EOG Resources, Inc. (EOG) Q2 2010 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the EOG Resources Second Quarter 2010 Earnings Results Conference Call. [Operator Instructions] At this time, for opening remarks and introductions, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead.

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing second quarter 2010 earnings and operational results. 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 website at www.eogresources.com. Effective January 1, 2010, the SEC now permits oil and gas companies, in their filings with the SEC, to disclose not only proved reserves, but also probable as well as possible reserves. Some of the reserve disclosures on this conference call and webcast, including those for the South Texas Eagle Ford, Barnett Shale and New Mexico Leonard plays may include potential reserves or estimated reserves not necessarily calculated in accordance with or contemplated by the SEC’s latest reserve reporting guidelines. We incorporate, by reference, the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page in our website. With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President of Investor Relations. An updated IR presentation was posted to our website last night, and we included third quarter and updated full year 2010 guidance in yesterday's press release. We're still on track to deliver 13% total company organic production growth this year. Our shift to a higher liquid ratio is proceeding as planned, and as with the first quarter in EOG's history where liquid revenues exceeded gas revenues. As we reported in our April analyst conference, production will increase every quarter this year, giving us strong momentum going into 2011. I'll now review our second quarter net income and discretionary cash flow, and then I'll provide operational highlights and discuss our capital structure. Tim Driggers will provide some financial details, and I'll close with comments regarding our macro hydrocarbon view in concluding remarks. As outlined in our press release, for the second quarter, EOG reported net income of $59.9 million or $0.24 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income to eliminate mark-to-market impacts and certain onetime adjustments as outlined in the press release, EOG's second quarter adjusted net income was $44.9 million or $0.18 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the second quarter was $656.2 million. I'll now address operational results, and we have plenty of good news to report. Perhaps the two biggest new items were our New Mexico Leonard Shale horizontal oil discovery and the results from some of the best wells ever completed in the Haynesville Shale. In Southeastern New Mexico, we've been working over a year on our Red Hills area, Leonard Shale play, and our first horizontal well now has a 300-day production history. I'll note that the Leonard may also be called the Upper Bone Spring or Avalon Shale, as there are some industry variance in terminology. We now feel we have reserve potential of 65 million barrels of oil equivalent net after royalty reserves on 31,000 of the 120,000 net acres we have in the play, which completed seven horizontal and four vertical wells, and we believe typical for well reserves for horizontal wells or about 400,000 barrels of oil equivalent net after royalty for $6.5 million well costs, which yields a 40% direct after-tax reinvestment rate of return using NYMEX future prices. Typical wells are at Lomas Rojas 26 #1H and #2H, which tested at 710 barrels of oil per day with 1.7 million cubic feet of rich natural gas, and 800 barrels of oil per day with 1.5 million cubic feet of rich natural gas, respectively. We have 100% working interest in these wells. We're currently testing other portions of our 120,000 acres and we'll have results before year end. I'll note that the production stream from this accumulation is analogous to our Barnett Combo play, since 1/3 of the production is crude oil, 1/3 is NGLs and 1/3 is residue gas. This play is just starting up. It will be late 2011 before we see a substantial production contribution from this asset. Moving to the Haynesville. During our April analyst conference, we advised that we delineated a new core area in Nacogdoches and San Augustine Counties in East Texas. Our most recent well results certainly confirm this. Our Murray #1H well have reached 25 million cubic feet a day of natural gas for the first 30 days, and the Crane #26-1H well average 27 million cubic feet a day for the same period. We have 96% working interest in those wells. Also in East Texas, at 49% working interest, Walter #1H well IPed at 21 million cubic feet a day. We believe the Murray and Crane Wells are two of the top three Haynesville wells completed anywhere in the Louisiana or Texas trend today. We continue to limit our flow rates in the Haynesville to manage pressure drawn out of the reservoir, and these two wells were also limited by short-term pipeline constraints. Fortunately, a significant portion of our 160,000 Haynesville and Bossier net acres are in this Texas sweet spot. In our April analyst meeting, we also noted that the Bossier Shale was a separate target, and our recent 100% working interest Red River 5#3H confirms our view, testing at 15.2 million cubic feet a day with 6,750 psi flowing tubing pressure. After several months of production, our Bossier wells appear to be as good as our Haynesville wells. Overall, we're extremely pleased with both our Haynesville and Bossier results, and this play will be the main driver to make up for the gas volumes being divested in our anticipated Canadian shallow gas property sale. I'll now provide more color regarding four of our horizontal oil plays: the Eagle Ford, Bakken, Barnett Combo and Niobrara. In the Eagle Ford, we're continuing to get consistent results. We're currently drilling with only a moderate activity level until we get all of our 3D seismic shot interpreted. Also, our activity in this area has been constrained by the lack of frac equipment. I'll note that we've previously dealt with similar problems and equipment availability issues in the Barnett, and we created a proactive unique solution there and we'll do so again in the Eagle Ford. Completion results we've noted this quarter, some of which we've articulated in our press release, indicate a consistent 120-mile-long accumulation with per well reserves similar to that outlined in analyst conference. Typical well completions are the Darlene #2H, Coalic 1H and Hoff 7H wells, which IPed at 1,033, 1,002 and 625 barrels of oil per day, respectively. The recently completed, the Borgfeld #1H and #2H wells, these are our first wells in Wilson County for 707 and 836 barrels of oil per day, respectively. We have 100% working interest in these wells. To date, we drilled and completed 31 wells in the Eagle Ford. We currently have 25 wells waiting on completion, which will contribute to the second half oil growth this year. We're currently running five rigs and we'll ramp up to 12 by year end. One measure of the intensity of our future Eagle Ford development is that we plan to drill 245 gross wells in 2011 compared to 111 wells this year. The same story of consistent results holds true in our Bakken play. We have 12 rigs running there at a typical per well reserves for both the Core and the Lite are similar to those previously provided. Two recent Core wells, the Van-Hook 7-23H and Fertile 37-07H came online at 2,525 and 1,654 barrels of oil per day. We have 64% working interest in the Van-Hook well. That's a correction for the 99% we noted in our press release, and we have 81% working interest in the Fertile well. A few days ago, we also completed the Van-Hook 8-36 well for 2,100 barrels of oil per day, which will contribute to third quarter volumes. Another note is the three recent wells on the western part of our acreage near the Montana state line, our Round Prairie, Carat and Hardscrabble wells, recently tested at rates that are typical over Bakken Lite wells, giving us greater confidence in the western extent of our acreage spread. This year, we plan to drill 42 Core wells, 57 Lite and 18 Three Forks wells. We'll also be drilling some longer reach laterals and will have results by year end. We are still early in drilling 1,280 acre space wells. A recent Eastern 1,280 space lateral is Palamo 2-18, which tested at 1,036 barrels of oil per day. In the Barnett Combo play, we're operating 14 rigs and our typical horizontal results are characterized by the Murray #1H well, which tested at 452 barrels of oil per day, with 2 million cubic feet of rich gas, and the Break 2H, which tested at 528 barrels of oil per day with 2 million cubic feet of rich gas. The King #1H and Olden B#1H wells were outlined in the press release and tested at 344 with 2.5 million cubic feet of gas, and 323 barrels of oil per day with 1.7 million cubic feet of gas. The Alamo B#6H well is still cleaning up and is producing 500 barrels of oil per day. We've expanded our definition of the Core Combo from the previous 125,000 net acres to 150,000 net acres based on recent drilling results. In all areas of the Combo, except the East, our results were similar to our models. On the last quarter's call, I noted outstanding results from the Settle B# 1H well, which was a horizontal drilled in the 25,000-acre eastern portion of our play previously designated for vertical exploitation. After producing this well for three months, we estimate it will produce 260,000 barrels of oil, 412,000 barrels of NGLs and three Bcf, net after royalty, in residue gas or 1.1 million barrels of oil equivalent net after royalty, for a $4 million well costs, and a greater than 100% direct after-tax reinvestment rate of return. These reserves are considerably higher than our model well estimates. Additionally, results from our second horizontal in this same area, the Richardson #3H, seem positive, is a 325 barrel oil per day restricted rate while still cleaning up after frac. Additionally, or accordingly, we've changed our 2010 Combo program toward more horizontals and less verticals in the eastern area. Our original plan was 126 horizontal and 120 vertical wells. Now it's 200 horizontals and 34 vertical wells. This switch from verticals to horizontals, with 100% rate of return, will likely increase the overall oil ore of the Combo play. I'll also note that we currently have several large multi-well patterns on after frac flowback, and we expect to see a significant increase in our Combo production in the second half. We also have some new data on our Colorado Niobrara play. We've completed two additional wells, the Critter Creek #02-03H and #04-09H, and they're producing at managed restricted rates of 570 and 600 barrels of oil per day, respectively. We have 100% working interest here. We have four rigs running in this play. But as we've previously stated, we want to observe production from these and earlier wells until year end, before we make a reserve estimate because the reservoir is heavily fractured. In Southwest Kansas, we also recently completed two nice shallow vertical wells with 100% working interest. The Cynthia 35-1 IPed at 1,700 barrels of oil per day, and the Brookover 8-2 well IPed at 260 barrels of oil per day. Several offsets to these wells are planned for the second half of the year. Returning to our natural gas assets, we're continuing to have good results in the Barnett gas window. We're running two rigs in the Barnett gas area and recently completed six more unit wells in Tarrant County with an average IP of 7.5 million cubic feet a day each, with 68% working interest. Our all-in total Barnett gas finding cost year-to-date is $1.48 per Mcf. In the Horn River Basin, we're completing 11 wells from our winter drilling program and anticipate having flow results on next quarter's call. In conjunction with Apache, we're making steady progress with Kitimat LNG, although we are still early into our project. The key to this project is securing an oil index LNG contract, and we're in the preliminary stages of discussions with potential off-takers. In summary, all our North American operations are proceeding as expected, but we've had recent upsides in the New Mexico Leonard Shale, the Eastern portion of the Barnett Combo and the Texas Haynesville. Outside North America, our Trinidad asset is currently in a producing node. We plan to begin development drilling in the Toucan field during the fourth quarter. In China, we've completed a second horizontal gas well, and it's performing okay, but not as good as our first well. By year end, we'll have completed two more gas wells and one oil well, and we can assess the overall program. Outside of operations, another part of our business plan this year involves the sale of some producing natural gas assets and some horizontal shale gas and oil acreage that we are looking to close by year end. This one encompass two separate packages. The first consists of Canadian shallow gas production of 170 million cubic feet of equivalents per day, which was put on the market two weeks ago. The second package will consist of 180,000 acres of domestic horizontal shale gas acreage in the Marcellus and Haynesville, and some rich gas and crude oil acreage in the Eagle Ford. We considered the JV related to this acreage, but instead decided on an outright sale because it's cleaner and less complicated. This acreage package is larger than we've contemplated three months ago. We spent about $1.7 billion over the last few years accumulating first mover horizontal shale acreage, and frankly, we have more good acreage now we can say grace over, given our manpower and capital structure plans. So we're going to monetize a bit in this acreage. Our intention is to close these sales by your end, and maintain a year end net debt-to-cap ratio of 25% or less for 2010 through 2012. You'll note that our estimated CapEx for this year has increased $500 million from prior estimates, primarily because of higher frac cost and the increased number of production facilities, particularly in the Eagle Ford. All of this incremental CapEx is related to oil projects, roughly 270 of the incremental $500 million is due to EOG installing oil facilities that we previously plan to have a third-party midstream company installed. We did this because of timing and cost issues. Even with this higher CapEx, we expect to maintain a year end net debt-to-cap ratio of 25% or less. I'll note that the potential sale of a small portion of our Eagle Ford acreage doesn't affect our 900 million barrel of oil equivalent, net after royalty, captured reserve estimate we previously provided. I'll now turn it over to Tim Driggers to discuss financials and capital structure.

For the quarter, capitalized interest was $19.8 million. For the second quarter 2010, total exploration and development expenditures were $1.3 billion excluding asset retirement obligations. Total acquisitions for the quarter were $4 million. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $55 million. At quarter end, total long-term debt was $3.7 billion, and the debt to total capitalization ratio was 27%. At June 30, we had $650 million of cash, getting us non-GAAP net debt of $3.1 billion or net debt to total cap ratio of 23%. The effective tax rate for the second quarter was 46%, and the deferred tax ratio was negative 24%. Yesterday, with the earnings press release, we included a guidance table for the third quarter and updated full year 2010. For the full year 2010, the effective tax range is 40% to 50%. This higher range is due to the impact of international operations. We've also provided an estimated range of the dollar amount of current taxes that we expect to record during the third quarter and for the full year. Transportation costs exceeded the second quarter guidance that we have provided, due to the impact of several firm transportation contracts in the North Dakota accrued by rail project. These marketing arrangements generally ensure more reliable markets and better prices for our products. During the second quarter, we had better realizations for both U.S. gas and U.S. crude oil. We sold our U.S. gas at a premium to Henry Hub during the second quarter. For the Bakken crude that is being shipped to Cushing by rail, we are realizing full WTI at Cushing. Now I'll turn it back to Mark.

I'll now provide a few macro comments. Regarding oil, we continue to be, what I'll call, rationally bullish, both short and long term. I'll note that 2010 global oil demand is currently expected to be 86 million barrels a day, the same level as in 2008. So oil demand has recovered from the global recession faster than almost anybody had predicted. The demand mix, of course, has changed, where China, India and the Middle East are bigger drivers than the OECD. Barring a doubled-dip recession will likely outlook for future oil prices. We have a small amount of oil hedged in the fourth quarter and have 6,000 barrels of oil a day hedged at $93.18 for 2011. North American gas, however, is more opaque. One hopeful sign is that recent U.S. storage has been filling at a net 2.6 Bcf a day lower rate than last year. Since May 1, we've injected 244 Bcf less over 91-day period. Additionally, Canadian storage has swung 128 Bcf year-over-year, or 1.4 Bcf per day during the same period. Combined, this is a four Bcf a day storage tightening year-over-year since May 1. This may be due to either hot weather, strengthening industrial demand or supply declines. We're also encouraged by the last two EIA-914 report showing flat production, which matches our internal models. We continue to be moderately bullish regarding short-term gas prices. We currently have 150 MMBtu per day hedged for 2011 at an average $5.44 price and 100 million BTU per day hedged for 2012 at an average of $5.44. Now let me summarize. In my opinion, there are two points to take away from this call. First, our conversion from a natural gas weighted to an oil weighted North American company is proceeding very well. All of our oil plays are performing similarly to what was presented in our April Analyst Conference, and we've now added a new Leonard Shale play. You'll recall that in our April conference, we specifically noted that our oil production growth would be lumpy and not in a straight line quarter-to-quarter and that's exactly what is occurring. This is the nature of the development of these horizontal assets for maximum reserve recovery, whereby we drill and complete a group of five to 15 wells together before bringing any of them to sales. I'll also note that as other E&P companies have subsequently proclaimed themselves to be liquids rich, the distinction between crude oil and lower-valued NGLs since to have been blurred. To recap, our acreage in Eagle Ford, Bakken and the Niobrara, our crude oil perspective with minimum NGLs, or the Barnett Combo and Leonard plays, provide both crude oil and NGLs. Although we have some associated NGL growth, overall, our program is dominated by crude oil growth, specifically, we expect roughly 75% of our 2010, '11 and '12 liquids production to be crude oil and condensate and 25% to be NGLs. And then our second closing point is that our capital plan is on track and consistent with that articulated at our Analyst Conference. Our intention is to shift this company to an oil mix organically, while maintaining a low debt level. Thanks for listening, and now we'll go to Q&A.

[Operator Instructions] Our first question today will come from Scott Wilmoth, Simmons & Company.

Just looking at the production guidance, there was a pretty healthy production ramp implied in second half 2010 in order to meet the midpoint of guidance and that's largely attributed to the U.S. You guys mentioned the Combo, being an area that will ramp significantly in second half. Are there other areas on a regional basis that are infrastructure bottlenecks or completion backlogs that are going to be relieved in second half 2010? Or is this ramp mostly going to be from increased drilling?

The other areas where we're going to see increased production are the Niobrara and the Eagle Ford clearly, and also in the Bakken, some of our key plays. And I'd say this, we don't have that much that's truly infrastructure related. The key point here is that we basically batch drill these wells, then we batch complete them before bring any single well online. And so as we mentioned in our April conference, you can't project our production growth for either 2010, '11 and '12, that is a straight line quarter-to-quarter-to-quarter. If you try and do that, it's just flat, not going to work. And it so happens that our second quarter production happen to be a quarter, where we were completing a lot of wells, but not bringing them to sales. And the third and fourth quarters are ones, where we're going to be kind of in the opposite of that cycle. We'll be bringing a lot more on sales relative to our operational activity.

And then moving on to well costs, can you talk about well costs in general? And can you identify what regions you're seeing the most inflation?

Yes, we've seen most of the increase there in the South Texas, predominantly because of the Eagle Ford Shale and the Haynesville. And yes, those stimulation costs are up. And yes, we're working these, essentially new plays and EOG will find ways to secure stimulation services and suppliers in order to lower those costs.

Can you quantify any of those increases?

Yes. We have the drilling costs, it's gone up about 3% predominantly on the rigs. Our average rig rates run at somewhere around 17.5% and about 17% first of the year. And stimulation cost have gone up anywhere from 10% to 40% just depending on the area. So you kind of factored in our well costs going up maybe somewhere around 6%.

And then on your second sale package, you mentioned 180,000 acres. Can you give us the breakout between the plays on the acreage?

Yes, we can give you a breakout. About 51,000 of that 180,000 are Marcellus acres in Bradford County, which is kind of in the sweetest spot of the Marcellus. About 117,000 acres are in Eagle Ford and some of that is in the dry gas, some of that is in the wet gas and some of that is in the oil window. So kind of broken in all three. And then a smaller amount, about 15,000 acres is in the Haynesville play.

And then lastly, this second sale package and your Canadian shallow gas package expected to close by year end. How far does that get you guys along your total divestiture process?

I mean, that's where we think we will be for all of 2010 and all of 2011 and '12. At this juncture, we don't plan any additional divestitures, except for maybe some very small things beyond these two packages.

Next is Brian Singer with Goldman Sachs.

Mark, in your comments, you mentioned that you had created a proactive unique solution in the Barnett that you plan to apply to the Eagle Ford. Can you talk and add a little bit more color on that in terms of reducing some of the frac constraints, when you expect to have that in place and whether that would alleviate some of the reasons for perhaps why the Eagle Ford moved a little more slowly in the quarter?

Kind for confidentiality purposes, Brian, but I'll give you a bit of a circuitous answer on that. There are two issues going on currently in the States and specifically in a place such as the Eagle Ford. One is just the availability of profit, whether that's sand, resin-coated sand or some kind of intermediates casing profit. There's a very, very tight market. And then the second thing is just the availability of pumping services, if you will. And although the service companies are expanding their unit of pumping services and it's probably going to lag the system a bit. And so we're going to address both of the issues, the profit and the pumping services in a way that we believe is going to give us a long-term cost advantage, but we don't want to go with a lot of specificity at this juncture. But our view is, we did a similar thing in the Barnett because we have very significant gas and, of course, the Combo liquids reserves. And we're talking about close to 1 billion barrels at the Eagle Ford, and so we're gearing up for something very long term and very permanent kind of a solution.

And when do you expect to have them in place? Is that something that will be gradual or is that something that is on the cusp of being completed?

It's gradual. It's in place currently, just very early stages. Most of that will take place in 2011

Then lastly, I think in response to the previous question, you indicated that the asset sales, the two packages are really it for the next few years. Given that, how are you thinking about managing CapEx versus cash flow in 2011? Or should we just look at the 25% net debt to total cap as your main source of what you're gearing for there?

Yes, I guess the bottom line on that, Brian, is that if we get the price that we think is a fair value for these two asset packages, plus with our expectations of how the carbon prices will be in 2011 and '12, the numbers kind of come out that we don't hit the 25% debt-to-cap level. We stay below that. So at this juncture, we don't look like we need to sell anything else. And so that's the way the plan works out. I don't want to go specifically into what we expect in terms of price for these packages, but I don't want to signal anything to prospective buyers, but that's the way we formulated our plan. We've accumulated so much acreage at such a cheap price over the last three years by being in the first mover position that gives us flexibility that some other people maybe don't have. And then we've looked at the JV piece of this thing and to us, the JV kind of complicates the issues. We end up using our manpower for something less than 100% working interest on there. And so we just thought it would be cleaner to kind of sever our position with an outright sale of this acreage.

To conclude then, if you get the proceeds that you're looking for, you'll probably end below the 25% this year. And then I guess next year, maybe you do spend a little bit over cash flow to generate 19% growth? Or do you have plans to stay within cash flow next year to achieve that great rate of growth?

No, as we would see it now, it's pretty consistent with what we said at our April Analyst Conference. We're likely to outspend our cash flow, our operating cash flow in 2010 and 2011 and then go positive on cash flow versus CapEx in 2012. And so what we need to do is get enough proceeds from these sales to cover us for the gap in both 2010 and 2011. That's what we believe.

And next is Leo Mariani with RBC.

Mark, you talked about selling off assets to kind of cover the gap, free cash flow gap in 2011. What are you thinking on, on gas prices next year in terms of what you're forecasting to kind of get you there?

Yes, pretty similar to $5.50 range. We're not counting on $7 gas prices next year. We take them as they come. But it's not a particularly aggressive gas price forecast. Pretty similar to what the NYMEX is indicating for '11 currently.

Jumping over to the Leonard Shale, I guess you guys reported two well results, horizontal well results that is and you had five others. Were those five others that you haven't disclosed rates on reasonably consistent over the two rates you reported, but those are the latest rates. Have you seen kind of improvement? Can you give us a little bit of chronology there?

The chronology there is we drilled a short lateral and completed that well and brought it on production of about 300 days ago. And we just observe production and kind of kept quiet about the play for four or five months to just see, is the production going to fall off sharply or what's it going to level out at. And during that interim, once we felt good about it, we began to accumulate a bit more acreage there. And so as we would see it, we've now spend enough time with this play and have enough production history and drilled enough wells over the 31,000-acre portion of our 120,000 acres that we feel pretty good about that portion, and we feel pretty good about the production declines. The two wells that we were reporting, those wells have been online anywhere from 30 to maybe 40, 50 days. And they're more the 5,000-foot lateral length wells with the optimized fracs. So they're more typical of what we would expect on a go-forward basis. And then concurrently, we're drilling on some of the acreage outside the 31,000 acres. And at least for a portion of that, we feel pretty good. Some of it we just have to see, but a portion of the additional acreage has really been confirmed by some other E&P companies drilling good wells kind of around us.

I guess, just jumping back to your production guidance. You talked about sort of lumpy oil growth here, a lot of wells coming on in the second half of the year to boost volume. I guess looking at your U.S. gas production, you guys also had a pretty good increase in your forecast, about 150 million a day I think, second quarter to third quarter. I guess you mentioned a bunch of oil plays ramping up, what's going to happen on the gas side to get your guidance there?

I meant to say, Leo, that the lumpiness is going to occur in both oil and gas for these horizontal plays. The two big drivers for the gas side in the third and fourth quarter volumes relative to earlier quarters, the biggest single driver is the Haynesville, another driver will be the Horn River in Canada, which will be -- we complete the wells in the summer and then bring them online about September or so. And then in our South Texas division, we expect to see some significant growth. The South Texas division will be partly from horizontals and partly from some vertical wells in the Frio and Vicksburg formation.

In terms of the Niobrara, you guys talked about focusing on 100,000 of your 400,000 acres there. Is there any particular geologic reason you're focusing on that, or is that more just sort of infrastructure related?

That's really infrastructure related. I mean, we drilled the first two wells in that area and they got a ton of publicity and then we just said, "Well, let's see whether we have enough sustained production here to justify putting in some infrastructure." And so we've been really drilling specifically in that area. Not so much because the other areas are less perspective but it's just we want to get a core area that can justify particularly some gas pipeline infrastructure in there.

Anything you're noticing about those last couple of Haynesville wells in terms of, why they're so strong? Any sort of geologic reasons and what are your well costs there on the Haynesville in that area?

I think they're pretty typical geologically. That Texas sweet spot at San Augustine County is that they're slightly deeper than it is in Louisiana PPD depths are probably 13,000, 14,000 feet as opposed to 11,000 or 12,000 in Louisiana. So you have more pressure, and rock quality is actually a little better as well. Some of the geologic characteristics, the amount of clay, the amount of total organic carbon are very both positive in that area. So it's pressure and well quality together. We think it's indicative of that whole Texas sweet spot. Where most of our acreage is concentrated frankly. Well costs, I'll turn it to Gary.

The well costs are just a little bit higher in the area, but we continue to make progress on drilling costs by just having program drilling going on there in the Haynesville and our drilling costs just down, really about 15%. But overall, we're looking at 30-plus percent rate return all-in on these Haynesville/Bossier play.

And Rob Morris with Citi has as our next question.

You address a lot of my questions on the $250 million increase due to completion frac services per well, that's, if I do my math right, whether you're counting the full year or just second half wells, is about $500,000 to $1 million increase per well on those costs, which -- is that correct? That would sort of correspond to around the 30%, 40% increase in the completion cost in Eagle Ford and Haynesville, more toward the upper end of the range as was mentioned. Is that correct?

What it works out to is, just looking at the stimulation portion what portion that is of overall completion and then what portion that is of overall total well costs. We're looking at this percentage stimulation increasing our overall 2010 drilling completion CapEx by about $230 million.

Right, which works you to about $500,000 to $1 million a well increase in costs versus what you've taken there before right?

Yes, that's pretty close.

On the Barnett Combo, flow rate you highlighted today were a bit less than on the wells you highlighted in the first quarter. But apparently, you're restricting the flow rate there also like you're doing on gas in the Haynesville. Do you have any data or evidence that restricting that flow rate on the Barnett Combo or any of the other oil play you just have is actually improving the EORs or the economics there or how are you looking at that?

Yes, the reasons for restricting in the Combo versus the Haynesville are a little bit different. There about in the Combo play, we frac those primarily with 100 mesh sand. And we noticed if we pull them too hard early on, you get a lot of frac sands flowback there, which could cut out your surface equipment and could damage your front frac. And so what we decided to do is just say, let's just put a choke in there essentially and just flow them back at restricted rates early on, mainly just to keep the sand from cutting out things. In the Haynesville, I'd tell you that -- so the Combo, it's almost become a mechanical necessity for us to do that. So what you can expect from future earnings calls are may be a little more modest production rates as we report. And mainly, we should arrest the declines a little bit. In terms of the overall reserves, we don't think we can ascribe at this point that reduced flowbacks is going to increase or decrease the reserves one way or another. We just don't have enough data.

You didn't mention, I don't think, the well costs on the Niobrara wells. You gave the flow rate, but did you have how much it cost to drill those wells?

Those, about $4 million.

You mentioned the solution in the Eagle Ford similar to what you've done in the Barnett to sort of address the availability of pumping services. In the Barnett, you actually purchased your own sand mine. Looking down here in the Eagle Ford, can you utilize that sand here to offset some of those costs? Or might you look at acquiring profit manufacturer or another sand mine in addressing that issue?

Yes, we don't want to go in too many specifics on that, but I mean, we need to kind of integrate upstream a little bit, if you will, to get our hands on some profits. And there are several ways to do that, which is we're very active in that. But for confidentiality reasons, we really don't want to go any further with the discussion on that right now, Bob.

And next, we hear from Irene Hass with Canaccord.

Questions on Niobrara. Firstly, where are the Critter Creek wells located in relations to the Jake well? And how long was the lateral lengths and frac stage? Secondarily, on these fractured chalk plays, I want to ask you guys, are you staying away from the Silo Field on purpose? Anything to do with a fractured complexity? And then also as compared with your other oil resource plays, what are the nuances in dealing with the Niobrara chalk? And then sort of lastly, what is on your to-do list? How much more work would it take EOG to get comfortable in assigning a EUR and also a projection of what Niobrara could mean to EOG?

The Critter Creek wells are south and west of our Jake and Elmer wells that we talked about previously and a little bit north of our Red Poll wells. So they're all bunched together in what we call the Hereford prospect, that 100,000 acres of our total of 400,000 acres. So they're on 640 spacing currently. We're testing some closer spacing in there right now. Regarding your second question about why we avoided Silo, as we said at the analyst conference, we have mapped that whole basin and try to understand where the geologic sweet spots were, and actually, Silo mapped up as a geologic sweet spot. But we felt it was already fairly well developed, although there are possible extensions to that field, down spacing to that field. But we did not focus our leasing efforts there, because we felt like most of them is already HBP, and we, instead, [indiscernible] in the other sweet spots that we had met. Relative the other oil plays, the big question we have here is, what is the contribution from the flow that we're getting from fractures versus matrix? And really, we have not much to update you on from the analyst conference. We still are looking at production. We're watching how fast pressure declines with production and trying to understand, are we seeing matrix kick in or not. We think we're seeing some positive indications on some and not on others. It's just too soon to tell. What we believe is it'll take the rest of this year. They're closely monitoring these wells and wells that we'll be drilling between now and then to really understand, is it going to be a very, very large play that includes matrix contribution? Or is it simply going to be strong economic good rate of return play but with less overall reserves because we have two space it at maybe 640s or 320s, instead of 163. So that's the big question we're trying to deal with right now. We are testing a lot of different kinds of completions and proppants and spacing and trying to understand what we can do to enhance matrix contribution, but it really is too soon to tell.

The two wells, are they -- how long are the lateral lengths?

They're about 5,500 spud in length, Irene. And as Loren was saying, there's a whole lot of experimenting going on with our stimulation treatments to try to determine how we best stimulate the matrix in order to determine individual wells EURs to make an estimate of potential here.

Joe Allman with JPMorgan has a question. Joseph Allman - JP Morgan Chase & Co: Just a follow-up on the two Critter Creek wells, so just to confirm, you stimulated both those wells?

Yes. They were stage frac-ed and the exact methodology of the stage frac is kind of what we're experimenting with. Since the Niobrara seems to be of some interest to everybody, I mean we'll give you a little more color on the -- the Jake and Elmer wells appeared to be kind of stabilizing each at about 150 barrels of oil per day. And of course, remember that the first six months, they had pretty significant production, I think, 50,000 barrels or so in the first six months or whatever. So I'd say, overall, we're still cautious. We don't want to proclaim victory but we're getting a little more positive feeling than we had three months ago, particularly in observation of the Jake and Elmer wells, since those wells have a little longer line. But it's almost an issue of, okay, is this going to be, as Loren said, a very large oil reserve accumulation? Or is this going to be a more moderate size oil reserve accumulation? That's kind of the where we stand today on the overall play. Joseph Allman - JP Morgan Chase & Co: And, Mark, are you selling any of your acreage there in the Niobrara?

Yes, we've got some acreage that, again, we just flat can't get to all the acreage that we've accumulated, and so we have some acreage there that we're on the process of disposing. What we really did, we made kind of a choice in the company, and we said, okay, we've got a plethora of acreage and whether it's on these shale gas plays or the oil plays. And for us, to properly address all that acreage, we would have to be running in 2011 and '12 well over 100 drilling rigs. And we would be, I would say, as a company, a little bit out of control in terms of optimally managing those 100-plus drilling rigs. And we could do it and they will be great, but it's a bit of an uncomfortable position. So what we decided to do is, we said, "What do we really need to hit those growth targets that we've put out there for 2011, '12 and go forward? And do we really want to try and be in a little more controlled environment as far as our operational environment and maybe monetize a bit of this acreage?" So that's a little bit of the philosophy that's taken us to this asset acreage monetization strategy. We're going to be go on pretty much to the max in terms of our operational effectiveness in the second half of this year and in 2011 and '12, and we really don't want to go past that limit just because we have acreage that needs to be serviced, if you will. Joseph Allman - JP Morgan Chase & Co: So how much acreage are you selling there in the Niobrara?

Well, it's probably somewhere around 20,000, 30,000 acres.

Yes, out of 400,000. So again, it's not half our acreage or anything like that, not even close to it. Joseph Allman - JP Morgan Chase & Co: And then on LNG, how are the discussions going related to the oil index contracts?

Yes, still early days. I'd say we've got positive signs. And I'm sure if you ask Apache, who we're with working very closely, you'd get the same feedback, that discussions are in the very early stages. The way I'd gauge this whole project is, it's about the whole LNG project, it's probably a 10-step project, and right now, we were probably at step two. We've got step one done, step two is looking pretty good, but it's just -- I'd say all the elements are there to make this project come together. But it would be the first LNG project built by a non-major company and also would be the first LNG project built in North America as export project, except one that's in Alaska that was built 20 or so years ago. So we have to realize that what we're taking on there is pretty big scope, but the prize also is very big. It's not going to move on a just a rapid timeline in terms of -- we don't want to set any expectations that on the next quarter call, we say, "Eureka, the project's a done and we're moving forward with it." It's going to evolve a bit more slowly than that.

David Heikkinen, Tudor, Pickering, Holt, is next. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: Just to follow-up on Kitimat, thinking about the project and when you would start actually investing capital. And then if we think about project financing as well, would that impact to your 25% net debt to total cap threshold, if you project financed? And then when would you actually start investing capital?

Online, Dave, as we would see it now for this plant would be probably 2015. So the big CapEx investments would probably be 2013 or so. And one -- as we've talked about selling down our interest in several of these shale gas acreage plays, the one area that you have not heard me mention at all is the Horn River. And we have a enough acreage up there where we believe we have 9.5-or-so net PCF. And one option we have there is to bring someone in who might be an off taker into the acreage position, and use that to get some of our net funding for the LNG plant. So we've got several kind of tools there. I mean one is project financing. So I would say overall, our view is, the 25% net debt to cap is going to be our target throughout this LNG project also. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then on the asset monetization strategy, given some good operational explanations for selling versus joint ventures. Can you give us some thoughts around kind of rate of return or cost of capital difference for joint ventures versus asset sales?

Yes, we haven't really gone down that road on there in terms of that. It's just we've only got a certain staffing level here, and we can expand it a bit. But we can't expand it, double it in a couple of year period. And the question really boils down to, do we want to devote some of our scarce staffing level to basically educating someone else on a shale play and we do 100% of the technical work for perhaps a 50% net interest in the production or so? And we would just prefer to do 100% of the technical work for 100% of the production, and so it's almost a philosophical issue more than a calculated financial issue when compared to rates of return. And we can do that because we are so long on acreage relative to what we can logically develop during a reasonable period of time, so that's why we're looking at going that around. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then a little more technically speaking, on the Eagle Ford, you had relatively low GOR. Really interested in your thoughts around drive mechanism and recovery factors as compared to some of your gassier plays that you're experts in?

Yes, we're still looking at a limited job mechanism and a recovery factor there of, perhaps 3%, maybe 4% of the oil in plays as we'd see it there. It's not a water driver. It's more -- it's basically going to be just an expansion drive reservoir there. But again, it's early days in terms of Eagle Ford. I'd tell our staff that if one of the big integrated companies had essentially 1 billion barrel oil discovery somewhere, they would probably have 200 technical people assigned to only that project. And we certainly don't have 200 technical people assigned to this essentially 1 billion barrel project. And so I'd say, we've got it identified as far as length, width, pretty darn well, but there's a lot of other things that we're going to be working on and just kind of try to optimize. So what is the right spacing here? Where is the right location that we can drill a well in this? In some portions, you have two targets perhaps, upper and lower Eagle Ford. In other portions, you only have one target. And then there's also the potential of you have the Austin Chalk and the Buda that are very dear to Eagle Ford there. That some of our explorationists are clamoring to drill some wells in because they feel there are significant potential in those that we certain haven't had in anywhere. So what I'd offer to you is, this year, as we mentioned on our April conference, this is just a very slow start-up year for the Eagle Ford. And we'll probably shift from low gear to second gear in 2011 in the Eagle Ford, and then third gear in 2012 and maybe high gear in 2013 or so. It's just -- it's not one we're going to able to just turn it on and have these rapid volumes, and we'll be learning the whole time come. That's why we're going a bit more slowly here with only five rigs. If we're making any errors, I think technically, we don't want to multiply it times 14 or 15 rigs at this time. So that's more of an answer than you want to get, David. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then just on the Montana Bakken, your well result and just kind of differences. Can you give us any thoughts around types of completions? Or any differences in how you have completed those wells, and how you might complete them going forward?

Basically, we're -- a primarily external packers on a lot of those things. In terms of the reserve levels that we're seeing, we're seeing situations where it appears like the reserves are very similar to our Bakken Lite reserves that we articulated in April conference. And we'll probably be going to longer laterals out there, perhaps 7,500-foot laterals in that area. So the reason we kind of pointed it out is that there wasn't all that much drilling in kind of Western North Dakota, Eastern Montana portion of the acreage we had. And we always had a little bit of question mark, is it going to be good that far out? And we feel it's been answered in a positive manner now.

And we'll take our final question today from Biju Perincheril with Jefferies & Co. Biju Perincheril - Jefferies & Company, Inc.: When you look at 2011 activity levels and to the extent that you can talk about those, I mean are there any areas where you would see activity slowing down? I'm thinking Niobrara, Eagle Ford. Those activity levels haven't been rising to offset that?

Yes, I'd say that our Rocky Mountain gas development, we're not planning on doing much anything there and not even slow it down a bit year-to-year. Mainly because that acreage is all held by production in there, and we will be ramping up in several of the oil plays as we go forward.plays Biju Perincheril - Jefferies & Company, Inc.: Would it be fair to say, net-net, you'd be looking at a higher rig count in 2011, slightly?

Yes, probably. We haven't finalized any plans yet, but that's likely. And it's a higher rig count, 100% of the incremental rig count will be to those -- for oil projects. Biju Perincheril - Jefferies & Company, Inc.: And the Niobrara, I think one of the wells that you talked about at the analyst meeting was unstimulated completion, I think it was the Red Poll. How is that production holding up versus the other two that you mentioned that are stabilizing around 150 barrels a day?

Yes, that was -- we tried an unstimulated hole there, kind of an open hole completion. And what we ended up doing, post-analyst meeting is, we went in and cleaned it out and did more of a case-hole completion. And that well appears to be stabilizing in about 400, 500 barrels of oil per day. So it -- really, right now, what we call the Hereford ranch share, we've got five new wells pretty good. So let's say, we're warming up to the play consciously. Biju Perincheril - Jefferies & Company, Inc.: And then lastly, on the Leonard Shale, you'd said the production characteristics sort of similar to the Barnett Combo. But when you look at the rocks here today, would you say it more similar to the Eagle Ford in terms of [indiscernible] and the rock properties?

No. I think the Upper Bone Spring or Leonard, as we call it, is probably more similar to the Marcellus or Barnett or something like that, not to the Haynesville. It's more of a silica basis. It's got plenty of oil in plays for sections and it is a Combo-type three, probably a pretty good-sized play. It covers a large [indiscernible]. There's a lot of stratigraphic variation in play, both in the target itself and then in the barriers that you have, the amount saturation in the gas. So a lot to be learned by industry in that entire play right now.

Okay. Thank you everyone for listening, and we'll talk to you again in three months.

And that does conclude our conference call. Thank you for your participation.