration side it will be materially affected by those two. You know, generally what you'll see us do is we'll probably drill a couple of deepwater exploratory wells in the lower tertiary each year on average going forward and we may pick up a few deepwater Myocene opportunities to compliment that as we go forward. But generally, you'll see us in the one to three range as it relates to our opportunities on average over about a four or five-year period.

One last question. On the deepwater side we've seen quite a bit of activity in the Walker Ridge side. Any kind of particular thoughts why so much on the Walker Ridge and not maybe as much, although you're seeing good success in the Keithley Canyon or some other place?

I'm sorry. Could you repeat that? I didn't hear it all.

So the bulk of the activity on the subsalt side seems like an industry is focussed on Walker Ridge. Any kind of technological, geological explanation for that, versus not being focused somewhere else in the deeper waters?

No, we just will -- we'll generally -- we just continue to work the portfolio and identify the best opportunities for us to drill going forward and we stay pretty tight-lipped about everything else.

Our final question is coming from David Heikkinen, Pickering Energy Partners.

Good morning and question on the Woodford, the net acreage for the one TCF potential?

The net acreage is about -- it is about 70,000 acres.

Okay. And have you tested the Woodford and Ardmore basin at all?

We're currently looking at a couple of different areas. And we have not announced any test in the Ardmore basin.

Okay. And then, thinking about the corporate target of 350 to 370 million barrels of oil equivalent in reserve adds this year -- or goal, and then adding 115 wells to the Barnett, seems like you could have some upside to that target. Is that a reasonable thought process?

This is Vince, there is always pluses and minuses. That is why we give a range and we aren't updating our reserve target range for this year. If there were some risk barrels in that range for lower tertiary which we think -- now think we will not book this year, and so I just don't think we're prepared to move the range.

Okay. That's cool. So still on target, though, for the original range. No concerns with that.

Absolutely. Comfortable within that range.

Not trying to get too much into the weeds, but you're drilling some offset wells to Quest Star in the Vermilion basin. Any idea of how we should think about that from a Devon standpoint of how meaningful that could be?

Too early. It is just too early to tell at this point.

That's perfect. Thanks a lot, guys. Thanks.

Okay. We're at the top of the hour. Larry, do you have any closing remarks for the call?

Well, yeah, I hate to summarize because I would just like to repeat every sentence we've gone over, but clearly we had very strong financial results for this quarter. And it was driven by production growth, really throughout the company; which is exciting not only in and of itself, but we're clearly solid in a position to reach the upper end, as we've said, of our full-year production target of 221 million BOE through organic growth. At the same time that we're keeping expenses under control across the board, outstanding performance at Barnett shale with 36% over last year, as well as all of our low risk core projects that will be supplemented in the second half of the year with Merganser and Polvo as those longer term projects start to come on stream. Continue to advance our projects in the high impact portfolio in the lower tertiary. All in all, very pleased with the first half results and look forward to a great second half.

For those that we didn't have time to answer questions, we'll be here this afternoon. Thank you and look forward to talking to you again in November. Take care.