Good day, ladies and gentlemen, and welcome to the Devon Energy’s fourth quarter and year-end 2009 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’d like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Good morning, everyone, and welcome to our call. I’m going to start with – start the call with a few preliminary comments, and then turn it over to our Chairman and CEO, Larry Nichols. Larry’s going to provide an overview of 2009 and recap our reserves performance for the year. Following Larry’s remarks, our President, John Richels will review 2009 financial results and update our 2010 outlook. And then our Executive Vice President of Exploration and Production, Dave Hager, will cover fourth quarter operating highlights. We’ll conclude the call in about an hour. So if we don’t get to your questions in the Q&A period, please feel free to follow-up with us later in the day. A replay of this call will be available later today through a link on our homepage. That’s www.devonenergy.com. In November of 2009, we filed a Form 8-K with detailed guidance for 2010. During the call today, we’re going to update some of that guidance, and those updates will be posted to our Web site under the Estimates link in the Investor Relations area of the Web site. In addition, the 2009 Form 10-K, we expect to file that on February 26th, and it will reflect this updated guidance. Before we get to the business of the call, we’re obligated to remind you that the discussion of our expectations, plans, forecasts, and estimates are all considered forward-looking statements under US Securities Law. And while we always make every effort to give you the very best data possible, there are many factors that could cause our actual results to differ from our estimates. For a discussion of those risk factors, please refer to our Form 8-K filed in November 16th, 2009. One final compliance item, we will make reference today in the call the various non-GAAP…

Thanks, Vince, and good morning, everyone. This year, 2010, is a transition for Devon. A very much of a transition year as we divest our onshore international assets, and refocused all of our efforts on Devon’s very powerful North American onshore growth engine. Our philosophy of focusing on optimizing returns and refusing to get caught up in that growth at any cause mentality is reflected in the very solid 2009 results that we reported today. We have achieved solid production growth while significantly reducing operating costs and delivering industry-leading finding and development costs. Including the properties we are divesting, we increased company-wide oil and gas production to a record 682,000 Boe per day. Production from our North American onshore properties also grew to a record 603,000 Boe per day, which is up 6.5% over 2008 production. At the same time, we drove unit operating costs from those North American onshore operations from our continued operations down 14% to just $7.16 per equivalent Bo per barrel. We generated $4.7 billion of cash flow from operations, funding most of our $5.1 billion in capital expenditures. With that capital, we drilled more than 1,100 successful wells, driving proved reserves to the highest level in our company’s history and delivering outstanding reserve replacement results. Our marketing and midstream business delivered yet another year of better than forecasted results reaching $512 million in operating profit. And finally, we maintained a very strong financial position, ending the year with a net debt to capitalization ratio of 29%, and unused credit lines and cash on hand totaling $2.8 billion. In today’s news release, we provided a summary reserve report data for continuing operations in accordance with accounting standards. Although the results from those continuing operations are in press today, what I wanted to talk a little bit…

Thank you, Larry, and good morning, everyone. Today, I’ll take you through a brief review of the key events and drivers that shaped our 2009 financial results, and also take you through our outlook for 2010. As Vince mentioned earlier, we have reclassified the assets, liabilities, and results of operations for our international assets into discontinued operations for all accounting periods presented. As a result, I’ll focus most of my comments on our reported continuing operations. And just to reiterate, our reported results from continuing operations include both the North American onshore assets that we are keeping and the Gulf of Mexico assets that we plan to divest. Let’s with start production. Total 2009 company-wide production, including international, came in at $249 million equivalent barrels, or some $11 million Boe greater than our beginning of the year forecast. Looking at continuing operations alone, and again, under accounting rules that includes the production from the Gulf properties that we’re divesting, 2009 production was $233 million oil equivalent barrels or approximately 639,000 Boes per day. That’s 10 million barrels higher than our 2008 production from continuing operations, and more than 1 million barrels above the guidance we’ve provided in our most recent update. When you examine just the North American onshore assets as the assets that we will be retaining in the repositioned company, you’ll see that 2009 production increased 36,600 equivalent barrels per day or about 6.5% over the full year 2008. This growth was achieved in spite the voluntarily reducing production in the second half of the year. The primary drivers of our onshore production growth in 2009 include our Jackfish SAGD Project as well as our Barnett, Cana, and Arkoma Woodford Shale plays. Reported production was also supplemented by lower crown royalty rates in Canada. Fourth quarter production from…

Thanks, John, and good morning, everyone. Our growth in oil and gas reserves and production has already been covered in this call and reflects the outstanding results achieved with our 2009 capital budget. We drilled 1,130 wells onshore in North America, included 1,077 development wells and 53 exploration wells. Essentially, all of the development wells were successful, and all but a couple of exploratory wells were successful. 2009 capital expenditures for exploration and development projects from our North America onshore operations totaled $3 billion, including $840 million in the fourth quarter. To reach the $3.2 billion of drill-bit capital that Larry referred to, you would add capitalized G&A and interests to the EMP total. From only 23 operated rigs running in late August, we gradually ramped up activity over the last four months of 2009, and we exited the year with 64 operated rigs running. We currently have 80 operated rigs running. On the oil side, at our 100% Devon-owned Jackfish thermal oil project in Eastern Alberta, our daily production reached 33,700 barrels per day in late December, a little shy of 35,000 barrels per day facility capacity. The contribution from four new in-fill well pairs that are currently steaming should allow us to hit the 35,000 barrel per day capacity in the near future. Jackfish continues to be one of the best performing SAGD projects in the industry as measured by both production for well and steam oil ratio. Construction of our Jackfish 2 Project is now roughly two-thirds complete, with costs continuing to trend under budget. Jackfish 2 remains on schedule for first oil in 2011. Last quarter, we told you about our decision to move forward with our Jackfish 3 project. During the fourth quarter, we submitted a project summary document, the first step in the regulatory…

Thanks, Dave. Operator, we’re ready for the first question. I will remind everybody that we will ask you to limit your questions to one question and one follow-up per call.

Yes, sir. (Operator Instructions). Your first question comes after the line of Doug Leggate of Merill Lynch. Please proceed. Doug Leggate – Merrill Lynch: Well, thanks. Good morning everybody. The question really relates to what you’re going to do post the disposal program. If looking at our numbers, and arguably we’ve got a big oil price assumption for this year, will we see a lot of cash flow and obviously a lot of incoming cash from disposals. Can you just talk a little bit about – looking at your own asset base that are some major basins and some major place where you’re not involved. The Marcellus is probably one at the jump site. How are you thinking about potentially redeploying net cash and consolidation opportunities? That’s the broad first question, and I have a follow-up.

Well, this is Larry. As we said in previous calls, the reason for the sale of these assets is that we have reviewed our North American on-trail [ph] portfolio, all aspects of it. We see a lot of opportunities in every single one of those areas where we are, that can consume our cash flow for a long time to come. If you just look the number of unreal locations that we’ve already talked about proved or certainly de-risked under real locations, we have a lot of growth potential in the assets we already have. We’re always looking for new areas within that area to expand, both by leasing or supplemental small acquisitions of acreage. So there’s a lot of opportunity we see, both on the oil side and on the gas side, both on the shale gas in the US and in Canada as well as the heavy oil up in Canada. John, you want to – or Dave, you want to add anything?

I have a whole lot of – yes, as Larry said, Doug, I think we have so much opportunity. While we always have to keep looking at new opportunities to supplement what we have, there’s no compelling reason to do that. If we see something that really fits very well, then we always need to look at that. That may mean that we take something else and push it out the backdoor, frankly, if it comes into our portfolio and competes better per capital. But as Larry said several times, we don't see any real holes in our asset base at this time. We have chosen not to move into the Marcellus because we have a lot of other opportunities to go to that specific question. But we know that not only with regard to the plays that we've already identified on our acreage, but we’re going to find a lot more opportunity on this huge asset base the we have that’s mostly held by production as we continue to look through all of horizons in our asset base. Doug Leggate – Merrill Lynch: Perfect. Thanks, John. My follow-up is actually related to the disposal, the assets that you’re planning to dispose of. The capital program, John, you had given us some indication before as to what you’re expected allocation of capital to assets that were for sale would be. Could you update that number and maybe comment on whether or not you’re actually going to be able delay additional capital in places like Brazil given that obviously this things are for sale. Are you going to try to fill some of that and wait until bio-phase takes that over?

All right. Just give me those numbers again. When we gave our guidance in November, we said that we’re going to spend about $1.5 billion on the properties that we were disposing. And that was about $600 million more than the revenues that were attributable to those properties at that time using the price deck. As Larry mentioned earlier, we sold the Cascade, St. Malo, and Jack. That accounts for about $400 million. So that’s about $1.1 billion that we’re going to spend on the disposal of properties – on distribution properties in 2010. Now that’s not going to happen. We’ve done that. We’ve assumed, as I said earlier, that we're going to own this properties until the end of the year just – because we had to put a pin on a date somewhere. And that’s the only reasonable thing to assume. But as we go through the year, we will sell those properties, which will defray some of the additional capital costs. We’re not going to slow down our programs, frankly, on the properties that we have. We’ve got programs laid out. And we’re proceeding with them. And we’ll do that notwithstanding the fact that these are going to be sold.

I might just add, particularly on Brazil, I think the activities we’ve been undertaking have been value adding. When you look, we’ve had a discovery at Wahoo. We’ve successfully appraised that discovery. We’ve had a new discovery recently at the Itaipu well, and we have some very exiting exploration prospects. We’re going to be drilling in block BMC 34 this year. So we think this is a capital that’s well spent and it’s just going to help out with the value of the assets. Doug Leggate – Merrill Lynch: All right . Terrific. Thank you very much.

Your next question comes from the line of David Heikkinen of Tudor Pickering of Tudor Pickering. Please proceed. David Heikkinen – Tudor Pickering: Good morning. You all disclosed your risk locations with the Wolfberry, Barnett, and Cana. And one of the things we’ve been trying to segregate is the number of locations that are booked as PUD interest locations. I’m just making sure that we’re not double counting. Can you go through the Wolfberry, the Barnett, and the Cana, and just disclose the number of PUDs that you have – PUD locations you have and then what the risk locations are, and if there’s any other areas that have high PUDs or risk locations that we ought to be thinking about with that as well?

Dave, this is Vince. I’ve got some of the answers to the questions you’re asking. In the Barnett, we have – at 12/31/2009, we had 707 PUD locations booked. That compares to the north of 7,000 risk locations in the Barnett. And in the Cana, we had 68 PUD booked, compares to some 3,500 risk locations that we’ve identified in the Cana. In the Wolfberry, we estimate we have 1,100 risk locations. I think we’ve got very few PUD locations booked there, less than 20 is my recollection. I don't have the exact number in front of me. Was there another area you asked about? David Heikkinen – Tudor Pickering: No. those are the primary ones. And just to make sure I’m comparing apples and apples of that acreage and locations, are those gross locations or are they net?

Those are gross locations. Of course, in the Barnett, we can have very high working interests, and in the Cana and Wolfberry as well. All three of those places are high working interest plays, probably 80% or better.

And Dave I might just add in the Barnett, for instance, so even though Vince said we have over 700 PUD locations, the PUDs are only 22% of the proved, and we have over 4,300 PDP locations booked there.

Yes, we’re only – total proved reserves in the Barnett were only 22% PED at this point. David Heikkinen – Tudor Pickering: Yes. You didn’t book very many PUDs as a relative ratio to the peers for sure. The other question just – since you hinted on BMC 34 additional exploration, can you just talk about the prospects from the timing, just so we will know what you’re doing there?

Yes. We have a – in BMC 34, we plan to drill four wells this year. We have just – three of those wells will be post-salt wells, above the salt. And one of the wells will be a pre-salt well. We have just Spud the first of the post-salt wells called Itaipu and is currently drilling. And then we just have one rig down there. We're just going to be drilling those wells back to back. We may add a second rig to make sure that we get all of the wells drilled this year. We may add a second rig for some activity later in the year because we also would have some activity up in BMC 32 because obviously, we have a nice discovery there. But basically, it’s a four-well program throughout 2010. David Heikkinen – Tudor Pickering: Those are commitment wells for the Bakken.

Yes. Those are commitment wells, and we have a deadline facing in some time in January of 2011 to have those wells down. So that’s why we may add a second rig to make sure we get that done. David Heikkinen – Tudor Pickering: Okay. Thank you.

Your next question comes – your next question comes – yes, sir?

No, go ahead with the next question.

All right. Your next question comes from the line of Mark Gilman of Benchmark. Please proceed. Mark Gilman – Benchmark: Hi, guys. Good morning. Dave, I wonder if you could just address – and I’ve got a follow-up question afterwards. What kind of spacing the 2010 program the Barnett’s going to focus on?

Well, the bulk of our locations are on 40-acre spacing. That’s where the 500-foot spacing, we call them, but they’re essentially 40-acre spacing. That’s where the bulk of them are located. We will have some that we’re doing on a 250-foot spacing or 20-acre spacing. Mark Gilman – Benchmark: Okay. And then just shifting to a slightly different gear, I’m curious as to getting a better understanding of the logic in terms of carving out Cascade, Jack, and St. Malo in the divestment program. And I’m wondering in particular, does that imply that you did not receive as what you would consider to be an attractive and satisfactory offer for a much broader swap of the package, if not the entire offshore package in the US?

Mark? Mark, it’s, John. That doesn’t imply anything. We had that data room open. And as you'll recall, we had some additional activities on Cascade that we’re continuing well into December. And so we have results coming in. We’ve made those results available to the folks that were in the data room. And so they were looking at that. And we got the bid from Maersk initially. I think it was early in December. So it was just – it just reflected the activity levels and the maturation of the programs on those assets. So we’ll just continue ahead now with the sale of Cascade in conjunction with our (inaudible) Maersk scene and all of the exploration blocks we have in both the (inaudible) and the Maersk scene. Mark Gilman – Benchmark: Okay, John. Thank you.

Your next question comes from the line of Brian Singer of Goldman Sachs. Please proceed. Brian Singer – Goldman Sachs: Thank you. Good morning.

Good morning, Brian. Brian Singer – Goldman Sachs: I’m fully recognizing that I may have asked a similar the questioning on the previous calls. Can you talk more on the type curve and decline rates in the Cana-Woodford. Last quarter, I think, your wells had IPs of about 6.5 million a day, and you’ve got it to EURs of around 10 Bcfs. It seems like the wells drilled in the fourth quarter had slightly lowered at least initial IP rates. Do you feel more comfortable with the slightly higher EUR. What’s changing in the pressure tube, decline rate, and the new or existing wells that’s giving you more confidence in the EUR improvement? And if I could follow-up after that, thanks.

Yes. It may not have been real clear for my prepared comments there. But we’re really talking about two different areas within Cana. The wells that we drilled in the most recent quarter were outside the core area. And so that’s one reason they – the IPs were a little bit less. The other reason is, frankly, that we tend to choke these wells back pretty good. We find that that leads to better EUR overall by not bringing those out-wells on at a high rate. So a combination of those two things, the fact that they were not located in the core, plus the fact we choke them back a little bit, why those IPs are a little bit less, the 11 Bcf equivalent per day that we’re talking about, per well – 11 Bcf per well as it relates specifically to the core area of Cana. Overall in Cana, we’re saying 8 Bcf equivalent per well for all of Cana.

That’s the type curve brand that we presented in our November update. It’s the 8 Bcf type curve that we said was representative of our overall acreage position as opposed to the high liquid square area. Brian Singer – Goldman Sachs:

The one thing, the comment there, I guess you’d say, we were not obviously going through any sort maximum IP rate for any reason. We were just – the well itself appeared to be capable with very little drawdown of a very high rate. What we're seeing obviously is the Haynesville down there is thinner. And so, although it had a very high initial rate that the overall EUR may not be as substantial as you might think from the initial rates. So it's not – I don't think it's clear at all that bringing the well on at a higher rate had anything to do with the ultimate EUR. It's just fact that the Haynesville is thinner down there. Now, we are currently drilling two Bossier shale wells down there. The Bossier shale is thicker in this area. And obviously, you know there have been some very nice Bossier shale wells announced here recently. And so we're still optimistic for the overall area. So it's just – I think it's more of a product of the geology, really, rather than a strategy about how strong we bring those wells on. Brian Singer – Goldman Sachs: Thank you.

Your next question comes from the line of Bob Morris with Citigroup. Please proceed. Bob Morris – Citigroup: Good morning. My first question's on the Barnett. You mentioned that the uncompleted well inventory at year-end was 225, but at the end of the last quarter was 159, and the total number of wells you're going to drill for the year was 210. So it appeared you didn't complete any other wells that you drilled in the period in the Barnett. So first question is, is that true? And if not, then why was the uncompleted well inventory at 50% over what it was in the last quarter?

Now that's essentially true. As we announced previously, we were curtailing our production in the last part of 2009. And so we've completed very few of our Barnett wells. And then we have now started completing those wells. And we're drawing down the completion inventory as we speak. Bob Morris – Citigroup: Okay. Thank you. Second question was on the Haynesville, on the well that (inaudible) 30 million a day. And just overall on the Haynesville, what do you expect the EURs there to be now?

Well, we're still learning on this southern area to be quite frank. So we've just drilled one well down there. We're going to have some additional wells that we're going to drill down there, as I mentioned, targeting the Bossier. So I think we'll know a lot more after a few wells and we – than we would know right now in the southern part of the play. Now in the greater Carthage area, I think some very positive story that we're very confident in this greater Carthage area up in Panola and Shelby counties. So we'll be – have EURs on the order of 6 Bcf equivalent per well. And when you couple that with your uncompleted costs, around $8 million, we think that play is very economic. And we have a net resource potential up there of about 4 Bcf. And so we're very encouraged with about 1,000 locations up there. So we're very encouraged by the greater Carthage area up in Panola and Shelby counties. But we have a lot to learn yet, I think, as we go to the south. And so, we need to drill some more wells to see if that's where – how well that's going to work. Bob Morris – Citigroup: Okay. Thank you.

Your next question comes from the line of Robert Christensen of Buckingham Research Group. Please proceed. Robert Christensen – Buckingham Research Group: Can you update us on your plans for the South China Sea, the exploratory well in light of the three great discoveries that Husky had? Do you have an obligation to drill there before it's sold?

Yes. We do have an obligation. That is part of the divestment program overall that we're doing with international. And we have been working on that divestment program. We don't have any announcement at this point. But obviously, there are – we have to well commitments essentially for this year. And we're working through that as part of the divestment process. Robert Christensen – Buckingham Research Group: Do you have a rig in line to go drill them? Have you lined that up yet? I mean what's your thinking in terms of you building as opposed to someone just selling it to?

Well, we have identified a rig that could potentially drill those wells. It depends a little bit on the purchase here and their plans. It can go into additional phase also and if they choose to do so. And so, we're talking through all those options with the potential purchasers of the assets. Robert Christensen – Buckingham Research Group: Swinging back to the Barnett, I mean is there an easier solution as opposed to drilling more wells to resurrect production a little bit deeper with a series of maybe gas compression additions on your end? Or you've done that once before, I think pretty successfully where you picked up the horsepower to get more outlet? Is that cheaper? Will you do that?

This is Darryl Smette. Yes. You're right, Bob. We have, in the past, certain areas lowered compression increased deliverability out there, and that has been successful. Some places have been more successful than others. But in all of our places that's been successful. We continue to do some, I'd call it, pilot projects on some of these areas to see whether the costs will support increased productions. But we will continue to look at that as we continue to drill wells out there. And so that could be an option in the future. We'll continue to lower line pressure, both on our existing wells, but on some of the new wells, we're bringing on stream also. Robert Christensen – Buckingham Research Group: On that (inaudible) question in the refract opportunities out there, I mean that was a big part of the Devon story a while back. Is that still – we should–

Bob, I'm going to have to – a couple of follow-ups. We're going to have to move to the next caller.

Your next question comes from the line of John Abbott [ph] of Richard Capital [ph]. Please proceed. John Abbott – Richard Capital: Yes. Hi. I was just curious on the follow-up to Brian's question. Did you mention on the Cana where well costs are and how many fracs you've – you're using per well at this point.

Yes. The overall Cana well costs are on the order of about $8 million or so. Number of fracs, I don't think I have that data handy right here. If we go to another, maybe I'll come back and get it to you real quick. I don't have exactly how many fracs I have. John Abbott – Richard Capital: And I guess if you looked at it on a relative basis, do you think that the Cana has the possibility to be as incremental from a rate or return or NTV [ph] standpoint? As for Barnett, do you think that Barnett's going to be better?

We think that Cana is as strong, if not better than the Barnett from a rate of return. It's very strong, particularly in the area that has a high liquids content. John Abbott – Richard Capital: Got it. Great.

I just found that we're doing about nine frac stages here per well, so to answer your question. John Abbott – Richard Capital: Superb. Thanks very much.

Thank you.

That ends the Q&A session. Do we have any closing remarks?

Yes. As we've discussed, 2010 is going to be something of a transition year with some confusing numbers with continuing or none – discontinued operations. But when you look through that, our 2009 results confirm that we have one of the best asset portfolios in North America onshore. And we expect to emerge from our repositioning in 2010 we have a very deep inventory of low risk growth opportunities and outstanding balance between natural gas and oil, one of the lowest overall cost structures in the industry, and extensive midstream business that allows us to capture additional capital, and one of the strongest balance sheets in our peer group. With that, we believe that this positions Devon to deliver per share growth that is second to none, without the need for external financing for a long time to come. Thank you very much for the call.

That ends today's call.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.