Welcome to Devon Energy’s third quarter 2008 earnings conference call. At this time all participants are in a listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. This call is being recorded. At this time I would like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you and good morning everyone. Welcome to Devon’s third quarter 2008 conference call and webcast. Today’s call will follow our usual format after my introductory remarks Devon’s Chairman and CEO, Larry Nichols will provide his prospective on the company; then Steve Hadden, our Executive Vice President of Exploration and Production, will cover the operating highlights and ramping it up will be Devon’s President, John Richels, who will give us a brief financial review. At that point we will open up the call to your questions and we will remind you that we ask you the limit each calling to one question and one follow-up. We will try to hold the call to about an hour and as a reminder, a replay of the call will be available later today through a link on our website. During the call today, we will be taking some of our fourth quarter estimates and I want to remind you that, you can find the summary of our estimates on our website. You simply go to the Investor Relations section and click on the Estimates page. As far as guidance for 2009 goes, we typically give top-line production guidance and capital expenditure guidance for the upcoming year end December and then we follow that up with detailed guidance for production expenses and CapEx in an 8-K filing about the time we report earnings for the previous year. Please note that all of our references today for plans, forecasts, expectations and estimates are forward-looking statements under U.S. Securities law, and while we always strive to give the very best guidance possible, there are many factors that could cause our actual results to differ from our estimates and we would encourage you to review the discussion of risk factors that can be found in the Form…

Thanks, Vince and good morning everyone. What a difference a quarter can make this has been amazing. But in spite of the extraordinary conditions in the capital markets and challenges present of our two hurricanes in the Gulf of Mexico. And the disruptions to production in the ACG field in Azerbaijan, Devon had a really very good third quarter. Reported net earnings reached a record $2.6 billion and excluding the mark-to-market hedging gains, net earnings were a very solid $1.4 billion. Cash flow before balance sheet changes, climb to $2.6 billion which is a 49% increase over the third quarter of 2007. Our net Barnett Shale production set, we had another record, averaging more than 1.1 Bcf of gas equivalent per day in the third quarter. We completed the sale our of interest in Cote d’Ivoire in the third quarter, which brings our aggregate after-tax proceeds from all of our African divestures to more than $2 billion. And during the third quarter, we continued to de-leverage our balance sheet, by using cash redeem $983 million of exchange or the Chevron exchangeable debentures, which in turn freed up 14.2 million shares of Chevron stock. In the wake of the recent credit market deteriorations, I want to take a few minutes with you and comment on Devon’s financial position and on September 30, Devon had $1.2 billion of cash on hand and very low debt levels. In fact our net debt-to-cap was 13% at the end of the third quarter. In addition, we have more than $3 billion of unused credit lines and only $177 million of debt maturities that mature between now and the second half of 2011. This financial strength has allowed us to maintain access to the commercial paper markets throughout this entire recent credit crisis. Another way we’re…

Thanks, Larry and good morning to everyone. I will begin with a quick recap of the company-wide drilling activity. In the third quarter, we drilled 636 wells, of these 22 are classified as exploratory with 91% successful, remaining 614 wells reclassified as development of which 98% were successful giving us an overall success rate for the quarter or roughly 97%. Our total rig count average to 158 rigs during the third quarter, with our operated rig count peaking in September at a 106 rigs running. Capital expenditures for exploration and development were $2.1 billion for the quarter, bringing the year-to-date ENP CapEx to $5.5 billion. Let us now move to our quarterly operational highlights beginning with the Barnett Shale field in North Texas, where we currently have 38 Devon operated rigs running. We continued to see excellent results from our horizontal in filed drilling programs. During third quarter, we bought 67 wells online were drilled on 40 surface acre spacing or approximately 500 feet apart, those 67 wells have an average IP rate of 2.2 million cubic feet of gas per day. In addition, we’re now seeing the early results from our pilot infill program. These wells are spaced 250 feet apart, which results in one well per 20 surface acres. During the quarter we bought two of these wells online with an average IP rate of 3.7 million cubic feet a day. These were two exceptional wells and I would caution that we don’t think this will be typical. Now, these two wells do however, demonstrates 250 foot offsets have significant potential in some areas. In total during the third quarter we bought a 142 Barnett wells online at an average rate of $2.3 million cubic feet of gas per day. Our net Barnett Shale production set yet another…

Thank you, Steve and good morning. I planned to take you through a quick analysis of the key drivers that shaped our third quarter financial results and review how these factors impact our outlook for the fourth quarter. As a reminder we reclassified the assets liabilities and results of operations in Africa at discontinued operations for all accounting periods presented. I will focus my comments as a result on our continuing operations excluding the impact of the African operations. Well. Let’s begin with production. Devon’s third quarter production totaled $58.6 million equivalent barrels or 637,000 barrels per day that’s pretty much inline with our revised forecast of 59 million barrels. Production for the quarter would have been well above our revised forecast had it not been for disruptions from the storms in the Gulf of Mexico in the operational downtime at the ACG field in Azerbaijan that Steve mentioned, which in aggregate reduced third quarter production by about 2 million barrels. Overall, Devon’s company wide production increased by 19,000 equivalent barrels per day or 3% when compared to the third quarter of 2007. Production growth from our core North American onshore assets more than offset the 2 million barrels lost in the Gulf and ACG. In the U.S. onshore segment delivered that strong growth despite production curtailments resulting from Hurricanes Ike, led by growth from our Barnett Shale and east Texas fields, U.S. onshore production grew by 54,000 barrels per day or 16% over the third quarter of 2007. Our Canadian business also contributed production growth it was up about 4% over the year ago quarter. The continued ramp up of oil production from our Jackfish SAGD and Lloydminster projects drove this growth. Looking ahead to the fourth quarter Devon remains on track to deliver meaningful production growth depending upon…

Operator, we are ready for the first question.

(Operator instructions) your first question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed with your question. David Heikkinen – Tudor Pickering Holt: Good morning just a question on your leasing both in the Haynesville and Horn River Basin. Can you talk about the royalty that you are paying or using?

Yes, this is Steve. I will talk to you about in the Haynesville, with the 100,000 acres the royalty runs about a quarter on averages for the 100,000 that we are adding. David Heikkinen – Tudor Pickering Holt: Okay.

.: David Heikkinen – Tudor Pickering Holt: Okay, and then Horn River?

Horn River has a sliding scale based on the Canadian royalty which is based on both the price and the well.

Yes, David that was all crown acreage. David Heikkinen – Tudor Pickering Holt: Okay.

So, there is nothing not a negotiated royalty on that. David Heikkinen – Tudor Pickering Holt: Perfect, and then looking at your financial position and that it was $1.4 billion of acquisitions in the quarter, is that was a great number just wanted to clarify that in fourth quarter?

I think that was $1.4 billion included some of the acquisitions in the third quarter and the acquisitions that we plan to close in the fourth quarter David Heikkinen – Tudor Pickering Holt: Okay, so that included.

That includes both. David Heikkinen – Tudor Pickering Holt: That’s the total second half of the year.

400 in the third quarter and the balance we think.

And what we really talking about David is what we had done over and above our mid year capital forecast that we gave out in the last quarter. David Heikkinen – Tudor Pickering Holt: Okay, helpful. And then looking at kind of operation results at each one of the areas, I mean delivering pretty high rate wells. When you think about a horizontal well in the Haynesville Lime, how much better results would you expect from that?

That’s a great question David. Right now we are drilling vertical wells in, we would expect to see improvement with the horizontal wells, but we just haven’t drilled one yet and don’t have any benchmark to set on the Lime. So, we’re really taking a wait and see. We are very up of course with those results when you see those kinds of wells with only $5.5 million of capital. They are extremely economic, they hold up relatively well and so we are very excited about the vertical wells that we are drilling. We will drill that first horizontal well in January and just see what we get. They are – the old ratio of three to five, we’re not sure if that three to five times the rate, we’re not sure if that will hold in the Lime. David Heikkinen – Tudor Pickering Holt: Okay and then on the marketing and midstream just the detail on fourth quarter guidance. What do you building in for kind of an average NGL percent of NYMEX oils at around the 40% to 45% we are seeing now or?

Yes, it’s running around 48% right now and I think that’s the numbers that were running through model for the fourth quarter David Heikkinen – Tudor Pickering Holt: And then as you look forward to next year, do you think you normalize back to the 50% to 55%?

Well, our best guess at this time is that we’ll probably go back to the 50% to 60%. David Heikkinen – Tudor Pickering Holt: Okay.

But obviously with all of the turmoil we’re seeing in the credit markets and how that’s affecting not only our industry, but a downstream consumer that’s certainly subject to some fluctuation. David Heikkinen – Tudor Pickering Holt: Thanks guys.

Your next question comes from line of Brian Singer with Goldman Sachs. Please proceed with your question. Brian Singer – Goldman Sachs: Thank you, good morning.

Good morning. Brian Singer – Goldman Sachs: Going back to the Haynesville Lime wells. How are you thinking about that whole opportunities and ultimately if you think about commingling – first of all is that even possible or worthwhile? And how do you think about the total potential from the couple wells that you drill there?

Brian, let me see if I can break this down. We’re focused in both obviously there is multiple pace there in that area. You get everything from the Travis Peak down through the Pettit, the Cotton Valley, the Haynesville Shale and then the Haynesville Lime, which is just below the Shale. Right now, we’re focused on not comingling those and working on getting a good read on the long-term performance of the Lime and testing Lime across our acreage position and then in few other places. So, we don’t have plans right now to do commingled completions in the Lime and the Haynesville Shale. We are continuing with our Haynesville work. We have probably a half a dozen vertical wells that are down in the Haynesville and producing – in Haynesville Shale and producing and then these two horizontal wells will be done here very quickly. We will frac the first one just next week and get those results and then the second one drilling Shelby County. We’ll have those results sometime in the fourth quarter and then continue with that horizontal program so, we are not taking it up in terms of coming up program at this point. Brian Singer – Goldman Sachs: Okay and from a big picture perspective, how you are looking at the production growth in 2009 overall in the context of trying to spend within your cash flow and how should we think about the aggressiveness of further leasing next year relative to you what we have seen this quarter in the last couple…

Brian, this is Vince. I will take a shot at that. I think that the key thing that you have said is that, we planned a little within our cash flow and we are running a variety of scenarios right now for capital spend for 2009 under various commodity price environments and that is still a pretty big wildcard. We have provided some guidance over six or nine months ago, we showed you some expected growth curves under a couple of different practicing scenarios that kind of shows the variability with commodity prices, when you live within cash flow. As far as the aggressiveness of leasing in 2009, I think we are a very opportunity rates at this point, we have made some big strives as especially, if we can close these deals that they are looking for the closing in the fourth quarter and I think that is not a pace that we would expect to repeat every year. So, we will be focused more on developing what we have in 2009 than making large acreage captures like we did in the second half of this year.

And Brain, if I can maybe just add a couple of points that Larry who was talking about as John speaking on that Larry mentioned earlier, I think they are really important. What we have done here, first of all and we have had some terrific opportunities to pick-up very, very attractive acreage recently and as Vince said, we tended to be opportunity driven and what we really did is as Larry said, in essence swapped the African properties for these very, very good properties in North America, where we have a physical and regulatory stability that we have, but it is really important for us to maintain the strong balance sheet and the liquidity, particularly in these times of uncertainty having that financial strength is a real key for us and we are not going to roll that. Brian Singer – Goldman Sachs: Great. Thank you.

Your next question comes from line of Tom Gardner with Simmons & Company. Please proceed with your question. Tom Gardner – Simmons & Company: Thank you. Good morning, gentlemen. A question concerning the Haynesville Lime just your thoughts on what’s controlling the productivity and just how broaden opportunity is it in side stock and field in outside?

Tom, this is Steve. It is relatively early in the place. This is the first preface that I want give to these comments and we have drilled these wells and gotten very good results early on. Right now in the area we have 24000 acres, net acres just in the area where we have been drilling these wells, and we are in the process of defining those limits, but, we – the limits of the field where we can get that kind of repeatable performance. But that being said we think there is significant running room there. There is questions like at those rates what’s the appropriate spacing, what are the limits within that area of the Lime that that perspective area of the Lime and then of course we are expanding our thinking to other areas looking to where the Lime maybe productive. So it’s relatively early and we are not at a point to where we will talk about, what we think is driving the performance of the wells at this point, because we think that’s a bit of competitive issue right now. Tom Gardner – Simmons & Company: Yes, I understand. Jumping over the gross pack in light of your continued success there, are you anticipating revising your $90 million barrel resource potential upward at any point?

We’ll look at that again here coming at the end of this year and then very early next year and we will revise our resource potential there. We think to look at it generally on an annual basis unless we have a very significant event and I don’t see it’s making us a near term revision based on the results of those three wells at this point, but we will take another look at it in January and then make another assessment. Tom Gardner – Simmons & Company: Great and just one question on your acreage acquisition there in the Haynesville, where was that the 50,000 acres?

It was really all over in between east Texas and some in Louisiana. Tom Gardner – Simmons & Company: And similar question for Horn River, do you see that incremental acreage is being just as perspective issue original holding?

Yes, absolutely, we think it’s good or better than the original acres that we have assemble there so. That the last 46,000 acres we added with that sale, fit right in, and compete very well on as far as reservoir quality in the shale there. So, we are real excited about that position. We are about 153000 acres, which is one of the top holders in the play. Tom Gardner – Simmons & Company: Thanks guys.

Your next question comes from the line of Mark Gilman with Benchmark. Please proceed with your question. Mark Gilman – Benchmark: Hi, guys good morning. I guess a couple of things. First, Steve can you comment on the upside potential you see on the Drunkard's Wash acquisition?

We think there is upside. We aren’t prepared at this point to really talk about the upside, it’s a great position for us. Number one, because we think it has significant potential in Farren, which is primary coal seam that’s being produced right now and we have a lot of experience in that area. We are looking forward, we just got property; we are looking forward to work, which is Conoco. They have about 25% and then XTO’s was about 31 and we are sitting here with 44%. So, we are just now really digging into that. We do think there is upside potential, but we are not at the point where we talk about it in some detail yet. Mark Gilman – Benchmark: Okay. Steve, secondly what you trade for that additional interest in the St. Mallow unit

Essentially what it was, we had a very small position in a discovery call Julia, which was I think its just, if I think about in mind it just to the east maybe a little bit to the north and east of St. Mallow – and we traded a small interest in Julia for that 2.5% in St. Mallow. Mark Gilman – Benchmark: Okay and finally, this relates to certain extent to one of the questions that have been raised up to this point. It almost appears, if the lion’s share of the incremental acreage, maybe even the entire acreage package in the Haynesville, is located considerably west of where one might on a very preliminary basis be thinking in terms of a suite spot of the play. Is that an accurate observation in terms of how the acreage position as it stands currently plays out or would you choose to characterize it differently?

Mark, I don’t think that it was as Steve said, it wasn’t 50,000 acres in one area and the next 50,000 acres is in one area, what we did as we continue to increase our interest in fill in and around the areas that we think of most perspective in the area and Steve then his folks have done a lot of work on doing some very detailed isopack mapping of the thickest parts of the Shale and where we think the most commercial in best parts to that play are going to be located and so, its really scattered around there, but adjacent to area where we all ready have interest, so that we can take advantage of scale and when we really start our drilling operations.

Clearly the East Taxes part of the play is going to be a very, very attractive area, but it still way too early in the development of this field to say where are the suite spot or the suite spots there maybe several in this filed are located.

Okay guys thanks very much.

(Operator instructions)

It appears that a couple of the questions in the queue were ended inadvertently dropped. So, if you got a question please renter.

(Operator instructions) your next question comes from the line of Rehan Rashid with FBR Capital Markets. Please proceed with your question. Rehan Rashid – FBR Capital Markets: Good morning. On the deepwater side U.S. Gulf of Mexico is there any thoughts on what the program could look like for ’09?

Well, yes this is Steve. We will continue with the appraisal work that we talked about on St. Malo and Jack. We will be drilling a well; actually we will spud the well at Cascade probably in, well definitely in this fourth quarter and then be drilling in through the first quarter of next year on the Cascade well. We also potentially could have another operated exploratory well from the exploration standpoint and we will drill, we will finish drilling the first operated well, the first producing well at Cascade in the first half of the year and then drill the second well during 2009 for Cascade heading towards that first production in 2010. So, principally you are going to see us doing appraisal work and the development work at Cascade and then we may have a exploration well or through in the deepwater but we are just going through our 2009 budget now. Rehan Rashid – FBR Capital Markets: Got it, Steve just taking with the deepwater here have all the drilling that you guys have done let’s just say over the last year or two anything that has changed or what have you added to your knowledge base with regards to how the evolution would look like in the sub-salt you ask versus maybe kind of look what it seems like the more faster evolution on the Brazilian side?

Well in the Gulf of Mexico, we are continuing to add to our knowledge base, we have got a couple of very good discoveries on the go and what we are learning and working through issues around completions and production facility configuration and optimizing those things is very important that we get from Jack and St. Malo, but we are able to also go through that information and combine that information with what we are getting out of the Cascade operation from a completions standpoint and completions design standpoint also from a facility standpoint where we are going to have the first FPSO in the Gulf of Mexico and so we are getting a lot of information and moving up the learning curve quite quickly in the Gulf of Mexico and we will bring that to bare along with our partners experience when we look places like Cascade and potentially if we have a discovered at Bass, we will apply there. In Brazil, it is still a bit early, but obviously we have a bit of experience in Brazil with FPSOs in net operation, because we bought the FPSO in for Polvo and we have got a good relationship with Petra brass and our partners with them on many of those blocks. We also obviously can bring that, bear that experience that we have in the Gulf of Mexico working together with either Petra brass or other partners that we have in the Gulf – in Brazil and apply those learning. So, I think we feel very good where we are positioned there from our learning’s and development standpoint and we are very encouraged by the Oahu discovery and by our inventory of billable opportunities we have both in the pre-salts and in some other targets. Rehan Rashid – FBR Capital Markets: Okay, thanks. On going to Haynesville Lime quickly, anything that you can share in terms of well designed on both of the vertical one that you just drilled and how are you thinking about the horizontal frac numbers, length of well bore whatever that can share?

Well, not much at this point, where – and basically the IPs and the performance of the wells and so we still view this really competitive in evolving opportunity that is really a great opportunity of those kind of rates and that kind of economic leverage that we get in wells that are over 20 million a day for $5.5 million. Rehan Rashid – FBR Capital Markets: Okay and on the realize on gas prices for onshore U.S. and 70% of NYMEX and any process to what will need to happen and where the boardwalk coming online next year, how will that help and when should be – what can we expect this differentials improve a little bit?

Yes, this is Darryl. You are here right on and of course, we have just went through two months of exceptionally warm weather being September and October and now going into November and you couple that with the increased capacity – or the increased supply we are seeing out of the Barnett Shale or the Fayetteville shale, out of east Texas, all of that gas is really trying to go to a constrained pipeline system going east and that has really affected differentials in those different areas and currently those differentials you probably have seen are in the 275 range. Boardwalk is due to come on in the first quarter right now our best estimate is probably going to be February 1 and mid-February Devon has substantial front transportation in that pipeline, we would expect that once that pipeline becomes operational that you will see those differentials which are now quite wide. We will begin to narrow and our hope is that they will go back to where they were maybe six, eight months ago. So, we do think there is hope on horizon obviously with the downturn in commodity prices in the financial situation we are in, we don’t know what the impact is going to be on drilling for this industry, but as you probably know for new wells we’ve drilled as an industry over the last two or three years. We have seen about a 60% decline in the first year with base that declining about 30%. So it’s not going to take very long if we do have a downturn and active rigs drilling to see that impact on U.S. supply.

Rehan, we’re going to have to move on, we can take one more question. Rehan Rashid – FBR Capital Markets: Okay. That’s it from me. Thanks.

Your next question comes from the line of John Rogovin [ph] with Wachovia. Please proceed with your question. John Rogovin – Wachovia: Hi, good morning everybody. I’m sorry if I missed a little bit more this detail, but could you just walk me through the bigger picture driving force behind with Chevron transaction and the assets swap?

The big picture drivers on the Chevron transaction. John Rogovin – Wachovia: Yes, if you look at the implied value on the asset, it just seems a little bit rich from a share assets value perspective. So I wanted to see if there was an underlying driving force that was not necessarily outlined in the press release?

We, it’s important to bear in mind that had we just issued those shares to the exchangeable holders or sold the shares that we would have had a tax bill of approximately $350 million. So that impacted our assessment of the relative values of the transaction, but the value that we put on the Drunkard's Wash assets suite itself. We think it’s a very reasonable value.

Yes, there are two things you need to look at and looking at that. One is our alternative for – is what Vince just said our alternative to deal with that was to sell the shares and realize a very large tax gain up-front. Second is as we have said several times we think that field has significant undeveloped potential that given our expertise in this time reservoir we think we can add. John Rogovin – Wachovia: Okay and then just kind of corners off the Brian’s question earlier maybe asked a little bit of a different way. Do you have an estimate of what you back of the enveloped maintenance CapEx number for 2009 just a whole production flat? I know you haven’t given too much detail on the full year budget, but just trying to get a feel for given the current environment where things shake out?

Of course, one way to approach that is our F&D has been running in $16 to $18 barrel range – barrel equivalent range and you can multiple that times our production number and you see where we are in terms of maintenance capital versus growth capital. John Rogovin – Wachovia: Okay, I just want to make sure they tie with my numbers. Okay, thank you. I guess the last thing moving up to the Horn River. There has been some pretty solid results coming from some your competitors. Can you just give me an idea of where your acreage position is in relation to some of the larger caps that have had announcements out there? And then secondly is there any what do you see as a largest hurdles and/or constraints out there if you look at the development project maybe three or five years down the road?

Yes, John this is Steve. If you look at our acreage position in Horn River we are adjacent to the major property holders that you will see. The first partial that we captured up there was a little bit to the eastern side. This latest partial is just a little bit on the western flank, but still adjacent to the some of the other major property holders up there and then the other part of the acreage is right in between those two. So, we feel like we are in a very good part of the play in very good position relative to the shale. Some of the challenges up there simply exist around, the commercial challenges that end up being around, we are optimizing completions and making sure we get our cost down as it relates to the wells themselves and get that inline relative to the good gas potential that we are seeing from the shale and then once you get above ground of course there are commercial issues of both either processing or transporting the gas moving out and we have worked with people in that area have dealt with those early challenges quite well we think and feel optimistic about the future and development going forward, but those were some of the challenges, that we saw and still see to a degree Horn River area.

Sometimes, we will hear people talking as well about the fact that it’s a winter drilling area and that’s a challenge today, but as we move forward there are more and more roads being all weather roads being put in drilling pads that type of things. So, the while the winter drilling aspect is more of a challenge that will decrease overtime. John Rogovin – Wachovia: Great, thanks a lot guys.

Operator I am showing a couple of minutes after the top of the hour. We still got quite a few questions in the queue. So, out of respect for everybody’s time we are going to cut the call off and remind you that we will be around all day to answer any questions you want to follow up with. Thank you.

Ladies and gentleman, thank for your participation in today’s conference. This concludes the presentation. You may now disconnect, good day.