EOG Resources Inc (EOG) 2011 Q2 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources second-quarter 2011 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, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second-quarter 2011 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 reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast, including those for the Eagle Ford, may include 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 Bill Thomas, Senior EVP Exploration; Gary Thomas, Senior EVP Operations; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President Investor Relations. An updated IR presentation was posted to our website last night and we included third quarter and updated full-year guidance in yesterday's press release.

I will now review our second quarter net income and cash flow followed by operational highlights. In addition to our typical play results, I'm going to also address several hot-button topics such as weather-related down-time, logistical issues, and our plan to deal with a wide differential in crude oil prices between benchmark WTI and LLS. Tim Driggers will provide some financial details and then I will provide macro and hedging comments along with concluding remarks.

As outlined in the press release for the second quarter EOG reported net income of $295.6 million, or $1.10 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income to eliminate marked-to-market impacts and certain one-time adjustments as outlined in the press release, EOG's second-quarter adjusted net income was $299.2 million, or $1.11 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 $1.15 billion.

I will now discuss our 2011 business plan and operational results. Our business plan continues to be consistent and straightforward. We have completed the organic conversion to a liquids based Company by exploiting our world-class North American horizontal oil positions while preserving 100% of our core North American natural gas resource play assets and maintaining a low net-debt to total cap ratio. Our investments in high rate of return domestic oil plays will flow through the income statement as net income increases and show up as superior ROEs and ROCEs. There have been 2 changes since the last quarter regarding the capital side of the Business.

We've increased our anticipated 2011 asset sales from $1 billion to $1.6 billion. The incremental $600 million of sales are primarily mature long-lived domestic gas properties and other acreage. None of these sales involve any of our horizontal oil or gas resource plays. Through mid-year we've closed on $944 million of sales, and we have signed purchase and sale agreements on another $271 million worth. Although we expect to close all $1.6 billion by year-end it's possible some of these may not close until the first quarter of next year. However, this $600 million of incremental dispositions will be partially offset by a $400 million CapEx increase primarily caused by higher service costs. Later on this call, I'll describe our plans to mitigate these costs in 2012 with our self-source fracs.

We've recently had a lot of investor inquiries regarding weather-related down-time and crude oil take-away logistics. Here's our situation. In the second quarter we incurred the expected amount of weather related down time in our North Dakota Bakken operations. We also had a small amount of down-time in our Barnett Combo play due to the lack of crude oil trucks. Because of the transportation contracts we put in place earlier this year in the Eagle Ford we were able to move oil to sales and had no unusual crude take-away down-time in that area. Since mid-March we've also had weather related down-time in our Manitoba Waskada play.

Going into the second half, the down-time in Manitoba has continued and Bakken production also continues to be impacted by residual flooding. Due to this impact we've slightly revised our full-year oil growth from 55% to 52%, a total of 2,400 barrels per day from our previous mid-point target of 115,800 barrels per day. A very small tweak to the big picture. Our total Company full-year growth target of 9.5% is unchanged as is our NGL estimate. We still forecast a dramatic 50% plus year-over-year growth in crude oil production. You will also note that our second-quarter domestic realized oil price versus WTI was likely better than similarly situated oil producers. This is primarily because of our Bakken crude-by-rail system and having a dedicated truck fleet to service the Eagle Ford.

During the North Dakota spring flooding, even with some re-routing of trains this crude-by-rail system allowed us to move our crude at much better differentials than by truck. We've also had a lot of investor inquiries relating to persistent WTI to LLS crude differential. And we think we're better prepared to deal with in this 2012 than any similarly situated producer. We expect to have the capability to rail most of our Bakken and some of our Eagle Ford production to Louisiana instead of Cushing in 2012. And if this differential persists we should capture the higher margin. Last week we signed an agreement for a 70,000 barrel a day unit train off-loading facility to be built in St. James, Louisiana. The EOG-owned facility is expected to be in service late in the first quarter 2012. With our rail system next year we will have the flexibility to move crude to EOG-owned facilities at either Cushing or Louisiana.

In the second quarter, our total Company production increased 11.6% year-over-year and more importantly, crude oil increased 50% and NGLs 38% year over year. At EOG, we realize that in a $4 gas price world, increasing gas production is at best marginally profitable while growing liquids is quite profitable. Consequently, I'm amazed that any buy or sell side analyst that accords any importance to North American gas production growth, which is pushing more gas into an already over-supplied market.

During the second quarter, 105% of EOG's total volume growth came from liquids as opposed to gas. With today's 22 to 1 value differential between oil and gas, we think the debt adjusted production growth metric is essentially useless. What matters is EPS, EBITDA, and cash flow per share growth. The IR presentation we placed on our website yesterday shows an independent analysis of how EOG ranks versus the peers for the 2010 through 2012 period on these metrics. EOG shows up as best-in-class. And I'd suggest you review. That's the payoff for our organic oil growth that's unmatched by any company our size.

I will now discuss the major drivers of our oil growth starting with the Eagle Ford. As most of you know, this is the hottest play in the US, and EOG has the largest net position in the oil and wet gas windows, 561,000 acres of any company in the trend. We continue to be the biggest producer from the oil window with net-after-royalty production of 34,000 barrels of oil equivalent per day at the end of the second quarter, 83% of which is crude oil. I expect we'll consistently be the largest Eagle Ford net oil producer for the next decade. We're continuing our high activity level to vest our leases since essentially all our acreage is prospective. Our press release contains multiple individual well results, so rather than providing you a well-by-well recitation I will provide some context regarding the overall play.

There are 4 key points. First, our well results continue to be remarkably consistent across our 120-mile acreage spread, and we've been 100% successful on completions. Our typical IP rates throughout the trend range from 700 to 1,600 barrels of oil per day plus gas and NGLs. As we've stated on previous calls, our Eagle Ford drilling rates of return are excellent. We think they're the best of any large play in the industry. The IR slides posted to our website show one, sell side analysis of forecasted first month Eagle Ford per well revenue for EOG and the peers, and we're happy to see that our wells rank first. This is indicative of our well quality compared to others in either the oil or rich gas windows.

Second, we estimate there to be approximately 21 billion net-after-royalty BOEs in place within our 535,000 net acres in the oil window. Our current stated net-after-royalty oil recovery potential is 900 million BOE, which we believe is the largest lower 48 on shore domestic net oil discovery in the last 40 years. This represents about 4% of total recovery of total oil in place. And now that we've got the reservoir characterized, we're working on ways to improve this recovery factor.

In the short term, these potential recovery factor improvements fall into 2 categories. Improving per well reserves, or reducing well spacing to maximize the NPV of the play. We're working on both of these, and we have encouraging news to report today regarding preliminary well spacing results. Our 900 million BOE net-after-royalty potential recoverable reserve estimate assumes approximately 130 acre well spacing. As noted in our press release, we've recently experimented with tighter spacing and early results indicate that tighter spacing may be more optimum. It's too early to quantify the reserve impact of closer spacing, but it's definitely positive. Simply put, we need more time to observe the production of these more closely spaced wells.

Third, during the first quarter we've had 2 independent ratifications of our Eagle Ford acreage value. The first was the Marathon purchase which most analysts have valued at about $21,000 per acre. We believe EOG's 561,000 net acres have a higher average geologic and product quality than this transaction. The second ratification was a BHP purchase of Petrohawk. Both the size and quality of our acreage we believe significantly surpasses the Petrohawk position. I will also remind everyone that as first mover in the oil window our acreage acquisition cost was approximately $450 per acre.

Fourth, last quarter I noticed some Eagle Ford crude oil take-away issues. To date our interim trucking and railcar logistical solutions have allowed us to avoid any shut-ins, and we're hopeful we can handle our increasing oil volumes until mid 2012 when the Enterprise oil pipeline is installed. As you have undoubtedly heard on multiple earnings calls, everything in the Eagle Ford is tight. Rigs, frac equipment and crews, sand, and product take-away capacity. So far we've dodged a lot of bullets and haven't had to slow our 2011 program down because of bottlenecks. We expect to begin using frac sand from our Wisconsin sand mine in the fourth quarter which will reduce our well cost and provide a reliable sand source. To provide some scale for you, this facility will ultimately serve most of our North American resource plays. By combining forecast changes in pumping cost with the self-sourcing of frac sand in the Eagle Ford we expect to save about $1 million per well compared to early 2011 well costs.

To summarize the Eagle Ford, we have the largest and best quality acreage position in the hottest play in the US which is generating very strong per well direct after-tax reinvestment rate of returns. As with all our oil resource plays we intend to develop this asset without a JV.

Shifting to the Bakken, we continue to be the largest North Dakota oil producer and achieve consistent results. We plan to drill 106 gross wells this year, and we're pleased to note that a recent sell side analysis of Bakken peak oil production rate per well ranked us second of 17 companies. This attests to the performance of our wells. The main issue in the Bakken during the second quarter wasn't well performance, it was weather as you have undoubtedly heard by now from other area producers.

In our May guidance we correctly forecast for down-time from the severe ice storm in the second quarter, but we underestimated the impact that the recent flooding in the Bakken and Manitoba Waskada areas would have on our full-year production. As of today we still have production shut-in in both areas because of flooding. Net-net, this flooding is the main reason we slightly shaved our full-year oil production forecast. Our Barnett Combo play is also performing well but we did have a small amount of second quarter oil and NGL production curtailed due to lack of crude oil trucks. We think this problem has been resolved. We continue to tweak our combo frac designs and have recently achieved higher initial oil and gas rates per well. We hope this translates into higher reserves per foot of treated lateral, but it will take 6 months to determine our results.

Our press release also noted a new successful mid-continent horizontal oil play, the Marmaton sandstone in the Oklahoma panhandle. During the quarter, we drilled 8 strong Marmaton wells such as the 100% working interest Davis 3 #1H which IP'ed at 1,050 barrels of oil per day with 5 million cubic feet a day of rich gas for $4.3 million well costs. We have 34,000 net acres in this play. Because we don't have a huge acreage position, this will be a contributory rather than a game breaking play for EOG but it will help us grow mid-continent liquid volumes.

In the West Texas Permian Basin we've had success in all 3 of our oil plays, the Wolfcamp, Leonard, and Bone Springs. We have a total of 240,000 net acres that are likely productive in 1 or multiple intervals. As we see it now the biggest of these 3 plays for EOG is the Wolfcamp. During the quarter we successfully proved up new acreage with the 100% working interest University 9 #2802H which tested at a peak rate of 583 barrels of oil per day and 250 mcf a day of gas. We also completed a well with a long 9,100 foot lateral for 935 barrels of oil per day with 830 mcf a day of gas. As with all new resource plays, we've rapidly reduced both our drilling and frac costs and thereby improved RORs.

We recently drilled a Wolfcamp well to 14,200 feet measured depth in 7 days which is excellent. We've achieved similar positive well results in both the Leonard and Bone Springs. In 2012 we'll be ramping up our Permian Basin oil drilling now that we have multiple proven successes in all 3 plays. This will develop into a more significant growth area for us in 2012 and beyond, and we expect our total net reserve estimate here to increase over time.

In our DJ Basin Niobrara play we've expanded the acreage we've proven up. All the results reported to date have been on our 80,000 net acre Hereford Ranch prospect. This quarter we drilled successful wells on an additional 89,000 net acres, expanding our prospective acreage to 169,000 net acres. The Niobrara has some unique production characteristics that we haven't seen in any other oil resource play. Some wells start out at lower initial rates but then exhibit much flatter declines than other plays. For example, the well that kicked off the play, the Jake 2-01H started out at 645 barrel oil per day stabilized rate and is currently producing 275 barrels of oil per day at a low decline rate 22 months later. To summarize the Niobrara, this will definitely be a contributory play for us and will optimize frac technology. We might turn into it an even more significant asset.

Last quarter I introduced our successful Wyoming Powder River Basin Turner sandstone horizontal liquids play. We didn't drill any Turner wells this quarter but we plan to drill 7 additional wells during the second half. During the quarter we also added 100,000 net acres in Argentina's Neuquen Basin. Our target is the Vaca Muerta shale, which we believe will be oil productive. We'll drill our first 2 wells in 2012.

Turning to the dry gas side of the ledger, we continue to focus essentially all natural gas investments in areas where we must drill to hold acreage. Mainly the Marcellus and Haynesville shales. We're continuing to generate consistent well results in these areas. In British Columbia you've likely already heard Kitimat project status updates from EnCana and Apache, and we concur with their status comments. Like them, we're excited about the project but it's not yet a done deal. The project is contingent on the cost estimate study and ability to lock-in long-term oil indexed off-take contracts. I will now turn it over to Tim Driggers to discuss financials and capital structure.

Good morning. Capitalized interest for the quarter was $14.8 million. For the second quarter 2011 total cash exploration and development expenditures were $1.64 billion excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $180 million.

At second quarter-end 2011, total debt outstanding was $5.2 billion and the debt to total capitalization ratio was 30%. At June 30, we had $1.6 billion of cash on hand, giving us non-GAAP net debt of $3.6 billion for net debt to total cap ratio of 23%. On a GAAP reporting basis, the effective tax rate for the second quarter was 46% and the deferred tax ratio was 71%. Yesterday we included a guidance table with the earnings press release for the third quarter and updated full-year 2011.

For the third quarter the effective tax range is 35% to 50%. For the full-year 2011 the effective tax range is 35% to 45%. We have 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. For each $1 per barrel change in wellhead crude oil and condensate price, combined with the related change in NGL price, the sensitivity is approximately $24 million for net income and $36 million for operating cash flow. EOG's price sensitivity for each $0.10 per mcf change in wellhead natural gas prices is approximately $15 million for net income and $23 million for operating cash flow excluding the impact of swaptions.

Now I'll turn it back to Mark to discuss hedging and provide his concluding remarks.

Thanks Tim. Now I'll discuss our views regarding macro and hedging. Regarding crude oil, we still like both the short and long-term supply demand fundamentals, although guessing which way short-term prices will move is obviously a speculative call. We currently are 26% hedged August through December of this year at a $97.02 price. And for 2012 we're approximately 7% hedged at $106.37 price. We continue to have a 1 to 3 year cautionary view regarding North American gas prices but believe 2014 and later markets will balance as gas powered electricity demand increases. For this reason we have no interest in growing 2011 North American gas volumes at current price levels. Our hedges are consistent with our macro view.

For North American natural gas, we're approximately 50% hedged at a $4.90 price for September through December of this year. Additionally, we've sold options at a $4.73 price that if exercised would mean we're 88% hedged through year-end. For 2012, we're approximately 39% hedged at a $5.44 price with options that if exercised would increase to a 70% hedge level at a $5.44 price.

Now let me summarize. In my opinion there are 6 important points to take from this call. First, our reinvestment RORs are very strong. I think they're the best in the industry led by the Eagle Ford. This is driving our EPS, EBITDA and cash flow per share growth. Second, we believe our unit cost containment this year is excellent considering the inflationary environment. Third, we're the leading oil producer in the 2 hottest and highest ROR domestic oil plays, the Bakken and Eagle Ford. No one our size is growing domestic oil volumes comparably to EOG. All of our plays are on shore and all the oil is sweet and high quality. This quality crude is in demand by refineries and we'll be able to access LLS prices early in 2012.

Fourth, we're not interested in growing North American gas volumes at current prices, unlike most other companies. Fifth, we're accomplishing all this while maintaining low debt. And sixth, I will be 65 years old next month, and it's appropriate that investors may want to know my plans. I plan to be in my current job for at least the next 18 months, and when I do retire, my successor will be a long tenured EOG employee who has the EOG DNA. Across our 10 operating divisions in North America the average tenure of our general managers is 17 years. Here in Houston, Bill Thomas and Gary Thomas, Senior Executive Vice presidents of Exploration and Operations have a combined 65 years at EOG.

As with any public company we have succession planning discussions with our Board and when appropriate, we'll announce when decisions have been made. Thanks for listening. And now we'll go to Q and A.

(Operator Instructions) Brian Lively, Tudor Pickering Holt.

Just in the Niobrara, can you provide us with a resource estimate update on the 160,000 net acres that you think are de-risked at this point?

Yes, we haven't really come out with a resource estimate yet on there. It's no secret that the Niobrara has proven to be one of the more I'd say complex horizontal oil plays that both we and the industry have dealt with. I'm sure you're aware there's been mixed results from various companies in the Niobrara. I'm pleased to say EOG probably has the best results in the Niobrara of any company, but we're still in kind of an understanding and evaluation phase of it as opposed to -- so we really don't want to give a number at this point in time, because there's a pretty wide range.

Maybe just on the Hereford Ranch area, even if not total resource what are you seeing sort of as the average EUR per well or just some context on that?

I'd say the average is probably in the 200,000, 225,000 barrel oil equivalent range. The good thing we're seeing on these wells is that many of them, they don't come in at really extremely high IPs. They will come in at 300 to 400 barrels per day but after a year or so they're still making 200 barrels a day so the decline rates are really low in them, and that's very encouraging to us. We've also had a lot encouragement on our step-out drilling as Mark has indicated in his comments and in our press release. So just overall we're real positive in what's going on in Niobrara. We think it's going to be a significant play for EOG, but again, we want to have a little bit more time to drill some more wells and evaluate the production before we come out with a reserve potential number.

Certainly understandable. Thanks a bunch.

Brian Singer, Goldman Sachs.

First on the Bakken and the Eagle Ford can you talk to the costs associated with railing that to Louisiana, i.e., how we should think about the combination of quality and transport differential and can you also maybe add some color on where your current rates are relative to the second quarter average, whether we've seen a step-up?

Yes, in terms of when you say current rates, are you talking about oil production rates or --

Oil production rates, that's right.

What we're programming this year for the Bakken is not a particularly strong step-up in oil production rates in the second half of the year compared to the first half. Where the growth is going to come in oil production rates is primarily from the Eagle Ford and secondarily from 3 different areas really. The biggest secondary area will be the Combo play, and then also some contributions from the plays in the Permian Basin and mid-continent.

In terms of the rail cost, we haven't disclosed the costs or incremental cost to rail it from Cushing to St. James, Louisiana, and because it's possible we may be conducting third-party business there and don't want to give any proprietary information away. But what I can say is relative to the current price value differential between LLS and WTI, it's totally obvious, if those differentials exist next year, we'll be railcarring every possible barrel we can to St. James as opposed to Cushing.

Okay. Thank you. And then as a follow-up, going back to the Niobrara, can you talk a little bit to why you think you're seeing the flatter declines and flatter IPs there? In the past I think you had highlighted that unique frac technique although I think you mentioned in your comments that you needed to optimize frac further. If you could add some color there. Thank you.

Brian, early on we, with some of the wells that came on with high IPs, we were thinking this was really more of an open fracture play but as time goes along and we see more production from the well, we're realizing that we're getting some contribution from the system permeability which would be a combination of maybe some real -- from micro fracture system and the matrix firm or the wells wouldn't be so low decline. So that's what gives us encouragement. It does take -- if you don't have open fracture systems you really need to stimulate the rock more. So it's really important for us to continue to learn and to refine our completion techniques to make this successful. And we're going to have to get our well cost down on the play, because the IPs are not that high. So we've got some work to do but we certainly see really good encouragement from the results so far.

Brian, let me just give a little more color, which may be helpful to people on the call. You know, if you look at what's going on with the Niobrara, I would say the play, kind of liquids-rich play that's most similar to it in one respect was the Barnett Combo in that the reason we basically own the Barnett Combo play, the overwhelmingly dominant acreage holder there, is because that play was very technically tough to turn into good economics. And hence everybody else shied away from it. It took us several years to turn that into the kind of play we wanted to. And right now we're really accruing the benefits from the Combo play, which has given us extremely strong economics.

The Niobrara is kind of like that in that it's not the slam dunk -- the Eagle Ford and the Bakken were slam dunks. We came out of there in the first inning and hit homeruns. Those were just easy rocks to deal with. Some of these plays are ones that because the rock quality is superior, you can knock the ball out of the park right in the first inning and some of them it takes you until the fifth inning or so until you knock the ball out of the park. Right now with the Niobrara we're probably in the third inning or so on that one.

Thank you.

Leo Mariani, RBC Capital Markets.

Just wondering if you could comment on what you're seeing on Eagle Ford in terms of recovery factors. I think you mentioned 4% Mark. I think you had previously had a range of 3% to 4% roughly a year ago. Just wanted to get a sense of what you thought was responsible for some of the up-lift and maybe sort of any guesses where you think this number might migrate to over time if you think there's going to be some upside there.

I would say our view is there will be upward pressure on our 900 million net-after-royalty reserve estimate there. Generally we had been -- that estimate was based on 130-acre spacing which in rough terms translates to maybe 1,200 foot to 1,500 foot between lateral wells, and we're now in the process of we have 2 to 3 months production history from wells spaced more closely, and we're drilling a lot of the wells that are currently being drilled are on this more close spacing, and the initial reservoir simulation results, actual production results, are encouraging. But as usual, we're pretty cautious in giving out estimates. So we could come out with some flashy number right now, but we just want to get more well results than the 3 wells that we have at down-space conditions and watch production for awhile before we give you any additional numbers on the Eagle Ford reserves.

Got you. I guess just jumping over to the Wolfcamp play, looks like you guys are seeing fairly higher production rates there than your last round of updates in a well that did just over 1,000 BOE per day when you throw in the gas. Wanted to get a sense what's happening there, if you guys are continuing to experiment with different frac techniques. I know you mentioned longer laterals on that particular well. What do you think is driving the better production there?

Well, there's several things going on. I think certainly the longer laterals are making a big contribution to the better wells. We have also recently continued to tweak or completion techniques. And we now have -- I think on the last call we had 1 well. We now have 7 wells that we've completed with a new frac technique, and these 7 wells are averaging, over the first 30 to 60 days, about 15% to 20% better production than the old kind of completion techniques. So we don't -- have not upgraded our EURs yet. We want to watch them a little bit longer. But that's also very, very encouraging.

We've also drilled a number of step-out wells to prove up additional acreage, and so we're very encouraged about this Wolfcamp play. It's moving along very nicely. We're getting our costs down, we're proving up additional acreage, and we're proving the results from the wells that we're drilling. It's all going really well.

Great, thanks.

Scott Wilmoth, Simmons & Company.

You mentioned the Wisconsin sand mine coming on-line in 4Q could provide enough sand for most of your resource plays. You guys quantified the impact in the Eagle Ford. What could that mean to cost savings across your portfolio maybe in terms of total CapEx for next year?

If we use this sand and we have our dedicated frac fleets on maybe, oh, goodness, most of our wells there in the Eagle Ford, we already have that going in the Barnett. We're going to use this sand also in Pittsburgh, some also in West Texas. We could probably be looking at savings around $400 million, just on the sand part. Then we have the benefit of the dedicated frac fleets and that improved efficiency there. We have these contracted to a similar to what we have drilling rigs contracted to us, just the day work basis.

Okay, thanks, that's helpful. Then when I think about rig activity in the Eagle Ford currently at 22 rigs, can you talk about initial plans are running into 2012 and what your future activity level needs to be to hold your acreage in the future?

Yes. Right now we're planning on-ramping up our activity in the Eagle Ford, and that's obviously going to be a function to some degree of oil prices. So we're going to drill 250 wells this year in the Eagle Ford, and as a minimum we drill 250 wells next year there, and in terms of some of the other areas there, we'd just be deciding what is the cash flow that we're going to generate next year and then try and balance it here. And obviously this is -- we may -- depending on what oil prices do, there's a big function there.

David Tameron, Wells Fargo.

Mark, I think you might have mentioned it but I missed it. Can you talk about what the recovery rates are right now in the Eagle Ford, what you think the recovery rates are?

About 4%, David.

4%. You said the additional down-spacing. What do you think that would take to get that well to tighter spacing?

We haven't said. All we're saying is that if the down-spacing works the recovery factor will likely be higher than 4% but no quantification on how much higher.

Okay. On the M&A, on the divestiture front, the $1.6 billion, the additional $600 million you've said not in core plays. Did you characterize the gas versus oil, what the midstream? Is it E&P property? Can you give us a little more color there?

As far as the producing properties that we're selling, all of that is gas properties. Most of it is properties that we've had for some time like East Texas, and we're selling scattered properties in mid-continent, Gulf of Mexico properties offshore, and that's approximately half of our overall dispositions, and the balance of that is the lease holds and facilities.

Irene Haas, Wunderlich Securities.

Seems like you guys have got these resource plays down to a science. Specifically in mid-land basin the horizontal Wolfcamp play. What do you think is the optimal length, I noticed that you still have some EUR up there on your presentation? Could there be an upside to it? I'm wondering how much it costs to drill and complete this play particular. Are you going for multiple benches? Are you focused on bench A, B, or C, and that's all I have for you today.

Yes Irene. We've been drilling laterals anywhere from 6,000 to 9,000 feet. And the length of the lateral depends on a lot of different things, the geology and the lease parameters and things like. Of course, we drill them as long as we can to make better wells. You always get higher rates of return on that. We are testing multiple spacing patterns. We're drilling some wells on 990-foot spacing between laterals and some on 660-foot spacing. And we are -- we primarily only tested the middle Wolfcamp. It's got 3 different pays over about 1,000 feet of gross intervals so there's a lot of oil and gas in place. There's 3 potential pay zones. We've primarily been testing the middle pay, but we do have plans to test the upper pay. So there's a lot of work to be done. There's enormous amount of potential, and it's going really well. The well cost running right now about $5.4 million a well. And they're steadily going down. Our group in West Texas is doing a great job on getting the cost down.

Great, thank you.

John Herrlin, Societe Generale.

With Argentina, you said 2012 drilling, what are you going to do for things like frac equipment? It's not a country that's well-known for having large fleets.

Yes, the -- I mean, there is a small amount of frac equipment in country right now, and then the major service companies are in the process of shifting additional frac equipment down there. It's -- for the first couple of wells, it's going to be kind of 1-off deals that we'll have to schedule months and months in advance to get the fracs done. But our logic is, if this shale turns out to be something that is commercial and productive, that you will see them, particularly the major service companies just move equipment in there in the 2013 through 2015 time frame. So it's -- we're pretty optimistic about the quality of that shale. We charged our people with the only way we go outside North America is if we could find a shale and oil shale that we thought looked superior to Eagle Ford, and we believe we found one there. So time will tell.

So it wasn't the beef.

No, it wasn't the beef, John.

Okay. With the Wolfcamp, how optimistic should we be? It's pretty thick shale interval. How excited are you about it or can you put it in context of your other plays?

Yes, in relative terms, we're pretty excited about the Wolfcamp. That one, we think that we have a very good chance of making consistently good wells there. So on a scale whereby we kind of said on this call that the mid-continent Marmaton was going to be a contributory play and we said the Niobrara was a contributory play and maybe we could get it someday to being more than a contributory play, I would say the Wolfcamp has got a chance to be kind of a game breaking play for us in the Permian Basin as opposed to just a contributory play.

Bob Brackett, Sanford Bernstein.

If we think about crude-by-rail do you worry that some of your competitors will follow what you have done and get to a point where the rail system can no longer support that export capacity, and what do you think that limit of export capacity could be?

Yes, we're not -- the limitation right now, Bob, is not the rail system. It's tanker cars. That's where the real shortage is. It's tanker cars and terminal lane capacity in Louisiana. Right now, we investigated for example a Greenfield railcar terminal in Louisiana. The problem is the time to get the permits, the time to construct the Greenfield plant. You're looking at minimum of 12 months from start time, probably more like 18 months. So what we've done is we teamed up with a company who's got an existing terminal system there, a company called NuStar. And all we're going do is to augment that with building a railcar facility.

The issues, everyone would like to get their crude there, but right now the issues are we could railcar our crude there and there are some rail terminals in Louisiana, except they will capture those who own the terminals, capture all the economic rent of that high LLS WTI differential so there's no benefit to producers to go through those terminals. So that's why we're going essentially through our own system there where we can capture that economic rent. I will also say that we -- we're quoting the nameplate capacity of 70,000 barrels a day but we can very readily up-scale that to 140,000 barrels a day without a whole lot of incremental investment.

So the issue there is we don't think there's going to be a lot of people who are able to move this stuff by railcar just because the barrier to entry is 12 to 18 months for Greenfield facilities. So we think we will be advantaged in 2012 and the first half of 2013 relative to pretty much any other producer in ability to move crude to get the LLS price. So on a timing issue, and you're aware, as are most people that the real question is when will there be an additional pipeline system out of Cushing to the Gulf Coast. And every time I look, it looks like that's been delayed or slowed down a bit more. So it looks like to me that at least through 2012 and probably early 2013 there's going to be some kind of differential, pretty high differential between Cushing and LLS.

Thanks.

Rob Morris, Citi.

In the Eagle Ford, what are your well costs running currently?

They're running about $6 million. We drill wells --

Because I think last quarter -- so with the sand mine or sand source in the fourth quarter reducing well costs by $1 million, you've also noted in your budget increase still pretty persistent service cost inflation. So to what extent will that saving on the sand be offset by inflation on other components here and what do you expect the average well cost in Eagle Ford to be next year?

We would say that the average well cost next year would probably be less than, oh, somewhere in the $5 million to $5.5 million next year. We are seeing cost creep there just because it's such an active area. Both there and the Bakken. That's where we've seen the increased cost of maybe somewhere 8% to 10% for 2011 above 2010. But there's more equipment that's being brought into the Eagle Ford, so I think, yes, we'll see that subside.

Yes, Bob, one way to look at it is, we kind of quoted some economics and quoted a well cost of $6 million. We are seeing upward pressure on that currently, and we quoted about $1 million savings for all this frac stuff when we get in place in Eagle Ford, but probably now, there will be $1 million savings but that will be offset by maybe a $0.25 million price increase just with this cost pressure. So $5.25 million next year may be a reasonable cost estimate, you'll remember we quoted knock-out economics at $6 million cost. So we'll have, at these reduced costs, what I believe are the absolute best reinvestment rate of returns of any play in North America. So we feel pretty good about that.

Okay. On the service cost side, obviously everybody is putting up pretty good margins and returns in these oil plays. When do you think some of this service cost inflation will begin to level out here?

We're seeing it level out. Last year we were seeing, for instance, stimulation costs were up 30% to 50%, and this year we've got areas where it's flat and then areas, like the Rockies I mentioned again, it's up 15% to 20%. But mid-continent is up only about 5%. So we're seeing some of that flattening with the additional equipment that's being constructed and put in place.

Rehan Rashid, FBR Capital Markets.

Along the same lines, how long are your typical drilling or completion contracts for? What I'm trying to get to, if oil prices contract or stay lower, how long before you get some of those inflation numbers back to you?

Yes, I mean, that's good question. If you take our overall drilling rigs, we're running roughly 70, 72 rigs. We've currently got about half of them contracted long-term. Long-term means generally a year, 2 years, maybe 3 years at the most. And half are just uncontracted, just well-by-well. And the same on kind of our frac commitments. We've got these dedicated pumping fleets, and for our total frac requirements across the Company, about 50% of those requirements are covered by these kind of long-term agreements. So in the scenario where you just had an utter collapse in both oil and gas prices and everybody had to pull in their horns and slow down activity, in abstract theory we could reduce our activity by 50% without incurring any contracts that we really would have to negotiate around.

Okay. And the completion contract terms are the same 1 to 3 years, right?

Yes.

Quick follow-up on maybe a little bit on the geology on the Eagle Ford. I joined late so I apologize if you mentioned this already. The Eagle Ford well performance holding better than modeled. Any kind of color around kind of why that could be happening?

I'm not sure I would say it's better than modeled. It's the same kind of -- we would describe as similar reserves that we've been talking about for the last 6 months in the Eagle Ford, which is nominally 430 to 460 MBOE net-after-royalty per well. But the consistency just is what continues to amaze me. The press release we quoted 16 wells. We could have listed a whole lot more than 16 wells. So I'm just amazed that we haven't frankly drilled any real stinkers. We've got all these rigs running, drilling all these wells, and a bad well is one that starts out at 700 barrels of oil a day, which is really a good well.

So the point to make is we haven't seen any inconsistency in the Eagle Ford, and the down-spacing is what we're really focusing on now, is how densely can or should we drill these wells to maximize the NPV of this asset given that right now we're just slating 4% overall oil recovery. What you are going to see in all these horizontal oil plays, whether it's the Bakken, the Wolfcamp, so on and so forth, is phase 2 of development of all these plays is going to focus on improving the recovery factor. And if you go back to the natural gas side, a lot of you will remember that we quoted initially in the Barnett shale in Johnson County, a recovery factor that was turned out to be much lower than what we're currently achieving. We're right now achieving recovery factors in the Barnett shale of roughly 40% or so I think is our number.

Now, we'll never get to 40% oil recovery factor in these plays, but we really think what you people as analysts should be focusing on is who is the industry leader in improving recovery factors after these oil shales have been found and initial development is started. And just as EOG was the industry leader in finding most of these oil shale plays in North America, we believe we'll be the industry leader in attacking the improved recovery portion of it.

And ladies and gentlemen this does conclude today's question and answer session. At this time I would like to turn the conference back over to Mr. Papa for any additional or closing remarks.

Thanks for listening. I've just got two additional comments. If you listened to the drift of this call, what you can take away from it is essentially everyone of our horizontal oil plays we have upbeat news that we shared with you this quarter. And that's pretty rare. And then the second point, I will reiterate it again, because I'm really just befuddled why anybody in the industry pays the slightest attention to natural gas growth in North America is beyond me. And I continue to see particularly sell side write-ups that say this company is growing at this rate. In my mind, it doesn't matter if you're growing at that rate if your primary driver of your growth is natural gas, which is barely profitable at best.

So I would sure like people to focus more on the parameters we quoted which are the EPS, EBITDA, cash flow growth and rates of growth of those. And I think you'll view EOG as the stand-out company in those parameters. Thank you very much. That concludes my comments.

Ladies and gentlemen, this does conclude today's conference. We thank you for your participation.