Welcome to Devon Energy's First Quarter 2009 Earnings 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. You may begin, sir.

Good morning, everyone, and welcome to our call. I'm going to begin with some preliminary comments about our first quarter results, and then I will turn the call over to our Chairman and CEO, Larry Nichols for his thoughts on the quarter and the outlook for the future. Following Larry's remarks, our President, John Richels will provide a financial overview of the quarter. Then Devon's new Executive Vice President of Exploration and Production, Dave Hager will review operations. We'll conclude the call in about an hour. So if we don't get to your question during the Q&A period, please feel free to follow up with us after the call. As always, we'll ask everyone to that ask a question to limit it to one question and one follow-up. A replay of this call will be available later today through a link on our homepage. During the call today, we're going to update some of our 2009 forecast and estimates based on actual results for the first quarter. Since the revisions are pretty minor we are not issuing a new 8-K, but we will post those changes to our guidance on our website. If you want to find those, just click on the estimates link found in the Investor Relations section of the Devon website. Please note that all references in today's call to our plans, forecasts, expectations, and estimates, are forward-looking statements under US securities law and while we always attempt to be as accurate as possible, there are many factors that could cause our actual results to differ from our estimates. So, we urge you to review the discussion of risk factors and uncertainties that we provide in the Form 8-K with the forecast, the last one was issued on February 4. One other compliance note, we will refer…

Thanks, Vince, and good morning, everyone. The first quarter of 2009, as we all know, continued to present a very challenging environment for our industry. While oil prices did stabilize and improve somewhat, realized natural gas prices in most of North America were weak the entire quarter. In spite of these challenges, Devon had a very good quarter. Total oil and gas production was up, both on a sequential quarter basis and on a year-over-year basis. Based on our first quarter results, we are reconfirming our production guidance of somewhere between 235 million and 241 million BOE for the full year. That's the number that we gave you earlier. Our production growth was driven by record production from several fields that included the Barnett Shale, the Arkoma-Woodford Shale, Powder River Basin, all those had record production and we continued to ramp up the Jackfish, as planned, up in Canada. The earnings, before the impairment charge, were well above expectations due to higher than forecasted overall production, lower than expected operating costs, better than expected performance from marketing and midstream, and a lower than expected overall tax rate. As a result, excluding those items that analysts do not forecast, we earned $216 million or $0.48 per share in the quarter. This is about $0.20 above the first call estimates. Finally, in spite of dramatically lower oil and gas prices, we generated roughly $1 billion in cash flow from operations. Now, looking ahead, the challenging commodity price environment will likely persist through the remainder of 2009, that's been our view for sometime. In spite of significant reducing our rig count in the first quarter of this year, Devon actually increased natural gas production as a carryover from our robust activity levels in 2008. While we're confident that lower activity levels will eventually…

Thanks, Larry, and good morning, everyone. I'll begin by looking at some of the key events and drivers that shaped our first quarter financial results and review how these factors impact our outlook for the remainder of the year. Let's begin with production. In the first quarter, we produced 61.6 million equivalent barrels or approximately 685,000 barrels per day. This exceeded the top end of our guidance range by over 2% or nearly 15,000 barrels per day. Better than expected results from Barnett Shale, lower royalty rates in Canada and restored volumes in the Gulf of Mexico provided the upside to our first quarter performance. When you compare our production results to the first quarter of 2008, you will find that company-wide volumes increased by 45,000 barrels per day or about 7%. Led by the Barnett Shale, the US onshore region grew production by 17% or 63,000 barrels per day over the same quarter a year ago. Canada also contributed significant growth of 14% year-over-year due mostly to the ramp up of production from the Jackfish SAGD project. In aggregate, Devon's North American onshore assets delivered growth of over 16% over the first quarter of 2008. The onshore growth was partially offset by lower production from the Gulf of Mexico with natural declines and curtailments due to Hurricane Ike both contributing. Our international production declined by 19,000 barrels per day when compared to last year's first quarter and that's due almost entirely to a contractual reduction last year in Devon's share of production from the ACG field in Azerbaijan. Looking ahead to the second quarter, we expect to produce between 61 million and 62 million barrels equivalent, essentially flat with first quarter production. Given the way our assets are performing, we feel very good about our full year production forecast.…

Thanks, John, and good morning, everyone. Before I begin my part of the review, I'd just like to comment on how pleased I am to be part of the Devon team. This is an outstanding company with high quality people, strong values, and great assets. I will begin with a quick recap of company-wide drilling activity. Throughout the first quarter, we tapered our rig count and by the end of March, we had just 30 Devon operated rigs running. This is about the level of activity we expect to maintain for the remainder of 2009. In the first quarter, we drilled 451 wells. Of those, 30 were classified as exploratory, of which 93% were successful. The remaining 421 wells were classified as development, of which 99% were successful. As John mentioned, capital expenditures for exploration production were $1.3 billion in the first quarter. We gradually reduced activity during the first quarter, so our first quarter capital does not fully reflect the extent of the reduced activity. On the cost side of the equation, we have seen deflation across many of our operating areas in the range of 10% to 15% since the beginning of the year. The amount of cost reduction we are able to realize varies by operating area and the extent of any pre-existing contracts for goods and services. For example, in the Barnett, despite having long-term contracts for rigs and pipe significant reductions in frac cost has still allowed us to realize a 15% to 20% savings and the total cost of drilling and completing Barnett well. Company-wide, we expect to see our costs fall another 10% to 20% on average by the end of the year, as service costs continue to respond to lower commodity prices. Moving now to our quarterly operations highlight, we’ll start with…

Thanks, Dave. Operator, we're ready for the first question. We will remind you that we are asking you to hold your questions to one question and one follow-up.

(Operator Instructions). The first question comes from the line of Brian Singer from Goldman Sachs. Please proceed.

When you considered selling long-lead time projects or doing a joint venture, seeking a partner, how were you thinking or did you think about the returns and risks of the lower tertiary versus the oil sands at least the Jackfish as the potentiality alternative source of proceeds? Or are you explicitly choosing one over the other, should we read anything into that?

Well, first, we are not selling. We're looking for a partner. It's not a sale per se. We will maintain a continuing interest in that project. The problem is just the scope. Both of those projects are very successful, but the amount of capital that's required in the lower tertiary is significantly larger over the next several years than the capital required in Jackfish. As the sole operator and sole owner of Jackfish, we have greater capacity to control the timing of that. So they're both very good projects. They obviously have very different characteristics, but they're both very attractive projects.

Brian, it really is not a question of, this is not a return related question. As Larry said, when you look at the capital profile in the deepwater project, we're in the fortunate position of having a lot of success there. Those capital demands just continue to increase in 2010, 2011, 2012, so it's more related to that.

That's helpful. Thank you.

In an essence, Jackfish 1 is funding the cash flow requirements for Jackfish 2. So, we have already primed the pump so to speak up there.

That's helpful. Thank you. My follow-up, I appreciate the color on the various plays and drilling results. Could you speak to the well costs that you're seeing, particularly in your various Haynesville areas and Groesbeck as well in the Woodford?

Yes, I can address that. Currently, on the Haynesville wells, our first wells cost up on the order of 11 million to 12 million. Our most recent well is down around $9 million. We believe that we're going to be able to continue to drive those well costs down, just as we have historically in the Barnett and other resource type plays. If you look up in the Northridge area, our average drilling complete there is somewhere in the order of $6 million to $7 million, Cana on the order of $8 million to $10 million, of course Barnett we're down around $3 million or so drill to complete costs.

For those of you that don't know the Northridge area is our area of focus in the Oklahoma Woodford Shale.

The next question comes from the line of Ellen Hannan from Weeden & Co. Please proceed. Ellen Hannan - Weeden & Co.: Thank you. In terms of the costs on your Jackfish 2 project, with the declines in costs that we have seen across construction industries, commodities etcetera. Has the cost to develop that second project come down materially, was my first question? My follow-on, if you will, is getting back to the Gulf of Mexico, how much of the percentage would you be comfortable selling down and do you give up any operatorship there?

Ellen, let me, on the first question, on Jackfish 2, we are seeing those costs come down somewhat. But there's a good chunk of that that was committed last year already, as we can appreciate, long-lead time items like the boilers and the turbines are things that we ordered early on and even some of the steel. So, some of that was locked in. What we're really seeing is that the cost of some of the services that we're contracting are coming down and of course we're getting a lot better access to labor. We're building a project that we're pretty sure is going to come on, on schedule and with the highest quality services. So, it is coming down a bit. We had talked about the fact that that was going to be about $1 billion project for us and we're still kind of in that range.

I might also add that we're benefiting from the Canadian/US dollar exchange rate which has improved.

Right. Certainly, that exchange rate has come down, you will remember from about parity a year ago to somewhere it's been fluctuating a little over $0.80. Ellen Hannan - Weeden & Co.: The second part of the question was percentage we would be willing to sell down in the deepwater Gulf and would we give up any operatorship?

In some of those projects, obviously there already is an operator, BP or Chevron, and so that probably wouldn't affect operatorship at all going forward on some of the undeveloped projects. We own over 50% of those. So, I really don't see that affecting operatorship. In terms of how much we might negotiate in and that's really hard to tell, it depends on what the terms are, but I certainly don't see us giving up any more than 50% as an absolute maximum. It's a hard number. I almost hesitate to say that because the headline is Devon to sell 50%, it probably won't be that much.

The next question comes from the line of Ben Dell from Bernstein. Please proceed.

I guess, my first question was around some of the commentary you made on the Haynesville. When you look sort of further out 5 to 10 years' time, what you believe the Haynesville could contribute to your volumes? And I guess the second question I had was on the EUR that you mentioned, what sort of second year, third year, and fourth year decline would you need to see to make that number achievable?

Well, as far as how much it's going to contribute over the long term, we're so early on in the evaluation of the play. We have five wells across our 570,000 acres that we have in the play that is really difficult to give a characteristic. We know we have a very large resource in place underneath our acreage. We really need to get more penetrations across the larger span of our acreage before we really feel confident saying too much on how much can ultimately contribute. We're excited with what we have seen so far, but it's just very early on to say how much it may ultimately contain. Regarding the declines, as I mentioned in the remarks we are seeing somewhat flatter declines we think in the area that we are at and you may see areas where there have been higher IP's on wells. Those declines we anticipate we will continue to shallow out in years two, three and four. I don't have an exact number for you. Frankly, it's very early for us to be able to determine. Most of our wells have only been on the order of 30 to 90 days. So, our early indications are as I said we're confident ultimately in the 5 Bcf to 8 Bcf is achievable in the Carthage area.

Okay. And I guess, I'm not sure this counts as a follow-up. But, if you do sell down in the lower tertiary as you plan, what would you do with your rig commitments? Do you have plans to reduce your rig commitments or are you looking to sell those with the acreage or with the positions?

Well, we're evaluating our rig position right now. As most of you know, we do have two deepwater rigs in the Gulf of Mexico and one is working for us in Brazil. We do think that there is a possibility that we may need one less of those rigs, and so we're in discussions with various companies out there about possible farm out arrangements on one of the rigs. So, it's not an absolute necessity that we do this, but we think that from a cost management standpoint and able to control or not be obliged to force our exploration program to move quicker than we would be comfortable, it would probably be better to move one of those rigs out. So, we're in discussion with various companies on that issue right now.

I'll remind you Ben that we've talked before about the fact that we fortunately have these rigs at very advantages day rates, compared to many of the rigs that have been on the markets. So we don't really see any issue if we decide to move that way.

Your next question comes from Joe Allman from JPMorgan. Please proceed.

Thank you, good morning everybody.

Good morning, Joe.

Just clarification on the CapEx could you just again state what’s your CapEx right now and has that changed from the prior CapEx?

We have not changed our estimate on CapEx for the year. We had talked range of CapEx $3.5 billion to $4.1 billion so…

That's for the EMP piece and some mid-stream and corporate capital and dividends that will also present capital demands but they're all currently inline with our previous forecast, Joe. No changes.

Okay. Got you. And then just in the Gulf of Mexico besides the lower tertiary activity was there anything else that went on in the first quarter?

No significant activity outside of the lower tertiary. So we.. no.

Okay. All right. That’s very helpful. Thank you.

And the next question comes from the line of Rehan Rashid from FBR Capital Markets. Please proceed.

Good morning. On your take away capacity from the Barnett Shale area, could you talk about kind of where we are in terms of incremental [FT] capacity and how that's going to play out for the rest of the quarter?

Yeah, this is Darryl Smette and I'll answer that. As we have said we currently have about 1.2 Bcf of production that's coming out of the Barnett. Devon has a substantial amount of gathering capacity there along with two gas processing plants. And so between the gathering capacity that we have and plus the gathering capacity we have under contract with third parties, we have about 1.4, 1.5 Bcf of gathering capacity out of there now without impression or additional line use.. As we take gas away from the Barnett, we currently have in place about 1.2 Bcf a day of firm transport and about another 300 million a day of contracts with end use consumers that have firm transport. So right now we're at about 1.5 Bcf takeaway capacity out of the Barnett.

And this 1.2 of firm transport, Darryl, what was it at the beginning of the year and are you taking this to Transco 85 all the way?

We do have a long-term commitment on Gulf crossing that will move gas to Transco 85. That pipeline while it’s operational now, it's not up to maximum capacity. Currently we're moving about 350 million a day on that pipeline. We have firm transportation on that system of 700 million a day. The total capacity available to Devon up to 700 million should be available we think mid-June to maybe mid-July.

Okay, thank you.

I might just add that on that Gulf South we also have the ability to move gas from Woodford Shale area and our Carthage Haynesville play too. So we could use that firm capacity for all three of those plays.

So we should see good material improvement and realized prices.

I think you will see, you will see differentials as those capacities is available and we see the additional pipelines being built out there. Once that capacity is available not only from Gulf crossing but some of the other, the [The Canadian] Morgan line. I think you will see differential shrink and shrink substantially, you've already seen it. If you look at the first quarter of this your differentials is about $0.80 in the Carthage area, in the last two months that's been down to about $0.35 to $0.40 You’ve already seen differential strength $0.40 to $0.50.

The next question comes from the line of Doug Leggate from Howard Weil. Please proceed.

Couple things. First of all on production guidance when you last spoke to us you suggested flat versus last year But the first half was -- the guidance was $6.60 to $6.70. You're now suggesting I guess 685 thereabouts as the average for the first half of the year. So, are we really expecting not much of a decline in the second half or are you thinking that things are looking a little better relative to 2008 at this point.

Doug, this is Vince. Obviously the first quarter was a little better than we expected so the assets are performing well. Still a lot of the year in front of us and as Dave mentioned we're winding down drilling activity in the first quarter. We want to see another quarter of history before we draw any conclusions about where in the range we have put out we will be or consider changing the range.

Okay. Related question, Vince from the mid-stream guidance, pretty strong quarter in Q1 relative to the guidance of the year, so again same kind of question are we looking to move that guidance higher or how are you feeling about that right now?

Yeah, this is Darryl, and I'll take that one. Right now we're keeping our guidance where we have had it previously. Kind of echoing what Vince said, one of the things we're looking to see is how our wells continue to perform. If our wells continue to perform above expectation then we would probably increase that range in terms of what mid-stream will do. But since a lot of our gas goes through facilities that are mid-stream known, and if that production would decline then the range we gave you are probably pretty good number.

If I could quick follow-up on the Gulf of Mexico, on the lower tertiary sales are there any preemption rights with your partners there, and that's it for me.

No, the answer to that's no

Okay, thanks.

The next question comes from the line of Mark Gilman from The Benchmark Company. Please proceed.

Guys, good morning. Just a point of clarification on the partner issue, if you would. Can I assume that the middle lower Miocene properties are not included, Larry, and you stated intent here?

No, it's the lower tertiary, that's where the capital requirements are and as we have said in the early part the goal is to rebalance our capital expenditures, our long-term goal has been to have 10% to 15% of our capital budget in these long-term projects. That's where we have been for a very long time, many, many years and we think that's the right place for us to be when we want to get back to that.

If I could just follow up with respect to the Barnett, Dave traditionally companies utilize about a 20% in place assumed over life recovery rate. I'm wondering about your thoughts on that in the context of the potential number of 10 acre locations that you have defined up to this point?

This is Vince, I'll take a stab at that. It's not really an easy question, because our recovery rates across our expansive acreage position vary a lot depending on the specific local area that you're in. And so we've used a risk approach, there's large portions of our acreage that we think can be down-spaced significantly and in fact we drilled a lot of infill wells during the first quarter with very good results. But to draw the different conclusion about our overall expected recovery of the gas in place over our vast position, I just don't think we're there.

Mark, another way to answer your question is last year I think last on March 28th of 2008 we gave an overall resource evaluation of the Barnett Shale and I think if you look back at that or get with Vince I think it will give you a pretty good handle on how we are evaluating the potential of the various down-spacing opportunities in the overall Barnett shale and our evaluation has not changed significantly since that presentation.

Dave, if I could just ask how many 10 acre locations do you have at this point being identified?

I actually think we provided some detail on that in that resource update. I'll get with you offline on that Mark, and we can …

I don't think so, but please do. Okay.

But first of your question is really important, and that is while we did hit a record peak in the first quarter for the Barnett with only eight rigs running, we expect that to flatten and decline a little bit. But the resource we have there is still there. And once we get back to being really active we are by no means finished with our drilling in the Barnett shale.

In fact Mark you might remember, that we when we provided our resource update, we indicated that we have 7,500 identified undrilled locations in the Barnett Shale, so to go to Larry's point there's a lot of drilling potential there. Those are a variety of different types of wells, not all 10 acre in fill wells obviously but there are many years of drilling left for us on our acreage.

Not to beat it to death, but in some acres 10 acres will work, in others areas 10 acres may not work as well. So, I think you need to look at it as overall resource evaluation. I think we gave a pretty good evaluation on that March 28th report. But you can get with Vince, if you need more details.

Okay. Thanks guys.

The next question comes from the line of David Heikkinen from Tudor Pickering Holt. Please proceed.

Morning, guys. Had a question on your future development cost $9.3 billion that has 2 billion of abandonment. How much that is for the lower tertiary.

We don't have at our fingertips, that's not something that we would mind disclosing at all, we just don't have the details of our abandonment cost in front of us.

Not your abandonment cost, the development cost. Just trying to get an idea of what type of capital commitment you have in your four discoveries already?

I can give you an idea David on for the next few years we're seeing capital needs on the order of 800 million to $1 billion dollars or so per year for the four lower tertiary discoveries that we currently have. And that's just over the next three to four year type timeframe. I don't have total numbers and exact total number for you David. But that will give you an idea of what we're looking at.

So a significant percentage of your total then, that's useful. The other question is an assumption it seems like on the call that you're going to sell for cash or joint venture for cash, would you swap prospects, are you looking to do anything along those lines or is it just purely reducing interest and trying to garner some dollars?

We would certainly consider swaps, those are exceedingly difficult to do. But consistent with what we said the objective is. And the objective is not to generate short-term immediate cash, we have no real pressure there. The short-term, the objective is really to reduce the long-term capital commitment and get it back in line with the overall budget. We really just had more success there than we have the cash flow to go forward with. So we would certainly consider a swap, or just a pure format.

Okay, thanks.

The next question comes from the line of Tom Gardner from Simmons & Company.

This will be the last question that we have time for in the call.

And the final question comes from the line of Tom Gardner from Simmons & Company. Please proceed. Tom Gardner - Simmons & Company: Yeah, I just wanted to get some more resolution on your ceiling test write down, was the reduction all allocated to the US calculation or was it spread across additional countries in which you operate?

It was substantially all in the US. Tom Gardner - Simmons & Company: Okay. And just following up with some well economic questions if you will. Specifically the Cana, Woodford Shale. Can you give us an idea of what is going on with respect to the fact that the initial rate to EUR seems to be a little atypical for shale? What are you seeing there, what sort of long-term gas price do you need to make this an attractive development for Devon?

Well, again we are seeing strong overall EURs on this, a little bit shallow or decline on the Cana than we have seen in some of the other areas. In general, we feel a breakeven gas price on an [NPV 10] basis is approximately $4 per Mcf for the Cana. Tom Gardner - Simmons & Company: Good. Okay. Thank you very much.

We have no further questions at this time. I would now like to turn the call back over to management for closing remarks.

Thank you. As they pointed out and we try to limit this to one hour, so thank you very much. We think we had a good quarter and looking forward to the rest of this year. Take care.

This concludes the presentation for today. Ladies and gentlemen, you may now disconnect. Have a wonderful day.