EOG Resources Inc (EOG) 2010 Q2 法說會逐字稿

Good everyone and welcome to the EOG Resources second-quarter 2010 earnings results conference call. As a reminder, this call is being recorded. 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 US investors that appears at the bottom of our press release and investor relations page of 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 are still on track to deliver 13% total Company organic production growth this year. Our shift to a higher liquids ratio is proceeding as planned, and this was 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 will now review our second-quarter net income and discretionary cash flow, and then I will provide operational highlights and discuss our capital structure. Tim Driggers will provide some financial details, and I will close with comments regarding our macro hydrocarbon view and 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 one-time 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 will 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 Southeast 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 is 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. We have completed seven horizontal and four vertical wells, and we believe typical per-well reserves for horizontal wells of about 400,000 barrels of oil equivalent, net after royalty, for a $6.5 million well cost, which yields a 40% direct after-tax reinvestment rate of return, using NYNEX future devices.

Typical wells are our 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 enriched natural gas, respectively. We have 100% working interest in these wells.

We are currently testing other portions of our 120,000 acres and will have results before year-end. I will note that the production stream from this accumulation is analogous to our Barnett Combo play, since one-third of the production is crude oil, one-third is NGLs and one-third 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 averaged 25 million cubic feet a day of natural gas for the first 30 days, and the Crane 26 #1H well averaged 27 million cubic feet a day for the same period. We have 96% working interest in both wells.

Also in East Texas, our 49% working interest Walters #1H well IP'd 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 to date.

We continue to limit our flow rates in the Haynesville to manage pressure drawdown 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 6750 psi flowing tubing pressure.

After several months of production, our Bossier wells appear to be as good as our Haynesville wells. Overall, we are 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 will now provide more color regarding four of our horizontal oil plays, the Eagle Ford, Bakken, Barnett Combo and Niobrara. In the Eagle Ford, we are continuing to get consistent results. We are currently drilling with only a moderate activity level until we get all of our 3D seismic shot and interpreted. Also, our activity in this area has been constrained by the lack of fracking equipment. I'll note that we've previously built with similar proppant and equipment availability issues in the Barnett, and we created a proactive, unique solution there, and will do so again in the Eagle Ford.

Completion results we've noted this quarter, some of which we've articulated in a press release, indicate a consistent 120 mile long accumulation, with per-well reserves similar to that outlined in the analyst conference. Typical well completions were the Darlene #2H, [Coalich] #1H and Hawke #7H wells, which IP'd at 1033, 1002 and 625 barrels of oil per day, respectively.

We 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've 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 are currently running five rigs and will 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 and our 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 37-7H, came online at 2525 and 1654 barrels of oil per day. We have 64% working interest in the Van-Hook well. That is 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 2100 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 of our 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 will also be drilling some longer-reach laterals, and will have results by year-end. We are still early in drilling 1280 acre spaced wells. A recent Eastern edge 1280 spaced lateral is the [Palermo] 2-18, which tested at 1036 barrels of oil per day.

In the Barnett Combo play, we're operating 14 rigs and our typical horizontal results are characterized by the [Bray] #1H well, which tested at 452 barrels of oil per day, with 2 million cubic feet of rich gas, and the [Bray] #2H, which tested at 528 barrels of oil per day, with 2 million cubic feet of rich gas.

The King #1H and Olden #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 are similar to our models.

On the last quarter's call, I noted outstanding results from the Settle #1H well, which was a horizontal drilled in a 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 3 Bcf net after royalty and residue gas, or 1.1 million barrels of oil equivalent, net after royalty, for a $4 million well cost 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, with a 325 barrel of 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 ROR of the Combo play.

I will also note that we currently have several large multiwell patterns on after-frac flowback, but 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 2-3H and 4-9H, and they are 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] IP'd at 1700 barrels of oil per day, and the Brookover 8-2 well IP'd 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 are continuing to have good results in the Barnett gas window. We are 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 are completing 11 wells from our winter drilling program and anticipate having flow results on next quarter's call. In conjunction with Apache, we are making steady progress with Kitimat LNG, although we are still early into our projects. The key to this project is securing an oil-indexed 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 mode. 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 is performing okay, but not as good as our first well. By year-end, we will 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 will 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 a JV related to this acreage, but instead decided on an outright sale because it is cleaner and less complicated. This acreage package is larger than we contemplated three months ago.

We've spent about $1.7 billion over the last few years accumulating first-mover horizontal shale acreage, and frankly, we have more good acres than we say grace over, given our manpower and capital structure plans. So we are going to monetize a bit of this acreage.

Our intention is to close these sales by year-end and maintain a year-end net debt to cap ratio of 25% or less for 2010 through 2012.

You will note that our estimated CapEx for this year has increased $500 million from prior estimates, primarily because of higher frac costs and the increased the number of production facilities, particularly in the Eagle Ford. All of this incremental CapEx is related to oil projects. Roughly $270 million of the incremental $500 million is due to EOG installing oil facilities that we previously planned to have a third-party midstream company install. 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 will note that the potential sale of a small portion of our Eagle Ford acreage doesn't affect our 900 million barrel oil equivalent, net after royalty, captured reserve estimate we previously provided.

I will now turn it over to Tim Driggers to discuss financials and capital structures.

For the quarter, capitalized interest was $19.8 million. For the second quarter of 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, giving us non-GAAP net debt of $3.1 billion, or net debt to total cap ratio of 23%.

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 had provided due to the impact of several firm transportation contracts and a North Dakota crude-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 US gas and US crude oil. We sold our US gas at a premium to Henry Hub during the second quarter. Where the Bakken crudes is being shipped to Cushing by rail, we are realizing full WTI at Cushing.

Now I will turn it back to Mark.

I will now provide a few macro comments. Regarding oil, we continue to be what I will 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 double-dip recession, we like the outlook for future oil prices. We have a small amount of oil hedged in the fourth quarter and have 6000 barrels of oil a day hedged at $93.18 for 2011.

North American gas, however, is more opaque. One hopeful sign is that recent US 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 a 91-day period. Additionally, Canadian storage has swung 128 Bcf year-over-year, or 1.4 Bcf per day, during this same period. Combined, this is a 4-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 are also encouraged by the last two EIA-914 reports 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 a 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 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 will recall that in our April conference, we specifically noted that our oil production growth will 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 will 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 seems to have been blurred.

To recap, our acreage in Eagle Ford, Bakken and the Niobrara are crude oil prospective with minimum NGLs, while the Barnett Combo and the 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 will go to Q&A.

(Operator Instructions) [Scott Wilmoth], Simmons & Company.

Looking at the production guidance, there is a pretty healthy production ramp implied in second-half 2010 in order to meet the midpoint of guidance, and that is largely attributed to the US. 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?

It is not the -- the other areas where we are 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 would say that we don't have that much that is truly infrastructure related. The key point here is that we basically batch drill these wells, then we batch complete them before we 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 as a straight line quarter to quarter to quarter. If you try and do that, it is just flat not going to work.

And it so happens that our second-quarter production happened 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 are going to be kind of in the opposite of that cycle. We will be bringing a lot more on sales relative to our operational activity.

Great. That's helpful. And then moving on to well costs, can you talk about well costs in general? And can you identify what regions you've seen the most inflation?

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

Can you quantify any of those increases?

Yes, the drilling cost has gone up about 3%, predominately on the rigs. Our average rig rate is running somewhere around 17.5% and it was about 17% the first of the year.

And stimulation costs have gone up anywhere from 10% to 40%, just depending on the area. So (multiple speakers) kind of (inaudible) into our well cost going up maybe somewhere around 6%.

Okay, thanks. And then on your second sale package, you mentioned 180,000 acres. Can you give us the breakout between the plays on 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 the Eagle Ford, and some of that is in the dry gas, some of that is in the wet gas and some of it is in the oil window. So it is kind of broken into all three. And then a smaller amount, about 15,000 acres, is in the Haynesville play.

Okay, thanks. 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?

That is 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.

Okay, great. Thanks, guys.

Brian Singer, 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 then whether that would alleviate some of the reasons for perhaps why the Eagle Ford moved a little bit more slowly in the quarter?

Yes, kind of for confidentiality purposes, Brian, I will give you a bit of a circuitous answer on that. But there are two issues going on currently in the States, and specifically in a play such as the Eagle Ford. One is just the availability of proppant, whether that is sand, resin-coated sand or some kind of intermediate strength proppant. There is -- it is 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 is probably going to lag the system a bit. And so we are going to address both those issues, the proppant 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 are talking about close to a billion barrels at Eagle Ford. And so we are gearing up for something very long-term and very permanent kind of a solution.

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

It is gradual. It is in place currently or just very early stages. Most of that will take place in 2011.

Great. Thanks. And then lastly, I think in response to that previous question, you indicated that the asset sales, that 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 are gearing for there?

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 what hydrocarbon 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 is the way the plan works out. I don't want to go specifically into what we expect in terms of a price for these packages, but -- I don't want to signal anything to prospective buyers. But that is the way we've formulated our plan.

We've accumulated so much acreage at such a cheap price over the last three years by being in a first-mover position that it 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 issue. 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 from -- with an outright sale of this acreage.

Okay, great. So I guess to conclude then, if you get the proceeds that you are looking for, you will 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?

As we would see it now, it is pretty consistent with what we said at our April analyst conference. We are 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 is what we believe.

Great. Thank you.

Leo Mariani, RBC.

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

Pretty similar to $5.50 range. We are not counting on $7.00 gas prices next year. We take them if they come, but it is not a particularly aggressive gas price forecast. Pretty similar to what the NYMEX is indicating for 2011 currently.

Okay. 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 hadn't disclosed rates on reasonably consistent with the two rates reported? Were those the latest rates? Have you seen kind of improvement? Can you give us a little bit of chronology there?

The chronology is we drilled a short lateral and completed that well and brought it on production about 300 days ago. And we just observed 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 is 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 spent 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 are more the 5000-foot lateral length wells with the optimized frac. So they are more typical of what we would expect on a go-forward basis.

And then concurrently, we are 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 is, 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.

Okay. I guess jumping back to your production guidance, you talked about sort of lumpy oil growth here, a lot of wells coming on in second half of the year to boost volumes. I guess looking at your US gas production, you guys also have 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 kind of happening 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 are -- 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.

Okay. In terms of the Niobrara, you guys talked about focusing on 100,000 of your 400,000 acres there. Is there any particular geological region you are focusing on that, or is that more just sort of infrastructure related?

It is really infrastructure related. We drilled the first two wells in that area, and they got a ton of publicity. 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 prospective, but it's just we want to get a core area that can justify particularly some gas pipeline infrastructure in there.

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

I think they are pretty typical geologically of that Texas sweet spot in Nacogdoches, San Augustine Counties, in that they are slightly deeper than it is in Louisiana. The TVD depths are probably 13,000, 14,000 feet, as opposed to 11,000 or 12,000 in Louisiana. So you have more pressure.

And the raw quality is actually a little better as well. Some of the geologic characteristics, the amount of clay, the amount of total organic carbon, are both very positive in that area. So it is pressure and raw quality together, and we think it is indicative of that whole Texas sweet spot, where most of our acreage is concentrated, frankly. Well costs, I will turn that to Gary.

The well costs are just a little bit higher in there, but we continue to make progress on drilling costs by just having programmed drilling going on now in the Haynesville. And our drilling cost is down really about 15%. But overall, we are looking at 30% plus rate of return all-in on this Haynesville Bossier play.

All right. Thanks, guys,

Rob Morris, Citi.

Three questions real quick here. You've addressed a lot of my questions on the $250 million increase due to completion frac services, which, per well, that is -- if I did my math right, whether you are counting the full year or just second-half wells, it was about $500,000 to $1 million increase per well on those costs, which --. Is that correct? That would sort of correspond to around a 30%, 40% increase in the completion costs in Eagle Ford and the Haynesville, more toward the upper end of the range that 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 are looking at this percentage stimulation increasing our overall 2010 drilling completion CapEx by about $230 million.

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

Yes, that's pretty close.

Okay. On the Barnett Combo, flow rates you highlighted today were a bit less than on the wells you highlighted in the first quarter. But apparently you are restricting the flow rate there also, like you are 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 plays that you have is actually improving the EORs or the economics there? Or how are you looking at that?

The reasons for restricting in the Combo versus the Haynesville are a little bit different there, Bob. 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 sand flowback there, which could -- cuts out your surface equipment and could damage your frac pack.

And so what we've 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 would say the -- so the Combo, it has almost become a mechanical necessity for us to do that. So what you can expect on future earnings calls are maybe a little more modest production rates as we report, and mainly -- which will arrest the declines a little bit. In terms of the overall reserves, we don't think -- we can't ascribe at this point that reduced flowbacks are going to increase or decrease reserves one way or another. We just don't have enough data.

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

Those are about $4 million.

$4 million. And then just last question very quickly. You mentioned a solution in the Eagle Ford similar to what you'd done in the Barnett to sort of address the availability of proppant and 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 proppant manufacturer or another sand mine in addressing that issue?

We don't want to go into too many specifics on that. But we need to kind of integrate upstream a little bit, if you will, to get our hands on some proppant. And we have several ways to do that. We just -- we are very active in that, but for confidentiality reasons, we really don't want to go any farther with the discussion on that right now, Bob.

Sure, I understand. Okay, great. Thank you.

Irene Haas, Canaccord.

I have questions on Niobrara. Firstly, where are the Critter Creek wells located in relation to the Jake well, and how long was the lateral [legs] and frac stage?

Secondarily, on these fracture plays, I want to ask you guys, are you staying away from the silo fuel on purpose? Anything to do with the fracture 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 EUR and also a projection of what Niobrara could mean to EOG?

That's a long list, Irene. Let me kind of start with the first bit. 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 well. So they are all bunched together in what we call the [Hereford Prospect], that 100,000 acres of our total of 400,000 acres.

So they are on 640 spacing currently. We are 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 had 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, downspacing of that field. But we did not focus our leasing efforts there because we felt like most of it was already HBP. And we instead (technical difficulty) in the other sweet spots that we had mapped.

Relative to the other oil plays, the big question we have here is what is the contribution from the flows we are getting from fractures versus matrix. And really, we have not much to update you on from the analyst conference. We are still looking at production. We are watching how fast pressure declines with production, and trying to understand are we seeing matrix kick in or not.

We think we are seeing some positive indications on some and not on others, and it is just too soon to tell. What we believe is it will take the rest of this year closely monitoring these wells and the wells that we will 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 a strong economic good rate of return play, but with less overall reserves because we have to space it at maybe six 40s or three 20s, instead of one 60s or 80s. So that's the big question we are trying to deal with 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.

Of the two wells, how long are the lateral lengths?

They are about 5500 spud in length, Irene. And as Loren was saying, there is 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 well EURs to make an estimate of potential here.

Okay, great. Thanks.

Joe Allman, JPMorgan.

Just a follow-up on the two Critter Creek wells. So just to confirm, you stimulated both those wells?

Yes, they were stage fracked, and the exact methodology of the stage frac is kind of what we are experimenting with. Since the Niobrara seems to be of some interest to everybody, we will give you a little more color on the -- the Jake and Elmer wells appear to be kind of stabilizing each at about 150 barrels of oil per day. And of course, remember that in 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 would say overall, we are still cautious. We don't want to proclaim victory, but we are getting a little more positive feeling than we had three months ago, particularly in observation of the Jake and the Elmer wells, since those wells have a little longer life.

But it is 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 is kind of where we stand today on the overall play.

That's helpful. 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 are in the process of disposing of.

What we really did, we made kind of a choice in the Company, and we said, okay, we've cut 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 it would be great, but it is 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 a philosophy that has taken us to this asset -- or acreage monetization strategy.

We are going to be going pretty much to the max in terms of our operational effectiveness in the second half of this year and then 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.

Thanks. And then of the -- so how much acreage are you selling there in the Niobrara?

It's probably somewhere around 20,000, 30,000 acres.

Yes, out of 400,000. So it is again, it is not half our acreage or anything like that, not even close to it.

Okay, got you. And then on LNG, how are the discussions going related to the oil index contracts?

Still early days. I would say we've got positive signs. And I'm sure if you asked Apache, who we are working with very closely, you would get the same feedback, that the discussions are in the very early stages.

The way I would gauge this whole project is it is about a -- the whole LNG project is probably a 10-step project, and right now we are probably at step two. We've got step one done, step two is looking pretty good. But it is just -- I would say all the elements are there to make this project come together. But it would be the first LNG project built by a nonmajor company, and also would be the first LNG project built in North America as an export project, except one that's in Alaska that was built 20 or so years ago.

So we have to realize that -- what we are taking on there is a pretty big scope. But the prize also is very big. So it is not going to move on just a rapid timeline in terms of we don't want to set any expectations that on the next quarter call that we say Eureka -- the project is a done deal and we're moving forward with it. It is going to evolve a bit more slowly than that.

All right. Very helpful. Thank you.

David Heikkinen, Tudor, Pickering, Holt.

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 your 25% net debt to total cap threshold, if you project financed? And then when would you actually start investing capital?

The on-line days 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 enough acreage up there where we believe we have 9.5 or so net Tcf. And one option we have there is to bring someone in who might be an offtaker 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. 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.

Okay. And then on the asset monetization strategy, you've given some good operational explanations for selling versus joint ventures. Can you give us some thoughts around rate of return or a cost of capital difference for joint ventures versus asset sales?

We haven't really gone down that road on there in terms of that. It is 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 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 if 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. So it is almost a philosophical issue more than a calculated financial issue on comparative 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 is why we are looking at going that route.

Okay. And then a little more technically speaking, on the Eagle Ford, you had relatively low GORs. Really interested in your thoughts around drive mechanism and recovery factors as compared to some of your gassier plays that you are experts in.

We are still looking at a limited drive mechanism and a recovery factor there of perhaps 3%, maybe 4% of the oil in place, as we would see it there. And it is not a water-drive reservoir. It is basically going to be just an expansion-drive reservoir there.

But again, it is early days in terms of the Eagle Ford. I tell our staff that if one of the big integrated companies had essentially a 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 essentially a 1 billion barrel project.

And so I'd say we've got it identified as far as length, width pretty darn well. But there is a lot of other things that we are going to be working on and just kind of trying to optimize. 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 is also the potential -- you have the Austin Chalk and the Buda that are very near the Eagle Ford there, that some of our exploration is for clamoring to drill some wells in because they feel there is significant potential in those that we certainly haven't had it in anywhere.

So what I would offer to you is this year, as we mentioned in our April conference, this is just a very slow startup 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 is just -- it's not one where we are going to be able to just turn it on and have these rapid volumes.

And we will be learning the whole time. That is why we are 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 wanted to get, David, but anyway.

Helpful, no. Just on the Montana Bakken, well results and just kind of the differences, can you give us any thoughts around the types of completions or any differences in how you think about completing -- how you have completed those wells and how you might complete them going forward? That's it. Thanks, guys.

Basically, we are using primarily external packers on a lot of those things. In terms of the reserve levels that we are seeing, we are seeing situations where it appears like the reserves are very similar to our Bakken Lite reserves that we articulated in the April conference. And we will be probably going to longer laterals out there, perhaps 7500-foot laterals in that area.

So the reason we kind of pointed it out is that there wasn't all that much drilling in the kind of western North Dakota/Eastern Montana portion of the acreage we had. And we always had a little bit of a question mark, is it going to be that good that far out? And we feel it has been answered in a positive manner now.

Thanks, guys.

Biju Perincheril, Jefferies & Company.

A couple of quick questions. When you look at 2011 activity levels, and to the extent you can talk about those, are there any areas where you would see activities slowing down? I'm thinking Niobrara, Eagle Ford, those activity levels, [have they] been rising to offset that?

I would say that our Rocky Mountain gas development, we're not planning on doing much of anything there, and might 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. Does that answer your question?

Yes. So would it be fair to say that you would be looking at a higher rig count in 2011? Slightly?

Yes, probably. Probably. We haven't finalized any plans yet, but that's likely. And the higher rig count -- 100% of the incremental rig count will be (inaudible) for oil projects.

Fair enough. And then 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 has that production holding up versus the other two that you mentioned that are stabilizing around 150 barrels a day?

We -- that was -- we tried an unstimulated (inaudible) there, kind of an open-hole completion. And what we ended up doing post the analyst meeting is we went in and cleaned it out and did more of a cased hole completion. And that well appears to be stabilizing at about 400 or 500 barrels of oil a day.

So it -- really right now in what we call the Hereford Ranch area, we've got five good wells. It's pretty good. So like I say, we are warming up to the play cautiously.

Very good. And then lastly, on the Leonard Shale, you said the production characteristics sort of similar to the Barnett Combo. But when you look at the rock, is it a --would you say is it sort of more similar to the Eagle Ford in terms of (inaudible) 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 Eagle Ford or the Haynesville. It's more of a silica-based system. It's got plenty of oil in place per section, and it is a combo 2 and 3 (inaudible), probably a pretty good-sized play. It covers a large (inaudible). There's a lot of stratigraphic variation in that play, both in the target itself and then in the barriers that you have, the amount of saturations you have. So a lot to be learned by industry in that entire play right now.

Okay. Got it. Okay. Thanks.

Okay, thank you, everyone, for listening, and we will talk to you again in three months.

That does conclude our conference call. Thank you for your participation.