Welcome to Devon Energy's second quarter 2009 earnings conference call. At this time all participants are in listen-only mode. After the prepared remarks, we will conduct the question-and-answer session. This call is being recorded. At this time lied like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Good morning, everybody and welcome to Devon's second quarter call. I've got just a couple of housekeeping items and then I'll turn the call over to our Chairman and CEO, Larry Nichols. He'll give us an overview of the quarter and some thoughts about how Devon is positioned for the future. Following Larry's remarks, our President, John Richels will provide a financial review and then following John's comments, Dave Hager, our Executive Vice President of Exploration and Production will discuss operations. This will be followed by a Q&A period and as usual we will hold the call to about an hour or so. If we don't get a chance to get to your question today, please feel free to follow up later in the day. As always we will ask the participants on the call to keep their questions in the Q&A session to just one question and one follow up. 8-K: These updates will also be posted to the estimates page on www.devonenergy.com. Please note that all references today to our plans, forecast, 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 and we therefore urge you to review the discussion of risk factors and uncertainties that is provided with the form 8-K that we are going to file today. One other compliance note. We will refer today to various non-GAAP performance measures. When we make reference to these measures, we are required to make certain disclosures under US Securities law. Those disclosures are available on our website and again that is www.devonenergy.com. With those items out of the way, I'll turn the call over to Larry Nichols.

Despite a rather challenging environment, Devon had a very positive second quarter. Total production increased 5% over the first quarter this year and 12% over the second quarter last year. It increased to 719,000 Boe per day which sets an all-time record for a combined production of oil, gas and NGLs for Devon. Our realized crude prices climbed more than 50% over the first quarter, which more than offsets the lower natural gas prices. This of course underscores one of Devon's strengths of having a balance between oil and gas. Cost trends were favorable with most categories coming down in the second quarter with better than expected production, lower cost and stronger oil prices, we generated net earnings of $314 million for the second quarter. Excluding those items that analysts generally do not forecast, Devon earned $379 million or $0.85 cents per share for the quarter which is $0.26 cents or 44% above the first call mean. We generated cash flow of $1.1 billion in the second quarter which more than funds our CapEx expenditures for the period. We exited June with cash and unused credit lines of about $2.6 billion and a net debt-to-cap ratio of 35%, actually a little below 35%. With abundant liquidity and a very strong balance sheet, we are well positioned for an upturn in the current cycle. Our second quarter performance reflects the very high quality of our oil and gas property base. In spite of the dramatic decrease in drilling activity in the first half of this year for Devon, our assets significantly outperformed expectations. Furthermore our oil and liquids components supported sufficient cash flow to fully meet the demands of our capital program and dividends during a period of very low natural gas prices. Based on the very strong performance of our…

Thank you, Larry, and good morning everyone. I'll begin by looking at some of the key events and drivers that shaped our second quarter financial results and review how these factors impact our outlook for the second half of the year. We will document these changes to our outlook in a Form 8-K that we expect to file later on today. So let's begin with production. In the second quarter, we produced 65.4 million equivalent barrels or approximately 719,000 barrels per day. This result exceeded the top end of our guidance range by $3.4 million barrels or about 5%. Roughly two-thirds of the 3.4 million barrel beat was attributable to our North American onshore assets. The remaining third of the out performance was due to lower royalty rates in Canada and, as many of you know, Canadian royalties are calculated on a sliding scale and the lower natural gas prices during the quarter lowered royalties and increased Devon's share of production. When you examine our production performance in greater detail, you'll find that we experienced strong year-over-year growth across most of our major operating regions. Overall, Devon's company-wide production increased by 76,000 barrels per day or nearly 12% when compared to the second quarter of 2008. Once again, our US onshore properties contributed significant production growth, up 12% or approximately 46,000 barrels per day over last year's second quarter. The leading driver of our US onshore performance was strong growth from our Barnett Shale assets. In Canada, production increased by 28,000 barrels per day or 17% year-over-year. In addition to lower royalty rates, the continued ramp up of our Jackfish SAGD project drove the strong results from our Canadian segment. Devon's international properties also delivered meaningful growth in the second quarter. Improved results from Brazil and Azerbaijan increased international production…

Thanks, John. And good morning to everyone. Operationally, the second quarter was a very good one for Devon. As Larry said, we set an all-time record for production of oil, gas and natural gas liquids. All of our major assets are performing very well. We have leveraged our shale expertise and established years of drilling inventory, not only in the Barnett, but also in the Haynesville, Cana-Woodford and Horn River. Furthermore our Jackfish SAGD project continues to deliver industry leading performance. I will begin the operational highlights with a quick recap of company-wide drilling activity. During the second quarter, we continued our reduced activity levels and at the end of June, we had just 24 Devon operated rigs running. We drilled 198 wells in the quarter with only one dry hole. Of the 198 wells, nine were classified as exploratory and the remaining 189 wells were classified as development. Capital expenditures for exploration and development were $848 million dollars for the quarter. This brought total exploration and development capital for the first six months to $2.1 billion. In the second half of 2009, we expect E&P CapEx to continue at roughly the second quarter pace, putting us squarely within our previously forecasted range of $3.5 billion to $4.1 billion for the full year. Service and supply costs continue to respond to lower activity levels across most of our operating regions. On average, company-wide we've seen our costs deflate by about 17% since the beginning of the year and we expect to see another 5% to 7% in the second half of 2009. Industry-wide drilling rig costs were down about 40% year-to-date and tubular costs are down about 30%. We have not yet experienced the full benefit of these improvements because of term rig contracts and the advanced purchase of enough…

Operator, we are ready for the first question.

[Operator Instructions]. Your first question comes from the line of Tom Gardner with Simmons & Company. Please proceed. Thomas Gardner - Simmons & Company: I had a question regarding Devon's progress in derisking acreage in some of your key emerging plays, specifically in the Haynesville. I understand you have about 580,000 gross acres that may have changed, but have you ruled out any of this other than what you indicated in this morning's release as not being perspective or being perspective?

No, we have not ruled out any of the acreage as not being perspective. We are methodically moving our way through the acreage position. At this point we drilled most of the wells in the Carthage area and we are very confident that we have derisked that area. We are now moving to the south. We are currently drilling a well in the San Augustine county, the [Cardill] well. After that we will be drilling a well in Shelby county which is in between Carthage and San Augustine county. That will help to derisk an additional 47,000 acres. A great deal of the remaining acreage is actually minerals and held by production. So there's not as much of an urgency to derisk most of the other areas, outside of the acreage that I just mentioned. Thomas Gardner - Simmons & Company: I have a similar question on the Cana-Woodford. I understand about 112,000 acres. Have you ruled any of that out?

It's about 109,000 acres and, no, we have not ruled any of it out. The Cana-Woodford is working extremely well. The bulk of our drilling to date has been concentrated on what we call the core and the central portion of the position. We are now moving out to the western portion of the acreage position to evaluate it. So far everything has worked outstanding and as I mentioned, we are adding two additional rigs up there. So, we are obviously pleased with the results we are seeing.

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

Just going through your guidance and I saw the 8-K, but working through numbers I understand you got 3 million barrels of curtailment. It looks like two of that is really in the fourth quarter. Does that imply that you expect fourth quarter gas prices to be much lower than the third? Or is it just you haven't started curtailing yet?

David, this is Vince. We actually just started implementing the curtailments. So the impact will be disproportional to the fourth quarter. It really doesn't reflect that we think fourth quarter is any worse than third.

Looking at kind of run rates, so fourth quarter volumes at 61 million barrels and third quarter is around 57 million barrels of oil equivalent to hit the midpoint of guidance.

That's correct.

You talked about Jackfish ramping and Polvo, what's your natural decline rate from third quarter to fourth quarter, then if you have the same breakdown that you walk through as far as third quarter, what's in the guidance? It would be useful to get the same thoughts on fourth quarter.

If you take our actual Q2 production of 65.4 million barrels, you take the midpoint of Q3 of 61 million barrels that would imply a reduction of 4.4 million barrels. We would break that out basically as about a million barrels due to the voluntary reductions that we've described. The plan turnaround at Jackfish and Panyu, probably about another million barrels. We have about half million barrels built in there for hurricanes and probably a change in the Canadian royalty structure where we will not get quite as favorable results. It will just under in the third quarter relative to second quarter. It will probably result in the reduction of about a million barrels or 900,000 barrels there. So that leaves the natural production decline from second to third quarter of about a million barrels.

Then I was trying to do the same breakdown of third into fourth on the 61 million barrel midpoint, just at the midpoint of full year 245 would be 57 million barrels, can you do the same breakdown.

For there, we would have about 2 million barrels of voluntary reductions going from third to fourth quarter. Of course Jackfish and Panyu would come back on. So that add back about a million barrels. We also anticipate though about a million barrels of decrease wafting and that's just a timing of waftings on our international properties which should be about 2 million barrels for production decline.

That's mostly US gas on the production decline?

Yes.

Thinking about capital spend right then, have you thought about what that implies for 2010 production and the correct amount of spend?

David, we are really just getting into very early stages of developing our 2010 capital budgets and so we really haven't forecast that out through 2010 at this point.

I would add the fact that we have deferred a lot of completions, if in fact we are in an environment that encourages us to bring that production on in 2010, it bodes well for our 2010 production profile.

Just thinking about that plus other major projects, I put a 3% kind of quarter-over-quarter base decline and then you do major projects and some more completions, is that a fair way to bracket things? Just thinking 2 million barrels on a 60 million-barrel base.

We can't point out any flaw in your logic, although obviously our activity levels have a tremendous impact on our production profile. And so until we establish what that will be for 2010 we don't really have a [number] for it.

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

Conceptually, you talked a little bit about hedging and the increases which is kind of new over the balance of the year, but conceptually what would stop you taking a more significant hedging position, on making a little bit more of an effort to maintain production in the Barnett in particular? I'm just trying to think how your planning comes together on that?

First of all, as you know there are different ways to handle risk. Our philosophy in the past has been that if we had a strong balance sheet which we have traditionally had and if we are a low cost operator which we have traditionally been, then that's a way to minimize risk or to manage risk and we have traditionally not hedged a lot except when we did for specific reasons like when we did acquisitions and that kind of thing. We actually went through and we've taken a look at whether a more systematic or a formulaic approach makes sense where you just continually hedge a certain amount of production. We really don't think that that responds well to the markets and makes a lot of sense many. We just haven't seen the evidence of that being the right thing to do. What we are doing, though, is continually monitoring our expected cash flow, our capital programs. We have a bigger piece of our capital programs these days that is dedicated to longer-term projects that you don't want to slow down too much on, our view of prices and making a call on that basis. So it's something we are continually monitoring. When we develop our 2010 capital budget and as we continue to develop a view on pricing for 2010, we may well put some more hedges in place, but we haven't at this time.

It's both I'd say. Current $4 economics, there is certainly at least breakeven, probably a little bit better and normalized numbers are substantially better than that. So it's just a play that's working as well as any play that we have out there in the company I would say at this point. So we do want to establish our acreage position, make sure we are holding our acreage position, but it's also an extremely economic play overall for us.

Are you able to give any risk locations at this point or is it too early?

Well, what we've said is that we think we have net risk potential out here of about five Tcf. That translates to risk locations of little bit in excess of 1500.

Were there any reserve upward revisions in the quarter that helped your depreciation charges?

Actually, Doug, there were. All of our Jackfish barrels came back on. They came off at year end, both the Jackfish 1 and Jackfish 2 and they are all back on and that's somewhere in the neighborhood of 300 million barrels that came on just as a result of the economics. With the large variance between oil and gas on energy equivalent basis and with the narrowing of the differentials that we talked about earlier, those projects have become extremely profitable and they are all back on.

John said all the reserves on Jackfish 2, that is the ones that we lost at year end, but we are no place close to fully booked at Jackfish 2.

We only booked at 80 million barrels at Jackfish 2. I mean the ones that came out off year end. Vince is right.

300 million were back in the second quarter?

That's correct.

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

With respect to the voluntary curtailments is there any portion of it that is dictated by expected cash loss as opposed to just you don't like the price?

There's actually on a number of the projects, we are saving the cost of completion. We are saving capital by deferring these completions particularly in the Woodford and the Washakie is allowing us to actually save costs. We are also saving some money on the compression as well. Yes, it's more than just we don't like the price. It's that we can save some dollars as well.

There is one field, the Powder River, where the economics are marginal and so we are setting that field in or portions of it for negative cash flow. But the vast majority of their curtailments are clearly voluntary, very profitable operations that we just elect not to sell the gas into a very weak gas market, rather keep that gas in the ground and sell it next year at a higher price.

Vis-a-vis the Jackfish Dave, can you talk a little bit about the progression in terms of steam-oil ratios and where it stands currently?

When we first scoped out Jackfish, Mark, we were assuming that we would see a steam-to-oil ratio that was less than 3 and that whole field, the reservoir and the wells have performed better than we have expected. So we are actually on many parts of that project now, at below 2.6 steam-oil ratio which if you look at the other way, it's one Mcf per barrel and the wells continue to produce at levels which are really industry leading results. So, it's been just a terrific lease for us and a terrific project.

In an environment of the reduced activity in the Barnett, what are you doing with respect to the 20-acre program? And if there's activity in that regard, Dave, what kind of oil rates are you seeing?

We are drilling a few on 20 acres, the bulk of them we are drilling are on 40-acre and 80-acre spacing. We are drilling a few on 20-acre and we are seeing performance of very similar, but very, very close to what we are seeing on the 40-acre and 80-acre spacing. So, it continues to have very similar economics.

Next question come from the line of Brian Singer with Goldman Sachs. Please proceed.

play:

Well, the net pay was as anticipated. We had no surprises in the well. We actually saw a little bit more pay than we had prognosed pre-drill. There's no change in our resource estimates out there as a result of this well. Very happy with the results.

Also on the Gulf of Mexico. Anything we should read into the potential decision for an additional Cascade appraisal well?

It's an exciting project and certainly we are drilling an appraisal well right now that if successful could double the size of the field. I think BP has said if successful, it could be one of the largest if not the largest field in the Gulf of Mexico. The fact we are maybe considering an additional appraisal well just means that we like the project and we are going to keep evaluating it. That's all you can read into it.

Plunging forward.

On the Cana play, you highlighted the 8.4 million a day IP rate and expectations for a 14 Bcfe work and I think implied in that a much shallower decline rate relative maybe what we are typically used to in some of these plays. Can you just talk a little bit about that and what you are seeing from some of the wells that have been in production for a little bit longer?

Well, overall I think we can say that our IPs out there and we typically don't bring these on quite as hard as we do in some of the other areas, but we typically see IPs on the order of 5 million to 6.5 million cubic feet a day. Our EURs out there are ranging from around 6.5 Bcf to 9 Bcf per well. At those kind of numbers, it's a highly economic project.

Is there anything in a decline versus a normal 50% to 70% decline? It would seem like there seems to be a much shallower decline coming from the Cana-Woodford wells and I just wonder if that's right and if you are seeing that in the wells [30, 0:43]inaudible] that have been in production so far?

These are always ranges, Brian. I think maybe they are on the lower ends of the range. We take your point there that the EURs as compared to the IPs are a little bit different. You have to remember that one well as we said was no what we expect to see on a regular basis. That was kind of an anomaly, that 14 million Bcf EUR well. What kind of interesting about the Cana as compared to the Woodford in Eastern Oklahoma, it's over pressured more, so it's a little bit different, some different production characteristics as well.

I think the issue there really is that we choose not to bring these wells on at such a high rate and so that's why you are just seeing a lower overall IP to the EUR. We could bring these on, more of them at a higher rate. It's a little bit like I described in my prepared remarks on the Haynesville that we have seen some evidence that it can perhaps degrade the overall EUR, if you try to bring these wells on too hard initially. So, that's going to change your overall decline rate I think you are looking at.

And if I could just ask one last one of the two MMboe you are expecting to be deferred in the fourth quarter which I think translates to about 130 million cubic feet a day. Could you give us some sense on what the percent breakout is between what would be drilled to completed, but shut in versus drilled and not completed?

The shut in overall is probably on the order of about half million barrels or so and more about 1.5 million barrels or so on the ones we are not completing .

Not to beat a dead horse here, but you ask about decline rates in the Cana. Our early indications, what we are looking for 50% to 70% in the Cana Shale, as opposed to say the Haynesville where decline rates are 75% first year or greater. 50 to 75 is a big difference in terms of IP to EUR. I think it's fair to say that the early view of the Cana is lower decline rates than the Haynesville.

Your next question come from the line of Rashid Rehan with FBR Capital Markets. Please proceed.

Any update on the data room for the lower tertiary sales?

The data room has opened, but we are not pushing that because we want to wait until the next Cascade well is down. And that's when we will really start asking for business when that data is in, so that process is ongoing satisfactorily.

On the cost front, we do talk about having locked up tubulars and stuff at much higher prices and somewhat the same for rigs. If we were to reprice those two contracts, any thoughts on to what kind of savings, we could net from that, so I can think about what CapEx could look like?

As it relates to the rigs, currently it's about a 40% decrease for the rigs we have under contract to what the current market is. The number of rigs we have under contract will change as we go out, obviously some of those will move down. We currently have 30 rigs under contract that was out or down as we go in the out years. In terms of our tubulars, we would see about a 30% improvement in the 75% of the need that we have. If we were buying on the open market today, most of that surplus material will go away as we move through the rest of this year and most of it will be gone by the time we enter 2010.

If there any dollar number besides these two savings and what would it add up to?

40% on a average rig cost. It's running right now about $16,000 or $17,000. 40% above that, about $23,000, $24,000 a day.

And basis differential across the board, are we seeing some benefits as time progresses and your new take away capacity.

Yes, we actually have seen a decrease in the basis differential in virtually all of the major producing areas over the last couple of months. The biggest change in basis differential just in the last month or so has been in the Rocky mountains which have been trading between dollar and a dime and $1.50, and going into this month it's actually trading between $0.30 and $0.45 cents. We've actually seen a decrease in basis, in East Texas Gulf Crossing is now on and operating about 95% capacity and that basis differential has moved from about $0.50 cents down to about $0.20 cents this morning.

And your [Transfer] 85 capacity is helping in all this, right.

Absolutely. We are moving about 655 million a day on Gulf Crossing now. A majority of that right now at this moment is going to Station 85. Some of that we are dropping off at places in between but certainly helping.

Operator, I'm showing the top of the hour. Let's make this our last question.

Your last question comes from the line of Biju Perincheril with Jefferies & Company. Please proceed. Biju Perincheril - Jefferies & Company: The completed well costs that you highlighted for in Cana, $8 million, is that a good number to use going forward? Then you sort of alluded to the returns in Cana. Can you give us some rate of return metrics in Cana and compare to it what you are seeing in the Barnett? And also maybe some guesstimate of what you expect from Haynesville, the Carthage area?

Yes, first to your question on Cana for the drilling costs, yes, we are seeing on the order of $ 8 million to $9 million per well. The costs are continuing to come down with each well that we drill out there. I think around $8 million longer term is a very good number to use. In regard to the economics of Cana relative to Barnett, we are seeing as good if not slightly better economics for what we are currently drilling out in Cana as compared to the Barnett. Not to say the Barnett is not good. Obviously it hasn't changed to the negative at all. Cana looks like it's as good or even a little better which means basically at a $4 Henry Hub, you are probably more like a 10% or so breakeven rate of return on those more normalized price at $5.50 or so. You are certainly looking at 20% to 25% rate of return at least on these type projects. We are still in the early stages of Haynesville and we are still derisking the acreage. So I think we are going to see variable and we need to understand it better before we can give you a comprehensive answer to that, but we are certainly confident in the Carthage area where we say we derisked 74,000 of our 110,000 net acres. At price environments around 550, we are getting between 20% to 25% rate of return in that area as well at the kind of costs that we are now achieving in the play where we've been able to drive drilling costs down and the kind of recoveries we are anticipating of five to six Bcf per well.

I think it's important to note that the economics that Dave's talking about are full cycle rates of return, fully loaded with our acreage costs and not go-forward drilling economics

This concludes our question-and-answer session and ends the presentation. Thank you for your participation in today's conference. You may now disconnect and have a great day.