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EOG Resources Inc. (NYSE:EOG)

Q3 2009 Earnings Call

November 06, 2009; 9:00 am ET

Executives

Mark Papa - Chairman & Chief Executive Officer

Tim Driggers - Vice President & Chief Financial Officer

Gary Thomas - Senior Executive Vice President, Operations

Loren Leiker - Senior Executive Vice President, Exploration

Analysts

David Tameron - Wells Fargo

Michael Jacobs - Tudor, Pickering, Holt

Leo Mariani - RBC

Brian Singer - Goldman Sachs

Joe Allman - JP Morgan

Scott Wilmoth - Simmons & Company

Monroe Helm - Cimarron Capital

Irene Haas - Canaccord Adams

Shannon Nome - Deutsche Bank

Operator

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.

Mark Papa

Its 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. The risks associated with forward-looking statements have been outlined in the earnings release and EOGs 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.

The SEC currently permits producers to disclose only proved reserves in their 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 U.S. investors that appears at the bottom of our press release and investor relations page of our Web site. An updated investor relations presentation and statistics were posted to our Web site 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 of Investor Relations.

Ill 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 recent operational highlights. Tim Driggers will provide some financial details and then Ill provide some macro comments and concluding remarks.

As outlined in our press release, for the third quarter EOG reported a net income available to common stockholders of $4.2 million or $0.02 per share. 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 as outlined in the press release. EOGs 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 who focus on non-GAAP discretionary cash flow, EOGs DCF for the third quarter was $819.4 million. Our third quarter production and costs were in line or better than the mid-point of our guidance and because our crude oil production numbers continue to be a bit stronger than forecast, were increasing our full year 2009 total companys 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 were 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 dont see the economic rationale regarding growing gas production in adverse markets. If you recall, we purposely didnt 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 the fall by 2%.

In 2010, well 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. Ill note that with our arsenal of gas assets we can easily organically grow our gas at a 15% annual rate for multiple years. So were continuing to moderate our gas drilling activity.

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 other liquids growth will occur in North America and the majority will be from the US.

For the past year weve been telling people that oil horizontal drilling in unconventional rock was a game changer and our 50% targeted growth rate provides solid evidence. Ill also note that we expect further significant liquid increases in subsequent years. We haven’t finalized our 2010 CapEx yet and well 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 “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, which roughly equal growth increments. Ill 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 per 640 acres, its one of the richest oil deposits weve ever encountered. Were 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 #1 and Stephenson #1 wells. These wells IPed at a 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 $2.2 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’ll 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 Dontress [ph] B1H and C1H, and 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 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. Ill note that our activity to date has been in some of the thickest parts of the play.

2010, we plan to run a 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 well 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 Fertile #13-18H in 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 58H clay water 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 approach 100% after-tax rate of return and the Lite wells yield 35% after-tax rate of return.

Additionally, preliminarily tests indicate that the Three Forks is productive and not pressure depleted under our portion of our 500,000 acres. The next steps order determine how much of our acreage is perspective with Three Forks potential and well have more details on subsequent costs.

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

In the mid-continent EOG continues to achieve solid results in 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 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 NGLs. We have a 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 a 100% after tax reinvestment rate of return.

Now, Ill turn to the North American gas side of the ledger. We recently consummated a Haynesville acreage transaction in Nacogdoches County, Texas. EOG acquired approximately 50,000 acres of Haynesville deep rise. 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 the Louisianas DeSoto Parish which is in the original core area and weve previously reported well IPs of 15 plus million cubic feet a day.

Remainder of the acreage is primarily in Nacogdoches and San Augustine Counties in East Texas. And our recent well results confirm a second core area in Nacogdoches County. Our Gammage #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 the short lateral, but we follow that up with several outstanding wells that rivaled the best sound in Louisiana core area.

Also in Nacogdoches County, the Hill #1, Pop #1 and Hassell #1 wells each IPed at rates in excess of 15 million cubic feet a day, the 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.

Wells, an early production history indicate weve found a new Haynesville sweet spot and the acreage acquisition noted earlier offsets these wells. These wells have higher bottom hold pressures than the established North Louisiana sweet spots yielding estimated gross reserves of 10 Bcf per well for $10 million well cost.

We believe were consistently making the best Haynesville wells in the industry. 92% of our wells IPed rates greater than 10 million cubic feet a day and only 8% IPed at less than 7 million cubic feet a day. We also 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.

Well 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 well have modest year-over-year Barnett gas growth in 2010.

In the Horn River Basin we completed seven wells this summer in the 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 a well cost by 35% over 2008 levels and has now set cost targets for each area that provide attractive rates of return. Three wells in one pattern IPed at 23.4, 19.3 and 17.2 million cubic feet a day while the four wells in the other pattern tested at rates between 16 and 18 million cubic feet a day.

We produced these wells throughout the winter to evaluate the efficacy of each pattern. We believe the three high rate wells are among the best in the play topping out 16 million cubic feet a day well completed last year.

The BC government has recently approved our application for royalty incentives for 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. Were planning a slow but steady Horn River activity ramp up and expect to drill 12 wells in 2010.

In the Marcellus, were operating two rigs and well continue that same level of activity in 2010. Our results continue to be consistent. The COP 2316-5H and 6H wells and the Punxsy [ph] 9H well recently IPed at 2.6, 2.9 and 3.2 million cubic feet a day respectively. These are likely 2.5 to 3 Bcf NAR wells for $1.65 in cost.

Recently obtained pipeline connects for our first Marcellus production, an expected average of about 16 million cubic feet a day of Marcellus sales in 2010. So were prosecuting this development program at a conservative phase.

Our horizontal gas wells continue to provide surprising upside in areas previously thought to be depleted. In our Green River basin big tiny areas, we drilled two horizontal wells in the center of the field thats been producing for 50 years and have wells with IPs of 3 million cubic feet a day with 100% rate of return economics, indicating we have horizontal sand stone potential in this old field.

We also achieved 100% rate of returns drilling three oil sand directional wells under Nueces Bay near Corpus Christi, Texas. Two recent wells are the State Tract 788 Gas Unit #1 and 692 #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.

Tim Driggers

Thanks Mark. For the third quarter exploration and development expenditures were $969 million, excluding asset retirement cost. In addition, expenditures for gathering systems, processing plans 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 or 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%. Weve also provided an estimated range of the dollar amount of current taxes that we expect to record during the third quarter and full year.

Now, Ill turn it back to Mark to discuss the macro environment, our hedge position and his concluding remarks.

Mark Papa

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 decline is becoming more opaque. You may have noticed that the EIA recently revised downward their estimates of 2008 gross production by about half a Bcf a day but did not adjust our 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 1 to 2 Bcf a day increase in 2010 LNG imports. We expect the gas market to tighten by mid 2010. Were already seeing evidence of this tightening.

Storage injection since mid June have been running about 2 Bcf a day less than last year and 0.5 Bcf a day less than five year average. Our financial gas hedge position is shown in our 8-K is unchanged from last quarter. We have 44% of our fourth quarter 2009 North American natural gas hedge 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. Were long bullish regarding oil and at no oil hedges. To summarize our interject and editorial comment regarding industry year end reserve bookings, its 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 cost. 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 youll have one less comparative tool to measure industry results.

Let me summarize, in my opinion there are six important points to take away for this call. First, the impact of our horizontal oil play is just gaining momentum. Our year-over-year total company organic liquids growth for 2008-2009 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 of these horizontal oil projects in unconventional rock yield between 30% and 70% after-tax rates of return at un-escalated $75 oil prices and a 15% return at $50 oil price. We dont 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 out performance during the past decade.

Third, as you probably already suspected all of these oil concepts have been generated in-house and were 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 oil reserves. During the past three years weve spent around $1.3 billion on acreage and most of that was for horizontal oil and liquids rich gas contents.

Fourth, weve extended the Haynesville suite spot on to our East Texas acreage and increased our Haynesville net acreage position by 32%. All of this incremental acreage using the new suite spot.

Fifth, we continue to have success in the Horn River and Marcellus gas plays and we expect $1.45 all in funding 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 were transforming our North American production mix organically instead of through the value destroying M&A or mega acquisition.

We also expect to continue to have one of the lowest all in unit cost in a group in spite of the fact that our peers have collectively written off $41 billion in the past 12 months compared to no major write-offs for EOG. Its a very exciting time to be at EOG.

Thanks for listening and now well go to Q&A.

Question-and-Answer Session

(Operator Instructions) Your first question comes from David Tameron - Wells Fargo.

David Tameron - Wells Fargo

A couple of questions, can I get a 2010 CapEx number to those that 13% growth? Can you give us the range or what you are thinking, you said you see the growth number out there?

Mark Papa

We havent finalized the CapEx yet and we will give that early next year. But the only thing I can give you is directionally 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.

David Tameron - Wells Fargo

Its alright. Moving to the Bakken, a year ago at the conference you gave us some oil in place number, I think the number was 9 million barrels per section of oil in place, have you guys take any look at that or do you that have in front you as far as what that new number is oil in place per section up in the Bakken, what you guys think?

Mark Papa

Yes, the 9 million barrels for the core area is correct. 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 acreage, we still got a fair amount of drilling yet to do in that, but thats pretty well a slam dunk.

The real question is we have technically related to the Bakken are out of the remaining 410,000 acres how much of that is productive in what we call the Bakken light. Now, our terminology Bakken Lite is equivalent to everybody elses Bakken, because nobody else has a Core. And what we found is that were encouraged that it appears likely 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, weve been fully aware that the Three Fork zone exists below of at least a part of our acreage and its probably productive, its about 40 feet below the Bakken in the core area and one of the questions we have was, well were getting such monster wells in the core area, are they fracs that were giving through the Bakken Core, are they actually draining the Three Forks also.

During this past quarter weve opened up a portion at a Three Forks in wells in our core area where weve already produced the Bakken regular core and were very encouraged to find that the pressures that exist in a Three Forks do not indicate pressure depletion from the core. So there is certainly a strong indication that we may have another oil field beneath our core oil field and I would say these pressure results are consistent with 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, its really 500,000 acres and then how much of the 400,000 non-core Bakken acres are really productive under this Bakken Lite concept.

David Tameron - Wells Fargo

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

Mark Papa

Its probably 50-50 the Core and then 50% would be Lite/Three Forks and thats a rough number David.

Operator

Your next question comes from Michael Jacobs - Tudor, Pickering, Holt.

Michael Jacobs - Tudor, Pickering, Holt

Hoping you can nail me out the conceptual question, you are purview to more industry chatter than most. Id 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?

Mark Papa

Yes. Thats code for whats going on in Eagleford and our flip response is to know how the Eagleford, but its an open secret that we are drilling some wells at Eagleford, but its just too soon for us to really opine on the results were 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 well disclose what the situation is in South Texas.

Michael Jacobs - Tudor, Pickering, Holt

Okay. Recognizing that some places are earlier than others, how would you rank Bakken Core by Barnett Combo horizontal Cleveland oil and what you have heard others are doing in the Eagleford in terms of rates of return kind of your favorite areas from a rate of returns standpoint?

Mark Papa

Im not sure, well I mean clearly the Bakken core is the winner in rates of return, those returns are approaching a 100% in the current oil prices. Once you get out of that area our feeling is if you take a look at the horizontal oil plays that weve disclosed and other 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 were finding that across different basins the rates of returns similarities are not all that desperate, except for the one outline which happens to be the Bakken Core and there we just, we got the over pressured Bakken with everything we could want. But everything else is pretty consistent.

So the key thing were really, except also for Waskada which turns out, thats not really shale play that one were getting 100% rates of return. But most of the others were into 30% to 70% range. But the key point here is that these arent unconventional rock plays that are just barely scrappened by a with a 15% rate of return or just fairly beating your cost of capital. These are ones that we think are going to be key differentiators for us.

And weve been very open about it, we think this is a game change and we think we are three years ahead of the rest of the industry, and we are not going to talk about it much to specifics until we have situations such as Barnett Combo or 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 complication and we dont intend to do that.

Michael Jacobs - Tudor, Pickering, Holt

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.

Mark Papa

That just for the lower basically the lower Haynesville what we call it, we believe that the lower Bossier or the upper Haynesville I dont know how you tell it is likely also productive on significant squash of our 153,000 acres and well probably have more color on that at the next earnings call was currently drillings some wells to target that specific zone.

Michael Jacobs - Tudor, Pickering, Holt

Just one more and Ill hop off. Recognizing what you said about increasing the price of poker. Can you just give us the geologic concept that you tested with Korat and kind of how happy or not your in terms of testing a concept.

Mark Papa

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

Michael Jacobs - Tudor, Pickering, Holt

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

Mark Papa

Ill turn out over to Loren.

Loren Leiker

Yes, really not sure Michael we are asking about the Bakken is whole as we dividing the Core area which is in North Dakota. In a Lite area which is primarily North Dakota as well although it is sloppier and handle little bit. Our 500,000 acres includes large portions of core area I think we talked about at 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 sale, but with viable frac barriers between the Bakken and the Three Forks. So, geologically, its a very similar play and were trying to lay a horizontal in the area and put an effective frac on it and give recovery efficiencies around 10% or so for the oil in place in all three of those zones.

Operator

Your next question comes from Leo Mariani - RBC.

Leo Mariani - RBC

A question on the Horn River, just trying to get a sense of when you guys expect it to ramp up production and you talked about adding 12 wells. I think previously you talked about kind of a 2011, 2012 ramp, just curious have anything is changed obviously there has been lot of industry activity over there and just wanted to get a sense of what you think the timing could be on Kitimat project?

Mark Papa

Yes, the proposed timing on the Kitimat project Leo is they are coding us a date of 2013 and weve got a memorandum of understanding which is just a very preliminary agreement to supply about 200 million cubic feet a day there. So at this stage what were basically aiming towards is to have production of 200 million cubic feet a day or greater by 2013 and every year there will a kind of slow ramp up toward that target, but its fair to say and I think the other industry players will say the same thing.

Were in very early stages of learning how best to deplete this asset. Our conclusion from both our findings and rest of the industries findings all are that the Horn River gas accumulation is going to rival the Haynesville in terms of size. And but the issues of well spacing and how to stimulate this so forth are really basically have a six month window to kind of learn out of there. So what our strategy is were going to slowly increase our activity and really just not get a bit hurry on this asset, similar to what were talking about in the Marcellus actually, particularly in a gas market that is bit uncertain for us right now.

Leo Mariani - RBC

Okay thanks. Jumping over to your Horizontal Cleveland oil play sounds like it get some pretty good results there. Trying to get a sense of what do you guys think that running rim is there in terms of your acreage and well of an inventory?

Mark Papa

Yes, I would say its just moderate in terms of our acreage and an ability to run there. This would be a contributing play to some of our liquids growth, but its not going to be a major driver of our liquids growth between 2010 and 2011.

Leo Mariani - RBC

Okay, and your Barnett Combo area, you guys talked about I think if I heard correctly about roughly 90,000 acres you thought with kind of more in the Core I think youve got little over 250,000 acres out there, is it going to be similar to the Bakken play was a core and sort of Lite area?

Mark Papa

Yes, thats one way to look at it, what we expect will happen throughout 2010 is that 90,000 acre Cores going to expand. And well end up with considerably more than 90,000 acres that we consider productive and give us a bit rate of return and our total acres there really something like 350,000 in there. But I would say we are extremely optimistic about the results were getting in the Combo.

Again, as mentioned on previous earnings calls we own this play you will get zero information from other peer companies, leading to results for this play because they have zero position in the play. So its one or you may have some trouble triangulating on but if you have some questions about that play just look at our 50% year-over-year liquids growth were anticipating for 2010.

Leo Mariani - RBC

Okay, I guess that you would did that small acquisition lately, I think you would mention the production there and I think Ive missed what you had said about the production associated with that acquisition?

Mark Papa

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

Leo Mariani - RBC

Okay. I guess last question here in the Haynesville obviously you did nice a acreage acquisition there just curious to kind of what the potential is to continue to add acreage in that play and thats the strategy you are going to continue to pursue?

Mark Papa

Yes, the acreage is really, really tight there. So the potential to add significant amounts acreage is pretty low. So were - at least as we see it today, its not obvious that were going to be accreting our whole lot of gas acreage really anywhere in North America incrementally.

So for 2010 you can expect that whatever dollars we spend on acreage is going to very heavily skewed toward either oil or very wet gas. So its not in our plan right now to dramatically continue to increase our Haynesville acreage position.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

Can you add a little more color on you 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?

Gary Thomas

Yes, Brian weve met this course with lot of proprietary well control. Its kind of moving target, were not sure exactly what thickness we need to convert the vertical, but back of the envelope number right now be somewhere between 10 to 15% of that acreage would be vertical territory that is of the 90,000 core acres and reminder horizontal.

Brian Singer - Goldman Sachs

Then going back to it, I think it was Davids question early on, I know you are now putting out of a number for CapEx for next year, youve took the time to advance that CapEx that you would keep net debt flat or spend within cash flow and I just wonder how you are thinking about CapEx versus cash flow even though you are not providing any specific numbers for next year?

Mark Papa

Yes, I mean the only thing were going to comment at this time is that were good to remains a company that has very low net debt relative to peer groups all I want to say about at this time, Brian.

Operator

Your next question comes from Joe Allman - JP Morgan.

Joe Allman - JP Morgan

In the market about a year ago you said that you tested in the Bakken that you tested a Three Forks/Sanish in the partial field and that you didnt take it with good work there and now you are saying that in the core you are seeing a work, whats changed between then now and how much of your acreage do you think is perspective for the Three Forks/Sanish?

Mark Papa

An acreage number as what percentage we think but whats really changed our view is that frankly and a lot of other operators up there have offset our acreage with good Three Forks wells, and so in a way they proven up what we think are likely significant swaps 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 start to develop the Lite area that we said, weve got the stuff well get to in time and just kind of the time where we are beginning to get to it now.

Joe Allman - JP Morgan

Then still in the Bakken, what are the cost per well for the Bakken Lite section?

Mark Papa

That’s $4.4 million and you get about 300,000 barrels of oil for a Bakken Lite well.

Joe Allman - JP Morgan

Then moving on to the Haynesville of your 150,000 net acres how much is in East Texas and how much in the Louisiana?

Gary Thomas

60% to 40%. Probably 60% Texas and 40% Louisiana.

Joe Allman - JP Morgan

And its the concentration that Texas is that in what your consider the new Core?

Mark Papa

Very half percentages in the core.

Joe Allman - JP Morgan

Okay that’s helpful. And then, earlier you talked about your unreserves 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 you going to handle the PUDs and probably this year?

Mark Papa

Yes. I don’t want to comment on we’re going to end up our potential write-downs or write offs or anything the only comment Ill make as we go around one on one particularly in early in the year everybody says what share finding cost relative to peer companies whats your reserve replacement relative to peer companies, and in my humble opinion youve just lost the tool of having that be a useful metric.

Because I expect with the variance it’s the forwarded companies on PUD booking that those that select the book liberally can have or show up with extremely low finding cost and those that book more conservatively for PUDs could have higher finding costs and as far as trying to evaluate across companies in my opinion it’s just going to be invalid from this point forward.

Joe Allman – JP Morgan

Then just lastly I think it’s probably for Tim, I know it’s the capitalized interest was higher than it typically is this quarter, the third quarter, could you describe that first please?

Tim Driggers

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

Operator

Your next question comes from Scott Wilmoth - Simmons and Company.

Scott Wilmoth - Simmons & Company

Just following up on the Bakken light acreage, what percentage have you already delineated, could you put some numbers on that?

Mark Papa

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

Scott Wilmoth - Simmons & Company

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

Gary Thomas

We’re drilling generally 5000 foot laterals on most of our horizontal wells. And generally, we’ve been increasing the number of stages, so right now we’re somewhere around the 15 stages on those Bakken Lite wells and plan to rise it to 17.

Mark Papa

Yes, it’s fair to interject the statement here, you know there are some companies that have very initial production rates has been reported and one thing there is kind of technical question is kind of unanswered across the industry there some companies are drilling liquid of 1280 laterals were they’re basically trying to drilling 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 recorded. Once you would expect to get higher production rates, we’re kind of in a count at this point were we are talking about basically 640 kind of wells we want to drilling them 640 acres or less with the laterals so our laterals are shorter.

So just comparing IPs across companies, you almost have to tie in what’s 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 the industry and EOG will solve over the next year or two.

Scott Wilmoth - Simmons & Company

Okay and then keeping on the spacing. What are the well spacing you guys are currently using in the horizontal Combo wells?

Mark Papa

We are still experimenting on that, we’ve quoted in our previous remarks. That on the vertical wells we’re basically looking at 20 acre or possibly more than spacing and we are drilling someone 20 acres spacing right now and some one are more dense pattern. In terms of the combo wells of sales on horizontal side we’re still trying to sort out what is the proper spacing, but you will recall that a fair amount of jobs in kind of which is gas ended up commonly 40, 50 acres spacing in there. We don’t know yet on oil, but we’ll know that the next up to distant future.

Scott Wilmoth - Simmons & Company

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

Mark Papa

I have just say modest activities plans for 2010, we really up until a couple of 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’ve got our first wells actually flowing to sales. So as we related multiple times we think this is an infrastructure challenged area and we’re going to go fairly slow pace relative to our acreage position, we’re just in two rig programs next years, two rigs will get us probably about 45 wells next year.

Scott Wilmoth - Simmons & Company

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

Mark Papa

Yes, at least a year. So, I really think that in the macro view from North American gas, it’s going to be 2013 or so before the Marcellus plays any significant roles.

Operator

Your next question comes from Monroe Helm - Cimarron Capital.

Monroe Helm - Cimarron Capital

You made the comment early on that of course on drilling gain change your, horizontal oil drilling anyway seems to me like horizontal gas drilling has been a better game change than people thought.

And I’m just wondering if in your models you kind of continue to push out to the right when we’re going to get gas supply and demand at a balance, I’m 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 under belt?

Mark Papa

Yes, that’s a dollar question Monroe, and we’ll admit that we’re a bit puzzled by the recent EIA data particularly the obvious data that just came out few days ago. And we kind of what’s 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 flow and if you look at the Canadian production situation, the Canadian production kind of levitated for six months maybe nine months longer at relatively stable levels before it started to fall.

There was a longer lag time between when the drilling really slowed down and when the production slowdown and that may will be just due to un connect the wells and what we believe is that’s probably the situation here in domestic gas right now, it was a backlog of unconnected wells and that we’ve probably work the way through that. I know that EOG was pretty well worked away through that. But I would have to comment that we have a degree of range of possibilities just what’s going to happen on gas supply and we don’t see that our number is likely to be 100% accurate at this time.

Monroe Helm - Cimarron Capital

You all have this, about the only company I have heard of it has a luxury of diverting a significant part of their CapEx next year into oil drilling, most companies are announcing if they are planning on increasing their CapEx to gas next year, partly because they have place else to put the cap, the cash flow. And a lot of it’s going into these higher productivity on conventional horizontal wells and, I don’t know you want a name.

Can you talk about what, those companies have a difference of the economics and you do and if you are in one those companies and you’re looking at something like the Haynesville and that was all you can focus that and that was your best position. What kind of gas price would you need to meet your minimum rate to returns on something like the Haynesville?

Mark Papa

I would look at the Haynesville in terms of gas price or reinvestment rate of return the Haynesville is about equivalent to a Barnett, which is roughly equipment that we believe will ultimately come into Marcellus. So we don’t buy the notion that the Haynesville is clearly head and shoulder is about gas play that’s an economics, but certainly hedge to build economics or what gas price need if you really look at and it oil and cost including the land cost, seismic cost and everything else. We still continue to believe unique up and like about $6 gas price for these things to work. That’s the input we give you Monroe.

Operator

Your next question comes from Irene Haas - Canaccord Adams.

Irene Haas - Canaccord Adams

You guys undisputed leader in low permeability oil play. I would like to ask two simple questions. Firstly is, there isn’t always kind of up tick of these shale gas play which you expect to find possible shale oil plays, should I expect Haynesville, Combo play from you guys. Secondarily, can it be replicated outside the US in Canada and elsewhere?

Mark Papa

Yes, Irene I think the idea that the emptied and buried to all the gas play should hold an oil play, conceptually correct and it just last mature if rocks should be in oil window not the gas window, but the timing is really more torturously right in that. In Haynesville, I won’t comment specifically, the Haynesville Marcellus certainly these are the shale plays do not have a oil window, in other words the shale does not exist physically and they have setting any oil window.

Other plays probably do have an oil window. And we’re currently prospecting heavily and a number of those are the plays right now. Internationally its harder to say, I mean we’ve looked at 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 kind of rocks that we’re seeing in North America, the cost structure is going to be a bit prohibitive we think.

Operator

Your last question comes from Shannon Nome - Deutsche Bank.

Shannon Nome - Deutsche Bank

A following up from Monroe’s question, the comment you made Mark on the macro picture with the industries well completions backlog which you seem to think is largely cured, 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 pretty significant number.

You have to think over the last few months as gas prices have towed around with $4 levels, is there have been companies continuing to drill on deferred. Do you have any more precise thoughts on that, can you speak to what the achieved backlog is for example on the Barnett Shale of uncompleted wells?

Mark Papa

Your question is that is big conundrum and the other ancillary part of that is if you add up all the public companies as to what their legend are going to grow gas volumes in the US next year. It’s bigger number than its consistent with the production declines and we would project. So we don’t have a lot of specific is to what other companies have in terms of backlogs, we know our backlog is really a relatively modest in terms of wells uncompleted.

I believe it’s probably be about three or four months from now when to get EIA there and it’s 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 I believe it really be in the range of about 4Bcf a day for the full year, but we have to say that we have some questions as to we can’t pound a table and say it’s going to be exactly for because a lot of opaqueness out there right now.

Shannon Nome - Deutsche Bank

Okay. And then back to EOG, more importantly I hear you on your no habla Eagleford 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’ve been it’s mostly Rockies one would think given just where that oil is in the US or just more widespread?

Mark Papa

What we can say, we think is fairly geographically spread across North America, the only play we were pursue oil play horizontally we’re pursuing outside North America is in China. We have a zone that we will be testing year in 2010. So it’s all in North America, but I have a really don’t want to go within in more specific.

Shannon Nome - Deutsche Bank

And my sense is on unconventional oil stuff, unlike maybe a Hayneville or Barnett kind of discovery that we are talking about maybe I don’t know you the numbers doesn’t 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 be unfold or are our talking about just a few larger discoveries that you’ll be taking the ramp up of over the next few years?

Mark Papa

If you just look at the basement deposition models, the oil plays in the shale are in the positive similar to the gas plays and I think that we’ve all been surprised by the huge magnitude of these North American horizontal gas plays. So we believe potentially some of these oil plays are going to have a very meaningful size.

Shannon Nome - Deutsche Bank

And then in terms some of the petro physical properties of these new place in our – are in very early testing stages a bit. You experienced so far to just that you said earlier that the combos one of the more prolific wells that resources you encountered would be fair to say that the rest of what your testing is probably not going to be quite impressive in terms of oil and place recovery factor or do you think that’s good chance that some will be competitive?

Mark Papa

The answer is we’ve just don’t know at this point, but let me there all be characterized by a relatively low recoveries of oil and plays. The Bakken we’re talking about 10% the combos are going to be less in 10% at least with current technology. So one characteristic is generally going to be all the plays that for 640 acres that pretty significant amount of oil and gas in fact but the percentage of that we recover will be economic, but it would be fairly low percentage of what’s actually in place.

Shannon Nome - Deutsche Bank

Exactly, and you just spoken to 2% equity factors in the combo previously, it sounds like 280 Mboe per well number that doesn’t towards three is that correct?

Mark Papa

We now believe it’s going to be higher 2%, we don’t want to get into that, we just have to get some more data before we can open what exactly we think it will be Shannon.

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

Operator

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

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Source: EOG Resources Inc. Q3 2009 Earnings Call Transcript
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