德文能源 (DVN) 2007 Q3 法說會逐字稿

Welcome to Devon Energy's third 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. To ask a question, (OPERATOR INSTRUCTIONS). This conference is being recorded. If you have any objections, you may disconnect at this time.

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

Thank you, operator and good morning to everyone. Welcome to Devon's third quarter 2007 conference call and webcast. Today's call will follow our standard format, that is starting with our Chairman and CEO, Larry Nichols who will provide his perspective on Devon in the quarter. And following Larry is Steve Hadden, our Senior Vice President of Exploration and Production, will cover the operating highlights. Then Devon's President, John Richels will conduct the financial review. As usual, we'll open the call up to questions and we will try to hold the call to about an hour. A replay of the call will be available later today through a link on our website, that is devonenergy.com. We will also be posting to the website a new issue of Devon Direct, that's our electronic report that includes highlights from the webcast and includes links to a supplementary information. During the call today, we are going to update some of estimates based on actual results for the first three quarters of year and our outlook for the balance of the year. In addition to the updates that we'll provide in today's call, we plan to file a form 8K later today and that will document all the details of our updated guidance.

Also, please note that the references in today's call to our plans forecast estimates and so on are forward-looking statements as defined by U.S. Securities Law. There are a number of factors that could cause our actual results to differ from those estimates so we'd encourage you to review the discussion of risk factors that accompany the estimates in the form 8K.

One other compliance note: We will make reference to certain non-GAAP performance measures. When we use these measures, we're required by Securities Law to provide certain related disclosures. You can see those disclosures. They're available on our website, again, that's devonenergy.com. Finally, I want to remind you that our decision to sell our assets in Africa triggered the discontinued operations accounting rules. Under those rules, we exclude oil and gas selected from the assets selected for the divestiture from 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 bottom of the statement of operations.

However, in the spirit of full disclosure, you will find an additional fable in today's news release that includes a detailed statement of operations and the related production volumes attributable to the properties that we're divesting. Also, I want to point out that net earnings from discontinued operations were $91 million in the third quarter, however that does not mean that the discontinued operations would have contributed the full $91 million of additional earnings if we were not selling them. That's because the accounting rules for discontinued operations require us to stop recording depletion expense on the sales properties once we make the decision to divest them. Had we not chosen to exit Africa, we would have reported net income associated with the divestiture properties of $66 million or $25 million less than the $91 million of income from discontinued operations for the quarter.

Accounting for these discontinued operations also complicates the comparability of earnings estimates. Most of the analysts that reported estimates at the first call of this quarter excluded the impact of the discontinued operations. The mean estimate of earnings per share from the analyst that excluded it was $1.39 per share. That compares to our non-GAAP earnings from continuing operations of $1.41 per share. The mean estimate for analyst that included discontinued operations on their estimates was $1.47 a share, and that compares to our non-GAAP diluted earnings to $1.55 per share for the third quarter, including discontinued operations. In either case, our non-GAAP earnings beat the street expectations. With those items out of the way, I'll turn the call over to Larry Nichols.

Thanks, Vince. The third quarter was another excellent one for Devon. We made progress both from an operational standpoint, the financial standpoint and some important strategic actions of which I'll comment on in a moment. For the third quarter, oil and gas production exceeded our expectations at our guidance. Our production grew 10% over the third quarter 2006, which provides us with our sixth consecutive quarter of organic production growth. We outperformed our third quarter forecast by nearly $2 million equivalent barrels which allows us to increase our full year production forecast. John Richels will discuss the drivers of this production outperformance in a revised guidance in a little bit.

The financial results for the third quarter were also very positive. Net earnings were $735 million and earnings per share exceeded street expectations both with and without discontinued operations. Cash flow before balance sheet changes increased 15% to $1.8 billion, bringing the year-to-date cash flow to $5 billion. We funded total capital expenditures of $1.6 billion and we repurchased 120 million shares of our common stock and ended the quarter $1.7 billion of cash and short-term investments. We ended the quarter with net debt suggested cap at its lowest point in ten years at 19%.

Following the end of the third quarter, we moved forward with our Africa divestiture program by closing the sale of the Egyptian operations in early October. As of the closing date, the adjusted sales price was $341 million and we do not expect to pay any income tax on this transaction. We are finalizing purchase and sales agreement and getting the necessary partner in governmental approvals for the remaining African assets. Although the process has been complicated and time consuming, we're optimistic that we can complete all of these transactions by the end of the first half of 2008.

In today's release, we provided an update our previously announced MLP, our master limited partnership. As noticed in the release, we have reconsidered our plans to form a marketing and midstream MLP. This decision reflects our views about the current condition of the public market for yield driven instruments. The market today is just less receptive than it was when we announced our plans so we're putting that project on hold. With Devon's marketing and midstream business generating more than $450 million in operating profits, we believe it is prudent to be very cautious with any decision affecting this important and strategic part of our business. Although we have no firm debt timeline for revising the projects, we will reconsider in the future, should markets conditions can change.

Before I turn the call over to Steve Hadden, I want to share our perspective on the royalty situation in Alberta. As you probably know, in late October the Alberta government announced a change in the role regime in that province. With Canada providing a quarter of Devon's current oil and gas production and with most of that in Alberta, any change in the royal structure is a course of concern. The new structure is somewhat complex and we're still evaluating the impact of the changes on our Canadian operations, but it does seem likely that there'll be some economic impact. Devon's capital investments are of course based not just on royalty rates but rather on expected full cycle returns. Those expected returns are Impacted by our expectations for production, realized oil and gas prices, capital costs, operating costs, foreign exchange rates and a host of other things.

On a positive note, last week the Canadian federal government announced a budget proposal which, if enacted would reduce corporate income taxes which would have a positive impact on our Canadian returns. You can be assured that our future investment allocation decisions will continue to take into account not only the implications of the Alberta government's decision to change the terms under which we operate, but also all of the returning criteria we evaluate. Fortunately, Devon has a very large and diverse portfolio which will allow us to reallocate capital both within capital and both between Canada and between Canada and across all of our other operating divisions. We'll of course choose those areas which generate the most favorable return. At this point, I'll turn the call over to Steve Hadden. Steve?

Thanks, Larry and good morning to everyone. Let's start with a look at our 2007 capital spending. During the third quarter, our expiration and development CapEx totaled $1.4 billion bringing year-to-date E&P capital expenditures to $3.8 billion. As we noted in last quarter's call, we expect full year E&P capital to commend near the top of our forecasted range at about $5.3 billion. At the end of the third quarter, we had 150 rigs running company-wide with 89 of those rigs drilling Devon-operated wells. We drilled 599 wells company-wide during the quarter. 24 were classified as exploratory of which 92% were successful. The remaining 575 wells were development wells and about 98% of those wells were successful, giving us an overall success rate for the quarter of roughly 98%.

Now, let's move to our quarterly operational highlights beginning with the Barnett shale field. We reached a significant milestone during the third quarter by drilling our 1,000th Devon-operated Barnett shale well. It was just about five years ago that Devon pioneered horizontal drilling in the Barnett. Due to the superior economics and reduced surface impact, almost all the wells being drilled in the Barnett today are horizontal. Horizontal wells make up about 1/3 of our Barnett producers but account for 2/3 of our Barnett production.

Our Barnett shale production averaged a record 856 million cubic feet of gas equivalent per day in the third quarter. This was a 7% gain from the second quarter and up 32% compared with the third quarter of 2006. In our last call last quarter, we revised our year-end target rate to 875 million cubic feet equivalent per day and we're well on t he way to hit that goal. We'd also previously announced a longer term net target rate of 1 BCF per day by the end of 2009. Given our progress to date and the pace we're on, we now expect to reach the 1 BCF mark per day by early 2009. This is more than twice the forecasted production of our next closest competitor. This leading position in the play has been well established through our first mover advantage. That advantage has given us unmatched signs and scale in the play.

Since 2001 with our acquisition of Mitchell, we built at least positioned of over 735,000 acres with very favorable lease terms. Devon has an average royalty burden of under 20% on these leases. This compares to our royalty burden on most leases taken in the Barnett over the last several years of 25% or greater. The economic impact of a lower royalty burden is dramatic. On a typical 2.5 BCF Barnett well drilled for about $3 million in a $6 per MCF realized gas price environment , a well with a 20% royalty burden has about 1.4 times the present value of a well with a 25% royalty burden.

A large portion of our acreage is concentrated in the better areas of the play. such as the core area in Johnson County. Accordingly, we have a superior acreage position and years of additional drilling inventory in the better portions of the play. Our history of being the first to identify new applications of technology has been well established since the beginning. Devon was the first to unlock the early potential of the play with light sand tracks and horizontal drilling. While all of the major operators in the play have the same drilling and completion services available to us, the various operators choose to complete wells differently. Various lateral lengths and number of track stages can impact IPs per well, recoveries per well and ultimately, well economics.

Rather than focus on maximizing per well production or reserves, Devon has chosen to optimize return with our well designs. We now have 3,000 wells in the play and we're drilling at a rate of over 500 wells per year, by far the largest in the play. This scale allows us to establish an in depth knowledge of the reservoir as well as very strong long-term relationships with the leading drilling and pumping service providers in the country, proving reliability, performance and value.

We have been asked recently if we plan to integrate vertically in the play through the purchase of drilling rigs or completion-related assets. It's always been our view that it's best to allow the specialists to do what they do best while our team stay focused on combining innovation and our deep understanding of the Barnett shale to deliver the best value growth in return for shareholders. These relationships has allowed Devon to hold our well cost flat over the past year despite the cost escalations experienced by our industry over the same period. We accomplished this while ramping up activity from 385 wells in 2006 to over 500 wells this year, growing our production 32% compared to the third quarter of 2006. Devon will keep its focus on maintaining the lead position in the play with the best acreage position, the best lease terms and the most consistent execution and will provide an early achievement of our 1 BCF per day goal.

During the quarter, we completed a total of 127 Barnett wells, 50 of which were in the core and 77 were outside the core. We remain on pace to drill 500 wells in the Barnett shale this year and we are running 32 Devon-operated rigs,

nine in the core area and 23 outside the core. Our non-core drilling program in Johnson County continues to shine. In the third quarter, we put 39 new wells online in Johnson County at an average rate of 2.9 million cubic feet per day. For particularly strong wells, each had 24-hour sustained additional production rates averaging above 5 million cubic feet per day. North of Johnson County and Southern Wise County, we bought two exceptional wells online at 5.4 and 6 million cubic feet per day. We continue to see solid results from our non-core horizontal drilling with typical yields between 1.5 and 2.5 BCF per well with some as high as 8.4 BCF.

In addition to expanding the play in new directions, an important part of our activity in the Barnett shale is infield drilling or down spacing in areas that have already been fully developed on primary spacing. These infill wells are usually referred to as 20-acre infill wells. However, I will remind you that. with horizontal drilling, one well can replace several 20-acre vertical well locations. Consequently, from a surface development prospective, 20-acre infill horizontal well actually occupies 80 surface acres. Since we began this horizontal infill program, we've completed a total of 139 of these infill wells. A total of 127 that have been connected to the producing grid are horizontal with average initial production 2.2 million cubic feet per day. Economics from the horizontal infill wells we've drilled to date are very solid at an average drilling incompletion cost of about $2.9 million and approximately 2.1 BCF per well estimated recovery.

In addition, we've been experimenting with further horizontal down spacing. We have completed a total of 11 operated wells that are spaced to result in two wells per 80 acres or 40 surface acres per well. Seven of these have been tied into production with an IP of $2.5 million per day. This down spacing is one of the ways we expect to convert into proved reserves more of the 13 trillion cubic feet of potential represented by Devon's 735,000 Barnett acres. While we are very encouraged by these early results, we'll need to see more production date before developing large areas based on one horizontal well per 40 acres.

In the Woodford shale in eastern Oklahoma, we currently have five operated rigs drilling in the play. We bought a total of eight new operating well online during the quarter with individual well production rates as high as 40 million cubic feet of gas per day. We now operate 46 wells in the Woodford with gross operated production running about 38 million cubic feet a day. Our net Woodford shale production averaged 20 million cubic feet per day in the third quarter up almost 70%. compared with the third quarter of 2006. On the average, our Woodford shale wells are costing between 4.1 and 4.3 to drill and complete and yielding about 2.5 BCF od reserves per well.

Moving to the Rockies and the Washakie Basin in Wyoming, we had five rigs running throughout most of the third quarter. During the quarter, we drilled 16 wells and bought 15 on production. Devon's net production at Washakie averaged to about 100 million cubic feet per day in the quarter.

Shifting to east Texas, we continued with a 7-rig vertical Cotton Valley drilling program in the Carthage area. In the third quarter, we drilled 25 vertical wells and continued an active recompletion program. At the end of the quarter, we were drilling the 66 well in a 95-well vertical program that is planned for this year. Looking forward, we have a significant drilling inventory with as many as 420 additional vertical locations available including about 65 20-acre infill locations.

We also continue to see good results from our 3-rig horizontal drilling program in the Carthage area. We drilled and completed five new Cotton Valley horizontal wells during the quarter including the 100% working interest at [Davis Ford H] well that averaged 6.6 million cubic feet of gas per day for the first 30 days of production. Since we first tested the horizontal drilling concept in the Carthage area about one year ago, we've drilled 11 out of 11 successful horizontal wells. These wells cost from $5.5 million to $7 million per well to drill and complete with estimated ultimate recovery of 3 to 6.5 BCF per well. We have as many as 96 additional horizontal locations to drill at Carthage.

In total, our net Carthage production averaged $260 million cubic feet of gas equivalent per day for the third quarter up 5% from the second quarter average and up 8% from a year ago. With a lot of running room for both the horizontal and vertical well programs, we believe we can continue to grow Carthage production well into the future.

Shifting to the Gulf of Mexico and our deepwater production operations, we established production from these two subsidy wells at Merganser in the third quarter. These gas wells are flowing into the independent hub and are currently producing at a combined rate of more than 68 million cubic feet of gas per day net to Devon's interest. This rate is 36% better than our forecasted rate, so we're obviously very pleased with yearly performance of these wells.

In our deepwater and [sea] exploration program, we expect to begin drilling on the [Sturjus] north prospect located in Water Valley block 138 in early 2008. We made an initial discovery at Sturjus in 2003, encountering over 100 feet of net oil pad. Sturjust north is located adjacent to the Sturjus discovery but we'll test to separate geologic structure. Devon has a 25% working interest in the Chevron-operated prospect.

Our lower tertiary exploration program was in full swing during the quarter. Early drilling on our Chuck prospect located in Walker Ridge 278 has gone slowly as the Ocean Endeavor rig was being debugged by Diamond Offshore . We believe that most of the start-up issues have been resolved. We're currently drilling below 21,000 feet. Chuck is targeting a large subsold structure in about 6,500 feet of water, and Devon is the operator of Chuck with a 39.5% working interest. We expect to begin drilling an exploratory well on the Green Bay prospect around year end. This lower tertiary exploration prospect is located on Walker Ridge 372 in approximately 6,300 feet of water. The prospect is about 20 miles north of the Saint Malo discovery and about 18 miles east of the Chuck prospect. Devon has a 23.4% interest in Green Bay.

We are continuing with appraisal and development activities on the four significant lower tertiary discoveries which we participated in to date. Last quarter, we began drilling a location on our Kirkley Canyon Block 244 in the Cascada unit. This location, previously known as Cortes Bank is located about 12 miles west of our 2006 Cascada discovery. The well was drilling in a side track hold to a proposed depth of 33,000 feet when mechanical issues forced the well to be abandoned before reaching the target objective. While it's always a disappointment to spend capital on a well that fails to reach its intended objective, this result does not dampen our enthusiasm for the unit. The Cascada discovery well clearly encountered a very significant oil column and we have a lot of work left to do to fully understand the potential of the unit. The joint owners are now integrating the results from the two wells along with seismic data to determine our next location in the unit. Devon has a 20% working interest in the unit which is operated by BP. The next well operation is expected sometime in the first half of 2008.

At Cascade, our lower tertiary development with Petrobrass in the Walker Ridge area, we sanctioned development during the quarter. We have submitted operating and development plans to the MMF and we have awarded the FBS one of our shuttle tanker contracts. We now anticipate initial production at Cascade to likely be in the first half of 2010. Our approach to development in Cascade will allow us to produce the first wells over a sustained period. Reservoir information gathered during that initial period phase will help us determine the optimum number and placement of producing wells and allow optimization of full field facilities for the project. Devon and Petrobrass each have 50% working interest at Cascade.

At Jack, also in Walker Ridge deepwater lease area, Devon and our co-owners expect to finish drilling operations on a second delineation well, the Jack Number 3, in the first half of next year. The well will be operated by Devon and drilled with the Ocean Endeavor rig.

Finally, at St. Malo, also in the Walker Ridge deepwater area, we are currently drilling our second delineation well and we hope to have the results in the first quarter of 2008. These additional Jack and St. Malo wells will provide important data that will help the partners determine the optimum development approach to these discoveries. I will remind you that Devon has a 25% working interest in Jack and 22.5% working interest in St. Malo.

Moving to Canada, about midstream oil play in Alberta, we've increased production by over 50% over the past 12 months to 34,600 barrels of oil per day. We continue to have an active 5-rig program in the quarter as we drill 125 Lloydminster wells. The second 10,000 barrel a day expansion at at our Manatokan plant is underway and we expect to complete that work by the end of 2008.

At the Devon-operated Jackfish thermal heavy oil project in eastern Alberta, we began steam injection in the third quarter. We're wrapping up final pre-commissioning activities and expect to see first production from Jackfish around the end of this year. As previously indicated, production will then ramp up toward an expected sustainable rate of 35,000 barrels per day.

At Jackfish 2, engineering and budgeting work continue and we expect to receive regulatory approval around mid-2008. At that point, we'll make a formal decision about the project. This project would add another 35,000 barrels a day of thermal oil.

Moving to the international arena, development drilling at the Devon-operated Polvo project on block BMC8 in Brazil continued during the third quarter. We achieved first oil on July 26th and has completed first three of a total of ten plan producing wells which reached a combined gross rate of 9,500 barrels per day. The field's first lifting of 385,000 barrels occurred on October 21st. The fourth well is currently drilling. The additional wells will be drilled and tied in throughout the remainder of this year and into 2008 as we ramp up the field's production.

In Azerbaijan, where Devon has a 5.6% working interest in the ACG oil field, our share of ACG production averaged to about 28,000 barrels per day in the third quarter. As expected, there were about 17 days of down time at ACG in the third quarter to perform facility upgrades to both offshore and onshore infrastructure. Field production has since been brought back on line.

In China, we expect to drill our Watermelon prospect located on block 4205 in the first quarter of 2008. You might remember, block 4205 is adjacent to block 2926 where Husky [Sinuk] announced a multi PCF gas discovery. However, this well has all the typical risks of an exploration well. Devon operates block 4205 with 100% working interest. That concludes my comments on our operational highlights for the quarter. I'll now turn the call over to John to review our financial

Thank you, Steve and good morning, everyone. This morning, I will take you through a brief review of the key drivers of our third quarter financial results and take a look at how they impact our outlook through the remainder of the year. You can find the details of our updated forecast in the form 8K that we'll be filing today as Vince mentioned earlier. As a reminder, we've reclassified the assets, liabilities and results of operations in Africa, discontinued operations for all accounting periods presented. As a result, I'll focus my comments only on our continuing operations which exclude the results attributable to the divestiture properties.

Let's begin with production. In the third quarter, we've produced 56.8 million equivalent barrels or approximately 618,000 barrels per day. This exceeded our guidance by about 3% or nearly 2 million barrels. Approximately 3/4 of this outperformance was due to better than expected results from several of our core properties in North America and the remainder of the outperformance was attributed essentially to the absence of anticipated down time for hurricanes in the Gulf of Mexico and the postponement of plan facilities repairs that are offshore Panyu project in China. Thankfully, we've had an uneventful hurricane season and the repair work at Panyu is now scheduled to begin in the fourth quarter of 2007.

When you compare our third quarter results to the same quarter a year ago, you'll find that company-wide production increased by 10% or approximately 55,000 barrels per day. This reflects year-over-year growth in our U.S. onshore, Canadian and international segments. Production from the U.S. onshore region grew by nearly 40,000 barrels per day or 12% when compared to the third quarter of 2006. Continuing a trend, the leading driver of our U.S. onshore performance was strong production growth from our Barnett shale assets. We also experienced significant growth in the international sector almost entirely attributable to increased production from the ACG field and Azerbaijan.

In Canada, total third quarter production increased 2% over the third quarter of 2006. This was achieved in spite of significantly scaling back on our Canadian conventional natural gas program. Growth in Canada was driven principally by drilling on our Lloydminster oil properties.

Looking ahead to the fourth quarter, we expect to grow company-wide production for a seventh consecutive quarter. In total, we anticipate fourth quarter production of approximately 57 million equivalent barrels. The growth drivers will be our U.S. onshore assets, a full quarter of production from Merganser and Polvo and an uninterrupted quarter of production in Azerbaijan. However, this growth will be offset somewhat by the rescheduled down time per equipment replacement in China along with the anticipated declines from our conventional gas fields in Canada. Based on strong performance for the first nine months coupled with a bright fourth quarter outlook, we are now increasing our full year production forecast to 223 million equivalent barrels. This will add another percentile to the 10% year-over-year growth target we had previously forecast for 2007.

Although we expect to finish 2007 ahead of our previous production forecast, we're not increasing our guidance for 2008 at this time. We typically finalize our capital budget in the fourth quarter and submit it to our Board of Directors in December for approval. Following Board approval, we provide updated production guidance. Until we complete the budgeting process and determine the optimal level for our 2008 capital spending, we'll stick with our previous forecast for 2008 of 240 to 247 million barrels equivalent.

Moving onto price realizations starting with oil, in the third quarter, the benchmark WTI oil price rose to an average of $75.21 per barrel. That's a 16% increase from the second quarter of 2007. In addition to higher benchmark prices, regional differentials remain tight with the result of price realizations in all of our producing regions where we are above the mid point of our guidance ranges. Our company-wide realized price came in at $67.41 per barrel or about 90% of WTI. That's a 12% improvement in realized prices over the last quarter. Although differentials have widened recently for heavy and sour crudes as benchmark prices have increased, we're still comfortable with our full year guidance for oil price differentials. I'll remind you that since none of our oil volumes are hedged, we are benefiting from further increases in oil prices that we're seeing in the fourth quarter.

On the natural gas side, the benchmark Henry Hub index averaged $6.16 per MCF in the third quarter, some 6% below last year's third quarter. Our company-wide gas price realizations were generally in lined with guidance at approximately 86% of Henry Hub. Wrong price realizations in the Gulf of Mexico and in Canada were mostly offset by continued price weakness within the Rocky Mountain producing area. You're probably aware that the price differentials in the Rockies have widened significantly over the past several months due primarily to constrained regional export capacity. The impact on Devon, however, has been limited because the Rockies represent less than 10% of our company-wide natural gas production. Looking ahead to the fourth quarter, we expect natural gas price differentials to be very similar to the third quarter.

Turning now to our marketing and midstream business. Once again, marketing and midstream operations delivered excellent results. Marketing and midstream operating profit for the quarter came in at $133 million, $21 million more than in the third quarter of 2006. The increase is due to higher gas processing margin in the 2007 quarter. Based on the strength of the first three quarters, we're again increasing our 2007 operating profit forecast. We now expect Devon's marketing and midstream full year operating profit to come in between $460 and $490 million. At the mid point, this represents an increase of $35 million from the mid point of our previous guidance range.

Moving to expenses. Third quarter lease operating expenses were at the low end of our guidance range coming in at $457 million or $8.04 per equivalent barrel. This was essentially flat to our average LOE rate for the first half of the year. For the quarter, unit LOE costs remained steady or decreased in most of our major operating regions with the exception of Canada. In Canada, LOE remains under pressure from the strength of the Canadian dollar.

In the fourth quarter, we expect a moderate rise in LOE cost due to new development projects ramping up production and also a seasonal increase in operating costs in Canada. For the full year, we expect lease operating expenses to be near the top of our previous guidance range. Our reported third quarter DV&A expense for oil and gas properties came in at $12.41 per barrel. This was 16 cents above the high end of the guidance range we provided in our second quarter conference call. The higher than anticipated depletion rate is entirely due to low spot gas prices in the Rockies at September 30th. This resulted in temporary reduction in reserves for the calculation of depletion. We expect the situation to correct itself in the fourth quarter and accordingly, we expect our DV&A rate to return to where it otherwise would have been. However, due to the higher than expected rate in the third quarter, we now expect our full year DV&A rate to come in near the top of our previous forecast range.

Moving on to G&A expense. G&A expense for the third quarter was $126 million. This result is a couple of million dollars above the quarterly range implied by our full year forecast and $13 million higher than last quarter. Higher employee related cost was the primary driver. Looking ahead, based on our year-to-date results and in anticipation of continued operative pressure on personnel costs, we're increasing our full year G&A guidance by $30 million to a new range of 490 to $510 million.

The final expense item I want to touch on is income taxes. After adjusting out the items that are generally excluded from analyst estimates, income tax expense for the third quarter came in at 33% of pretax income. The current tax position is roughly 10% of pretax earnings and the deferred tax piece came in about 23% of pretax earnings. This brought the adjusted income tax rate for the first nine months of 2007 to 32% with half current and half deferred. The 32% overall income tax rate with roughly half deferred reflects our expectations for the fourth quarter and full year 2007. In today's 8K, we're providing updated guidance that reflects the lower percentage of taxes that are classified as current.

After backing out income tax expense, our reported earnings from continued operations for the third quarter totaled $644 million or $1.43 per diluted share. Earnings from discontinued operations added another $91 million or 20 cents per diluted share in earnings. In aggregate, after backing out the items that are usually excluded from analyst estimates, our estimates are adjusted net earnings for the third quarter were $700 million or $1.55 per diluted share. This translates into cash flow before balance sheet changes for the third quarter of $1.8 billion bringing the total year to $5 billion.

We used cash flow to fund third quarter capital expenditures of about $1.6 billion leaving roughly $200 million of precash flow for the quarter. We used the majority of this precash flow to return more than $180 million to shareholders through share repurchases and dividends. We also received $106 million of exchange requests related to our Chevron exchangeable [debenchers] and we chose to retire those obligations with cash rather than to redeem them with the Chevron shares that we hold.

Even with the redemption activity, we concluded the quarter with a healthy cash balance of $1.7 billion and with our net debt to capitalization ratio under 20%. Looking forward, we expect cash flow from operations to roughly cover our capital demands. This will leave us with after tax proceeds from the African divestitures to repay short-term borrowings and to continue to repurchase our stock. All in all, this was another outstanding quarter for Devon. With that we'll open the call up for Q&A.

Operator, we're ready for the first question

Thank you. We'll now begin the question-and-answer session. (OPERATOR INSTRUCTIONS). Our first question comes from Brian Singer from Goldman Sachs.

Thank you, good morning. Question on Canada, if you look at your overall portfolio beyond Canada, what area do you see that has the greatest combination of opportunity and capacity to take capital should you further reduce drilling in Canada or would you look toward the acquisition market in part?

Brian, this is Steve. We have, as you mentioned, a very deep portfolio. Mainly where we would look is in the U.S. onshore business. John mentioned that strong 12% growth that we've seen happening in that aspect of the business and we would probably redeploy it into areas, like we have in the Barnett where we're now drilling 500 wells where we initially estimated we would drill 385 at the beginning of this year. We have good opportunities in the Carthage area and some of the east East Texas areas. So generally those are some examples of the areas that give us some of that swing. The U.S. onshore is a good opportunity for us.

I will mention that within Canada, we have both a very viable thermal oil business, but we also have the Lloydminster area and some very good cold flow heavy oil opportunities that I think you've heard earlier in our comments, that we've been able to grow about 50% year-over-year. Within Canada, we have a pretty good portfolio in Canada that allows us to redeploy capital within Canada away from maybe some of the lower returns we may be seeing in the Canadian conventional gas business into the very good and solid returns that we get in the Lloyd area. So, we can optimize within Canada first and then as we look across our portfolio, we have other areas where we can go deep for that near term growth.

Yes. This is Larry, I might add that within Canada, you need to realize that the royalty rights are different between oil and gas and they are different between different types of gas and different types of oil, and a lot of those are sliding scale type royalties. So it's a fairly complicated situation that can result in that reallocation within Canada.

Absolutely. Shifting to the Barnett, based on the strong results that we've seen, it would seem you could reach your 1 BCF a day target a little earlier than early of 2009. Do you feel that you are conservative there? Do you see any constraints in bringing wells online? And following up on the previous question, what do you think is your capacity to drill in the Barnett in terms of a number of wells per year?

We're very comfortable with where we are now. We're about 32, 33 rigs in the Barnett. That's probably an activity level that we would feel good at. At that rate, we drill about 500 wells a year and as we look forward, we're not having, as a matter of fact, if you look in the history over this year, our inventory of wells that we hooked up for instance has actually gone dramatically, it needs to trend downward. Even with that accelerated rate, because of our very strong midstream presence, the good partnership we have with cross tax and the relationships that we have in the field, we've been able to operate at this high level of accelerated activity pretty comfortably.

As we look forward to the BCF a day, we're going to continue to do the right things for value and for return. We are going to really want to take a close look at that as we go in through our budgeting process which we're in right now. We'll probably have a little clearer picture when we get that BCF a day, in time, maybe in December or January. I might add that the BCF a day is of course not the peak rate that we foresee out there. We're working through it on our budget for that process. It was merely the target that we picked which at that time seemed pretty aggressive, but we're clearly way ahead of schedule. There's additional growth on beyond that and after that.

Thank you.

Our next question comes from Tom Gardner from Simmons and Company.

Good morning, guys. Larry, I appreciate your comments concerning the difficulty, working your way through the Canadian royalty change.

We're having trouble hearing you, can you speak up?

Yeah, sure. I'm sorry, I believe one of the [other's] microphones cut out as well. But with regard to Canada and the royalty change there at Jackfish, any idea of the long-term implications to thermal [Sagdee] development in Canada? What oil price is required now for economic return there for Sagdee thermal?

Tom, this is John Richels. As you know, forecasting the oil price we need in order to optimize the returns from the thermal heavy oil project is really difficult because there are many variables. Oil price, natural gas price, since we're burning natural gas to create steam, there's the differential which s an important aspect of it, the cost the [unintelligible] and the transportation costs, and they all move in different directions. If you tell me what the oil price is and we can factor in some of those other variables, we can come up with that. That varies a lot, so that's a tough question to answer.

As far as royalty effect in Canada, I think there are two things that are important to realize. As Larry pointed out and Steve did, the royalty effect is variable among different kinds of assets in Canada. When we look at our Jackfish 2 project, our initial view of the legislation or the proposed royalty changes doesn't change the returns on that project materially. Had the royalty review panel recommendations been enacted, it would have, but the way it's now been proposed, it doesn't change it a lot. Frankly, the project remains sensitive to capital costs, foreign exchange rate and all of the other things that it previously did. The good thing about our Jackfish 2 project is we did some things with Jackfish 1 that will create some benefits for Jackfish 2 if we go ahead with it. Most notably the access pipeline so that the cost of the access pipeline was rally taken into consideration in Jackfish 1 and Jackfish 2 will benefit from it. Preliminary look or a preliminary view of it is that that project still looks pretty good and we're still doing all of our engineering and capital analysis of that project and we'll probably make a decision on that in the middle of next year.

Just using the normal relationship between oil and gas prices, can you bracket the oil price required for the thermal project? I mean is it--

You know, what we've used in the past, Tom, it was interesting, when we approved our Jackfish 1 project, when our board took a look at it, oil was $24.50, the differential was $7.50 gas price was roughly $3 and the return was about the same as it was a year ago when we looked at it again, and we're kind of doing a look back into the project, halfway through the construction of it. At that time, oil was $63, the differential was 23 and gas was $7. They had about the same return. So the relationship that we think is the most important is the relationship between WTI and the Lloyd heavy with a differential about 30 to 33% of WTI. That's the kind of differential that you need and frankly, we think that given that differentials have historically been in that 30 to 33% range, we think that over the long-term, that's where they'll settle because either third party processors will move and refiners will move into that space or if they don't, the EMP sector will continue to move into that space to get the differential to that level at which you can make a real good return on the upgrading side.

How are the economics of the thermal different from those who are mining the oil stands in Canada? Would you think that the mining is more cost-challenged or less?

I'm sorry, I couldn't hear that, Tom.

I'll speak up. There must be some problems with the line here. But, just comparing thermal with mining oil stands in Canada, how would the economics compare between the two?

Well, they're very different obviously because in the mining projects in operating gas first of all, it's a completely different equation. Also, all of those mining projects have an upgrader attached and are producing a quality of oil that trades up with, or sometimes above WTI as you know. So I think that without getting into all of the details, it'd take a lot of time on it, there are just very different types of projects.

Okay. One last question, moving over to the Gulf of Mexico, regarding the decision in the MMS royalty case. Did Devon agree to the royalty threshold and do you stand to benefit from the recent federal court decision on royalties?

The federal recent court decision was at the federal district level. It's not a surprising decision at all because if you read the legislation that Congress enacted that provided some royalty relief for the expensive deepwater, there is a plain reading of it. It shows that there is no real authority for the MMS to do what they tried to do. Therefore, we were not the least bit surprised that the federal court dispatched with that case in a fairly short summary argument. But that's just a district court. We'll wait and see what happens, whether it's appealed and if so, whether appellants or court rulings are. And gentlemen, I might go back to the comment on heavy oil. Even within steam-assisted gravity drainage projects, there is a wide variety of cost that those projects can incur. They're not all one cost structure, but we're happy about it in Jack, while we're proceeding on it, is among heavy oil projects, it is a very high quality, low cost project relative to many others.

Thanks guys.

Our next question comes from Gil Yang from Citi.

Good morning. Could you talk, Steve, a little bit about the acceleration of Barnett. Obviously, you said that you're drilling more wells. But is there some, and obviously you drilled some good wells as well, how much would you say the acceleration is due the increased activity level versus the better performance of the wells? And then, with respect to better performance, is it not only IPs, but are the decline rates doing anything unusually positive for you? Hello?

Sir, your line is open for your question.

Yes, can you hear me? Can you hear me?

Can you hear us, Gil?

No, I can't hear you I can barely hear you. All right. I can hear you a little bit.

Can you hear us now?

Yes, a little bit.

Okay. Back on the question on the Barnett shale, it's actually both things driving the acceleration of our activity. If you remember back in about a year, year and a half ago, we were running a lot of seismic getting some good processing and really going about better characterizing the non-core areas so we can get good solid repeatable results with our wells. We've also had some process improvements on the drilling side that allowed us to reduce our drilling days so we actually get more wells per rig. And we are getting better results. That's partly driven by those factors. So as we've built up our confidence in really being able to deliver a repeatable and improved results on average, we've continued to accelerate the program.

An aspect of the drilling activity that we have is the 20-acre infill. Those 20-acre infill wells, I think we started it off at about, estimating about 1.7 BCF per well when we initially talked about the 20 acres when we were in a pilot stage, I think you saw now, we're about 2.1 BCF per well with the larger program that we're drilling. And again, those are areas where we can even go back into the core and drill those types of wells. So we're seeing improved performance, part of it is reservoir characterization, part of it is the drilling efficiency that we're gaining and part of it is the integration of that reservoir characterization with our completions. So those factors are all driving the ramp up that we have from about 385 wells to the 500-well activity level.

Okay, thanks, that's helpful. Have you seen any change in the decline rates?

No, not materially. We're still looking at about the same exponents. Of course, we continue to monitor performance and that's how we make our reserve estimates and we're pretty happy and comfortable where we are right now with those decline rates that we have. .

Okay and can I ask the same question for Merganser? Those wells are out performing? Is it just greater permeability? Are the reservoirs larger than you thought? And what's going on there?

I think you probably know, Gil, when we drill these wells, we get a lot of static information, in other words, we can look at core information, we can look at log information, of course, our engineering and geologic teams make estimates of what we think those wells can flow and it's basically on a risk basis to actually see how the well would perform. Some of these larger intervals will perform under dynamic flow. You actually have to flow the well. I think we're simply seeing better performance as it relates to our risk estimate of what the permeability and the contribution of the well would be.

Do you have any indication yet that the reservoirs are- that there's no concern that they are compartmentalized in any fashion ?

It's still too early to really make other definitive conclusions on that since it's still early in the production life. We haven't seen anything negative to date.

Okay, thank you

Our next question comes from Ross Paine from Wachovia Capital Markets.

Hello, can you hear me?

Yes.

Yes, this is Jeff Hoffer for Ross Paine. I was just following up on the Barnett shale. Just looking at, what is the average well life you have there and as you look to potentially deployed additional cash flow to the area, how would you characterize the cost environment that you're facing in the region?

Okay, let me, Jeff, let me take the first issue first. As we look at the life of these wells, these are wells that initially come on and have a pretty good decline rate initially. Then they go in what we call exponential. So they begin to flatten out in their production profile. Some of these wells, you can estimate them to produce for as long as 40 years. The well lives can be very, very long.

If you look at terms of our cost environment, we're actually, we've actually seen the cost of our wells, year-over-year basis, remain flat. That's driven by the drilling efficiencies that we've been able to gain and partly by some of the softening in the acceleration of cost escalations that we have seen starting in about early 2005 and through 2006. From a cost standpoint, we're very comfortable in the environment that we're in. The average well is going to be around 2.7 to about $3 million a well and we're getting about 2.5 BCF on average out of each well.

Okay, thank you.

Our next question comes from Mark Gillman from Benchmark.

Guys, good morning. Can you hear me?

Yes.

A couple things, Steve, if you wouldn't mind. First, I think when you were discussing Chuck, you talked about a side track hole having ran into mechanical problems, what about the original hole?

Actually, Mark, that was on the Cortes bank well. The well we were drilling in the Cascada unit.

I'm sorry, Steve.

We were in the process of side tracking to gain some more reservoir information. The initial well we drilled to its total depth and we're in the process of looking at that information and working through that information. The side track that we had was a distance away from the original hole. We were trying to get some more reservoir information, but we didn't reach the objective and are disappointed with that, but we're still very excited about the Cascada unit.

Okay. With respect, Steve, to Cascade, do you have any numbers in terms of development cost, reserve numbers and estimated production?

No, I don't think we've put that out yet, Gill.

Okay. It looks as if on a pro rota basis that the performance of the first three wells doesn't necessarily get you to what the plateau estimate was. Is that evaluation premature?

Yes, we think it's premature to draw that conclusion. You know, on the first initial wells, we're drilling in the [Makka A] carbonates and we're, those carbonates can be a little bit tricky over time and you can have some variability. We're still very early in the drilling program. We have seven more wells to drill and we're still sticking by about that 50,000 barrels a day. If that changes once we we get a few more wells under our belt, we'll let people know.

Okay, Steve. And finally, with respect to Carthage. If I recall correctly, the last conference call you were talking about actually pulling back a little bit in terms of the drilling program as you better assessed horizontal performance. Now, you're moving to rig count back up to 13. What's really changed?

Yeah, Mark, actually in east Texas, the area where we were having problems was looking at the Groesbeck area and we were having some mechanical problems in getting into the full extent of the horizontal section and making sure that we had the completions going off and getting them, the numbers of stages of tracks that we wanted to have in the horizontal sections. We've had a very good effort with a team of people working on that. We actually have had some pretty good results. We bought one well on in the Groesbeck area, it came on at about 17 million cubic feet a day in the [unintelligible] field. So you can probably see us begin to ramp that back up as we move into 2008. On Carthage, that's been working very well. We haven't had any of the mechanical problem and we're continuing to run three horizontal rig lines as we continue to move forward with that horizontal program.

Okay, Steve, thanks a lot.

You're welcome, Mark. Operator, we'll take one more question and then we'll terminate the call.

Thank you. Our last question comes from David Hakanen from [Tudor Pickery.]

Just a follow-up. Volume lifted at Polvo in October?

The number was 385,000 barrels.

And then a schedule for liftings from here forward?

Right now, we have another one scheduled in December.

Okay and just a reminder on the production sharing contract at ACG, volumes versus oil price and how that works looking forward to today's oil prices.

Yes. It's a pretty complex PFC but the bottom line is as the oil prices get higher, we're going to have less cost oil coming to the contractor. And as we reach different payout traunches, as we reach different return traunches, we will have a drop in our nets. It's affected by oil price both on the net that we take and the cost of oil that we recover as prices go higher.

Yes, Vince. If I remember correctly, this is kind of a broad brush recap, we'll go through two traunch reductions in the next nine months or so that will reduce our net take to about half of the current level and then we really expect flat production for a long time thereafter.

That's perfect then. Thank you.

Okay, just a quick recap of the quarter. It was an excellent quarter again. Operationally, we delivered growth from our core development projects, we continue to see very promising results from our long-term exploration program. Our organic production growth at 10% over last year's third quarter positioned us to raise our 2007 production forecast which of course would in turn, lead to higher growth over 2007, over 2006. All of this leads to increases in revenues and earnings in cash flow. Divestiture program moving forward. We expect to be positioned to fully fund our capital needs, repay debt and repurchase stock in the year ahead. In summary, we're very happy with our continued high level of performance and think we're very well positioned for the future. Thanks and we'll talk to you again in February. Take care.