EOG Resources Inc (EOG) 2009 Q4 法說會逐字稿

Good day everyone, and welcome to the EOG Resources 2009 fourth-quarter and full-year earnings results conference call. At this time, for opening remarks and introduction, 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 fourth-quarter and full-year 2009 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 Barnett Shale, North Dakota Bakken, Horn River and Haynesville, 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 Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bob Garrison, EVP, Exploration; Tim Driggers, Vice President and CFO; Maire Baldwin, Vice President, Investor Relations; and Jill Miller, Manager, Engineering and Reserves.

An updated IR presentation was posted to our website last night, and we included first-quarter and full-year 2010 guidance in yesterday's press release. I will discuss our 2010 business plan in a minute, when I review operations.

I will now review our fourth-quarter and full-year net income available to common stockholders and discretionary cash flow, and then I will review our year-end reserves and finding costs. I will follow with recent operational highlights. Tim Driggers will then provide some financial details, and I will close with some macro comments and concluding remarks.

As outlined in our press release, for the fourth quarter, EOG reported net income available to common stockholders of $400 million, or $1.58 per share, and $547 million, or $2.17 per share, for the full year of 2009. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impacts and certain one-time adjustments, as outlined in the press release, EOG's fourth-quarter adjusted net income available to common stockholders was $234 million, or $0.92 per share, and $755 million, or $3.00 per share, for the full year.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the fourth quarter was $868 million, and $3.2 billion for the full year.

There are two salient points that emanate from these fourth-quarter and full-year results. First, we had no significant financial write-downs in either 2009 or 2008. We are one of only a few companies in the peer group who can make that statement, and we believe this is a testament to the way EOG runs its business.

And second, in February 2009, we provided a 3% full-year 2009 production growth target, which we increased in subsequent quarters to 5.5% and then 6%, and we ended the year with 6.5% actual growth. Historically, we've consistently hit our volume growth targets, and that should give investors confidence regarding our 2010 target.

Now I'll address 2009 reserve replacement and finding costs. For total company, we replaced 364% of our production at $1.18 per Mcfe all-in cash costs, including total reserve revisions. In the US, we replaced 431% of our production at $1.21 per Mcfe all-in cash cost, including total reserve revisions.

Total company proved reserves increased 24% to 10.8 Tcfe. These are strong overall numbers, especially since they include 786 Bcf of price-related and 95 Bcfe of performance-related negative revisions.

The biggest single portion of the negative revisions was in our Canadian shallow gas assets. For the 22nd consecutive year, DeGolyer and MacNaughton has done an engineering analysis of our reserves, and their overall number was within 5% of our internal estimate. Their analysis covered 81% of our proved reserves this year. Please see the earnings press release for the calculation of reserve replacement and finding costs.

I will now address our 2010 business plan, and then our 2009 operational results. Our 2010 production growth expectations are essentially identical to what we outlined last quarter -- 13% overall growth, consisting of 47% total company liquids growth and 2% North American gas growth. Our 47% liquids growth is comprised of 55% crude oil growth and a 28% NGL increase. This comports with our macro view, since we are bullish on oil and believe North American gas prices will be weak for the first half of this year and strengthen in the second half.

Accordingly, on a quarterly basis, our natural gas production profile is expected to increase sequentially this year. The majority of our gas growth will come from the Haynesville, Horn River and Marcellus plays, while the liquids growth will emanate primarily from the Bakken, Barnett Combo and Waskada areas.

I will now discuss each of these plays, starting with the Bakken, where we've got three noteworthy items to report. The first item relates to the Three Forks Formation, where we've achieved positive results from three wells. The Van Hook 100-15H well IP'd at 1390 barrels of oil per day, the Austin 101-15H well at 510 barrels of oil per day, and the Burke 100-20H well at 430 barrels of oil per day.

These are the first tests of the Three Forks Formation on our 500,000 net acres, and we can conclude that the Three Forks is productive over some portion of our acreage, and that the average Three Forks well yields similar reserves to our Bakken Lite wells, which is about 240,000 barrels of oil equivalent net after royalty, and generates a 35% after-tax reinvestment rate of return at current prices.

Secondly, we've successfully drilled a Bakken stepout in Williams County, North Dakota, 90 miles west of our Parshall Field. The Round Prairie 1-17H, where we have a 95% working interest, is producing at a stabilized rate of 450 barrels of oil per day, and likely has similar reserves to our other Bakken Lite wells. This well, along with results from other operators, indicates that a large amount of our total acreage is likely to be productive in either the Bakken or Three Forks, or both zones.

The third new Bakken data point is the results from our first longer lateral well, the James Hill 01-31H. To date, all of our wells have been moderate length laterals, a.k.a. 640s. The James Hill well has 1.5 times the reserves of a Bakken Lite well, which is proportional to its increased lateral length. We are evaluating the efficacy of drilling longer laterals, both 960s and 1280s, compared to our 640s, and haven't yet decided which is more efficient.

There has been a wide range of reported IP rates from different companies in this Bakken play. Part of the reason is that some companies are completing 1280 wells, which will have higher IPs, similar to two 640-spaced wells, and others are drilling 640s or 960s.

I will try and clear up another possibly confusing terminology issue. What EOG calls our Bakken Lite is equivalent to everybody else's Bakken. We've differentiated between our Bakken Core and Lite because we own the lion's share of the core. Based on our analysis, outside EOG's Bakken Core, the Bakken, or EOG's Bakken Lite, rock has a relatively constant quality across the basin.

On the logistical front, our North Dakota Crude by Rail project is up and running. We are now able to increase our netback by selling oil at Cushing, Oklahoma, as opposed to Clearbrook, Minnesota, and also avoiding major trucking costs. We brought this project to fruition in an eight-month period.

Our Prairie Rose rich natural gas pipeline is also now in service. This will allow us to sell our Bakken gas and NGLs in the Chicago market, also increasing our netbacks.

Now I will move to the Barnett Combo play. The bottom line here is that our fourth-quarter drilling results further confirm our estimates that we provided last quarter of 220 and 280 net after royalty Mboe per well for vertical and horizontal wells, respectively. We reference six of these wells in our press release, and I won't repeat them here.

We plan to drill 120 vertical and 126 horizontal combo wells this year and are testing various spacing patterns. Since we own essentially 100% of the combo play and it's not possible to triangulate EOG's results with other operators, I will provide a conceptual way to visualize the combo in relation to the Barnett gas areas, such as Johnson or Tarrant County. Horizontal wells in our Montauk County combo play yield, on a value basis, about one third crude oil, one third NGLs and one third gas; hence, the combo named.

I'll briefly mention two other horizontal oil plays where we are having continued good results. Our 2009 Manitoba Waskada results were as predicted. Last year, we drilled 48 wells and achieved an 88% after-tax reinvestment rate of return, and this year we expect to drill 100 similar wells.

In our midcontinent horizontal Cleveland play, we recently completed two strong wells. The Glass 134-2H well IP'd at 1000 barrels of oil per day and 1.1 million cubic feet of gas per day, and the Williston 45 #3H IP'd at 650 barrels of oil per day with 700 Mcf of gas. We plan to drill 24 Cleveland wells this year.

Now I will switch to our natural gas play, starting with the Haynesville. The big news here is that our initial test in the Bossier was successful. The Bossier is a shale interval 200 feet above the Haynesville with similar rock properties. The Sustainable Forest 5 #2 alternate well in De Soto Parish flow-tested at a 13 million cubic feet a day flow rate, with 7625 psi flowing tubing pressure.

Sub-surface frac and pressure analysis indicates this Bossier zone is separate from the underlying Haynesville zone. This means we have two viable targets over a portion of our 160,000 total net acres where both zones are present. We plan to drill 70 gross Haynesville and Bossier wells this year, and this area will be the largest single driver of our 2% year-over-year North American gas growth.

In the Barnett gas window, last year we completed 132 wells, primarily in Johnson County, with a direct finding cost of $1.52 and a total finding cost of $1.82 per Mcf. This year, we will turn 171 wells to sales at similar unexpected finding costs. We continue to add new locations on our core gas acreage through enhanced completion techniques that allow us to recover economic gas in and around formerly prohibitive geologic hazards.

In the Horn River Basin, we are continuing our steady ramp-up and expect to drill 12 gross horizontal wells this year. We've closely monitored the production performance of the wells we completed in 2008 and 2009 and are pleased to note that performance to date has met or exceeded our expectations.

In the Pennsylvania Marcellus Shale, we will operate a two-rig program throughout the year. We haven't obtained the high IP rates reported by some companies, but we are consistently getting 3 million to 5 million cubic feet per day initial rates, which yield good economics and we will be implementing some upgraded fracs when we restart completions this summer.

Regarding our activities outside North America, we still expect to have results from our China horizontal program by midyear, and will give you those results on our second-quarter call. We'll also have some results from our East Irish Sea drilling program within a few months.

I'll now turn it over to Tim Driggers to discuss financials and capital structure.

Good morning. Capitalized interest for the quarter was $16.6 million and for the year was $54.9 million. For the fourth quarter 2009, total cash exploration and development expenditures were $836 million, excluding acquisitions and asset retirement obligations. Total acquisitions for the quarter, including non-cash, were $501 million; $113 million were cash acquisitions. In addition, expenditures for gathering systems, processing plants and other property plant and equipment expenditures were $85 million.

For the full year, total exploration and development expenditures were $3.1 billion, excluding acquisitions and asset retirement obligations. Total acquisitions for the year, including non-cash, were $707 million; $318 million were cash acquisitions. In addition, total gathering, processing plants and other property plant and equipment expenditures were $326 million.

For 2009, approximately 37% of the drilling program CapEx was exploration, and 63% was development.

At year-end 2009, total debt outstanding was $2.8 billion, and the debt-to-total capitalization ratio was 22%. At December 31, we had $686 million of cash, giving us non-GAAP net debt of $2.1 billion for a net-debt-to-total-cap ratio of 17%.

The effective tax rate for the fourth quarter was 36%. The effective tax rate for the year was 37%. And the deferred tax ratio was 54%.

We also announced another increase of the dividend on the common stock. This is the 11th increase in 11 years. Effective with the next dividend, the annual indicated rate is $0.62 per share.

Yesterday, we included a guidance table with our earnings press release for the first quarter and full-year of 2010. I will note one item on the cost side. Unit transportation costs are expected to increase on a sequential basis and for the full year. This is being driven by the projects that EOG is undertaking in-house, primarily the Crude by Rail operation from Stanley, North Dakota to Cushing, Oklahoma.

This increase is being offset by reduction to the WTI differentials on our US crude oil that is being reflected in the guidance that we have provided.

For the first quarter and full year 2010, 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 first quarter and the full year.

EOG's price sensitivity for each $0.10 per Mcf change in wellhead natural gas prices is approximately $30 million for net income and $45 million for cash flow. For each $1.00 per barrel change in wellhead crude oil and condensate price, combined with the related change in NGL price, the sensitivity is approximately $22 million for net income and $33 million for cash flow.

Now I will turn it back to Mark to discuss the macro and his concluding remarks.

Thanks, Tim. Our view of the North American gas and oil markets is identical to the comments made on last quarter's earnings call. We believe the gas market is tightening, and prices will recover about midyear. We continue to believe the EIA-914 supply data is too high. Analysis of weather-adjusted storage drawdowns paints a picture of tightening market, which conforms to EOG's supply modeling.

Our gas hedge position is shown in our presentation and is unchanged from last quarter. We have only a small amount of gas hedged through June and are unhedged thereafter.

Our oil view continues to be that the 2010-12 NYMEX is reasonably reflective of future prices. We are long-term bullish on oil and have no oil hedges.

Now let me summarize. In my opinion, there are four points to take away from this call. First, the impact of our horizontal oil plays is clearly gaining momentum. During 2008 and 2009, we organically grew total company liquids at 42% and 28%, respectively. This year, we are targeting 47% year-over-year. The driver of this large growth has been horizontal oil.

Last year, 42% of our total drilling CapEx was directed toward oil. This year, that number will be approximately 60%. From the highlights we've provided, it is apparent that all three of our key liquids plays, the Bakken, Barnett Combo and Waskada, are performing as advertised. Additionally, we continue to work on other new play concepts.

Second, we haven't neglected the natural gas side of the ledger, and our gas resource plays are also performing as advertised. We are especially pleased with the upside from our recent Bossier test.

Third, EOG has a 10-year track record of ROCE leadership in the peer group, and although our 2009 ROCE was a low 5% due to weak hydrocarbon prices, we are likely one of a few peer E&P companies to report a positive GAAP ROCE for 2009. As we transition toward a higher percent of oil production, I want to remind everyone that the historic hallmarks of EOG -- focus on returns, low debt and low cost -- will continue.

And finally, just a housekeeping item. We plan to host an analyst conference on April 7 to give an overall operational update and will also provide a three-year volume outlook. We will also talk about our capital plans at that time.

Thanks for listening, and now we will go to Q&A.

(Operator Instructions) Joe Allman.

Mark, in terms of your activity in the Powder River Basin targeting oil and in the Northern Colorado/Southern Wyoming Niobrara oil play, could you comment on your activity there?

I am just going to make a comment at this time that we've got a policy of not commenting on any of our horizontal oil activities where we are still leasing acreage. And so at this point, I'm not going to make any comment regarding that.

I will acknowledge, because it is out there in the public domain, that we are drilling some horizontal oil wells in the Niobrara in the DJ basin. But that is as far as I'm going to go at this time, until we get our acreage completely locked up.

Okay. Thanks, Mark. And then in the Eagle Ford Shale, it appears that you are pretty active with rig activity there. Any comment there? And at what point does it become material enough where you feel like you actually have to disclose it to the public?

You know, what I'll comment on relating to the Eagle Ford is similar to what I said last quarter. We will acknowledge that we are doing some drilling activity, horizontal activity, in the Eagle Ford. Again, that is a matter of public record. And until our lease situation is tied up, we're not going to make any further comments.

Okay. Thanks, Mark. You announced in the release a Rocky Mount asset swap. Could you comment on that?

It basically was an asset swap relating to assets in Utah, and it certainly clouded our accounting, as we had to write up the asset received to fair value. So that was noted in the report. But basically, it was a swap just to further concentrate our assets in the Utah area.

Okay. Got you. Then lastly, the revisions, around what percentage of the revisions were proved developed reserves versus PUDs?

I don't have that number offhand, Joe.

(Inaudible)

Maybe nominally 30% were PUDs, although I don't really have it there. Basically, I will note that the revisions were -- frankly, were higher than we would have expected going into this period. We really got clipped relating to tail gas for the Canadian shallow gas properties. And that is the single biggest piece where the negative revisions occurred.

The good news about the revisions are that if gas price strengthens throughout the year as we expect, a lot of those revisions, maybe all of them, are going to come back 12 months from now.

Okay. I've got some more, but let me get back in the queue. Thank you.

Michael Jacobs.

Mark, in the past, I believe EOG has run a peak of around 70 rigs nationwide. Could you get to a similar level of activity in 2010?

Again, we'll address that issue as well as the capital issues in our April 7 analyst conference. Again, kind of going through what we will talk about in the April 7 analyst conference are, number one, we'll talk about the capital program that we anticipate. Number two, we will probably be talking about some of our stealth plays, where we've got our acreage pretty well locked up and finalized. And number three, and probably most importantly, we're going to give you some volume updates, both on natural gas and then on liquids for 2011 and 2012.

So it is our feeling -- and again, there is probably going to be a lot of questions on this call that I'm going to defer until April 7, so get ready for it, those of you that are in the queue. But when you walk out of there on April 7, you are going to have a pretty good understanding of EOG's overall strategy, where we are going with our capital structure and what kind of company this is evolving into over the next three years.

And just -- I was handed a sheet here on the PUD percentage on the write-downs, on Joe Allman's previous question there. I said 30%. It is really more like about 10%.

Okay. If I can move to the Bakken Lite area, you discussed well bore design a little bit. Can we get some color on completion designs in various portion of your Bakken Lite area. As you think about the increasing importance of improving conductivity of the well bore, how are you experimenting with various completions?

There are two things going on relating to the Bakken Lite areas, and this would also apply to the Three Forks. The first item we are investigating are really length of laterals. And I quoted 640s and 960s and 1280s there on the earnings call. What that really is is on a 640 well, we are drilling roughly 5000-foot-long laterals, and between 4500 and 5000 feet. The James Hill well I referenced is about a 7100 foot lateral. And then we are considering drilling laterals that would be 9000-foot laterals.

And with each of these, we are also looking at how many fracs to give per thousand feet of lateral. And so we've got two items going on right now, and it is fair to say that it is going to take us another couple months to really evaluate which way to go. But directionally, we are probably going to be going to the longer than 4500-foot laterals and perhaps more stage fracs along those laterals.

And as you think about the completion cocktail, would you think about tailoring in some ceramic proppant as well and just changing some of the nuances of the completion?

The vast majority of the wells we frac in the Bakken now -- and of course, we are the leading producer in the Bakken in North Dakota, so I guess we have the biggest database -- the vast majority of it has been just propped with 20/40 sand. We have used a bit of ceramic proppant in some instances, and we are still evaluating that. But it's not obvious to us that we need to go to anything more expensive than the 20/40 sand.

Okay. If I can just move to the Haynesville. Just a little more color on the decision to concurrently develop the middle and lower Bossier intervals. Are you suggesting that the two zones offer similar economics or was it more of a bigger call on dual-zone development through a single well bore?

I don't want to give the impression it is through a single well bore. It is not -- as we see it now, we drill a separate well to develop this Bossier and then another well to develop the Haynesville. So we are not looking at two laterals in the same well bore, at least at this junction.

The significance of what we said is that it looks to us, based on the couple months' production performance from this Sustainable Forest Well, that the productivity and the reserves from the Bossier are about identical to our typical Haynesville well. And that is pretty critical.

And we frac monitored this Sustainable Forest well, and we know that the frac did not go down into the Haynesville; i.e. what is coming out of well bore of that well is really Bossier production and not Haynesville production. And where that leads us to, if you take our 160,000 acres, our best guess at this time is that over half of that acreage has both zones.

So this is a pretty big deal in terms of what it could mean for total reserves on our acreage in the Haynesville.

Great. Last question and I promise I'll jump off. One of the things that the analyst community is going to be struggling with over the next few months is thinking about undeveloped versus unbooked locations, given the new SEC rules. And to help us better assess EOG's net asset value, would you be willing to start providing either net unbooked acreage or location as opposed to undeveloped to help us reconcile what is already included in your PV 10?

I kind of doubt that we would want to do that. You get into reporting -- you know, right now, we had a lot of work just reporting under these new SEC rules, and I'm not sure we want to go reporting net unbooked locations. So we'll take a look at that, but my initial blush is that that is something we are probably not going to get into.

Thank you.

Ben Dell.

I guess I just had one question, which is on your PDPs. They obviously fell year on year. And if I look at the PDP F&D number, it is very high both versus your history -- versus peers. It's also high if I take out the revisions.

Can you walk us through why the PDP number pretty much in every geography really didn't really grow, or in some cases declined?

Well, the revisions are a big portion of it there. And I can't really -- the only other explanation I can give you, other than the revision side, is that -- it is a pretty open secret that we spent a lot of money on leasehold for these stealth oil plays last year. And of course, all of that is reflected -- would be reflected in whatever mining costs you calculate.

So this -- we are going to look back, and 2009, I think, will be viewed as a positioning year for EOG relating to horizontal oil plays. And again, what I would ask of you -- I know you -- everybody out there is going to calculate reserve replacement in a different way, but I would say you will get a pretty clear picture in early April of kind of a lot more of the items relating to EOG. So I wouldn't take any data point right now out of context from this point.

Okay. And just a follow-up question. Obviously, we've seen the horizontal rig count now back at all-time highs. Can you give us an indication of what you are seeing on horizontal spot day rates, availability and also on pressure pumping rates and availability?

Yes, we've been able to acquire -- contract the rigs that we are going to need through the next year. We've got 39 rigs under long-term. That is, like a year contract. Rates are starting to increase in some of the high activity areas. And over the last two or three months, yes, we've seen them go up anywhere from 5% to 15%. And the same is probably going to relate to stimulation, where you expect maybe in 2010 to see stimulation costs creep upward maybe in the 5% to 15% range.

That's great. That's all I had.

We've been able to lock in most of our services. We've worked hard on the rigs and have in -- over 50% of them locked in, as well as locking in on the stimulation.

The other thing that we did in 2009 is while we had low tubular costs, EOG purchased most all of the tubulars that we are going to use in year 2010 as well.

Okay, great. Thank you.

Brian Singer.

Can you talk a little bit about production trajectory on oil? It looks like a lot of the increase you are projecting is going to come in the second, third and fourth quarters. Can you just talk a little bit about that?

And then secondly, on the natural gas side, could you comment on your uncompleted well inventory and when that comes back online or if it has already?

In terms of the -- particularly the production trajectory, your question relating to oil, it is pretty well certain that every quarter this year our oil production is going to be going up. And the big reason why it is second-half loaded as opposed to the first quarter really relates to the Bakken. Again, it is just due to seasonality on when we are going to frac a lot of the wells. And it is just more expensive to complete wells in the wintertime in North Dakota, as you can visualize.

So part of our plan is to go relatively slow on well completions until the summer, and then blitz it during the temperate weather periods in North Dakota. So what you're going to see is a big ramp-up at that point in time, really.

So that is the biggest single driver in the trajectory, other than just we've got cumulative higher rig activity that is going to occur in the drilling this year.

On the uncompleted well count, we have never had a significant amount of uncompleted wells. We've got a few Johnson County wells that we will be completing as we get into this year. But our view of that is that this whole concept of uncompleted gas wells maybe has been overblown. We don't see there is a tsunami of uncompleted gas wells out there in the industry that is going to get -- come on and flood the market or so.

Thank you. That's helpful. And just as a follow-up, on the Bossier, can you just provide any more color or characterization of how you are defining the play and kind of what keeps it to --I think you mentioned 50% of your acreage?

Brian, it is really just the geology of where that particular zone is deposited. It is not present in some parts of the play or it's clay-rich in some parts of the play. And in other parts of the play, it cleans up and loses clay content and becomes just as good in terms of porosity and permeability and actually pressure as the Haynesville itself. And we've mapped that out both with our own well control, a lot of core data that we've taken, proprietary core data, as well as industry -- other industry log data.

And do you see DeSoto Parish as being the sweet spot for the Bossier, or do you see it extending into other counties that you may not have acreage?

We're not really going to comment on its distribution just yet. I think we are still -- just not ready to talk about its total distribution yet. We will say, as Mark said earlier, it covers a substantial part of our acreage, at least 50%.

Thank you.

[Scott Wilmoth].

Sticking with the Haynesville, the new presentation you guys have, Haynesville Bossier production exiting the year at about 175 million a day. I think previous estimates were about 200 million a day. What drove that variance?

We just -- looking at the leadtimes to schedule the frac crews and factoring in some down time, it is just, I'll say, a more precise estimate of where we are looking at. It is certainly not an indication of our well performance. What we've seen so far is that the well performance has been -- indicates we've got pretty well -- strong reserves per well.

The other nuance that is dialed into that, Scott, is -- and you may have heard this with some other peer companies' calls relating to Haynesville -- is there is a theory out there now that you don't want to pull these wells real hard in the first year, and that will improve the ultimate recovery.

And we are -- I guess at this point, we are subscribers to that theory. We don't have enough data to confirm it's absolutely certain. But what we've dialed in there is that we are going to pull our wells a little bit less hard, lower rates, than the estimates we gave three months ago.

Okay. And then in the Bakken, do you guys have any plans to test a dual lateral in testing the middle Bakken and the Three Forks both?

Not in one well bore. We did some of that out in the Permian Basin about five or six years ago, and the mechanical complexities of that just -- it sounds like a great idea on paper, but the mechanical complexities are pretty darn high.

So at this stage, we will be looking at developing -- for those areas where we've got the Three Forks and the Bakken overlaying each other, at this stage, we are looking at developing them with two separate wells.

Okay. And then what is current production out of the basin in the Bakken, and where do you expect to exit the year?

Our net production right now is -- what -- about 26,000 or so? About 26,000 net after royalty, that is EOG. And I don't have an estimate as to where we are going to exit the year in the Bakken in front of me here. It will be minor.

Okay. They my last question, on the PUD percentage, obviously, has increased with the new SEC regulations. Can you give us a little insight into how many offsets were booked in your major unconventional plays?

Yes, was it about -- I guess the best way to describe it is what we ended up booking is not the most that we could have done under the five-year rule. In other words, this whole PUD issue is really thrown up in the air, as I noted on the last quarter's earnings call. And certainly, if we would have wanted to, we could have booked a whole lot more PUDs than we actually booked, and still been within the five-year rule. So hopefully, that gives you some insight into it.

Okay, thanks. That's helpful.

David Tameron.

Mark, just (inaudible) with that last question. How do you think about it as a management team or how do you decide what level of PUDs is appropriate? It looks like you came within 5% of D&M's number, so it sounds like you guys were all along the same lines. Can you just talk about that thought process?

Yes, we did a very sophisticated process as far as evaluating how many PUDs were available, could it be done within a five-year program, looking at the technical feasibility of that.

But I guess the best way I would describe it, David, is -- and again, I referenced it a little bit on the last call -- that expect to see a very wide variance among companies as to what they've done on PUD booking.

And what we did is, I would say, we took a middle ground approach. We took the SEC rules, and we said, well, they now allow us to book considerably more PUDs than in the past rules, but let's just not push that to the edge of the envelope and book the absolute maximum number of PUDs that could be done under these SEC rules.

And then we tempered that a bit with those areas that we had done a lot of drilling in and those areas that we hadn't done quite as much drilling in. So it is very subjective, and that is why you are going to probably see some interesting numbers come out as companies report.

Okay. Along those same lines, can you split out for us how much of the upward number in reserves was due to the new SEC rules, particularly the PUDs? Do you have that versus a year ago, just to give us a little more apples to apples?

No, we don't have that handy, David.

Okay. One more, going down this reserve path, one more question. Then I've got a macro question. But I guess two questions.

One, can you give me a PV 10? And then second, how should we think about -- your gas reserves are 80% -- I guess 83%. Yet all the focus is on oil going forward. Would you expect going forward to have the gas reserves maybe trend up a little bit and then oil take over a bigger percentage? Or how should we think about that -- if we think about this five years down the road, what would you expect those two percentages to be?

Relating to the PV 10, that will be issued when we issue our 10-K. And on the question of percentage of our total reserves that are gas versus oil versus NGLs, I think that the production is ahead of the reserves in terms of -- we are talking about 47% production from North America this year. That is clearly ahead of the reserve bookings. What you will clearly see over the next five years with EOG is that the percent of oil reserves relative to the percent of gas reserves is going to go up prospectively.

Okay, so we should see oil PDP's climb in the future? Is that accurate -- that would be correct?

Yes, I think that's an accurate statement.

Okay. And then one final question, just on the macro front. Can you give us your thoughts -- you know, there is conspiracy theories coming out of Oklahoma City, EIA data that people aren't sure if it is correct or accurate. Can you just give us your thoughts on going back a year to today, rig count decline, we haven't seen a decline in gas markets. Can you give us your current thoughts where you're at?

For what they are worth, we look at the 914 data and we try and tie that back to the IHS data, and we really can't tie that. It looks to us like the 914 data is just consistently overstating, particularly in the other states category. The second item we look at on the 914 data is just this balancing item, and the balancing item seems to have grown over time.

So we've tied our internal models to the IHS data. And even though the rig -- gas rig count has gone up considerably over the last four or five months, what it tells us is that production is still going to be down to the tune of [a Bcf a day] relative to December '08 throughout all of 2010. And only will it be in 2011 when you start to see the reversal due to the rig count.

And then the other data point that we think is probably the clearest data point that something may be amiss with the EIA data is just the -- if you look at how much storage drawdown has occurred in December and January, how many Bcf has been pulled out of storage, and you relate that to degree days compared to last year, it is a pretty good prima facie case that we must be tighter than we were a year ago, considerably, on supply/demand. So it's either got to be less supply or more demand, and we kind of believe it is probably less supply.

So you've had about -- it sounds like you're more of like a $7.00 gas guy for 2010. Is that --?

Well, I think -- we put out, I think, this morning on our website something like a $6.75 price for the full year '10.

All right. Thanks for the Q&A.

Leo Mariani.

You guys made some prepared comments about your oil differentials in the Bakken shrinking, but your transportation costs going up. Can you give us a sense of what the net benefit is to EOG on kind of a dollars-per-barrel basis of putting that rail in place?

Just the Cushing price right now is about $3.00 per barrel better than what we get there locally. And the average is usually round about $5.00 as far as it differs between North Dakota and Cushing.

And of course, we put in this Crude by Rail because there's time where the trucking and the trucking plus rail is much higher than either pipeline or Crude by Rail. So it is just a transportation alternative for us.

Okay, and what does it cost you guys to move your barrels by rail from Stanley to Cushing?

We don't want to get into specifics on that, other than the net of it shows up in the shrunk differentials that we are projecting for 2010 really, Leo.

Okay. You guys mentioned in your release that you sold some California reserves. Is that just kind of a legacy property, and can you give a sense of what production and reserves were associated with that?

Yes. The production was about 1000 barrels of oil a day. The reserves, on a Bcfe basis, were about 30 Bcfe. And the sales price was roughly $200 million.

Okay. Getting over to your Barnett Combo play, I know you guys reported a couple of wells in Montauk County and a horizontal basis here. It looks like those well results were a bit lower than some of the horizontal wells you reported in the past. And in Cook County, just trying to get a sense if you guys view these as stepout wells. I think in the past you had talked about sort of a 90,000 acre core position in the Combo. Has that changed? Has that number moved around as a result of some of your recent drilling? Give me a sense of that.

I wouldn't try and compare necessarily the rates we quoted, like this quarter versus last quarter. The most important thing is that the reserves per well we quoted last quarter and this quarter are identical. That is that 280 net after royalty Mboe for the horizontals and about 220 Mboe for the verticals.

So our read is that the wells we've completed this past quarter are essentially identical to the wells in the previous quarter. The initial oil rates are such that in some cases, you end up with a higher percentage of oil with the total mix than others. But the bottom line is we are pretty pleased with the consistency and don't read [at depth] at all that we've got some degradation of the combo relative to last quarter, because that is just not true.

Okay. Last question on your Rockies property swap. You talked abut this briefly. Just want to get a sense if there's net change as a result in reserves and production of moving some properties off and bringing some properties in there.

On the production side, it was basically an even swap. On the reserve side, yes, we made some adjustment to our reserves relating to that. But basically what we did is concentrate an asset where we now have a much higher working interest in one of our Utah assets.

Okay. Thanks, guys.

Ray Deacon.

Mark, I was just curious if you could break down the gross Haynesville and shale wells versus the upper Haynesville or the Bossier shales, I guess.

Oh, the number of wells?

Is it still predominately Haynesville shale wells?

Yes, well over half of the wells we are going to be drilling this year are going to be the Haynesville (multiple speakers) Bossier. Kind of where we are specifically on the Bossier, just a little more color there is, we've got the one well that we reported, the Sustainable Forest well. We are currently completing another well. We are drilling several other wells to really confirm what we believe, which is this zone exists over 50% of our acreage.

So we will definitely have more color on this. But even though Bossier is a new item, the Haynesville is going to be the bigger dog in terms of production impact relative to the Bossier for EOG 2010.

Okay, counted. And have you said what your return on capital employed target is going to be over the next three years?

Well, I think -- no, we haven't. All we can refer people to is we've, since 1999, we've averaged I think it is 19% ROCE over -- it is a 10 or 11-year average, including last year where it was only 5%. So be proud of that as -- and more importantly, the differential between us and other companies in the peer group is pretty dramatic in there.

We believe we will be able to keep that differential. And the main reason -- you got me started on this one, Ray -- the main reason why we believe we are going to keep that ROCE differential is that the preponderance of our CapEx on a go-forward basis is going to be invested in oil-related projects.

And simply put, the value you get for a BTU of oil, we believe is going to considerably exceed the value that is received for a BTU of gas. So relative to a lot of other companies who basically are going to be reinvesting primarily in gas over the next five years, we're going to be doing it primarily in oil. And we just think it is going to be a higher net-back to us.

So logically, you would expect that we are going to generate superior ROCEs just from that parameter, if nothing else.

Counted, great. Thanks very much.

Due to time constraints today, we will take our final question from Irene Haas.

I have a question back on the Bossier and Haynesville. As such, would you give us a little more color regarding thickness, TOC, porosity as the Haynesville presumably is dry gas? And really to step back one more step is that there's sort of positive implication on your sweet spot in East Texas, because that is probably a nice place to prospect for the Bossier Shale being a little shallower than Haynesville. And could we have better clay content in Nacogdoches?

Yes, Irene, it is dry gas, just as the Haynesville is. I mean they're only 200 feet apart, so the maturation parameters are essentially identical. TOC is fairly similar as well. Clay content is slightly higher in the Bossier than it is in the Haynesville ,at least in some areas.

Really, other than that, we are just not prepared to talk about where that sweet spot goes or doesn't go today. I think the well that we announced is obviously in De Soto, but we are looking at it in a number of other areas, both with fresh modern logs and fresh modern core.

Thank you.

Once again, we want to thank everyone for sitting in on the call and we will look forward to seeing many of you in person on April 7 here in Houston. Thank you.

This concludes today's conference call. You may disconnect at any time. Thank you for joining us. Enjoy the rest of your day.