Good day, everyone and welcome to the EOG Resources Fourth Quarter and Full Year 2008 Earnings Conference Call. As a reminder this call is being recorded. At this time for opening remarks and introductions, I would like to turn call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. I hope everyone has seen the press release announcing fourth quarter and full year 2008 earnings and operational result. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our Web site at www.eogresources.com. The SEC currently permits producers to disclose only crude reserves in their securities filings. Some of the reserve estimates in this conference call and webcast including those for the Barnett shale, North Dakota Bakken, Horn River and Hainesville may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release, and investor relations page of our Web site. An updated investor relations presentation and statistics were posted to our Web site last night. With me this morning are Loren Leiker, Senior EVP of exploration, Gary Thomas, Senior EVP of Operations, Bob Garrison, EVP of Exploration, Tim Driggers, Vice President and CFO, Moira Baldwin, Vice President and Investor Relations, and Jim Falconi, Manager of Engineering and Reserves. We filed an 8-K with first quarter and full-year 2009 guidance yesterday afternoon. I'll discuss our 2009 business plan in a minute when I review operations. I'll now review our fourth quarter and full-year net income available to common stockholders and discretionary cash flow and then I will review our year-end reserves and finding costs. I will follow that with a discussion of our macro hydrocarbon view, our 2009 business plan, and an operational review. As outlined in our press release, for the fourth quarter,…

Thanks, Mark. Capitalized interest for the quarter was $12.5 million and for the year was $42.6 million. For the fourth quarter 2008, total exploration and development expenditures were $1.2 billion. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment were $156 million. For the full year, total exploration and development expenditures were $4.9 billion with only $109 million of acquisitions. In addition, total gathering, processing, and other expenditures were $477 million. For 2008, approximately 25% of the drilling program CapEx was exploration, and 75% was for development. At year-end 2008, total debt outstanding was $1.9 billion and the debt to total capitalization ratio was 17%. At December 31, we had $331 million of cash, giving us non-GAAP net debt of $1.6 billion, for a net debt to total cap ratio of 15%, up slightly from 14% at year-end 2007. The effective tax rate for the fourth quarter was 37%. The effective tax rate for the year was 35% and the deferred tax ratio was 87%. We also announced another increase of the dividend on the common stock. This is the 10th increase in 10 years. Effective with the next dividend, the annual indicated rate is $0.58 per share. Yesterday, we filed a Form 8-K with first quarter and full year 2009 guidance. For the full year 2009, the 8-K has an effective tax range of 35% to 45% and a deferral percentage of less than 10%. The deferred tax ratio is expected to decline from prior years due to reduced capital expenditures and IDC [ph] expensing. The effective tax rate will depend in large part on the relative levels of foreign and domestic pretax income. Estimated exploration and development capital expenditures for 2009 excluding acquisitions are $2.85 billion estimating gathering, processing, and other expenditures for $250 million. Now I'll turn it back to Mark to discuss our hedge position and concluding remarks.

Thanks, Tim. For 2009, we have 43% of our North American gas hedge at a $9.73 price per floor including both financial and physical hedges. For 2010 we have 60 million cubic feet of gas a day collar or swap at an average $9.96 floor. We have no oil hedges, and we do have a small amount of 2009 through 2011 Rocky basis swaps. Now let me summarize. In my opinion, there are five important points to take away from this call. First, we achieved a 26% ROCE for 2008 and likely led the peer group in this regard, which further confirms our multi-year ROCE differentiation versus other companies. Second, 2008, we're likely one of the few peer companies that did not have substantial asset impairments or reserve writedowns. Additionally, we posted an attractive $2.60 per Mcfe all-in finding cost including price revisions. In my opinion, financial returns matter, particularly in the current environment. Asset impairments are often dismissed as noncash or nonrecurring. But these impairments do reflect cash that indeed was spent and now has to be written down because the investment value has dropped due to lower commodity prices. I'll also note that in my opinion, I think both the sell side and the buy side tend to underestimate the importance of the fact that we have no asset impairments nor any substantial reserve writedowns. Third, we're committed to keeping our debt low. In today's environment, I certainly don't have to remind this audience about the negative consequences of high leverage in any industry. Our dividend increase although small signifies our confidence in our go forward game plan. Fourth, as promised, we've now reported substantial tangible results regarding our Barnett combo play. This is important because the prize here is very big. Additionally, we've confirmed our first Hainesville success and noted further success in the Bakken light, Horn River and Marcellus plays. It's important to note that EOG has the premier position in what we believe are the top two large size oil plays in the onshore U.S. the Bakken and Barnett. With this line up in inventory, we expect to generate – we continue to generate superior reinvestment rates of return compared to others in both up and down hydrocarbon price cycles. And fifth, we're continuing to work on new horizontal ideas and will disclose them whenever we've got acreage positions locked up and tested a few wells. Thanks for listening. And now we'll go to Q&A.

Trisha, do you want to hook us into Q&A?

(Operator instructions). We'll go to Tom Gardner with Simmons & Company. Tom Gardner – Simmons & Company: Good morning, everyone.

Hey, Tom. Tom Gardner – Simmons & Company: Hey, Mark. With respect to your capital expenditure outlays in 2009, are there likely to be somewhat evenly distributed or front or back-end loaded?

They will probably be a bit front end loaded simply because we'll be in the process of shedding rigs throughout the year and so the expenditures in the first half of the year will be likely more than 50% of the total $3.1 billion CapEx. Tom Gardner – Simmons & Company: With that 2010 recovery comes a little early do you think you might pick up CapEx?

Yes. We certainly got the flexibility to do that. But the plan we're articulating now is one based upon the assumption that gas prices remained pretty dismal throughout 2009. Tom Gardner – Simmons & Company: Is EOG currently drilling but not completing wells in some areas?

Yes, the answer to that is yes, Tom, particularly doing that in areas that are susceptible to cold weather. For example, in the Bakken play, and also in our Bakken oil play and also in our Uinta Basin gas play, we're currently drilling wells and just going to wait for completion at least until late spring simply because to frac those wells in the winter time you have to heat the water and there is lot of incremental costs with that and we just in no hurry to rush production and cram it into a market currently has signs of oversupply. Tom Gardner – Simmons & Company: Other operators are doing inventory in those drilled, but not completed wells, too. Do you think that's going to be impactful to the timing or duration of the gas market recovery when it comes?

I know, Tom, there has been some comments by others relating to the Barnett shales. People have said they're slowing down in the Barnett shale and – but they have an inventory of wells yet to be completed. We've done a pretty thorough modeling of the Barnett shale on the gas side. And based on what we see, the signs, with the recount dropping and also factoring in that there is an inventory of wells yet to be completed, it's our belief that the Barnett shale is going to peak at about 4.9 Bcf a day in the first quarter of this year. And by the end of this year the Barnett shale will be down to about 4.3 Bcf a day. In other words, it's going to drop about 600 million cubic feet a day from the peak. So although there are inventories of completed wells, I think the example in the Barnett shale is that, number one, I certainly don't believe it's going to go to six Bcf a day and we think the first quarter is going to be the apogee of the production growth from it. That doesn't say that the Barnett is completely tapped out. What it says is that there is a huge amount of people who are dropping rigs in the Barnett and likely moving them – moving their activity to the Hainesville. Tom Gardner – Simmons & Company: One last question and then I'll hop off. Just wanted to see how your view of the Hainesville has changed over time. Obviously those were sweet wells that you drilled, first two at over $17 million a day. What do you think is fundamentally different to your ingoing expectations?

Yes, our prior position on previous calls, the Hainesville was – was what I'll call studiously neutral. And we said that we're not going to opine on the Hainesville until we get some EOG operated wells drilled on our own. Now that we've got two good wells under our belt, it's our feeling that the Hainesville is a real play. The question is what's going to be the total aerial extent of it. And then the other question is it impacts the gas market is what is the short-term takeaway capacity from the overall Hainesville. And at one point in time will there be an expanded pipeline system to take additional gas out of the Hainesville. But bottom line is we moved from neutral to positive play based on EOG operated well results. Tom Gardner – Simmons & Company: Thanks, Mark.

Okay.

We'll take our next question from David Heikkinen with Tudor Pickering Holt. David Heikkinen – Tudor Pickering Holt: Good morning. Just a question on the rig count and dropping how quickly drop rigs and are you paying any terminations to drop?

The answer on the second part, Tom, is no. We're not paying any terminations to drop. In terms of how quickly we're dropping them, I don't know Gary Thomas, you want to opine?

Yes, we had a peak of 82 rigs there in September and we're down to 64 now. We've got about 36 rigs under long-term contract. By year-end we'll be down to about 13 rigs under long-term. So just us being at 64 now averaging 45, it will just be like Mark had mentioned on our CapEx, little heavily weighted first half, probably mid-year or so we'll be down to 40 rigs. David Heikkinen – Tudor Pickering Holt: Thanks. And then on the Barnett combo play, just looking at the move towards more gas and NGLs away from oil, can you talk about how large an area you now think is perspective for the combo play and then the new resource assessment of 200 million barrels. Where have your wells been and what have you confirmed?

Yes, David. What we feel we've pretty well firmed up by the drilling we did in the second half of 2008 is an area that's got low risk development locations sufficient to generate about 50 million barrels of oil equivalent net to EOG. And what we're going to do this year is basically concentrate most of our drilling in this development area and drill a few step out wells to go beyond that. It's our belief that this project will expand or kind of maybe in 50 million barrel tranches and what our game plan is this year is hopefully to get well into development of the first 50 million tranche and by year-end have the second 50 million barrel oil tranche pretty well firmed up and just kind of step in that particular mechanism. If we would have been in a higher oil price environment and gas price environment, we'd be tramping down on the accelerator on this play, but in the current environment, we're going to just kind of proceed at a moderate pace but I think what is telling is the fact that we're generating somewhere between a 15 and a 5-0, 50% after-tax unlevered the investment rate of return at current hydrocarbon prices, which I think speaks well to the efficacy of the play. What you haven't heard probably on too many earnings calls is that the inherent economics in most of these plays in North America, current hydrocarbon prices are very, very weak. On oil plays, I'd say that for all of North America, you've got the Barnett core and the Bakken – sorry, the Bakken core and then the Barnett combo portion that are economic in today's prices. But I don't think there is anything in the deep water, nothing up in the heavy oil and nothing substantive that I'm aware of in the rest of North America that seems at these kind of prices. So it's a pretty stressed time for oil development and also gas development in terms of returns. David Heikkinen – Tudor Pickering Holt: And then in the UK, can you talk about the size of what you're exploring for both in the East Irish Sea and Central North Sea? That's my last question.

Yes, David. We have two wells planned, two oil gas planned in East Irish Sea. One is – the one is gas. Gas prospect is probably 90 Bcf to 100 Bcf gross size and we're 70% working interest. The oil prospects is around 50 million barrels, again 70%. And then in the Central Graben of the North Sea we have one oil prospect we're going to drill as operator, 30 million barrel to 50 million barrel size, we're 43% working interest in that well. David Heikkinen – Tudor Pickering Holt: Okay. Thank you.

We'll take our next question from Gil Yang with Citigroup. Gil Yang – Citigroup: Good morning. Couple of oil questions. Mark, you commented that in the Bakken you would be – you're drilling more than you're putting on line. You have spare deliverability. Can you give us – can you quantify that in any way?

I guess the best way to quantify is that if we add all our stuff producing full capacity now, we will be producing about 25,000 barrels a day. By the end of the year that number will probably be up in the range of 40,000 barrels a day to 45,000 barrels a day. Gil Yang – Citigroup: 40 to 45?

Yes, somewhere in that range. Gil Yang – Citigroup: Okay. And then looking at the – looking at the combo play, can you – is the growth that you're going to see for the company as a whole coming from gas liquid coming out of the combo or are there other regions of significant NGL growth?

Yes, there is two places of NGL growth relative to last year. One place is the Barnett in our western counties, in the gas Barnett. There were some limitations on gas processing last year and those have been fixed. So we'll have a full year of stripping out more liquids from the western Barnett counties. And then of course we've got in the – the northern Barnett, the combo play for now commissioning our processing plant and we'll be stripping out the NGLs for the combo play. And then the last item really relates to the Barnett. And I – I mean – the Bakken, excuse me. The Bakken, I said is really challenged on infrastructure issues on the oil side and also on the casing head gas side. And we're going to fix the casing head gas problem by laying a 75 mile pipeline to tie into alliance pipeline whereby – by sometime we believe in the third quarter, early third quarter we will be able to pipe our gas and extract everything from ethane and above and sell those in the Chicago market. So for the second half of the year we're going to see more natural gas liquids coming from the Bakken also. Gil Yang – Citigroup: Okay, great. And last question is, today's economics, do you expect there to be less stripping in the mid-continent than in the past year or two?

Yes, our read is the best barometer on NGLs is that they are generally been a function of crude oil and our logic is we do expect crude oil price at the firm in the second half of the year and we expect NGL prices to firm it kind of in line with that, which would give reasons for to maximize stripping certainly in the second half of the year if we're right at the hydrocarbon forecast. Gil Yang – Citigroup: But if that doesn't happen, sort of that if you freeze today's economics, what do you think would happen over the next year?

Well, it would be less stripping, but, it's just in the assumption that one may exist to what's going to happen to relative hydrocarbon prices and our assumption is that gas for the full year is not going to be particularly robust whereas hydrocarbons in terms of liquids will be more robust in the second half of the year. Gil Yang – Citigroup: Okay. Thank you very much, Mark.

We'll take our next question from Joe Allman with JPMorgan. Joe Allman – JPMorgan: Yes, thank you. Good morning, everybody.

Hi, Joe. Joe Allman – JPMorgan: Mark, in terms of – in terms of the infrastructure in the Bakken, you mentioned that casing a gas line, what other requirements do you have there to improve capacity in the Bakken?

Yes, the casing head gas line will fix the gas takeaway problem. The oil takeaway problem, we're looking at several options right now and it's certainly possible that the option we might land on is to rail car incremental barrels out of there, rail car those barrels either to Oklahoma or to all the way down to the ship channel – Houston ship channel here. And so we're evaluating those items. But it's our expectation that by the fourth quarter we'll have something sorted out and in place regarding the crude oil transportation portion of it. Joe Allman – JPMorgan: Okay. And as it would seem that production would be declining with a lot less activity there and some of that Montana Bakken oil declining, are you seeing some opening of pipeline capacity as we move through early 2009 here?

Well, we're certainly seeing the number of well drilling in the Bakken right now, a number of rigs operating is dropping pretty precipitously right now. This is by the entire industry and so there will be some decline in the production and that will make a little more space in the pipeline, but our view is that long-term there was so much potential up there in the Bakken that there is going to have to be a very, very significant pipeline infrastructure change and that might be two years to three years away to take away all the pipeline, everything by pipeline. So that's why we're looking at other alternatives such as rail cost. Joe Allman – JPMorgan: Got you. And then moving over to the Barnett combo. What kind of infrastructure requirements do you have there?

We spent 2008 pretty much putting those infrastructure items in place. So we're essentially good to go from this point forward and don't anticipate any infrastructure limitations there. So the question there really is how much capital do you deploy into the play and what's the relative economics of it and relative to the hydrocarbon prices and the economics are already there. The limitation we have is we want to be roughly balanced on cash flow and CapEx and so we're not going to overspend to go hog wild in this play during 2009. Joe Allman – JPMorgan: Got you. Mark, earlier when you talked about current hydrocarbon prices giving you up to a 50% or so rate of return, you were talking about the strip there, right?

Yes, basically just taking the strip for taking current prices and using the NYMEX and not even not to 10 years or so. Not really going with any big hockey stick in oil and gas. Joe Allman – JPMorgan: Got you. And then lastly, I know that you didn't have too much in the way of impairments or revisions, and but in terms of your ability to add reserves, did you have any issue with not adding some reserves because of the low prices at year-end '08?

No. Nope. Joe Allman – JPMorgan: Okay. Alright. Very helpful. Thanks, everybody.

We'll go next to Brian Singer with Goldman Sachs. Brian Singer – Goldman Sachs: Thank you. Good morning.

Brian. Brian Singer – Goldman Sachs: You spoke earlier with regards to I think Tom's question on the evolving Hainesville view. And I wondered if you could also do the same for the Marcellus, characterize how your view on the Marcellus has changed with the recent well results you've seen?

Yes, I'll let Loren handle that one.

Yes, Brian. We've mentioned that we have the 220,000 net acres, 40 of those in Bradford that we're feeling pretty strong about, really based on the last two wells we drilled here. It looks like there about 2.5 Bcf per well gross 2.0 net. That's a pretty area that Barnett is quite a bit thicker in and pretty good drop quality. In the other area we mentioned, which is on the NFG farmout, and really comprises the rest of our 220,000 net acres, we now had one well completed that we feel like we put our best foot forward on a patch up with that's a more like probably 2 Bcf well gross, 1.6 Bcf net which we think is quite replicable in that area. I guess overall I'd say that we like the rock parameters we're seeing in the Marcellus, although relative to the Barnett is quite a bit thinner. So the gas in place per square mile is less, the permeability is pretty decent. We still have a bit of a disconnect with maybe some of the rest of the industry and what we think the reserves per well going to be and perhaps that has some to do with the geology north versus geology south. But it's hard for us to see how. It's relative to Barnett, for example, in Johnson County, we're averaging 2.5 Bcf per well with about twice the gas in place per section and what we would consider to be better frac barriers and that's on 30-acre spacing. So the question really for the Marcellus is not just a good play, it's a good play, it's got good finding costs, decent reserves per well. The question is what is the drainage area going to be and what are the overall reserves going to be because of that? At about 80 Bcf gas in place per section which is what we would guess would be an average for the better part of the Marcellus, you have to have a 40% recovery efficiency on 80 acres spacing to make four Bcf wells. We think that's a bit of stretch at least in our area. Brian Singer – Goldman Sachs: Got it. Yes. That's really helpful color. Switching to just the general CapEx versus cash flow plan, assuming that you increased your spending in rig count to the extent that oil and gas prices move up, what gives you the confidence that gas prices will move to that, I think, 800 to 850 range in 2010 you spoke of and on the margin, if gas prices go up, will you use the additional cash flows – oil wells or gas wells?

Our feeling regarding 2010 on gas prices are that, if just take where we believe the – the total North American gas production will be by December, it will be roughly 3.3 Bcf a day lower than it started the year at. And the other more important part is that both in the U.S. and Canada, the slope at year-end is going to be inflecting downward fairly strongly. So as you get into 2010, even if you get an instant price increase, it's going to take until mid to probably late 2010 just to get that slope inflecting back to neutral and to turn it up on production growth. And we think if you basically have a 3.3 Bcf a day swing in, in supply for North America indigenously and we are predicating some recovery in 2010 for industrial demand versus this year that the market could turn around perhaps pretty violently in a – in a bullish way for – for producers. So, that's kind of our call. As to the question of will we be directed CapEx more heavily toward gas or oil? If you assume we end the year at $60 oil or $70 oil, we get pretty bullish on gas, I'd say that it's fair to say a preponderance of our – an increasing amount every year of our total CapEx will be devoted toward oil directed projects, I guess the best way to put it. Brian Singer – Goldman Sachs: That's helpful. I guess lastly, are there areas within your own portfolio or your thoughts on others that as a result of what you're seeing in Hainesville Marcellus will likely not return from a drilling perspective, i.e., are there areas that will be – that will see secular shifts down in the rig count?

Well, the one that's most surprising to me now is just the overwhelm industry Barnett reaction. And I don't believe it's – it's my belief you get two things going on in the Barnett. The first is I believe in the – in the urbanized area of the Barnett, I think that people are finding it's – it's becoming increasingly difficult to drill and complete wells in a cost-effective manner, not so much because of reserves are lacking but just because the costs are extremely high. To drill wells, frac wells, and connect them to sales in the urbanized area, which EOG is not located, and so I think that people are – are recognizing that, that area is a bit more economically challenged perhaps than the Street expects and you're seeing rigs move out of the Barnett. I would say that boom in the Barnett is probably over, but it will be a steady contributor and we're certainly not saying that the Barnett's going to go on – in aggregate it's going to go in something terminal decline over time. But I think we've clearly seen the peak of the Barnett. And then the other area that I've commented on very frequently is that the Gulf of Mexico, both the shelf and the deep water for gas, I think is in my opinion, it's – it's definitely on a secular decline, simply because the economics there just cannot compete with what we're seeing in some of these resource plays. Brian Singer – Goldman Sachs: Thank you very much.

We'll go next to Ben Dell with Sanford Bernstein. Ben Dell – Sanford Bernstein: Hi, Mark.

Hey, Ben. Ben Dell – Sanford Bernstein: I had just two quick questions. The first is on Trinidad. You mentioned you weren't drilling any exploration well. Do you have a feeling for whether Trinidad LNG can continue to support the volumes it's been exporting over the next two years to three years if the offshore plays don't invest incrementally?

Yes, that's a – that's just a tough question because we're not directly involved in the LNG there. Our feeling is that for the existing LNG plants, they're pretty well backed up by reserves. And I would be surprised if over the next short period of time that we see any shortfall in feedstock those LNG plants I think those reserves are pretty firm. I think the issue in Trinidad is that with no one looking for any new gas, the ability to grow the Trinidad industry in terms of having source and supplies, that's the big challenge that is going on there right now. Ben Dell – Sanford Bernstein: Okay. And just an another question, for the second year running, I think probably the third year running, your Canadian operations have reported weaker days than your U.S. operations. When you look at your 2009 capital budget, can you give us some indication of how much CapEx you'll be allocating to Canada versus the U.S. and how you stack up the investment in that region versus the U.S.?

Yes. Let me have Gary answer that, Ben.

Yes, in Canada we are as you probably would expect curtailing our activities there and it will be about 10% of our budget here for 2009. That's the combination of Calgary, Canada shallow gas, as well as BC operations in the Horn River.

Yes –what – part of the issue that we've had really in the last year or two relating to the Canadian refining cost has been the just startup investment of particularly land investment in the Horn River. So it's one of those that once we get it up and running it will look a lot better on finding cost. But clearly if you stripped out the Horn River for a minute, the relative prospectivity for the rest of Canada is a bit challenged, we're hoping to have some further horizontal drilling success up there in other plays over the next year or two, but that's not firmed up yet. Ben Dell – Sanford Bernstein: Okay. Thank you.

And due to time constraints, we'll have to take our last question today from Leo Mariani with RBC. Leo Mariani – RBC: Yes, thank you. Question on Hainesville, I was just trying to get a sense of what your takeaway capacity is in the area. Do you guys have any firm transportation on those pipelines and what's your plan for gathering?

Yes, we have firm transportation of $80 million a day coming on here in April this year. So we don't – we've got a couple of other outlets that are in the range of $20 million a day. So we don't see us having any curtailment here on volumes because of capacity restraints for the next year or so. Leo Mariani – RBC: Okay. Jumping over to Bakken, is there any update on progress of your 320 acre space wells?

Yes, in the Bakken area, in the core area, our current feeling is that most of the core is going to be adequately developed on the current 640 acre spacing. But there is part of the core that kind of border lines the Bakken light area that probably will be drilled on 320 acres spacing. But I would say the preponderance of the core is just not apparent to us the evaluation we've done at 320 acre spacing, it's going to be widespread across the whole area Leo Mariani – RBC: Okay. Question on the financial side here. I know that you had a pretty sizable current tax benefit in the fourth quarter, roughly $69 million. Just trying to get my arms around that a little more and what cause that?

As far as the shift between deferred and current – it's simply a shift in the decreasing gas prices and less taxable income and higher mark-to-market being reversed out. Leo Mariani – RBC: Okay. Last question here. You guys talked about I think $4.5 million well costs in the Barnett – I'm sorry, the Bakken light area. What do you guys seeing for well costs in the core? Have those changed at all? Have they come down for you folks at all?

Yes, they've come down. I guess probably last year we averaged about $5.4 million and they're down to about $4.8 million now and we've expect to see the $4.5 million well cost there, really the core as well as the branch, maybe little lesser on the branch. Leo Mariani – RBC: Okay. How about in your well play in terms of well costs these days?

In which play? Leo Mariani – RBC: The BC shale play neula [ph]?

Yes. We've got a goal of getting our well costs down there to $10.5 million. It's going to take us – working pretty well on that. We're in the range of $13 million right now. Leo Mariani – RBC: Okay. Thanks for your time.

Quite a few things in place there similarly to what we've done there in the Bakken. That's big advantage of having that play and they're pretty similar. So we're carrying that technology to BC right now. Leo Mariani – RBC: Okay. Thanks.

That will conclude today's question-and-answer session. I'd now like to turn the call back over to Mr. Papa for any additional or closing remarks.

I have no further closing remarks. I just like to thank everyone for staying with us on the call. We'll talk to you again in three months.

Thank you, ladies and gentlemen. That will conclude today's conference call. You may disconnect at any time.