Devon Energy Q3 2007 Earnings Call Transcript

| About: Devon Energy (DVN)

Devon Energy Corporation (NYSE:DVN)

Q3 2007 Earnings Call

November 7, 200711:00 am ET


Vince White - Vice President, InvestorRelations & Communications

J. Larry Nichols - Chairman of the Board, Chief ExecutiveOfficer

Stephen J. Hadden - Senior Vice President - Exploration andProduction

John Richels - President, Director


Brian Singer - Goldman Sachs

Tom Gardner - Simmons & Company

Gil Yang - Citigroup

Joe Hofer - Wachovia Capital Markets

Mark Gilman - The Benchmark Group

David Heikkinen -Tudor, Pickering & Co.


Welcome to Devon Energy’s third quarter earnings conferencecall. (Operator Instructions) I would like to turn the conference over to Mr.Vince White, Vice President of Communications and Investor Relations. Sir, youmay begin.

Vince White

Thank you, Operator and good morning to everyone. Welcome toDevon's third quarter 2007 conference call and webcast. Today’s call willfollow our standard format; that is, starting with our Chairman and CEO, LarryNichols, who will provide his perspective on Devon and the quarter; andfollowing Larry, Steve Hadden, our Senior Vice President of Exploration andProduction, will cover the operating highlights; and then Devon's, John Richels,will conduct the financial review.

As usual, we will open the call up to questions and we willtry to hold the call to about an hour.

A replay of the call will be available later today through alink on our website. That is We will also be posting to thewebsite a new issue of Devon Direct. That’s our electronic report that includeshighlights from the webcast and includes links to supplementary information.

During the call today, we are going to update some of ourestimates based on actual results for the first three quarters of the year andour outlook for the balance of the year. In addition to the updates that we’llprovide in today’s call, we plan to file a Form 8-K later today and that willdocument all the details of our updated guidance.

Also, please note that the references in today’s call to ourplans, forecasts, estimates and so on are forward-looking statements as definedby U.S.securities law. There are a number of factors that could cause our actualresults to differ from those estimates, so we would encourage you to review thediscussion of risk factors that accompany the estimates in the Form 8-K.

One other compliance note; we will make reference today tocertain non-GAAP performance measures. When we use these measures, we’rerequired by securities law to provide certain related disclosures. You can seethose disclosures. They are available on our website. Again, that’

Finally, I want to remind you that our decision to sell ourassets in Africa triggered the discontinued operations accounting rules. Underthose rules, we exclude oil and gas produced from the assets selected fordivestiture from reported production volumes for all periods presented. The relatedrevenues and expenses for the discontinued operations are collapsed into asingle line item at the bottom of the statement of operations.

However, in the spirit of full disclosure, you will find anadditional table in today’s news release that includes a detailed statement ofoperations and the related production volumes attributable to the propertiesthat we are divesting.

I also want to point out that net earnings from discontinuedoperations were $91 million in the third quarter. However, that does not meanthat the discontinued operations would have contributed the full $91 million ofadditional earnings if we were not selling them. That’s because the accountingrules for discontinues operations require us to stop recording depletionexpense on the sale properties once we make the decision to divest them.

Had we not chosen to exit Africa, we would have reported netincome associated with the divestiture properties of $66 million, or $25million less than the $91 million of income from discontinued operations forthe quarter.

Accounting for these discontinued operations alsocomplicates the comparability of earnings estimates. Most of the analysts thatreported estimates to First Call this quarter excluded the impact of thediscontinued operations. The mean estimate of earnings per share from theanalysts that excluded it was $1.39 per share. That compares to our non-GAAPearnings from continuing operations of $1.41 per share.

The mean estimate for analysts that included discontinuedoperations in their estimates was $1.47 a share, and that compares to ournon-GAAP diluted earnings of $1.55 per share for the third quarter, includingdiscontinued operations. So in either case, our non-GAAP earnings beat thestreet expectations.

With those items out of the way, I will turn the call overto Larry Nichols.

J. Larry Nichols

Thanks, Vince. The third quarter was another excellent onefor Devon. We made progress both from an operational standpoint, a financialstandpoint, and some important strategic actions, of which I’ll comment on in amoment.

For the third quarter, oil and gas production exceeded ourexpectations and our guidance. Our production grew 10% over the third quarterof 2006, which provides us with our sixth consecutive quarter of organicproduction growth.

We outperformed our third quarter forecast by nearly 2million equivalent barrels, which allows us to increase our full yearproduction forecast. John Richels will discuss the drivers of this productionoutperformance and the revised guidance in a little bit.

The financial results for the third quarter were also verypositive. Net earnings were $735 million and earnings per share exceeded streetexpectations, both with and without discontinued operations.

Cash flow before balance sheet changes increased 15% to $1.8billion, bringing the year-to-date cash flow to $5 billion. We funded totalcapital expenditures of $1.6 billion and we repurchased 120 million shares ofour common stock and ended the quarter with $1.7 billion of cash and short-terminvestments. We ended the quarter with net debt to adjusted cap at its lowestpoint in 10 years at 19%.

Following the end of the third quarter, we moved forwardwith our Africa divestiture program by closing the sale of the Egyptian operationsin early October. As of the closing date, the adjusted sales price was $341million, and we do not expect to pay any income tax on this transaction.

We are finalizing purchase and sales agreement and gettingthe necessary partner and governmental approvals for the remaining Africanassets. Although the process has been complicated and time consuming, we areoptimistic that we can complete all of these transactions by the end of thefirst half of 2008.

In today’s release, we’ve provided an update on ourpreviously announced MLP, our master limited partnership. As noticed in therelease, we have reconsidered our plans to form a marketing and midstream MLP.This decision reflects our views about the current condition of the publicmarket for yield-driven instruments. The market today is just less receptivethan it was when we announced our plans, so we are putting that project onhold.

With Devon's marketing and midstream business generatingmore than $450 million in operating profits, we believe it is prudent to bevery cautious with any decision affecting this important and strategic part ofour business. Although we have no firm timeline for revising the project, wewill reconsider it in the future should market conditions change.

Before I turn the call over to Stephen Hadden, I want toshare with your our perspective on the royalty situation in Alberta. As youprobably know, in late October, the Alberta Government announced a change inthe royalty regime in that province. With Canada providing a quarter of Devon'scurrent oil and gas production, and with most of that in Alberta, any change inthe royalty structure is of course a concern.

The new structure is somewhat complex and we are stillevaluating the impact of the changes on our Canadian operations, but it doesseem likely that there will be some economic impact.

Devon's capital investments are of course based not just onroyalty rates but rather on expected full cycle returns. Those expected returnsare impacted by our expectations for production, realized oil and gas prices,capital costs, operating costs, foreign exchange rates, and a host of otherthings .

On a positive note, last week the Canadian FederalGovernment announced a budget proposal which, if enacted, would reducecorporate income taxes, which would have a positive impact on our Canadianreturns. You can be assured that our future investment allocation decisionswill continue to take into account not only the implications of the AlbertaGovernment’s decision to change the terms under which we operate, but also allof the return criteria we evaluate.

Fortunately, Devon has a very large and diverse portfoliowhich will allow us to reallocate capital, both within capital and between --both within Canada and between Canada and across all of our other operatingdivisions. We of course will choose those areas which generate the mostfavorable return.

At this point, I will turn the call over to Stephen Hadden.Stephen.

Stephen J. Hadden

Thanks, Larry and good morning to everyone. Let’s start witha look at our 2007 capital spending. During the third quarter, our explorationand development CapEx totaled $1.4 billion, bringing year-to-date E&Pcapital expenditures to $3.8 billion. As we noted in last quarter’s call, we expectfull year E&P capital to come in near the top of our forecasted range atabout $5.3 billion.

At the end of the third quarter, we had 150 rigs runningcompany wide, with 89 of those rigs drilling Devonoperated wells. We drilled 599 wells company-wide during the quarter.Twenty-four were classified as exploratory, of which 92% were successful. Theremaining 575 wells were development wells and about 98% of those wells weresuccessful, 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 milestoneduring the third quarter by drilling our 1,000th Devon operated Barnett Shalewell. It was just about five years that Devon pioneered horizontal drilling inthe Barnett. Due to the superior economics and reduced surface impact, almostall the wells being drilled in the Barnett today are horizontal.

Horizontal wells make up about one-third of our Barnettproducers, but account for about two-thirds of our Barnett production. OurBarnett Shale production averaged a record 856 million cubic feet of gasequivalent per day in the third quarter. This was a 7% gain from the secondquarter and up 32% compared with the third quarter of 2006.

In our last call last quarter, we revised our year-endtarget rate to 875 million cubic feet of gas equivalent per day and we are wellon the way to hit that goal. We had also previously announced a longer term nettarget rate of 1bcf per day by the end of 2009. Given our progress to date andthe pace we are on, we now expect to reach the 1 bcf mark per day by early2009. This is more than twice the forecasted production of our next closestcompetitor.

This leading position in the play has been well establishedthrough our first mover advantage. That advantage has given us unmatched sizeand scale in the play. Since 2001, with our acquisition of Mitchell, we built alease position of over 735,000 acres with very favorable lease terms. Devonhas an average royalty burden of under 20% on these leases. This compares to aroyalty burden on most leases taken in the Barnett over the last several yearsof 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 mcfrealized gas price environment, a well with a 20% royalty burden has about 1.4times the present value of a well with a 25% royalty burden.

A large portion of our acreage is concentrated in the betterareas of the play, such as the core area in Johnson County. Accordingly, wehave a superior acreage position and years of additional drilling inventory inthe better portions of the play.

Our history of being the first to identify new applicationsof technology has been well-established since the beginning. Devon was thefirst to unlock the early potential of the play with light sand fracs andhorizontal drilling. While all of the major operators in the play have the samedrilling and completion services available to us, the various operators chooseto complete wells differently. Various lateral lengths and number of fracstages can impact IPs per well, recoveries per well, and ultimately welleconomics.

Rather than focus on maximizing per well production orreserves, Devon has chosen to optimize return with our well designs. We nowhave 3,000 wells in the play and we are drilling at a rate of over 500 wellsper year, by far the largest in the play. This scale allows us to establish anin-depth knowledge of the reservoir, as well as very strong, long-termrelationships with the leading drilling and pumping service providers in thecountry, providing reliability, performance, and value.

We have been asked recently if we plan to integratevertically in the play through the purchase of drilling rigs or completionrelated assets. It’s always been our view that it’s best to allow thespecialists to do what they do best while our team stayed focused on combininginnovation and our deep understanding of the Barnett Shale to deliver the bestvalue growth and return for our shareholders.

These relationships have allowed Devon to hold our wellcosts flat over the past year, despite the cost escalations experienced by ourindustry over the same period. We accomplish this while ramping up activityfrom 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 positionin the play with the best acreage position, the best lease terms, and the mostconsistent execution, and we’ll provide an early achievement of our 1 bcf perday goal.

During the third quarter, we completed a total of 127Barnett wells, 50 of which were in the core and 77 were outside the core. Weremain on pace to drill 500 wells in the Barnett Shale this year and we arerunning 32 Devon operated rigs, nine in the core area and 23 outside the core.

Our non-core drilling program in Johnson County continues toshine. In the third quarter, we put 39 new wells online in Johnson County at anaverage rate of 2.5 million cubic feet per day. Four particularly strong wellseach had 24 hours sustained initial production rates averaging above 5 millioncubic feet per day.

North of Johnson County in Southern Wise County, we broughttwo exception wells online at 5.4 million and 6 million cubic feet per day, sowe continue to see solid results from our non-core horizontal drilling withtypical 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, animportant part of our activity in the Barnett Shale is in-fill drilling ordown-spacing in areas that have already been fully developed on primaryspacing. These in-fill wells are usually referred to as 20 acre in-fill wells. However, I’llremind you that with horizontal drilling, one well can replace several 20 acre vertical well locations.Consequently, from a surface development perspective, 20 acre in-fill horizontal wellsactually occupies 80 surface acres.

Since we began this horizontal in-fill program, we’vecompleted a total of 139 of these in-fill wells. A total of 127 that have beenconnected to the producing grid are horizontal with average initial productionof 2.2 million cubic feet per day. Economics from the horizontal in-fill wellswe’ve drilled to date are very solid at an average drilling and completion costof about $2.9 million and approximately 2.1 bcf per well estimated recovery.

In addition, we’ve been experimenting with furtherhorizontal down-spacing. We have completed a total of 11 operated wells thatare spaced to result in two wells per 80 acres, or 40 surface acres per well. Seven of these havebeen tied into production, with an IP of 2.5 million per day. This down-spacingis one of the ways we expect to convert into crude reserves more of the 13trillion cubic feet of potential, represented by Devon's 735,000 Barnett acres.

While we are very encouraged by these early results, we’llneed to see more production data before developing large areas based on onehorizontal well per 40 acres.

It the Woodford Shale in eastern Oklahoma,we currently have five operated rigs drilling in the play. We brought a totalof eight new operated wells online during the third quarter with individualwell production rates as high as 4 million cubic feet of gas a day. We nowoperate 46 wells in the Woodford, with gross operated production running about38 million cubic feet per day.

Our net Woodford Shale production averaged 20 million cubicfeet per day in the third quarter, up almost 70% compared with the thirdquarter of 2006. On average, our Woodford Shale wells are costing between $4.1million and $4.3 million to drill and complete, and yielding about 2.5 bcf ofreserves per well.

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

Shifting to east Texas, we continue with a seven-rigvertical Cotton Valley drilling program in the Carthage area. In the thirdquarter, we drilled 25 vertical wells and continued an active recompletionprogram. At the end of the quarter, we were drilling with 66 wells in a 95 wellvertical program that’s planned for this year. Looking forward, we have asignificant drilling inventory with as many as 420 additional verticallocations available, including about 65 20-acre in-fill locations.

We also continue to see good results from our three-righorizontal drilling program in the Carthage area. We drilled and completed fivenew Cotton Valley horizontal wells during the third quarter, including the 100%working interest Davis 4H well that averaged 6.6 million cubic feet of gas perday for the first 30 days of production.

Since we first tested the horizontal drilling concept in theCarthage area about one year ago, we’ve drilled 11 out of 11 successfulhorizontal wells. These wells cost from $5.5 million to $7 million per well todrill and complete, with estimated ultimate recoveries of 3 to 6.5 bcf perwell.

We have as many as 96 additional horizontal locations todrill at Carthage. In total, our net Carthage production average 260 millioncubic feet of gas equivalent per day for the third quarter, up 5% from thesecond quarter average and up 8% from a year ago. With a lot of running roomfor both the horizontal and vertical well programs, we believe we can continueto grow Carthage production well into the future.

Shifting to the Gulf of Mexico and our deepwater productionoperations, we established production from the two subsidy wells at Merganserin the third quarter. These gas wells are flowing into the independent hub andare currently producing at a combined rate of more than 68 million cubic feetof gas per day net to Devon's interest. This rate is 36% better than ourforecasted rate, so we are obviously very pleased with the early performance ofthese wells.

In our deepwater [inaudible] and exploration program, weexpect to begin drilling on the Sturgess North prospect located in AtwaterValley Block 138 inearly 2008. We made an initial discovery at Sturgess in 2003, encountering over100 feet of netoil pay. Sturgess North is located adjacent to the Sturgess discovery but willtest a separate geologic structure. Devon has a 25% working interest in thisChevron operated prospect.

Our lower tertiary exploration program was in full swingduring the third quarter. Early drilling on our Chuck prospect located inWalker Ridge 278 has gone slowly as the Ocean Endeavor rig was being debuggedby Diamond Offshore. We believe that most of the start-up issues have beenresolved and we are currently drilling below 21,000 feet. Chuck is targeting alarge sub-salt structure in about 6,500 feet of water and Devon is the operator of Chuck, with a39.5% working interest.

We expect to begin drilling an exploratory well on the GreenBay prospect around year-end. This lower tertiary exploration prospect islocated on Walker Ridge 372 inapproximately 6,300 feetof water. The prospect is about 20 miles north of the St. 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 activitieson the four significant lower tertiary discoveries which we’ve participated into date. Last quarter, we began drilling a location on our Keathley CanyonBlock 244 in the Kaskidaunit. This location, previously known as Cortez Bank, is located about 12 miles west of our 2006 Kaskidadiscovery. The well was drilling in a side-tracked hole to a proposed depth of 33,000 feet when mechanicalissues forced the well to be abandoned before reaching the target objective.

While it is always a disappointment to spend capital on awell that fails to reach its intended objective, this result does not dampenour enthusiasm for the unit. The Kaskida discovery well clearly encountered avery significant oil column and we have a lot of work left to do to fullyunderstand the potential of the unit.

The joint owners are now integrating the results from thetwo 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 nextwell operation is expected some time in the first half of 2008.

At Cascade, our lower tertiary development with Petrobras in the Walker Ridge area, we sanctioned developmentduring the third quarter. We have submitted operating and development plans tothe MMF and we have awarded the FPSO and shuttle tanker contracts. We nowanticipate initial production at Cascade to likely be in the first half of2010.

Our approach to development at Cascadewill allow us to produce the first wells over a sustained period. Reservoirinformation gathered during that initial period phase will help us determinethe optimum number and placement of producing wells and allow optimization offull field facilities for the project. Devon and Petrobras each have 50%working interest at Cascade.

At Jack, also in Walker Ridge deepwaterlease area, Devon and our co-owners expect to finish drilling operations on asecond delineation well, the Jack Number Three, 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 WalkerRidge deepwater area, we are currently drilling our second delineation well andwe hope to have the results in the first quarter of 2008. These additional Jackand St. Malo wells will providing important data that will help the partnersdetermine the optimum development approach to these discoveries.

I will remind you that Devon has a 25% working interest inJack and a 22.5% working interest in St. Malo.

Moving to Canada, in the Lloydminster oil play in Alberta,we have increased production by over 50% over the past 12 months to 34,600barrels of oil per day. We continues to have an active five rig program in thethird quarter, as we drilled 125 new Lloydminsterwells. A second 10,000 barrel a day expansion at our [Manitokin] plant is underwayand we expect to complete that work by the end of 2008.

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

At Jackfish 2, engineering and budgeting work continue andwe expect to receive regulatory approval around mid-2008. At that point, wewill make a formal decision about the project. This project would add another35,000 barrels of day of thermal oil.

Moving to the international arena, development drilling atthe Devon operated Polvo project on Block BM-C-8 in Brazil continued during the thirdquarter. We achieved first oil on July 26 and have completed the first three ofa total of 10 planned producing wells, which reach a combined growth rate of9,500 barrels per day. The field’s first lifting of 385,000 barrels occurred onOctober 21st. The fourth well is currently drilling. The additional wells willbe drilled and tied in throughout the remainder of this year and into 2008 aswe ramp up the field’s production.

In Azerbaijan, where Devon had a 5.6% working interest inthe ACG oil field, our share of ACG production averaged about 28,000 barrelsper day in the third quarter. As expected, there were about 17 days of downtimeat ACG in the third quarter to perform facility upgrades to both offshore andonshore infrastructure. Field production has since been brought back online.

In China, we expect to drill our Watermelon prospect locatedon Block 4205 inthe first quarter of 2008. You might remember Block 4205 is adjacent to Block2926, where Husky and CNOOC announced a multi-pcf gas discovery. However, thiswell has all the typical risks of an exploration well. Devon operates Block4205 with 100% working interest.

That concludes my comments on our operational highlights forthe quarter. I’ll now turn the call over to John to review our financialresults. John.

John Richels

Thank you, Steve and good morning, everyone. This morning, Iwill take you through a brief review of the key drivers of our third quarterfinancial results and take a look at how they impact our outlook for theremainder of the year. You can find the details of our updated forecast in theform 8-K that we’ll be filing today, as Vince mentioned earlier.

As a reminder, we have reclassified the assets, liabilitiesand results of operations in Africa as discontinued operations for allaccounting periods presented. As a result, I’ll focus my comments only on ourcontinuing operations, which exclude the results attributable to thedivestiture properties.

Let’s begin with production. In the third quarter, weproduced 56.8 million equivalent barrels, or approximately 618,000 barrels perday. This exceeded our guidance by about 3% or nearly 2 million barrels.

Approximately three-quarters of this outperformance was dueto better-than-expected results from several of our core properties in NorthAmerica and the remainder of the outperformance was attributed essentially tothe absence of anticipated downtime for hurricanes in the Gulf of Mexico andthe postponement of planned facilities repairs at our offshore [Puguang]project in China. Thankfully, we’ve had an uneventful hurricane season and therepair work at [Puguang] is now scheduled to begin in the fourth quarter of2007.

When you compared our third quarter results to the samequarter 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 inour 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 tothe third quarter of 2006.

Continuing a trend, the leading driver of our U.S. onshoreperformance was strong production growth from our Barnett Shale assets. We alsoexperienced significant growth in the international sector, almost entirelyattributable to increased production from the ACG field in Azerbaijan.

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

Looking ahead to the fourth quarter, we expect to growcompany-wide production for a seventh consecutive quarter. In total, weanticipate fourth quarter production of approximately 57 million equivalentbarrels. Key growth drivers will be our U.S. onshore assets, a full quarter ofproduction from Merganser and Polvo, and an uninterrupted quarter of productionin Azerbaijan.

However, this growth will be offset somewhat by therescheduled downtime for equipment replacement in China, along with anticipateddeclines 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 fullyear production forecast to 223 million equivalent barrels. This will addanother percent or two to the 10% year-over-year growth target we hadpreviously forecast for 2007.

Although we expect to finish 2007 ahead of our previousproduction forecast, we are not increasing our guidance for 2008 at this time.We typically finalize our capital budget in the fourth quarter and submit it toour board of directors in December for approval. Following board approval, weprovide updated production guidance. Until we complete the budgeting processand determine the optimal level for our 2008 capital spending, we’ll stick withour previous forecast for 2008 of 240 to 247 million barrels equivalent.

Moving on to price realization, starting with oil, in thethird quarter the benchmark WTI oil price rose to an average of $75.21 perbarrel. That’s a 16% increase from the second quarter of 2007.

In addition to higher benchmark prices, regionaldifferentials remain tight with the results of price realizations in all of ourproducing regions where we are above the midpoint of our guidance ranges.

Our company wide realized price came in at $67.41 perbarrel, or about 90% of WTI. That’s a 12% improvement in realized prices overthe last quarter.

Although differentials have widened recently for heavy andsour crudes as benchmark prices have increased, we are still comfortable withour full year guidance for oil price differentials. I’ll remind you that sincenone of our oil volumes are hedged, we are benefiting from further increases inoil prices that we are seeing in the fourth quarter.

On the natural gas side, the benchmark Henry Hubb indexaveraged $6.16 per MCF in the third quarter, some 6% below last year’s thirdquarter. Our company-wide gas price realizations were generally in line withguidance at approximately 86% of Henry Hubb.

Strong price realizations in the Gulf of Mexico and inCanada were mostly offset by continued price weakness within the Rocky Mountainproducing area. You’re probably aware that the price differentials in theRockies have widened significantly over the past several months, due primarilyto constrained regional export capacity.

The impact on Devon, however, has been limited because theRockies represent less than 10% of our company wide natural gas production.

Looking ahead to the fourth quarter, we expect natural gasprice differentials to be very similar to the third quarter.

Turning now to our marketing and midstream business, onceagain marketing and midstream operations delivered excellent results. Marketingand midstream operating profit for the third quarter came in at $133 million,$21 million more than in the third quarter of 2006. The increase is due tohigher gas processing margin in the 2007 quarter.

Based on the strength of the first three quarters, we’reagain increasing our 2007 operating profit forecast. We now expect Devon'smarketing and midstream full year operating profit to come in between $460million and $490 million. At the midpoint, this represents an increase of $35million from the midpoint of our previous guidance range.

Moving to expenses, third quarter lease operating expenseswere at the low end of our guidance range, coming in at $457 million, or $8.04per equivalent barrel. This was essentially flat to our average LOE rate forthe first half of the year.

For the quarter, unit LOE costs remain steady or decreasedin 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 LOEcosts due to new development projects ramping up production and also a seasonalincrease in operating costs in Canada.

For the full year, we expect lease operating expenses to benear the top of our previous guidance range.

Our reported third quarter DD&A expense for oil and gasproperties came in at $12.41 per barrel. This was $0.16 above the high end ofthe guidance range we provided in our second quarter conference call. Thehigher-than-anticipated depletion rate is entirely due to low spot gas pricesin the Rockies at September 30th. This resulted in a temporary reduction inreserves for the calculation of depletion. We expect this situation to correctitself in the fourth quarter and accordingly, we expect our DD&A rate to returnto where it otherwise would have been.

However, due to the higher-than-expected rate in the thirdquarter we now expect our full year DD&A rate to come in near the top ofour previous forecast range.

Moving on to G&A expense, G&A expense for the third quarterwas $126 million. This result is a couple of million dollars above thequarterly range implied by our full year forecast, and $13 million higher thanlast quarter. Higher employee related costs were the primary driver.

Looking ahead, based on our year-to-date results and inanticipation of continued upward pressure on personnel costs, we’re nowincreasing our full year G&A guidance by $30 million to a new range of $490million to $510 million.

A final expense item I want to touch on is income taxes.After adjusting out the items that are generally excluded from analystsestimates, income tax expense for the third quarter came in at 33% of pretaxincome. The current tax position is roughly 10% of pretax earnings and thedeferred tax piece came in at about 23% of pretax earnings. This brought theadjusted income tax rate for the first nine months of 2007 to 32%, with halfcurrent and half deferred. The 32% overall income tax rate, with roughly halfdeferred, reflects our expectations for the fourth quarter and full year 2007.

In today’s 8-K, we are providing updated guidance thatreflects the lower percentage of taxes that are classified as current.

After backing out income tax expense, our reported earningsfrom continued operations for the third quarter totaled $644 million, or $1.43per diluted share. Earnings from discontinued operations added another $91million, or $0.20 per diluted share in earnings. In aggregate, after backingout the items that are usually excluded from analyst estimates, our adjustednet earnings for the third quarter were $700 million, or $1.55 per dilutedshare.

This translates into cash flow before balance sheet changesfor 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 $1.6billion, leaving roughly $200 million of free cash flow for the quarter. Weused the majority of this free cash flow to return more than $180 million toshareholders through share repurchases and dividends. We also received $106million of exchange requests related to our Chevron exchangeable debentures andwe chose to retire those obligations with cash rather than to redeem them withthe Chevron shares that we hold.

Even with the redemption activity, we concluded the quarterwith a healthy cash balance of $1.7 billion and with ournet-debt-to-capitalized ratio, or net-debt-to-capitalization ratio under 20%.

Looking forward, we expect cash flow from operations toroughly cover our capital demands. This will leave us with after-tax proceedsfrom the African divestitures to repay short-term borrowings and to continue torepurchase our stock.

All in all, this was another outstanding quarter for Devonand with that, we’ll open the call up for Q&A.

Vince White

Operator, we’re ready for the first question.



(Operator Instructions) Our first question comes from BrianSinger from Goldman Sachs.

Brian Singer -Goldman Sachs

Thank you. Good morning. A question on Canada; if you lookat your overall portfolio beyond Canada, what area do you see that has thegreatest combination of opportunity and capacity to take capital, should youfurther reduce drilling in Canada? Or would you look toward the acquisitionmarket in part?

Stephen J. Hadden

We have a, as you mentioned, a very deep portfolio. Mainlywhere we would look is in the U.S. onshore business. John mentioned that strong12% growth that we’ve seen happening in that aspect of the business. We wouldprobably redeploy it into areas like we have in the Barnett where we are nowdrilling 500 wells where we initially estimated we would drill 385 at thebeginning of this year.

And we have good opportunities in the Carthage area and someof the east Texas areas, so generally, that give us -- those are some examplesof the areas that give us some of that swing. The U.S. onshore is a goodopportunity for us.

I will mention that within Canada, we have both a veryviable thermal oil business but we also have the Lloydminster area and somevery good cold flow heavy oil opportunities that I think you heard earlier inour comments that we’ve been able to grow about 50% year over year.

So within Canada, we can actually -- we have a pretty goodportfolio in Canada that allows us to redeploy capital within Canada away frommaybe some of the lower returns we may be seeing in the Canadian conventionalgas business, and those are very good and solid returns that we get in theLloyd area.

We can optimize within Canada first and then as we lookacross our portfolio, we have other areas where we can go to for that near-termgrowth.

J. Larry Nichols

I might add that within Canada, you need to realize that theroyalty rates are different between oil and gas and they are different betweendifferent types of gas and different types of oil, and a lot of those aresliding scale type royalties, so it’s a fairly complicated situation that canresult in that reallocation within Canada.

Brian Singer -Goldman Sachs

Absolutely. Shifting to the Barnett, based on the strongresults that we’ve seen, it would seem like you could reach your 1 bcf a daytarget a littler earlier than early 2009. Do you feel like you are conservativethere? Do you seen any constraints in bringing wells online? Following up onthe previous question, what do you think is your capacity to drill in theBarnett in terms of the number of wells per year?

Stephen J. Hadden

You know, Brian, we’re very comfortable where we are now. Weare at about 32, 33 rigs in the Barnett and that’s probably an activity levelwe would feel good at [inaudible]. At that rate, we drill about 500 wells ayear and as we look forward, we’re not having -- as a matter of fact, if youlooked in the history over this year, our inventory of wells to hook up, forinstance, has actually gone down dramatically, [continue] to trend downward. Soeven at that accelerated rate, because of our very strong midstream presence,the good partnership we have with [CrossTex] and the relationships we have in thefield, we’ve been able to operate at this high level of accelerated activitypretty comfortably.

As we look forward to the bcf a day, we’re going to continueto do the right things for value and core [returns] and we’re going to want toreally take a close look at that as we go in through our budgeting process,which we’re in right now. Probably have a little clearer picture of when we getthat bcf a day sometime maybe in December or January.

J. Larry Nichols

I might add that the bcf a day is of course not the peakrate that we foresee out there. We are working through on our budget for thatprocess. It was merely the target that we picked which at the time seemedpretty aggressive, but we are clearly way ahead of schedule on meeting that andthere is additional growth beyond, after that.

Brian Singer -Goldman Sachs

Thank you.


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

Tom Gardner - Simmons& Company

Larry, I appreciate your comments concerning the difficultyworking your way through the Canadian royalty change.

J. Larry Nichols

We’re having trouble hearing you. Can you speak up?

Tom Gardner - Simmons& Company

Sure, I’m sorry. I believe one of you all’s microphones cutout as well, but with regard to Canada and the royalty change there, atJackfish, any idea of the long-term implications to thermal SAGD development inCanada? What oil price is required now for economic return there for SAGD orthermal?

John Richels

As you know, forecasting the oil price that we need in orderto optimize the returns from the thermal heavy oil project is really difficultbecause there are many variables. It’s oil price, natural gas price, sincewe’re burning natural gas to create steam. There’s the differential, which isan important aspect of it. The cost of [inaudible] and the transportation costsand they all move in different directions.

So if you tell me what the oil price is and we can factor insome of those other variables, then we can come up with that. But that varies alot, so that’s a tough question to answer.

As far as the royalty effect in Canada,I think there’s two things that are important to realize. As Larry pointed outand as Steve did, the royalty effect is variable among different kinds ofassets in Canada. When we look at our Jackfish 2 project, our initial view ofthe legislation or the proposed royalty changes doesn’t change the returns onthat project materially.

Had the royalty review panel recommendations been enacted,it would have, but the way it has now been proposed, it doesn’t change it a lotand frankly, the project remains sensitive to capital cost, foreign exchangerate and all of the other things that it previously did.

The good thing about our Jackfish 2 project is we did somethings at Jackfish 1 that will create some benefits for Jackfish 2 if we goahead with it, most notably the access pipeline. So the costs of that accesspipeline was really taken into consideration in Jackfish 1 and Jackfish 2 willbenefit from it.

So a preliminary look or a preliminary view of it is thatthat project still looks pretty good and we are still doing all of ourengineering and capital analysis of that project and we’ll probably make adecision on that in the middle of next year.

Tom Gardner - Simmons& Company

Just using a normal relationship between oil and gas prices,can you bracket the oil price required for the thermal project?

John Richels

You know, what we’ve used in the past, Tom, is -- it wasinteresting. When we approved our Jackfish 1 project, when our board took alook 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 itagain and we are kind of doing a look back into the project halfway through theconstruction of it, and at that time, oil was $63, the differential was $23,and gas was $7 -- had about the same return.

So the relationship that we think is the most important isthe 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, wethink 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 eitherthird party processors and refiners will move into that space, or if theydon’t, the E&P sector will continue to move into that space to get thedifferential to that level, at which you can make a real good return on theupgrading side.

Tom Gardner - Simmons& Company

How are the economics then of the thermal different fromthose who are mining the oil sands in Canada?Would you think that the mining is more cost challenged or less?

John Richels

I’m sorry. I couldn’t hear that, Tom.

Tom Gardner - Simmons& Company

I’ll speak up. There must be some problems with the linehere, but just comparing thermal with mining oil sands in Canada, how would theeconomics compare between the two?

John Richels

Well, they are very different, obviously because they -- Imean, in the mining projects, they’re not burning gas, first of all, and soit’s a fairly -- it’s a completely different equation. Also, all of thosemining projects have an upgrader attached and are producing a quality of oilthat trades up with or sometimes above WTI, as you know.

Without getting into all of the details, we would take a lotof time on it, they are just very different types of projects.

Tom Gardner - Simmons& Company

One last question, moving over to the Gulf of Mexico regarding the decision on the MMS royalty case. Did Devonagree to the royalty threshold and do you stand to benefit from the recentfederal court decision on royalties?

J. Larry Nichols

The federal recent court decision was at the federaldistrict level. It is not a surprising decision at all because if you read thelegislation that Congress enacted that provided some royalty relief for theexpensive deepwater, there is -- just a plain reading of it shows that there isno real authority for the MMS to do what they tried to do. Therefore, we werenot the least bit surprised that Congress, that the federal court dispatchedwith that case in a fairly short, summary argument. But that’s just a districtcourt. We’ll wait and see what happens, whether it’s appealed and if so whatthe appellate court rulings are.

I might go back to one -- the comment on heavy oil. Evenwithin steam-assisted gravity drainage projects, there is a wide variety ofcosts that those projects can incur. They are not all one-cost structure. Whatwe are happy about in Jack is that -- and why we are proceeding on it, is amongheavy oil projects, it is a very high quality, low cost project relative tomany others.

Tom Gardner - Simmons& Company

Thanks, guys.


Our next question comes from Gil Yang from Citigroup.

Gil Yang - Citigroup

Good morning. Could you talk, Steve, a little bit about theacceleration in the Barnett? Obviously you said that you are drilling morewells, but is there some -- and obviously you’ve drilled some good wells aswell. So how much would you say the acceleration is due to the increasedactivity level versus the better performance of the wells?

And then, with respect to the better performance, is it notonly IPs but are the decline rates doing anything unusually positive for you?Hello?


Sir, your line is open for your question.

Gil Yang - Citigroup

Can you hear me?

Stephen J. Hadden

Can you hear us, Gil?

Gil Yang - Citigroup

No, I can’t hear you -- I can barely hear you. I can hearyou a little bit.

Stephen J. Hadden

Can you hear us now?

Gil Yang - Citigroup

A little bit.

Stephen J. Hadden

Back on the question on the Barnett Shale, it’s actuallyboth things driving the acceleration of our activity. If you remember, back inabout a year, year-and-a-half ago, we were running a lot of seismic, gettingsome good processing, and really going about better characterizing the non-corearea so we could get good, solid repeatable results with our wells.

We’ve also had some process improvements on the drillingside that allowed us to reduce our drilling days, so we actually get more wellsper rig. And we are getting better results. That’s partly driven by thosefactors.

So as we’ve built up our confidence in really being able todeliver a repeatable and improved results on average, we continue to acceleratethe program.

An aspect of the drilling activity that we have is the20-acre in-fill. Now, those 20-acre in-fill wells, I think we started off atabout -- estimating about 1.7 bcf per well. When we initially talked about the 20 acres and we were in the pilotstage, I think you saw now we are about 2.1 bcf per well with the largerprogram that we are drilling.

Again, those are areas where we can even go back into thecore and drill those types of wells. So we are seeing improved performance,part of it is reservoir characterization, part of it is the drilling efficiencythat we are gaining, and part of it is the integration of that reservoircharacterization with our completions.

So those factors are all driving the ramp-up that we havefrom about the 385 wells to the 500 well activity level.

Gil Yang - Citigroup

Okay, thanks, that’s helpful. Have you seen any change indecline rates?

Stephen J. Hadden

No, not materially. We are still looking at about the sameexponents. Of course, we continue to monitor performance and that’s how we makeour reserve estimates and we are pretty happy and comfortable where we areright now with those decline rates that we have.

Gil Yang - Citigroup

Could I just ask the same question for Merganser? What isthe -- those wells are outperforming. Is it just greater permeability? Are thereservoirs larger than you thought? What’s going on there?

Stephen J. Hadden

I think, as you probably know, Gil, when we drill thesewells, we get a lot of static information. In other words, we can look at coreinformation. We can look at log information and of course, our engineering andgeologic teams make estimates of what we think those wells can flow and it’sbasically on a risk basis. To actually see how the well will perform, some ofthese larger intervals will perform under dynamic flow. You actually have toflow the wells, so we are simply -- I think we are simply just seeing betterperformance as it relates to our risk estimate of what the permeability and thecontribution of the well would be.

Gil Yang - Citigroup

Do you have any indication yet that the reservoirs, thatthere’s no concern that they are compartmentalized in any fashion?

Stephen J. Hadden

It’s still too early to really make any other definitiveconclusions on that, since it’s still early in the production life. We haven’tseen anything negative to date.

Gil Yang - Citigroup

Thank you.


Our next question comes from Ross Payne from WachoviaCapital Markets.

Joe Hofer - WachoviaCapital Markets

Hello? Can you hear me? This is Joe Hofer for Ross Payne. Iwas just following up on the Barnett Shale, just looking at -- what is theaverage well life you have there? And as you look to potentially deployadditional cash flow to the area, how would you characterize the costenvironment that you are facing in the region?

Stephen J. Hadden

Let me take the first issue first. As we look at the life ofthese wells, these are wells that they initially come on and have a pretty gooddecline rate initially. Then they go what we call exponential, so they begin toflatten out in their production profile. Some of these wells, you can estimatethem to produce for as long as 40 years, so the well lives are very -- can bevery, very long.

If you look in terms of our cost environment, we areactually -- we have actually seen the cost of our wells on a year-over-yearbasis remain flat. Now that’s driven by the drilling efficiencies that we’ve beenable to gain and partly by some of the softening in the acceleration of costescalations that we had seen starting in about early 2005 and through 2006.

From a cost standpoint, we are very comfortable in theenvironment that we are in. The average well is going to be around $2.7 millionto about $3 million a well, and we are getting about 2.5 bcf on average out ofeach well.

Joe Hofer - WachoviaCapital Markets

Thank you.


Our next question comes from Mark Gilman from Benchmark.

Mark Gilman - TheBenchmark Group

Good morning. Can you hear me? A couple of things, Steve, ifyou wouldn’t mind. First, I think when you were discussing Chuck, you talkedabout a side track hole having run into mechanical problems. What about theoriginal hole?

Stephen J. Hadden

Actually, Mark, that was on the Cortex Bank well, the wellwe were drilling in the Kaskida unit.

Mark Gilman - TheBenchmark Group

I’m sorry, Steve.

Stephen J. Hadden

We were in the process of side-tracking to gain some more reservoirinformation. The initial well we drilled to its total depth and we are in theprocess of looking at that information and working through that information.

The side track that we had was a distance away from theoriginal hole. We were trying to get some more reservoir information but wedidn’t reach the objective and are disappointed with that, but we are stillvery excited about the Kaskida unit.

Mark Gilman - TheBenchmark Group

Okay, with respect, Steve, to Cascade, do you have anynumbers in terms of development cost, reserve numbers, and estimatedproduction?

Stephen J. Hadden

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

Mark Gilman - TheBenchmark Group

Okay, Polvo, it looks as if, just on a pro rata basis, thatthe performance of the first three wells doesn’t necessarily get you to whatthe plateau estimate was. Is that evaluation premature?

Stephen J. Hadden

We think it’s premature to draw that conclusion. On thefirst initial wells, we are drilling in the [macha a] carbonites and thosecarbonites can be a little bit tricky over time and you can have somevariability.

We are still very early in the drilling program. We haveseven more wells to drill and we are still sticking by about that 50,000barrels a day. If that changes once we get a few more wells under our belt,we’ll let people know.

Mark Gilman - TheBenchmark Group

Okay, and finally with respect to Carthage, if I recallcorrectly, last conference call you were talking about actually pulling back alittle bit in terms of the drilling program, as you better assessed horizontalperformance. Now you are moving the rig count back up to 13. What’s reallychanged?

Stephen J. Hadden

Mark, actually in east Texas, the area where we were havingproblems was looking at the Groesbeck area and we were having some mechanicalproblems in getting into the full extent of the horizontal section and makingsure that we had the completions going off and getting the number of stages offracs that we wanted to have in the horizontal sections.

We’ve had a very good effort with a team of people workingon that. We actually have had some pretty good results. We brought one well onin the Groesbeck area, came on about 17 million cubic feet a day in the[Nantsugill] Field. So you can probably see us begin to ramp that back up as wemove into 2008.

On Carthage, that’s been working very well. We have not hadany of the mechanical problems and we are continuing to run three horizontalrig lines as we continue to move forward with that horizontal program.

Mark Gilman - TheBenchmark Group

Okay, Steve, thanks a lot.

Vince White

Operator, we’ll take one more question and then terminatethe call.


Thank you. Our last question comes from David Heikkinen from Tudor, Pickering.

David Heikkinen - Tudor, Pickering & Co.

Just a follow-up; volume lifted at Polvo in October?

Stephen J. Hadden

The number was 385,000 barrels.

David Heikkinen - Tudor, Pickering & Co.

And then a schedule for liftings from here forward?

Stephen J. Hadden

Right now, we have another scheduled in December.

David Heikkinen - Tudor, Pickering & Co.

Okay, and then just a reminder on the production sharingcontract at ACG, volumes versus oil price and how that works, looking forwardat today’s oil prices?

Stephen J. Hadden

It’s a pretty complex PSC but the bottom line is as the oilprices get higher, we are going to have less cost oil coming to the contractor,and as we reach different payout tranches, as we reach different returntranches, we could have a -- we will have a drop in our nets, so it’s affectedby oil price both on the net that we take and the cost oil that we recover asprices go higher.

Vince White

If I remember correctly, this is just kind of a broad brushrecap, we’ll go through two tranche reductions in the next nine months or sothat will reduce our net take to about half of the current level, and then wereally expect flat production for a long time thereafter.

David Heikkinen - Tudor, Pickering & Co.

That’s perfect, Vince. Thank you.

Vince White

Okay, just a quick recap of the quarter; it was an excellentquarter again. Operationally we delivered growth from our core developmentprojects, we continue to see very promising results from our long-termexploration program. Our organic production growth of 10% over last year’sthird quarter positions us to raise our 2007 production forecast, which ofcourse will in turn lead to higher growth over 2007 over 2006. All of thisleads to increases in revenues and earnings and cash flow. Divestiture programmoving forward, and we expect to be positioned to fully fund our capital needs,repay debt, and repurchase stock in the year ahead.

In summary, we are very happy with our continued high levelperformance and think we are very well-positioned for the future. Thanks andwe’ll talk to you again in February. Take care.

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