After the prepared remarks, we will conduct a question and answer session. (Operator Instructions) I’d like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin. Vince White: Thank you, operator. Good morning everyone and welcome to Devon’s second quarter 2007 conference call on web cast. I will begin with a few remarks and then our Chairman and CEO, Larry Nichols, will review the highlight of the quarter and bring you up to date on some of our recent initiatives. Following Larry’s remarks, Steve Hadden, he’s our senior Vice President of Exploration and Production, and he will cover the operating highlights. And then finally, Devon’s President, John Richels will conclude with a financial review. We’ll follow that with a Q and A session. As is our practice, we’ll try to hold the call to about an hour, so if we don’t get to your question, please give us a call this afternoon. A replay of today’s call will be available later today through a link on devonenergy.com. We will also be posting to our website a new issue of Devon Direct. This is an electronic report that included highlights from the web cast and also includes links to additional supplementary information. During the call today, we’re going to update some of the estimates for the year that are based on the actual results that we saw for the first six months of the year and our current outlook for the second half of the year. In addition to the updates that we’re going to provide in today’s call, we’re going to file an A-K later today and that document will give all the details of our updated guidance. Please note that in today’s call, we’ll talk about plans, forecasts, and…

(inaudible) is not usually inclined to such exuberant language, but it clearly was a terrific quarter that extends the momentum that we’ve been building for some time. We’re particularly pleased with the increase in production from continuing operations which was 16% better than the second quarter 2006, and 5% ahead of the first quarter 2007, demonstrating very solid organic growth. The second quarter of 2007 was our fifth consecutive quarter of production growth, and about 300 million barrels in our target for the quarter. There are several reasons for this out performance, they’re really across the board of our portfolio, and later in this call John Richels will explain those reasons and give a production outlook for the remaining two quarters. With regard to our second quarter financial results, they were also very strong. As Vince described, the second quarter earnings and the earnings per share came in better than analysts expectations. If you look at the numbers that Vince just gave you, whether you exclude or include discontinued operations, our earnings exceeded the estimates of analysts by 19%, and they were also the second highest quarterly earnings per share in Devon’s history. The cash flow before balance sheet changes was a record $1.8 billion, bringing the year-to-date total to $3.3 billion. Importantly, the 56.2 million equivalent barrels that we’ve produced in the second quarter puts us well on the way to producing at the upper end of our full year 2007 forecasts of 219-220 million BOE from continuing operations. That would be more than a 10% growth for 2007 over 2006. We’re very pleased about our performance at this halfway point in the year, and remain confident in the continued success for our long-term growth strategy that combines our predictable near term developmental projects with the higher impact longer-term…

Thanks Larry and good morning to everyone. We had an active second quarter drilling 434 wells company-wide. 14 of these wells were classified as exploration of which 79% were successful. The remaining 420 were development wells and about 99% of those were successful. We had 141 rigs drilling in June of which 88 were drilling Devon operated wells. Capital expenditures for explorations and development on our routine properties, and this excludes operations in Africa, were $1.2 billion in the quarter. This brought total exploration and development capital for the first six months to $2.5 billion. Now let’s move to the quarterly operational highlights beginning with the Barnett Shale field in North Texas where we continue to enjoy excellent success in production growth ahead of our plans. We are currently running 30 Devon operated rigs of which 13 are in the core area and 17 are drilling outside the core, including 11 in Johnson County. During the second quarter we completed a total of 147 Barnett wells of which 56 were in the core area and 91 outside the core. At the current pace we would drill about 500 wells in the Barnett Shale this year compared with our previous forecast of 385 wells. With this additional activity, we expect company-wide exploration and development capital to come in at the upper end of our forecast range of $4.9 billion - $5.3 billion. From an execution perspective, the new more automated rigs are enabling us to buck the trend and reduce drilling costs in the Barnett. Average drilling costs have decreased in 2007 versus 2006. This is largely due to a 10% decline in average drilling days per well down from 18.3 days in 2006 to 16.5 days in 2007. This is saving us about $190,000 per well in drilling costs and…

Thanks Steve, and Good Morning. This morning I want to take you through a brief preview of the key drivers that impacted our second quarter financial results. In addition, I will review with you how these factors are likely to affect our outlook for the remainder of the year. Events mentioned, we're issuing an 8k today, will provide further details of our updated 2007 forecast. As a reminder, we have reclassified the assets, liabilities and results of operations in Africa as discontinued operations for all accounting periods presented. As a result, I'll focus my comments on our continuing operations, which exclude the results attributable to Africa. Let's begin with production. In the second quarter we produced 56.2 million equivalent barrels for approximately 618,000 barrels per day. These results exceeded our guidance by over three million barrels or about 6%. Approximately half of three million barrel out-performance is attributed to better than expected performance from our core North American properties. The other half of the out-performance is attributable to favorable royalty adjustments in Canada, the timing of oil sales from the ACG field in Azerbaijan, and the rescheduling of expected downtime at our Panyu project in China. When you compare second quarter results of the same quarter a year ago, you’ll find that company-wide production increased by 84,000 barrels per day or roughly 16%. This strong year-over-year growth was driven primarily by our U.S. onshore and international segments. Production by the U.S. onshore grew by over 40,000 barrels per day, or 15%. When compared to the second quarter of last year, once again the leading contributor to our U.S. onshore performance was grossed in the Barnett Shell production. In addition we also experienced significant growth from our international sector, up nearly 45,000 barrels per day over the same quarter last year.…

Thanks John and operator we are ready for the first question.

We will now begin the question and answer session. (Operator Instructions) Our first question comes from Tom Gardner, Simmons & Company. Tom Gardner - Simmons & Company : Good Morning guys, could you comment on the potential for an additional offset wells to the two wells you have at Merganser and any additional comments you care to make on opportunities for additional gas development around the independent’s hub?

Yeah Tom this is Steve. Right now we don’t have any near term plans for future development around Merganser, which is essentially two wells 50% working interest and that will come out about 50 million cubic feet a day. We continue to work a prospect inventory in the eastern Gulf and as they come up and rank competitively where we can move them forward to drill we will do that, but right now we don’t have any specific plans to drill additional prospects in that area. Tom Gardner - Simmons & Company : Thanks for that. And regarding Palvo, how rapidly do you see production ramping up to your 26,000 barrels a day net and can you give us an idea of the crude quality and likely price realizations from that oil?

Yeah, this is Steve again. Relative to the Palvo development we started our production already. We’ve got two wells drilled. We’ll drill a total of ten and that includes a couple of injection wells. I anticipate that we would be ramped up to that 26,000 barrels a day net probably sometime around the middle of 2008. Tom Gardner - Simmons & Company : Thanks guys.

Our next question comes from Ben Dell, Bernstein and Co. Ben Dell - Bernstein and Co.: Hi Guys. I have one macro question and one specific one. Firstly the specific one on Cascade: You talked about, if I heard you right, sanction to end at 2007, previously you talked about production in 2009. Would that still be the case?

Yeah, our current target is still around the end of 2009 for first production, sanction decision would probably happen sometime this year. Ben Dell - Bernstein and Co.: Ok, and I know it’s a long way off on Jack, but Chevron has sort of made comment that they didn’t expect Jack to start off for (inaudible-Gorgon?) which puts it in the sort of 2014 plus range, is that sort of where you are looking, or the early part of next decade?

Well we’re working together with the partnership and I think our plans for the MMS say somewhere in that range of 2014, but it’s still very early as it relates to putting together the final production configuration and what the commercial sanctioning project or commercially sanctioned project would be going forward. So to speculate any more than that on timing would be a little bit premature from our perspective. Ben Dell - Bernstein and Co.: Ok, and lastly on the Macro side, you along with a number of other gas buyers have recorded pretty good volume growth, both year on year, a lot of it coming from the on shore which still appears to be out 5% despite the rate count flattening up. Do you think this is a trend you expect to see continuing on the Macro? And if so do you believe that its’ got any implications of future gas prices?

Well a couple observations Ben, we are going to see a lot of incremental gas demand coming out of the Canadian oil sans over the next couple of years. Certainly production growth does have implications on shore as well as bringing on the independent’s hub will be a significant increase and Golf production, but we remain long-term pretty bullish on the North American natural gas market.

Yeah Ben, I might add while DVN and a few other independents are achieving production growth, the majors have not chosen to put a lot of their capitol into U.S. onshore gas production and their production has generally been declining for many years. That could of course change, but while some independents have been achieving growth and DVN is pleased to be at the top of that list or at the top, don’t know exactly but compared to all that certainly a contender for that. Overall there's a lot of production in the decline and the U.S. and Canada, with imports from Canada declining, so there are a lot of moving pieces there. Ben Dell - Bernstein and Co.: Ok, great. Thank you for your time.

Our next question comes from John Herrlin, Merrill Lynch. Mr. Herrlin, your line is open. (Operator Instructions) John Herrlin – Merrill Lynch: Oh, Sorry about that. Good quarter. I don't normally say that.

Well, we appreciate it, John. John Herrlin – Merrill Lynch : Sure. Regarding your free cash, why not roll the commercial paper and shrink the denominator? You know, buying stock.

At the moment, since we have a registration statement on file, for our MLP, the company and all the officers are precluded from doing anything in the marketplace, so from a legal standpoint that is not an option to us at the time. Once that registration statement is filed, in approximately a month or so, then the use of free cash is something we can consider. John Herrlin – Merrill Lynch : Ok, that's fine. Would Steve – [would Chuck even mention] kind of a target size, or I missed it?

I didn't mention it, but I will tell you, we generally say the slower tertiary prospects are in the 3-500 million barrel range or bigger and this is in that range. John Herrlin – Merrill Lynch : Ok, Last one for me is on [Fratt] costs and the [front ad] you had good efficiencies with fit for purpose equipment. Are you seeing any drop in your [Fratt] costs at all?

No, we've seen some deceleration of the cost escalations if that makes sense, and we're just going through, we're getting into the period of time now to where we'll start looking at our contracts for 2008 and looking at pricing there, so we're just getting into that window where we're going to get a good look at the go-forward pricing here, but we have seen some flattening in the escalation rates. John Herrlin – Merrill Lynch : Do you plan to lock in any equipment longer term, like rigs?

We, as a matter of fact, we have kind of a blended portfolio, when you look at those 30 rigs, we have some of those rigs under a long term contract, some on much shorter terms, and we kind of just manage our risk that way, so some of those rigs are longer term contracts, some aren't. Some are shorter term. John Herrlin – Merrill Lynch : Ok, thank you.

Our next question comes from Mark Gilman, the Benchmark Company. Mark Gilman – The Benchmark Company: Hi Guys. Good morning. I have a couple of things. Steve, I wonder if you could just put a little more color on the scale back at [gross Beckett]. Is that a low cost issue that you're responding to?

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

Oh, they can range from about 6.5 million, to as much as $11 million depending on where we're drilling, how deep it is, and how far we try and reach out with that horizontal section. Mark Gilman – The Benchmark Company : That's drill completed?

Yes. Mark Gilman – The Benchmark Company : Ok. In the Lloyd Minister area. I wonder if you could talk a little bit about whether or not the production increases are associated with new areas, whether it's in-fill, and whether you’ve got a number of locations identified?

You know, it's a combination of those things. We continue to grow the Lloyd area, and the Lloyd Minister area. We did acquire the Iron River properties back in, I believe it was back in 2004, or 2005, and that had a lot of running room on it. That's adjacent to our Mannetoken field that we've had and developed for quite some time, and it was relatively undeveloped, so we're getting pretty good kick from the Iron River side, as well as other drilling in the Lloyd Minister area. Mark Gilman – The Benchmark Company : Ok. And just one final one from me. I assume that with the incorporation of Cortazian to the [casketing] unit that your interest in the unit, given that the percent in Cortez will still be 20%.

Okay. Mark Gilman – The Benchmark Company : Thanks a lot.

You’re welcome.

Our next question comes from (ph.) Raheen Fabji, UBS. Raheen Fabji – UBS: Good morning. This is a question on the convertible bond or exchangeable bond that you guys have upstanding on the balance sheet, convertible at Chevron stock, I guess. I’ve been told that some of the holders might be converting it before the Chevron dividend in August or later this month. Just wondering, what are the tax implications for that on your bottom line?

It must be a good question—we’re all looking at each other. It’s certainly their option to exchange at any time. As far as the tax implications—

One thing you have to recall is that we have the option of paying back either in stock or in equivalent amount of cash. And if we pay an equivalent amount of cash for anything redeemed, there’s no tax consequence. It only becomes a tax consequence for us at the time that we liquidate the underlying stock. Raheen Fabji – UBS: Right.

--because of the cost basis in that. We have a lot of flexibility there and particularly with our pre-cash position, today, we have a lot of flexibility determining how we might do that. Raheen Fabji – UBS: Okay. Has there been any thought or discussion on restructuring the convertible, or exchanging it to defer the tax implications?

There are a lot different opportunities available, and we have a lot of flexibility in terms of what we might do with is, something that we’ve looked at continually over the past few years, and we will continue to as we get closer to the maturity date which I think is August 2008. We’re continuing to look at that. Raheen Fabji – UBS: Okay. Thank you.

Our next question comes from Ray Deacon, BMO Capital. Ray Deacon – BMO Capital: Hey, John, I guess I had a question on jackfish and what the thought process is as far as second phase there, and maybe if you can speak to what the cost increases have been since you took on this first project, and/or if there’s any technologies that could help you mitigate some of those cost increases. And then maybe a quick comment on the foreign end—it sounded as though you were saying your well cost looks to be flat over year over year, so I guess is the implication that besides the drilling costs, completion costs have been trending up. Is that a fair way to look at it?

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

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

And what allows us to do too, Ray, is—you had asked if there were going to be different technology—we’re really looking at this as a look-alike to Jackfish One, taking advantage of the knowledge that we got from that rolling over some of the crude’s and the time period allows to do a lot of engineering, so we thought to go into it with a great deal of certainty. Let me turn that over to Steve now on your Barnett Shale question.

In regards to the Barnett, I think you had it spot on. Essentially, we saw that $190 thousand per well improvement on the drilling sides as for drilling only. When you look at the other costs for a total completed well, that improvement essentially offset those cost escalations year-over-year, so you end up with a flat well cost ’06-’07. Ray Deacon – BMO Capital: Got it thanks. John Richels : Which is a great result for such a major part of our capital expenditures. Ray Deacon – BMO Capital: Thanks very much.

Our next question is coming from Rehan Rashid of Friedman, Billings, Ramsey. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: Morning. Sticking with Barnett for a second, how should we think about future reserve growth? I know you guys talked about 3 TCF approved, 13 and change, [3P] potential, what could be some of the technology drivers or results, and just some sort of a timeline if you could, please?

Rehan, you mentioned the 13.5 TCF total resource potential that we’ve out before, and that’s on a risk basis. We’re very comfortable around that number right now as far as the total resource potential. Obviously, stepping up from 385 wells this year to 500 wells is going to have a positive impact on both our recovery and, ultimately, on our reserves. And we think we will continue to realize good, strong reserve additions from the Barnett for the foreseeable future, as we go through. So it’s just a continuous process of driving towards getting that ultimate recovery to 13.5 TCF or better. Some of things we’re doing are continuing to down space. We talked about the 20-acre in-fill program that we’ve done both in the core area and expanded a bit to the non-core. We have another 400 locations or so, plus or minus, that we’ve identified as far as 20-acre in-fill opportunities. There could be more, but right now we’re looking at about something in the range of 400. We also have opportunities with our refract programs. We do refracts when the well performance dictates that it’s time to do that. We’ve only done maybe about 40 or so this year, but we’re continuing to get very good results that give us additional recoveries as high as 0.7 BCF per frac, and so that’s another tool, or technology, that we’re using to continue to claw away at that total resource potential. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: What recovery factor did you assume when you talked about the 13.5 TCF risk potential there?

If you look at the 13.5 TCF, and you look at it, it’s a risk number. And if you look at the acreage under Devon’s control, and you look at our estimate of gas-in-place in that acreage under Devon control, it’s about 11-13% of the gas-in-place. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: Okay, and then do we need, once again, maybe [simul] fracs or trifacs to work for us to progress down this recovery factor path, or simply down spacing and marginal stuff like that would work?

We think the majority of it’s going to be with existing technology and continued improvements in our exploitation work as we move out into the non-core, and then look at the down spacing areas. There could be some additional potential with even smaller down spacing, or other technologies, but that’s not fully baked in or reflected in the 13.5 TCF. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: Okay, perfect. One more question, but on the deep water site, so it’s Cortez and it’s Chuck, what else from the deep water sub-salt for this year in terms of exploration?

I think we mentioned the Green Bay prospect that we just picked up 23% interest in. That should spud some time probably in the first quarter of this year. So that will probably be the last sub-salt exploration well that we’ll be drilling this year. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: Got it. And how will that program look like next year?

We haven’t finalized that program yet. As I mentioned before, we have appraisal work going on. The exploration work, we’re still working on finalizing that. We’re just going in. As we come out of August and go into September we’ll go through our budgeting process and really firm up those plans going forward. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: I guess a better way to phrase it would be, will it be dependant upon results from Chuck or Cortez, or not?

No, I don’t think on the exploration side it’ll be materially affected by those two. Generally, what you’ll see us do is we’ll probably drill a couple of deepwater exploratory wells in the lower tertiary each year, on average, going forward. And we may pick up a few deepwater Miocene opportunities to compliment that as we go forward. But generally, you’ll see us in the one to three range as it relates to our opportunities on average over about a four-five year period. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: One last question, on the deepwater side we’ve seen quite a bit of activity in the Walker Ridge side. Any particular thoughts why so much on the Walker Ridge and not maybe as much, although you’ve seen some good success, in the Keathley canyon or some other place?

I’m sorry, could you repeat that Rehan? I didn’t hear it all. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: So the bulk of the activity on the sub salt side seems like an industry that’s focused on Walker Ridge. Any technological, geological explanation for that versus not being focused somewhere else within the deeper waters?

We just continue to work the portfolio and identify the best opportunities for us to drill going forward and we stay pretty tight lipped about everything else. Rehan Rashid – Friedman, Billings, Ramsey, & Co.: Ok thank you.

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

Good morning. I have a question on the Woodford, the net acreage for the 1 TCF potential.

The net acreage is about 70,000 acres David Heikkinen - Pickering Energy Partners: Ok, and have you the Woodford and the Ardmore Basin at all?

We’re currently looking at a couple of different areas and we haven’t announced any tests in the Ardmore Basin. David Heikkinen - Pickering Energy Partners: Ok, and then thinking about the corporate target of 350-370 million barrels of oil at (inaudible) and reserve as this year (inaudible) goal and then adding 115 wells to the Barnett seems like you could have some upside to that target. Is that a reasonable thought process?

You know there are always pluses and minuses, that’s why we give a range and we aren’t updating our reserve target range for this year. If there were some risk barrels in that range for lower turf sharing which we now think we will not book this year and so I just don’t think we’re prepared to move the range. David Heikkinen - Pickering Energy Partners: Ok, that’s cool, so still on target though for the original range, no concerns..

Absolutely, we’re comfortable in that range. David Heikkinen - Pickering Energy Partners: I’m not trying to get too much into the weeds but now you’re drilling some offset wells to Questar in the Vermillion Basin. Any idea of how we should think about that from a Devon standpoint of how meaningful that could be?

It’s just too early to tell at this point. David Heikkinen - Pickering Energy Partners: That’s perfect, thanks a lot guys

Ok, we’re at the top of the hour so Larry do you have any closing remarks for the call?

Well yeah I hate to summarize because I’d just like to repeat every sentence we’ve gone over but clearly we had a very strong financial result for this quarter and it was driven by production growth really throughout the Company which is exciting not only of itself but we’re clearly solid in position to reach the upper end as we said of our full year production target of 221 million BOE, through our organic growth at the same time that we’re keeping expenses under control across the board. Outstanding performance at Barnett Shale with 36% over last year as well as all our other projects that will be supplemented in the second half of the year with (ph.) Morganza and Palvo, those longer term projects start to come on-stream. Continue to advance our projects in the high impact portfolio in the oil turf sharing. All in all very pleased with the first half results and look forward to a great second half. For those that we didn’t have time to answer questions we’ll be here this afternoon so thank you and I’ll look forward to talking to you again in November. Take Care.