EOG Resources Inc (EOG) 2009 Q3 法說會逐字稿

Good day, everyone and welcome to EOG Resources' third-quarter 2009 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 Friday morning and thanks for joining us. We hope everyone has seen the press release announcing third-quarter 2009 earnings and operational results. Also included was guidance for the fourth quarter and full year 2009.

This conference call includes forward-looking statements. 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 EOGResources.com.

The SEC currently permits producers to disclose only proved reserves in our securities filings. 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 other categories of reserves. 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. An updated Investor Relations presentation and statistics were posted to our website this morning.

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; and Maire Baldwin, Vice President, Investor Relations.

I will begin by reviewing our third-quarter net income available to common stockholders and discretionary cash flow and then I will discuss our 2010 operations plan and some of the recent operational highlights. Tim Driggers will provide some financial details and then I will provide some macro comments and concluding remarks.

As outlined in our press release, for the third quarter, EOG reported net income available to common stockholders of $4.2 million, or $0.02 per share. For investors who follow the practice of industry analysts that focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impacts as outlined in the press release, EOG's third-quarter adjusted net income available to common stockholders was $203.9 million, or $0.81 per share. For investors who follow the practice of industry analysts that focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $819.4 million.

Our third-quarter production and costs were in line or better than the midpoint of our guidance and because our crude oil production numbers continue to be a bit stronger than forecast, we are increasing our full-year 2009 total Company production growth forecast from 5.5% to 6% and our full-year total liquids production growth forecast from 25% to 27%.

Additionally, for the first time, we are providing a 2010 total Company organic production growth target of 13%. For 2010, our combined target for liquids growth is 50%, comprised of 55% total Company crude oil growth and 25% total Company NGL growth.

On the gas side, we project 3% North American gas growth and 4% combined gas growth from Trinidad, the UK and China. Let me provide some additional color regarding these 2010 growth plans. Our 3% North American gas growth target is a function of our macro view. We believe 2010 gas prices will start the year weak and end strong. We don't see the economic rationale regarding growing gas production in adverse markets.

You'll recall we purposely didn't pursue North American gas growth in 2009 versus 2008 because of low prices. In fact, the full-year 2009 guidance we updated yesterday has it projected to fall by 2%. In 2010, we will target flat North American gas production for the first half of the year and then an annualized run rate of 6% for the second half. Hence, the 3% year-over-year number. I will note that with our arsenal of gas sets assets, we can easily organically grow our gas at a 15% annual rate for multiple years, so we are continuing to moderate our gas drilling activity.

The majority of our 2010 gas growth will come from the Haynesville play. Our 50% total Company year-over-year expected 2010 liquids growth will primarily emanate from the Barnett Combo, the Bakken and Waskada horizontal plays with some contributions from other plays. All of the liquids growth will occur in North America and the majority will be from the US.

For the past year, we have been telling people that oil horizontal drilling in unconventional rock was a game-changer and our 50% targeted growth rate provides solid evidence. I will also note that we expect further significant liquid decreases in subsequent years.

We haven't finalized our 2010 CapEx yet and we will provide that early next year, but we expect that at least 60% of our North American budget will be allocated to oil. Recently, I have received some analyst questions regarding how this quote, unquote shale oil is actually recovered. The answer is we simply perforate and frac the oil wells in a manner similar to the shale gas plays. Our horizontal oil program is not analogous to the thermal projects occurring in Colorado and northern Alberta.

Simply put, ours is conventional production. Also the quality of oil we recover from these unconventional rocks is very good. No sulfur, 36 to 42 degree API gravity and similar or better than WTI.

The two biggest contributors to our 2010 liquids growth will be the Barnett Combo and the Bakken with roughly equal growth increments. I'll start with the Barnett Combo play. During the third quarter, we closed on another acquisition in the Combo core area whereby we acquired 7800 net acres and 350 barrels of equivalent oil per day of net production for $63 million.

Following the acquisition reported last quarter, this provides us near total dominance in the 90,000 acre Combo core area of eastern Montague and Western Cooke Counties. For a company that rarely makes an acquisition, this speaks to our confidence in this asset. Since we now have secured our acreage position, we can be a bit more forthcoming regarding results from the Combo.

This portion of the Barnett contains an average of 70 million barrels of oil and 175 Bcf gas in place for 640 acres. It is one of the richest oil deposits we have ever encountered. We are developing this Combo asset with both vertical and horizontal wells. In the eastern portions of the core area where the Barnett is between 700 and 1500 foot thick, we use vertical wells on 20 acre or even more dense spacing. Two recent vertical examples are the Fitzgerald No. 1 and Stephenson No. 1 wells. These wells IPed at 1067 and 450 barrels of oil per day with 2.1 million cubic feet of gas and 700 Mcf a day of rich gas respectively. EOG has 100% working interest in the wells. We expect the average vertical well to produce 220 Mboe net after royalty for a $2.1 -- excuse me -- $2.2 million cost yielding a 70% after-tax reinvestment rate of return at current NYMEX strip prices. Core areas where the Barnett is less than 700 feet thick, we will be using horizontal wells.

Four recent 100% working interest horizontal wells are the [Christian A1H] and [B1H], which IPed at 1000 barrels of oil per day with 2.5 million cubic feet of gas and 600 barrels of oil per day with 2 million cubic feet of gas. The [Duntrust B1H] and [C1H] had IP rates of 380 barrels of oil per day with 250 Mcf per day of gas and 360 barrels of oil per day with 225 Mcf of gas respectively. Our average horizontal per well reserves have increased with experience similar to our gas results in Johnson County.

In March 2008, we estimated per well NAR reserves at 152 Mboe. This grew to 210 Mboe in February 2009 and our last 14 horizontals have averaged 280 Mboe per well. At the current $3.3 million well cost, this yields a 60% after-tax reinvestment rate of return at current NYMEX prices.

I will note that our activity to date has been in some of the thickest parts of the play. In 2010, we plan to run 12 drilling rigs in the Combo, seven horizontal and five vertical, compared to only two rigs in the gas portion of the Barnett. We expect to drill 225 Combo wells in 2010 compared to 100 this year.

In the North Dakota Bakken, we will run 14 rigs in 2010, drilling in the Bakken core, Bakken Lite and Three Forks formations. Recent core wells are the Fertile 9-8H and 13-18H and the Parshall 3-19H, which IPed at rates ranging from 880 to 1150 barrels of oil per day. We have between 70% and 100% working interest in these wells.

Equally importantly, our Bakken Lite step-outs outside the core area are continuing to yield good results. The Ross 10-18H and 5-8H, Clearwater 2-1H and Cottonwood 5-34H wells IPed at rates ranging from 470 to 840 barrels of oil per day with working interest between 78% and 100%.

At current strip oil NYMEX prices, the core area wells approached 100% after-tax rate of return and the Lite wells yield 35% after-tax rate of return. Additionally, preliminary tests indicate that the Three Forks is productive and not pressure-depleted under a portion of our 500,000 acres. The next steps are to determine how much of our acreage is prospective with Three Forks potential and we will have more details on subsequent calls.

Also, both of our Bakken infrastructure projects are on schedule. Our wet gas pipeline will be commissioned next month and the crude oil railcar project will start up in February. We continue to believe that Bakken and Three Forks will be very big long-term plays for both EOG and the industry and will have a significant part of the infrastructure.

In the Mid-Continent, EOG continues to achieve solid results in the horizontal Cleveland oil play in the Texas Panhandle. The two most recent wells are the Cooper 436-3H, which began producing at a rate of 515 barrels of oil per day, plus 2 million of residue gas and 185 barrels of NGLs and the Cooper 436-4H, which went on production at a rate of 540 barrels of oil per day plus 3.3 million cubic feet of gas and 310 barrels of NGL. We have 100% working interest in both wells. We expect to drill 30 wells in this play over the remainder of 2009 and in 2010.

Our Manitoba Waskada horizontal oil project is performing better than expected and we expect to average 6000 barrels of oil per day net from this project in 2010 at 100% after-tax reinvestment rate of return.

Now I'll turn to the North American gas side of the ledger. Recently consummated, a Haynesville acreage transaction in Nacogdoches County, Texas, EOG acquired approximately 50,000 acres of Haynesville deep rights. After adjusting for [an] AMI partners likely exercising its right to acquire a portion, we have added 37,000 net acres. We now have 153,000 net Haynesville acres, but the location of our acreage is more important than the total number.

Our acreage is concentrated primarily in two areas. One portion is in Louisiana's DeSoto Parish, which is in the original core area and where we have previously reported well IPs of 15 plus million cubic feet a day. The remainder of the acreage is primarily in Nacogdoches and St. Augustine Counties in East Texas. And our recent well results confirm a second core area in Nacogdoches County.

Our Gammage No. 1 exploration well, which we had not addressed publicly, kicked off a lot of analyst speculation about this area. Actually, the Gammage turned out to be a decent well as a short lateral, but we followed that up with several outstanding wells that rival the best found in the Louisiana core area.

Also in Nacogdoches County, the Hill No. 1, Pop Pop No. 1 and [Hassle] No. 1 wells each IPed at rates in excess of 15 million cubic feet a day to 7250 psi flowing tubing pressure and we could have opened them up farther and obtained higher IPs. We have 42% working interest in these wells.

Logs and early production history indicate we have found a new Haynesville sweet spot and the acreage acquisition noted earlier offsets these wells. These wells have higher bottom-hole pressures than the established North Louisiana sweet spots yielding estimated gross reserves of 10 BCF per well for a $10 million well cost.

We believe we are consistently making the best Haynesville wells in the industry. 92% of our wells IPed at rates greater than 10 million cubic feet a day and only 8% IPed at less than 7 million cubic feet a day. We have updated our website with this comparative chart. We plan to run 10 Haynesville rigs in 2010 and increase our Haynesville net gas production from the current 40 million cubic feet a day to 200 million cubic feet a day by year-end 2010. The Haynesville will be the primary driver of our 2010 North American gas production increase.

We will also continue to be active in our Barnett gas Johnson County core area. Our 2009 finding costs here have averaged $1.45 per Mcf, and we expect a similar 2010 finding cost for our two-rig 2010 program. Combined with the gas from the combo play, we will have modest year-over-year Barnett gas growth in 2010.

In the Horn River basin, we completed seven wells this summer in a program focusing on improving operational performance and completion techniques, along with determining optimum spacing patterns. We were able to reduce our drilling days by 42% and our well costs by 35% over 2008 levels, and have now set cost targets for each area that provide attractive rates of return.

The three wells in one pattern IP'd at 23.4 million, 19.3 million and 17.2 million cubic feet a day, while the four wells in the other pattern tested at rates between 16 million and 18 million cubic feet a day. We will produce these wells throughout the winter to evaluate the efficacy of each pattern. We believe the three high-rated wells are among the best in the play, topping our 16 million cubic feet a day well completed last year.

The B.C. government has recently approved our application for royalty incentives for a significant portion of our acreage, which is a big step forward in making this play competitive with US shale plays. And we also have a memorandum of understanding with Kitimat LNG to supply a significant volume for their proposed LNG export terminal. We are planning a slow but steady Horn River activity ramp-up and expect to drill 12 wells in 2010.

In the Marcellus, we are operating two rigs and we will continue that same level of activity in 2010. Our results continue to be consistent. The COP 2316-5H and 6H wells, and the [Punctsy] 9H well recently IPed at 2.6 million, 2.9 million and 3.2 million cubic feet a day respectively. These are likely 2.5 to 3 Bcf NAR wells for $1.60 finding cost.

We recently obtained pipeline connects for our first Marcellus production and expect an average of about 16 million cubic feet a day of Marcellus sales in 2010. So we are prosecuting this development program at a conservative pace.

Our horizontal gas wells continue to provide surprising upside, even in areas previously thought to be depleted. In our Green River Basin Big Piney area, we drilled two horizontal wells in the center of a field that has been producing for 50 years and had wells with IPs of 3 million cubic feet a day with 100% rate of return economics, indicating we have horizontal sandstone potential in this old field. We've also achieved 100% rate of returns drilling Frio sand directional wells under Nueces Bay near Corpus Christi, Texas. Two recent wells are the [State Track] 788 gas unit No. 1 and 692 No. 1. Each of these will produce about 20 Bcf of gas with 1 million barrels of liquids per well.

Regarding our activities outside North America, we will be fracture-treating our first horizontal gas well in China this quarter, but it will be mid-2010 before we can declare whether this project is successful or not. We will be drilling several East Irish Sea and North Sea oil prospects during the first quarter as a follow-up to our success reported last quarter. I will now turn it over to Tim Driggers to discuss financials and capital structure.

Thanks, Mark. For the third quarter, exploration and development expenditures were $969 million, excluding asset retirement costs. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $89 million. Acquisitions during the quarter were $199 million.

Year-to-date through September 30, exploration and development expenditures were $2.5 billion, excluding asset retirement costs. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $241 million. Through September, acquisitions were $206 million.

Capitalized interest for the quarter was $13 million. At September 30, total debt outstanding was $2.8 billion and the debt-to-total cap ratio was 23%. At September 30, we had $609 million of cash, giving us non-GAAP net debt of $2.2 billion for a net debt-to-total cap ratio of 19%. The effective tax rate for the third quarter was 8%.

Yesterday, we included in the press release a table with fourth-quarter and full-year 2009 guidance. The guidance indicates a full-year 2009 total cap expenditure budget of $3.7 billion, including $320 million of acquisitions. For the full year 2009, the guidance indicates an effective tax rate of 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the fourth quarter and full year. Now I will turn it back to Mark to discuss the macro environment, our hedge position and his concluding remarks.

Thanks, Tim. Our review of the North American gas and oil markets is directionally consistent with our previous earnings call. We still expect North American gas prices to remain low through the end of this year, start out 2010 weak and end 2010 strong, due to supply declines that will occur throughout 2010.

Quantifying the magnitude of the domestic supply design is becoming more opaque. You may have noticed that the EIA recently revised downward their estimate of 2008 gross production by about a half a Bcf a day, but did not adjust their 2009 data. Given these revisions, our supply model can match the EIA 2008 volumes, but not the 2009 numbers. Assuming a year-end 2009 gas rig count of 740, we estimate production will be down 3.2 Bcf a day by December and 5 Bcf a day by June 2010 relative to December 2008. Combined with 0.8 Bcf a day year-over-year decline occurring in Canada, offset by a 1 to 2 Bcf a day increase in 2010 LNG imports, we expect the gas market to tighten by mid-2010. We are already seeing evidence of this tightening. Storage injections since mid-June have been running about 2 Bcf a day less than last year and half a Bcf a day less than the five-year average.

Our financial gas hedge position is shown in our 8-K and is unchanged from last quarter. We have 44% of our fourth-quarter 2009 North American natural gas hedged at $9.43 and then we are likely hedged for the first half of 2010. Our oil view continues to be that the 2010 through 2012 NYMEX is reasonably reflective of what oil prices will likely be. We are long-term bullish regarding oil and have no oil hedges.

Before I summarize, I will interject an editorial comment regarding industry year-end reserve bookings. It is our belief that the new PUD booking rules provide a much larger amount of flexibility than previously was permitted. Hence, you can expect to see big variations in PUD bookings across companies, making it difficult for analysts to make comparisons between companies regarding proved reserve replacement rates and finding costs. This is not code for EOG signaling a reserve or finding cost problem, but I felt that at least one industry executive should alert shareholders that you will have one less comparative tool to measure industry results.

Now let me summarize. In my opinion, there are six important points to take away from this call. First, the impact of our horizontal oil plays is gaining momentum. Our year-over-year total Company organic liquids growth for 2008 and 2009 and projected 2010 is 42%, 27% and 50% and we expect further growth in 2011 and later years. Using a 10 to 1 equivalency basis to account for economic evaluation, our 2010 North American liquids to gas ratio will be 44%, up from 36% in 2009. We previously estimated that EOG would organically evolve to a 50/50 mix by 2013. We now project that will occur in the 2011-2012 timeframe.

Second, all these horizontal oil projects in unconventional rock yield between 30% and 70% after-tax rates of return at unescalated $75 oil prices and a 15% return at $50 oil prices. We don't need escalating oil prices to generate superior reinvestment rates of return. Our horizontal oil inventory is a key differentiator and will likely allow EOG to outperform peer companies in ROCE for the next decade, similar to our outperformance during the past decade.

Third, as you probably already suspected, all of these oil concepts have been generated in-house and we are working on additional horizontal oil plays not delineated in this call. We expect to disclose these during the next 12 months after we lock up acreage and evaluate well results. During the past three years, we spent around $1.3 billion on acreage and most of that was for horizontal oil and liquids rich gas concepts.

Fourth, we have extended the Haynesville sweet spot onto our East Texas acreage and increased our Haynesville net acreage position by 32%. All of this incremental acreage is in the new sweet spot.

Fifth, we continue to have success in the Horn River and Marcellus gas plays and we expect an $1.45 all-in finding cost for our Barnett gas.

And finally, we expect to accomplish all of the above while maintaining the lowest net debt in the peer group. We can do this because we are transforming our North American production mix organically instead of through a value-destroying M&A or mega acquisition. We also expect to continue to have one of the lowest all-in unit costs in the group in spite the fact that our peers have collectively written off $41 billion in the past 12 months compared to no major write-offs for EOG. It is a very exciting time to be at EOG. Thanks for listening and now we will go to Q&A.

(Operator Instructions). David Tameron, Wells Fargo.

Hi, good morning, everybody. Congrats on the nice quarter, Mark. A couple questions. Can I get a 2010 CapEx number to go with that 13% growth?

No.

Can you give us a range or what you're thinking since you threw the growth number out there?

We haven't finalized the CapEx yet and we will give that early next year. But the only thing I can give you directionally is our intention is to continue to run this Company with the lowest net debt of any company in the peer group. So that should give you something to work with anyway.

All right. Moving to the Bakken, a year ago at the conference, you gave us some (inaudible) place numbers. I think the number was -- I have in front of me -- it was 9 million barrels per section of oil in place. Have you guys taken a look at that or do you have that in front of you as far as what that new number is, oil in place per section up at the Bakken, what you guys think?

Yes, your 9 million barrels for the core area is correct on there. So that number is the same. Just a little bit of description on the Bakken there. The core area, which is about 90,000 of our 500,000 acres, we have still got a fair amount of drilling yet to do in that, but that is pretty well a slamdunk.

The real questions we have technically relating to the Bakken are out of the remaining 410,000 acres, how much of that is productive in what we call the Bakken Lite? Now our terminology Bakken Lite is equivalent to everybody else's Bakken because nobody else has the core. And what we have found is that we are encouraged that it appears likely a pretty significant percentage of our acreage is going to work in the Bakken Lite to the tune of this roughly 35% reinvestment rate of return.

Additionally, we have been fully aware that the Three Forks zone exists below at least a part of our acreage and is probably productive. It is about 40 feet below the Bakken in the core area. And one of the questions we had was, well, we are getting such monster wells in the core area, are there fracs that we are getting through the Bakken core, are they actually draining the Three Forks also?

And during this past quarter, we have opened up a portion of the Three Forks in wells in our core area where we have already produced the Bakken regular core and we are very encouraged to find that the pressures that exist in the Three Forks do not indicate pressure depletion from the core. So there is certainly a strong indication that we may have another oilfield that [meets] our core oilfield. And I would say these pressure results are consistent with what at least one other operator has already delineated.

So our big projects for 2010 really are going to be delineating how much of the area is really productive in Three Forks and what are we looking at there out of this really 500,000 acres and then how much of the 400,000 non-core Bakken acres are really productive under this Bakken Lite concept.

Okay, and just one quick follow-up on that and I will let somebody else jump on. Up in the Bakken, 14 rigs, can you give us a breakdown of how much is core versus Lite next year? How much you need to field each play?

It is probably 50/50 the core and then 50% will be Lite/Three Forks. That is a rough number, David.

Okay, okay. That works. Thanks.

Michael Jacobs, Tudor, Pickering, Holt.

Good morning, everyone. Hey, Mark, thanks for disclosing all the color on well results and rates of return. I am hoping you can help me out with a conceptual question. You are privy to more industry chatter than most. I'd like your thoughts on how you think about geologic versus economic risk in South Texas as you think of acreage north and south of the Edwards Reef.

Yes, that is code for what is going on in Eagle Ford and our flippant response is no habla Eagle Ford. But it is an open secret that we are drilling some wells in Eagle Ford, but it is just too soon for us to really opine on the results we are achieving or what acreage position we have. So all we can offer on that is that, in subsequent calls, not necessarily immediately the next call perhaps, but in subsequent calls within the next 12 months, we will disclose what the situation is in South Texas.

Okay. And recognizing that some plays are earlier than others, how would you rank Bakken core, Barnett Combo, horizontal Cleveland oil and what you have heard others are doing in the Eagle Ford in terms of rates of return? Kind of your favorite areas from a rate of return standpoint?

Yes, I am not sure -- well, I mean clearly the Bakken core is the winner at rates of return. Those returns are approaching 100% at current oil prices. Once you get out of that area, our feeling is, if you take a look at the horizontal oil plays that we have disclosed and other ones that we are working on, we believe that one characteristic of all of them is that, at $75 flat on escalated oil, they are going to yield between 30% and 70% after-tax reinvestment rates of return. So we are finding that across different basins, the rates of return similarities are not all that disparate except for the one outlier, which happens to be the Bakken core and there, we have got the overpressured Bakken with everything we want, but everything else is pretty consistent.

So the key thing we are really -- except also for Waskada, which turns out -- that is more -- that is not really a shale play. That one we are getting 100% rates of return. Most of the others are in the 30% to 70% range. But the key point here is that these aren't unconventional rock plays that are just barely scraping by with a 15% rate of return where you are just barely beating your cost of capital. These are ones that we think are going to be key differentiators for us and we have been very open about it.

We think this is a game-changer and we think we are three years ahead of the rest of the industry and we are not going to talk about it much as to the specifics until we have a situation such as the Barnett Combo where we essentially own the entire play. We would be hurting our shareholders' best interest to disclose anything on any of these plays and to insight further acreage competition in them and we don't intend to do that.

That makes sense. One point of clarification if I can move to East Texas, the 10 Bcf per well, is that for the middle and the lower Bossier or is that just for the lower Bossier?

No, that is just for the lower -- basically the lower Haynesville is what we call it. We believe that the lower Bossier or the upper Haynesville, depending on how you call it, is likely also productive on significant swaths of our 153,000 acres. And we will probably have more color on that in the next earnings call. We are currently drilling some wells to target that specific zone.

Let me ask one more and I will hop off. And recognizing what you said about increasing the price of poker, can you just give us the geologic concept that you tested with [Kurat] and kind of how happy or not you were in terms of testing a concept?

Yes, you cut out a little bit. Testing the concept where?

Kind of when you think about Montana Bakken or Three Forks, whatever it is.

Yes, I will turn that one over to Loren.

Really not sure, Michael, where you're asking about. The Bakken as a whole, as we said, we divided into the core area, which is in North Dakota and the Lite area, which is primarily in North Dakota as well; although it does slop around a little bit. Our 500,000 acres includes large portions of the core area. I think we talk about it 90,000 to 100,000 acres in the core area. The other 400,000 acres is both Bakken Lite and Three Forks potential all within what looks like one basin-centered oil cell, but with viable frac barriers between the Bakken and the Three Forks. So geologically, it is a very similar play and we are trying to lay a horizontal in there and put an effective frac on it and get recovery efficiencies around 10% or so for the oil in place in all three of those zones.

Great. Thank you.

Leo Mariani, RBC.

Yes, good morning here, guys. A question on the Horn River, just trying to get a sense of when you guys expect to ramp up production. You talked about adding 12 wells. I think previously you had talked about kind of a 2011/2012 ramp. Just curious if anything has changed. Obviously, there has been a lot of industry activity over there and just wanted to get a sense of what you think the timing could be on the Kitimat project?

Yes, the proposed timing of the Kitimat project -- they are quoting us a date of 2013 and we have got a memorandum of understanding, which is just a very preliminary agreement, to supply about 200 million cubic feet a day to that. So at this stage, what we are basically aiming towards is to have production of 200 million cubic feet a day or greater by 2013. And every year, there will be kind of a slow ramp-up toward that target. But it is fair to say, I think the other industry players will say the same thing, we are in the very early stages of learning how best to deplete this asset.

Our conclusion from both our findings and the rest of the industry's findings are that the Horn River gas accumulation is going to rival the Haynesville in terms of size, but the issues of well spacing and how to stimulate this and so on and so forth are really -- you basically have a six-month window to kind of learn that up there. So what our strategy is we are going to slowly increase our activity and really just not get in a big hurry on this asset, similar to what we are talking about in the Marcellus actually, particularly in a gas market that is a bit uncertain for us right now.

Okay, thanks. Jumping over to your horizontal Cleveland oil play, sounds like you've got some pretty good results there. Trying to get a sense of what you guys think the running room is there in terms of your acreage and wells and inventory?

Yes, I would say it is just moderate in terms of our acreage and ability to run there. This will be a contributing play to some of our liquids growth, but it is not going to be a major driver of our liquids growth between 2010 and 2012.

Okay. In your Barnett Combo area, you guys talked about -- I think if I heard correctly -- about roughly 90,000 acres you thought was kind of more in the core. I think you've got a little over 250,000 acres out there. Is this going to be similar to the Bakken play where there is a core and then sort of a Lite area?

Yes, that is one way to look at it. What we expect will happen throughout 2010 is that that 90,000 acre core is going to expand and we will end up with considerably more than 90,000 acres that we consider productive that are going to give us a good rate of return. Our total acres there are really something like 350,000 in there.

But I would say we are extremely optimistic about the results we are getting in the Combo. And again, as I mentioned on previous earnings calls, we own this play. We will get zero information from other peer companies leading to results from this play because they have zero position in the play. So it is one where you may have some trouble triangulating on, but if you have some questions about the play, just look at our 50% year-over-year liquids growth we are anticipating for 2010.

Okay. I guess you did that small acquisition lately. I think you had mentioned the production there. I think I missed what you had said about the production associated with that acquisition.

Yes, a small amount. It was a 350 barrels of oil a day equivalent. So that was a modest amount of proved reserves we acquired from that.

Okay. I guess last question here on the Haynesville. Obviously, you did a nice acreage acquisition there. Just curious as to kind of what the potential is to continue to add acreage in that play and if that is the strategy you are going to continue to pursue.

Yes, the acreage is really, really tight there. So the potential to add significant amounts of acreage is pretty low. At least as we see it today, it is not obvious that we are going to be accreting a whole lot of gas acreage really anywhere in North America incrementally. So for 2010, you can expect whatever dollars we spend on acreage is going to be very heavily skewed toward either oil or very wet gas. So it is not in our plan right now to dramatically continue to increase our Haynesville acreage position.

Okay, thanks, Mark.

Brian Singer, Goldman Sachs.

Thanks, good morning. Can you add a little more color on your Barnett oil play in terms of the percent of your acreage that is in the vertical of the thicker section where you are using more vertical wells versus the less thick horizontal section?

Yes, Brian. We have mapped it, of course, with a lot of proprietary well control and it is kind of a moving target. We are not sure exactly what thickness we need to convert the vertical, but the back of the envelope number right now would be somewhere between 10% and 15% of that acreage would be vertical territory. That is of the 90,000 core acres and the remainder horizontal.

Great, thanks. And going back to, I think it was David's question earlier. I know you are not putting out a number for CapEx for next year. You have talked at times in advance of CapEx that you would keep net debt flat or spend within cash flow and just wondered how you are thinking about CapEx versus cash flow even though you are not providing any specific numbers for next year?

Yes, the only thing we are going to commit at this time is that we are going to remain a company that has very little net debt relative to the peer group. That is all I want to say about it at this time, Brian.

Okay, great. Thank you.

Joe Allman, JPMorgan.

Thank you, good morning, everybody. Mark, about a year ago, you said that you had tested, in the Bakken, that you tested the Three Forks Sanish and the Parshall field and that you didn't think it would work there. And now you are saying that in the core, you are seeing it work. What has changed between then and now and how much of your acreage do you think is prospective for the Three Forks Sanish?

We can't give you an acreage number as to what percentage we think, but what has really changed our view is that frankly a lot of other operators up there have offset our acreage with good Three Forks wells. And so in a way, they have proven up what we think are likely significant swaths of our acreage by just drilling wells right beside the acreage we own. And so we were so focused on developing the core area and starting to develop the Lite area that we said we have got this stuff, we will get to it in time and it is just kind of the time when we are beginning to get to it now.

Okay, that's helpful. And then still in the Bakken, what are the costs per well for the Bakken Lite section?

About $4.4 million and you get about -- I think we are quoting 300,000 barrels of oil for a Bakken Lite well.

That's helpful. And then moving over to the Haynesville, of your 153,000 net acres, how much is in East Texas and how much is in Louisiana?

60% Texas, (inaudible) 60% Texas and 40% in Louisiana.

Okay, got you. And is the concentration in Texas, is that in what you would consider the new core?

Yes, a very high percentage is in the new core.

That's helpful. Earlier, you talked about your unreserved and PUDs. Because of the gas price, the way the new calculation works, would you expect any write-downs yourself or impairments yourself and how do you think EOG is going to handle the PUDs and probables this year?

Yes, I don't want to comment on where we are going to end up or potential write-downs or write-ups or anything. The only comment I will make is that, as we go around 101s, particularly early in the year, everybody says, well, what is your finding cost relative to peer companies, what is your reserve replacement relative to peer companies. And in my humble opinion, you have just lost the tool of having that be a useful metric because I expect, with variants that is afforded companies on PUD booking, that those that elect to book liberally can have -- will show up with extremely low finding costs. And those that book conservatively for PUDs could have higher finding costs. And as far as trying to evaluate across companies, in my opinion, it is just going to be invalid from this point forward.

Okay, that's helpful. And then just lastly, I think it is probably for Tim. I noticed that the capitalized interest was higher than it typically is this quarter for the third quarter. Could you describe that for us please?

Well, the capitalized interest is just a factor of our unproved property over our debt. So as our unproved property continues to increase, the capitalized interest will continue to increase.

Okay, that's helpful. Thank you.

Scott Wilmoth, Simmons & Co.

Hey, guys, just following up on the Bakken Lite acreage, what percentage have you already delineated? Could you put some numbers around that?

In the Lite, it is a small percent of that 400,000 acres where we have really tested. We have tested -- primarily it is kind of north of our core area. In our IRR presentation we put out there this morning, there is a little map that kind of shows some of our acreage and we have been testing primarily to the north and we have a significant amount of acreage kind of to the west of our core area and that is where we will be evaluating next.

Okay and then on the $4.4 million well cost, can you talk about what laterals or frac stages you guys are using for that?

We are drilling generally 5000 foot laterals on most of our horizontal wells and generally, we have been increasing the number of stages. So right now, we are somewhere around 15 stages on those Bakken Lite wells and trying to increase them to 17.

Yes, it is fair to interject a statement here. There are some companies that have very high initial production rates that have been reported and one thing that is kind of a technical question that is kind of unanswered across the industry there is some companies are drilling what are called 1280 laterals where they are basically trying to drain two sections, two 640 acre sections with one well. So they are drilling very long laterals and the cost for those wells would be considerably more than the $4.4 million we quoted, but you would expect to get higher production rates.

We are kind of in the camp at this point where we are talking about basically 640 kind of wells where we want to drain 640 acres or less with the laterals, so are laterals are shorter. So just comparing IP across companies, you almost have to tie in, well, what is the well cost for one versus another and what the optimum depletion mechanism is there as far as 640 or 1280 laterals. It's probably just an open technical question that the industry and EOG will solve over the next year or two.

Okay. And then keeping on the theme of spacing, what are the well spacing you guys are currently using in the horizontal Combo wells?

We are still experimenting on that. We have quoted in our previous remarks that, on the vertical wells, we are basically looking at 20 acre or possibly more [depth] spacing and we are drilling some on 20 acre spacing right now and some on a more dense pattern.

In terms of the Combo wells themselves on the horizontal side, we are still trying to sort out what is the proper spacing, but you will recall that a fair amount of Johnson County, which is gas, ended up on nominally 40, 50 acre spacing in there. So we don't know yet on the oil, but we will know that in the next not-too-distant future.

Okay. And then lastly, can you just give us an update on Marcellus activity and plans for 2010?

Yes, I'd just say modest activity planned for 2010. We really, up until a couple weeks ago, we had zero sales from the Marcellus simply because of just delays on pipeline connects and just over the last few weeks, we got our first wells actually flowing to sales. So as we have related multiple times, we think this is an infrastructure-challenged area and we are going to go at a fairly slow pace relative to our acreage position with just a two rig program next year. Two rigs will get us probably about 45 wells next year.

Can you give us any color on roughly the time it took to get those first wells on production?

Yes, at least a year. So it is -- I really think that, in the macro view for North American gas, it is going to be 2013 or so before the Marcellus plays any significant role.

Okay, thanks. That is all I had.

[Monroe Helm], Cimarron Capital.

Congratulations on implementing your successful strategy. I think you are right, you are probably way ahead of the rest of the industry in converting from a gas company to an oil company. You made the comment early on that horizontal drilling is a game-changer, horizontal well oil drilling anyway. It seems to me like horizontal gas drilling has been a bigger game-changer than people thought and I am just wondering if -- in your models, you kind of continue to push out to the right when we are going to get gas supply and demand into balance. I am just wondering if this -- the game-changing horizontal gas drilling isn't making most of these models that people are looking at incorrect as far as forecasting supply and demand coming into balance.

Yes, that's a (technical difficulty) question, Monroe and we will admit that we are a bit puzzled by the recent EIA data, particularly the August data that just came out a few days ago. And we kind of thought, well, what is the proper thing to say on the earnings call regarding our macro view. But I really come down to the point that drilling has slowed dramatically and we believe that production will fall.

And if you look at the Canadian production situation, the Canadian production kind of levitated for six months, maybe nine months longer and stayed at relatively stable levels before it started to fall. In other words, there was a longer lag time between when the drilling really slowed down and when production slowed down. And that may well be just due to unconnected wells and what we believe is that is probably the situation here in domestic gas right now is that there was a backlog of unconnected wells and that we've probably worked our way through that. I know at EOG we have pretty well worked our way through that.

But yes, I would have to comment that we have a degree of -- range of possibilities as to what is going to happen on gas supply and we don't say that our number is likely to be 100% accurate at this time.

You all are about the only company I have heard of who has the luxury of diverting a significant part of their CapEx next year into oil drilling. Everyone else or most companies are announcing that they are planning on increasing their CapEx for gas next year, partly because they have no place else to put the cash flow. And a lot of it is going into these higher productivity unconventional horizontal wells and whatever play you want to name. Can you talk about -- those companies have a different set of economics than you do and if you are in one of those companies and you're looking at something like the Haynesville and that was your best position, what kind of gas price would you need to meet your minimum rate of returns on something like the Haynesville?

Yes, kind of look at the Haynesville -- in terms of gas price or reinvestment rate of return, the Haynesville is about equivalent to our Barnett Johnson County stuff, which is [roughly] equipment, stuff that we believe will ultimately come on in the Marcellus. So we don't buy the notion that the Haynesville is clearly head and shoulders above gas plays or its inherent economics, but it certainly has good economics.

As far as what gas price you need, if you're really looking at all-in costs, including land costs, seismic costs and everything else, we still continue to believe that you need something like about a $6 gas price for these things to work. That is the input we'd give you, Monroe.

Okay, thanks for your comments and congratulations. A great strategic move on your part.

Thank you.

Irene Haas, Canaccord Adams.

Hello, Mark. You guys are an undisputed leader in low permeability oil play. I would like to ask two simple questions. Firstly, does it always kind of updip of these shale gas play, would you expect to find possible shale oil play? Sort of should I expect a Haynesville Combo play from you guys? Secondarily, can it be replicated outside the US in Canada and elsewhere?

Yes, Irene, I think the idea that the updip area to all the gas plays should hold an oil play is conceptually correct in that just less material of rock should be in the oil window, not the gas window. But the plumbing is really more tortuously arranged than that. In the Haynesville, I won't comment specifically, but the Haynesville, Marcellus, some of these other shale plays do not have an oil window. In other words, the shale does not exist physically in an updip setting in the oil window.

Other plays probably do have an oil window and we are currently prospecting heavily in a number of those other plays right now. Internationally, it is harder to say. I mean we have looked at a lot of different kinds of international projects in various parts of the world and the cost structure is always one element that makes it more difficult to see how those can work. Unless you find something head and shoulders above the typical kinds of rocks that we are seeing in North America, the cost structure is going to be a bit prohibitive we think.

Thank you.

We have time for one last question.

Shannon Nome, Deutsche Bank.

How are you doing? Following up from Monroe's question, the comment you made, Mark, on the macro picture, was the industry's well, completions backlog, which you seem to think is largely tiered. Then I have heard a lot of my other companies say the same, but when you ask each individual company how many wells they have waiting on completion, it actually adds up to a pretty significant number. You have to think over the last few months as gas prices have toyed around with $4 levels that there have been companies continuing to drill and defer. Do you have any more precise thoughts on that? Can you speak to what EOG's backlog is for example in the Barnett shale of uncompleted wells?

Yes, your question is -- that is a big conundrum. The other ancillary part to that is, if you add up all the public companies as to what they are alleging they are going to grow gas volumes in the US next year, it is a bigger number that is consistent with the production declines that we would project.

So we don't have a lot of specifics as to what other companies have in terms of backlogs. We know our backlog is really relatively modest in terms of wells uncompleted and our belief is that it will probably be about three or four months from now when you get EIA data that has not got a lot of noise in it. But we believe it is just inevitable that production is going to decline in 2010 and the magnitude of that is -- believe it will be in the range of about 4 Bcf a day for the full year. But we have to say that we have some questions as to -- we can't pound the table and say it is going to be exactly 4 because a lot of opaqueness out there right now.

Yes, I hear you. Back to EOG, more importantly, I hear you on your no habla Eagle Ford comment, but $1.3 billion is a lot of money to spend even over several years. Can you give us any feel for general geography regions of some of this inventory that you have been stockpiling? Is it mostly Rockies, one would think, given just where the oil is in the US or is it more widespread?

Yes, I mean what we can say is we think that it is fairly geographically spread across North America. It is the only play, oil play horizontally we are pursuing outside North America, is in China where we have a zone that we will be testing here in 2010. So it is all in North America, but I really don't want to go into any more specifics.

And my sense is, on the unconventional oil stuff, unlike maybe a Haynesville or a Barnett kind of discovery, that we are talking about maybe, I don't know if the number is dozens, but a collection of smaller areas that collectively add up to a lot. Is that a fair assessment of how unconventional oil plays are going to unfold or are you talking about just a few larger discoveries that you will be taking the wraps off of over the next few years?

Well, if you just look at the basin depositional models, the oil plays in the shales are deposited similar to the gas plays. And I think that we have all been surprised by the huge magnitude of these North American horizontal gas plays. So we believe that potentially some of these oil plays are going to have a very meaningful size.

Nice. And then in terms of some of the petro physical properties of these new plays, and I realize you are in very early testing stages, but your experience so far suggests that -- you said earlier that the Combo with one of the more prolific oil resources you encountered. Would it be fair to say that the rest of what you are testing is probably not going to be quite as impressive in terms of oil in place and recovery factor or do you think there is a good chance that some will be competitive?

Yes, the answer is we just don't know at this point. But I mean they will all be characterized by relatively low recoveries of oil in place. I mean the Bakken, we are talking about 10% and the Combo is going to be less than 10% at least with current technology. So one characteristic that generally is going to be of all these plays that per 640 acres, there is a pretty significant amount of oil and gas entrapped, but the percentage of it that we recover will be economic, but it will be a fairly low percentage of what is actually in place.

Exactly. And you had spoken to 2% recovery factors in the Combo previously. It sounds like with a 280 Mboe per well number, doesn't that ease us up towards 3%, is that correct?

We now believe it is going to be higher than 2%, but we don't want to get into -- we just have to get some more data before we can opine what exactly we think it will be, Shannon.

Okay, that's fair. Thank you, Mark.

Dan, I think that would conclude the questions and I want to thank everyone for staying with us. We went over time a little bit there, but we believe 2010 is going to be a very exciting year for EOG. Thank you.

This does conclude today's conference call. Thank you for your participation.