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.

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 devonenergy.com. 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’sdevonenergy.com. Finally, I want to remind you that our…

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.…

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…

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…

Operator, we’re ready for the first question.

(Operator Instructions) Our first question comes from BrianSinger from 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?

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.

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.

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?

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.

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.

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.

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?

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?

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?

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?

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?

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.

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.

Can you hear me?

Can you hear us, Gil?

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

Can you hear us now?

A little bit.

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.

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

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.

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?

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.

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

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.

Thank you.

Our next question comes from Ross Payne from 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?

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.

Thank you.

Our next question comes from Mark Gilman from Benchmark.

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?

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

I’m sorry, Steve.

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.

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

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

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?

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.

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?

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.

Okay, Steve, thanks a lot.

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?

The number was 385,000 barrels. David Heikkinen - Tudor, Pickering & Co.: And then a schedule for liftings from here forward?

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?

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.

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.

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.