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Executives

Mark G. Papa - Chairman and CEO

Timothy K. Driggers - VP and CFO

Loren M. Leiker - Senior EVP, Exploration

Analysts

Thomas Gardner - Simmons & Company

Joseph Allman - J.P. Morgan

Brian Singer - Goldman Sachs

David Tameron - Wachovia Securities

David Heikkinen - Tudor

Eric Hagen - Merrill Lynch

Leo Mariani - RBC Capital Markets

Gil Yang - Citigroup

Ellen Hannan - Weeden & Co.

Marshall Carver - Capital One

EOG Resources, Inc. (EOG) Q2 FY08 Earnings Call July 30, 2008 9:00 AM ET

Operator

Good day, everyone and welcome to the EOG Resources 2008 Second Earnings Conference Call. As a reminder, this call is being recorded. At this time, I would like to turn the conference over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Mark G. Papa - Chairman and Chief Executive Officer

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second quarter 2008 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call.

This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

The SEC 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 and North Dakota Bakken plays 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 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 of Investor Relations.

The theme for this quarterly call is consistency. As you can tell from our financial and operating results, we continue to deliver what we promised to you at the beginning of the year. That's been a company hallmark and we are proud of it. We filed our 8-K with third quarter and full year 2008 guidance yesterday. These projections are consistent with the guidance we provided earlier in the year and I'll discuss them in a minute when I review operations.

I'll now review our second quarter net income available to common stockholders and discretionary cash flow and then I'll provide an operational review. Tim Driggers will then discuss capital structure and I will close with a hydrocarbon macro overview and a summary.

As outlined in our press release for the second quarter, EOG reported net income available to common stockholders of $178 million, or $0.71 per share. For investors we follow the practice of industry analysts who focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impact as outlined in the press release, EOG's second quarter adjusted net income available to common stockholders was $632 million or $2.52 per share.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the second quarter was $1.4 billion or $5.47 per share.

I'll now address our strategy and operational highlights. We believe there are five components that constitute a premiere independence E&P company and these attributes have been longstanding goals at EOG. Four of these components are measurable and the fifth is more subjective. The four measurable components are, ROCE, net adjusted production growth per share, overall unit costs and net debt to total cap ratio. In 2008, we believe we will score either at or among the highest in a peer group in all four categories.

We expect to generate peer-leading ROCE, unit cost control and lowest net debt to total cap ratio and we will be either the highest or in the top quartile regarding debt adjusted production per share growth.

The fifth and more subjective category involves being an early mover in new horizontal resources plays. We think we have got a demonstrable track record in this category and even if we are not first mover in potential plays such as the Haynesville and Marcellus we still have a significant low cost acreage position in them if these plays develop.

We value consistency at EOG and our 8-K indicates that our original 2008 goals remain the same today. We still expect to deliver 15% absolute production growth, all organic, even though we are currently experiencing natural gas and natural gas liquids curtailment in Johnson County due to the pipelines being at full capacity.

I'll now provide brief highlights regarding several of our key plays. I'll start with North Dakota Bakken oil. We have approximately 320,000 net acres in the Bakken. We are currently drilling with eight rigs. Seven of these are drillings in the core area and one rig is testing areas on the periphery of the core. We continue to make great wells in the core. Three examples this quarter are the Austin #5-14H, #24-33H and #9-11H wells which had peak rates of 3,744 barrels of oil per day, 1880 barrels of oil per day, and 3225 barrels of oil per day gross respectively.

During the first half of 2008, our average IP rate for all wells drilled was 1,732 barrels of oil per day and our direct after-tax reinvestment rate of return exceeded 100%. I think a 1,732 barrel oil per day average initial rate allows us to deem these as oil monster wells. We’ve now drilled enough wells whereby we can make a reasonable reservoir definition. We believe this accumulation consists of a high quality core area, which we call the Parshall Field. Per well reserves in this field are approximately 850,000 barrels of oil equivalent gross.

EOG is by far the dominant acreage holder in this sweet spot and this constitutes our 80 million barrel oil net reserve estimate. Also, as mentioned on the last quarterly call, we're monitoring results from our first 320-acre gas space well which was drilled in the core area and we are also evaluating the potential for secondary recovery of the field.

Around parts of this core area, we believe there's an extension area where wells are still very economic with 250,000 barrels of oil to 450,000 barrels of oil growth reserves per well. Not as prolific as the core, but still very good wells.

During the quarter we drilled in this extension area and based on preliminary test data we are excited about extending the play beyond the core. We are weighting to quantify any reserve impacts since further drilling would be required to confirm these results and that will take place over the next few months. Overall, we expect to drill 80 gross wells this year and at least 100 gross wells next year.

In British Columbia we commenced sales from our first two shale gas plays two weeks ago, one is a full lateral and one is a half lateral. We are pleased with the initial flow rates but want to watch these wells for a while before we provide specific details regarding per well reserves. We are currently running two rigs in this area and we will have a second full lateral well on sales next week.

As previously noted, our immediate short-term sales capacity will be limited to 25 million cubic feet a day to 50 million cubic feet a day until we have full pipeline takeaway capacity in 2011.

In the Barnett gas field our well results throughout the play continue to meet our exceed expectations. However, we are currently experiencing gas curtailments in Johnson County due to high pipeline pressures. Additionally, due to bottleneck NGL takeaway capacity at the processing plants we are not able to strip the optimum natural gas liquids out of the gas stream. We expect the gas takeaway problem to be ameliorated in October but the NGL bottleneck won't be fixed until next year. Accordingly, we will be selling less Barnett gas than capacity during the third quarter and expect the volume to pick up in the fourth quarter and the 8-K we filed last night reflects this fourth-quarter volume increase.

I'm pleased with our per well results. Our press release outlined five [inaudible] Johnson County, Martin wells that IPd [ph] at gross production rates of 6.1 million cubic feet a day to 9.2 million cubic feet a day each, all gas monster wells by my definition.

We are running four rigs in Hill County which is immediately south of Johnson and our per well reserves there are as expected, 1.5 net Bcf per well. In the western counties we are currently focusing on three development areas. In Palo Pinto County we drilled eight wells to-date averaging 1.1 net Bcfe per well. Our most recent well is currently testing at a 4.9 Mmcfe per day rate. We anticipate drilling 16 wells here by year-end.

In Erath County we recently drilled the Hughes #1H, which tested at 3 million cubic feet a day and anticipate drilling 12 offset wells by year-end. We’ve already drilled 49 wells in this Erath County development area.

In Hood County we drilled 25 wells to-date at an average 1 Bcf per well net and we are drilling additional wells. We recently completed the Black Ranch #9H at a rate of 2 million cubic feet a day gross. We have 61% working interest in this well.

To summarize, our Barnett western county activity is generating the results we anticipated. Regarding north Barnett oil play, from day one, we’ve noted this is a 2009 event. We are currently waiting to get our gas processing plant installed at year-end before we can give you further definition regarding production data or recovery practice. In the meantime, we are testing various techniques for optimum development.

I've had some feedbacks from Wall Street noting that people would like to see data from peer companies confirming this oil play. The reason for the lack of peer company… peer public company data is that EOG controls the vast majority of acreage in this play and simply put, there is not enough remaining acreage for anybody else to gain a significant foothold. I'll note there are at least two small private companies that are currently obtaining good economics with both vertical and horizontal oil wells in the area. I'll stress that we continue to be very excited about this play.

During the past six months we mentioned three other successful resource plays, the Mississippi Chalk, the Mid Continent Atoka and the Colorado North Park Oil. During the quarter, we further confirmed two of threes plays. In the Mississippi Chalk we completed a Greenville 24.8 [ph] and 2315 #4 wells for 4.1 million cubic feet a day and 2.7 million cubic feet a day net respectively. These are 70% after tax rate of return wells. In the Mid Continue Atoka, we are running a three-rig drilling program and during the second quarter we completed five horizontal wells. The Apple 438 #3H and Landers 522 #3H wells tested rates 4.7 million cubic feet a day and 6.2 million cubic feet a day net respectively, confirming that this also is a high return play.

We have identified over 150 drilling locations on our acreage and plan to increase drilling activity in this Mid Continent area in 2009.

In the Colorado North Park Basin area, due to seasonal drilling restrictions, we don't have additional results from the oil play at this time but our operations in this area continue.

Our other big resource play is the Vernal vertical Wasatch/Mesa development area in the Uintah Basin where we are running eight rigs and continue to get excellent results. Like all Rockies producers, we are trying to assess the impact of the September Rex pipeline curtailment. At this time we believe we can get our volumes moved but the basis differential will widen temporarily.

The two other potential resource plays that have recently attracted interest are of course the Haynesville and Marcellus. We have approximately 100,000 net acres in Haynesville and are currently drilling our first horizontal. Until we have our own well results we can't opine regarding the efficacy of this play.

In the Marcellus we have 220,000 net acres, are operating one rig and we will have some results by year-end. If the Marcellus works this will be a very slow developing play in the macro sense because of the major infrastructure issues. I'd estimate the Marcellus, if it works, would not contribute meaningfully to the macro domestic gas supply picture until 2012 plus.

Switching to outside North America, our Trinidad asset continues to perform as expected and our next volume ramp up will be 60 million cubic feet a day net in early 2010.

In the North Sea, we continued to align both oil and gas prices and will rebound from an inactive drilling year in 2008 and drill three to five exploration wells in 2009.

On July 1st, we finalized our China acquisition of 130,000 acres from ConocoPhillips. This is a tight gas asset in the Sichuan basin onshore China that's currently producing approximately 8 million cubic feet a day net.

The rock formation is a low permeability natural gas sand similar to our South Texas Wilcox Play. The prior operators, Burlington and ConocoPhillips, attempted to develop this asset with vertical wells and that was not very successful. We plan to use our South Texas analogy where we have unlocked half the net Tcf with horizontal drilling and we believe similar technology will unlock this sandstone play. If this works, we may develop up to one net Tcf on our acreage. We view this as a horizontal technology play in an energy-short country and hope this success could lead to broader opportunities in China.

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

Timothy K. Driggers - Vice President and Chief Financial Officer

Thank you, Mark. For the second quarter 2008, total exploration and development expenditures, including asset retirement obligations, were $1.15 billon with $6 million of acquisitions. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $108 million.

Capitalized interest for the quarter was $10.1 million. Year-to-date exploration and development expenditures, including asset retirement obligations, were $2.27 billion with $35 million of acquisitions. Total gathering, pipeline and other expenditures were $196 million.

At quarter-end 2008, total debt outstanding was $1.147 billion and the debt to total capitalization ratio was 13%. At June 30, non-GAAP net debt was $1.039 billion or net debt to total cap ratio of 12%. The effective tax rate for the quarter was 28%, and the deferred tax ratio was 58%.

The press release also highlighted a dividend increase of 12.5%. This is the second dividend increase this year and the ninth time the Board of Directors has increased the dividend in nine years.

Yesterday, we filed a Form 8-K with third quarter and full year 2008 guidance. We also filed the second quarter 10-Q which has our updated hedge position. With our current hedge position as outlined in yesterday’s 8-K filing, for every $010 change in the average 2008 Henry Hub strip, EOG's 2008 net income and cash flow is impacted by approximately $20 million. Similarly, for every $1 move in the average 2008 WTI strip, EOG's 2008 net income and cash flow is impacted by approximately $10 million.

For the full year 2008 the 8-K has an effective tax range of 32% to 36% and a deferral percentage of 65% to 75%. Using the midpoint of the updated 8-K guidance our full year 2008 unit cost for lease and well, DD&A, G&A, total exploration, net interest expense and excluding transportation and taxes other than income, our forecast increased 4.4% over 2007.

Estimated capital expenditures for 2008, excluding acquisitions are now $4.75 billion, reflecting a $370 million increase. Approximately $100 million of the increase is related to increased gathering and processing activity in the Bakken and Barnett. The increase in exploration and development expenditures is due to drilling activities and significantly increased leasing costs in new areas.

Now I'll turn it back to Mark to discuss the gas macro, hedging and his concluding remarks.

Mark G. Papa - Chairman and Chief Executive Officer

Thank you, Tim. Regarding the worldwide oil supply demand picture, we believe oil prices will be highly volatile but will move directionally higher over the next five years because we see oil demand, particularly in Asia and the Middle East outstripping worldwide supply growth.

In our mind predicting the North American gas market is more difficult because of the big influence of winter weather. Although there are current figures about domestic supply growth, we see the market as currently balanced based on the last nine weeks of storage injections with only one week out of range and that week was slightly affected by the July 4th holiday.

As we mentioned in the last quarter, we still expect November 1st storage to reach 3.3 Tcf to 3.4 Tcf which will be a bullish harbinger for 2009. I'm a big believer that winter weather has a very large effect on ensuing years gas prices so if someone could tell me how hot or cold next winter will be then I will tell you the 2009 gas price.

I will also comment regarding North American supply growth in a macro sense. We see the overall total Barnett field gas production peaking in 2009 at about 5 Bcf per day and then plateauing in 2010, 2011. Therefore, new resource plays will have to be the growth driver after 2009 and we don't see the British Columbia Horn River Basin filling that gap until 2011 plus. When you view supply growth in this context, the possible emergence of new domestic resource play is more digestible.

Our 2008 oil and gas hedge position is unchanged from the last earnings call. We have added to our 2009 gas hedge position and as a percentage of North American total… North American natural gas production we are currently 36% hedged at an average price of $9.71. We also have a small amount of 2010 gas hedged with swaps at an average of $9.87 and we also have some gas collared at $10 followed by $12 cap. At this time, we don't anticipate hedging any 2009 or 2010 oil.

Now let me summarize. In my opinion there are four important points to take away from this call. First, we believe we've carved out a strong consistent niche relative to the peer group in the four most important E&P metrics of ROCE, net adjusted production per share growth, low unit cost and low net debt. If the NYMEX is a good indicator of hydrocarbon prices through year-end, we expect to further pay down debt and end the year with a net debt to total cap ratio of around 8%. Today's dividend increase, the second this year, is further evidence of our conservative capital structure and our consistent game plan.

Second, we are well set up to generate 13% to 15% organic production growth in 2009 and 2010 with a continued mix shift toward liquids. Third, there is room for all of our captured big core resource plays to expand and we are already seeing evidence of that occurring in our Bakken accumulation similar to the reserve expansion we've noted in Johnson County.

And fourth, in addition to the Bakken, our other key plays are developing as expected and we continue to work on identifying new resource plays. I'll close by noting that I continue to be very confident regarding our consistent company strategy with our Bakken, Barnett gas, Barnett oil, British Columbia gas and Uintah Basin assets plus any other plays we don't have to capture any more assets to be assured of low cost, strong organic production growth well past 2010.

Since we have so many home-grown assets it's unlikely we'll participate in the acquisition market. Of course we continue to work to add new horizontal plays targeting both oil and gas, which will further strengthen our asset base.

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

Question and Answer

Operator

[Operator Instructions]. We will have our first question from Bian Dale [ph], Bernstein.

Unidentified Analyst

Hi, Mark.

Mark G. Papa - Chairman and Chief Executive Officer

Hi, Bian.

Unidentified Analyst

I had two questions, one was on the China assets. If I'm right the gas price domestically in China is set around $3.25. Is that what you're receiving and do you believe you are going to see upside in there as the government tries to raise the domestic gas price?

Mark G. Papa - Chairman and Chief Executive Officer

Bian, the gas price that you mentioned is not the gas price we are receiving but it's not totally out of the range either. Gas prices in the Sichuan basin are controlled by the government, but it's a negotiated formula and that formula is confidential, but it is tied somewhat to exports and somewhat to local consumption. I would say that the price is kind of at the high end of what would see as long-term prices in Trinidad right now. The gas demand, as we see it, is definitely increasing in China with time. Gas prices are on the upswing there. So, we are happy with the gas price that we currently have negotiated and feel like we can make a very good rate of return on the asset there as long as we can make the horizontal program work.

Unidentified Analyst

Do you mind telling me whether it's above or below the $3.25?

Mark G. Papa - Chairman and Chief Executive Officer

We are not really going to tell you the exact number, but it is certainly… right now in Trinidad I think our 8-K number is like $3.17, $3.20 something like that and we are in a range above that.

Unidentified Analyst

Right. And my second question was just on some of your oil shale plays. I was trying to get a feel for what sort of oil price would make a moderate activity in those plays? I think, Mark, you commented before that you believe the economics are still pretty good at $70 a barrel. Is that just sort of a number that you’d be looking for before you would change your activities there?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, we… $60 a barrel something like that, Bian, would be a number where we would start to think twice about it. I mean, at the current $120 a barrel we are making extremely high reinvestment rates of return on all of our oil shale plays. So, there's a lot of fat in there is the way I would describe it.

Unidentified Analyst

Okay.

Mark G. Papa - Chairman and Chief Executive Officer

Economic fat.

Unidentified Analyst

Okay. Thank you.

Operator

We will go next to Thomas Gardner, Simmons & Company.

Thomas Gardner - Simmons & Company

Good morning. Hey, Mark, you mentioned in light, you mentioned that you've increased your natural gas hedges in 2009. So, when you look beyond 2008 are you still bullish on North American natural gas or do you see the possibility of strong supply growth leading to gas on gas competition? And what do you see the governors to North American and natural gas supply being?

Mark G. Papa - Chairman and Chief Executive Officer

For 2009, Tom, my sense is we'll start the heating season with between $3.3 and $3.4 in storage which will be a little bit lower than last year, but not a crisis point lower. And then, I believe it's really kind of a weather call. I think if we have a normal winter or a cold winter we are going to be, at least in E&P comp, we will be very happy with the 2009 gas prices but there is a risk that if we have an extraordinarily hot winter I think the whole sector will probably be a bit disappointed in the gas prices. I really… the point I would make is that I think in a lot of analysts’ minds the Barnett Shale which has been by far and a way the biggest single growth driver of domestic production growth for last three or four years, I think, a lot of people believe the Barnett Shale is just going to continue to grow indefinitely year after year after year and our view is that the Barnett Shale as an aggregate probably has one more year of decent growth and that's 2009. And by year-end 2009 we believe Johnson County is going to be pretty well drilled up buy all operators on about 35 acres spacing. And that's going to remove a lot of the thrust. There will be continued drilling in Tarrant County but that's an urban area and the rate of drilling there is not going to be anything to write home about. So, when people view the gas macro 2009 and later, you ought to assume in our opinion that the Barnett is just not going to be the big driving force except for one more year.

Thomas Gardner - Simmons & Company

Thank you for that. Jumping over to the Bakken, you mentioned that your 80 million barrels booked ties to your core area but there's the potential for 320-acre down spacing and you have got the periphery that May be also incremental. Can you paint a picture of just how big that could be net to EOG and assuming that works out, what sort of… how long does that perpetuate a growth trajectory in your production and the play?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, the first point there, you mentioned 80 million barrels booked, we haven't booked anywhere near that. We booked just a small amount in relative terms so that 80 million barrels net is what we think the reserve size will be. I think we booked about 20 million barrels to date in there. In terms of the Bakken and the possible expansion, I think we need to view that as kind of two different things. In the core where the primary production is 80 million barrels and we are getting these really, really high per well initial rates, we've defined that early enough, we believe, to now it just boils down to two questions. One, can it be down spaced from 640s and 320s, and two, whether or not one is applicable, can we figure a way to get more than about 10% of the oil in place recovery and a 10% is what is about 80 million barrel count number. So, it's really boiling down to a pure reservoir engineering analysis there and we've said that it's probably going to be early next year before we can get some definition on those two items. On the second way that the Barnett can grow is by drilling outside this core. And this earnings… this conference call kind of notes we have drilled some wells outside the core. We are very optimistic with the results but until we watch the wells a little bit more closely for a little more period of time we are not going to give a number on a potential side. But, I think that the directional trend on at least the resource plays that EOG has captured would infer to me that just kind of like Johnson County where we started out saying, well, we have X Tcf we are going to capture in Johnson County and we up that number. The Bakken is looking like it's going to fit a similar trend. And we hope some of these other big resource plays such as British Columbia, such as the Barnett oil play we hope those will also follow that trend but it's just too early to tell.

Thomas Gardner - Simmons & Company

Great. Thank you for that. And just one last question on the Horn River Muskwa and then I will hop off here. Can you just make a comparison, if you will, of the Muskwa versus the Barnett just in the key shale properties and I will hop off?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, we provided an IR presentation kind of a slide that has logs [ph] from the Barnett, in fact the power logs from Barnett that we show normally show and in our typical catalogue for the Muskwa in which we point out that the thickness is actually greater in Muskwa. Average thickness is about 530 feet in the Barnett, the thickest part of the Barnett in fact is Central Johnson County, at least thickest part. We control acreage on it about 350 feet. So, it’s quite thicker. Permeability is about the same in the 200 to 300 nanodarcie range, which is quite good for a shale. Gas-filled porosity is roughly equivalent. Maturities are roughly equivalent. Silica content, which is quite important we think in determining the fracability of the shale. That’s actually slightly better in the Muskwa than it is in the Barnnet. So, the bottom line, when you add all those together and also the fact that the Muskwa is over pressured to a greater extent in the Barnett as you can pact more gas molecules per square mile in Muskwa than you can at Barnett. So, [inaudible] of about a 2x multiplier from our best Barnett to the Muskwa average of our 840,000-acre position. So, the bottom line is it’s a really good quality rock and there is more in a higher pressure than in Johnson County.

Thomas Gardner - Simmons & Company

Thanks for that.

Operator

We will go next to Joe Allman, J.P. Morgan.

Joseph Allman - J.P. Morgan

Hi, good morning, everybody.

Mark G. Papa - Chairman and Chief Executive Officer

Hi, Joe.

Joseph Allman - J.P. Morgan

Mark, what do you think about the prospectivity of the Three Forks/Sanish under your acreage and do you have any plans to test the Three Forks/Sanish?

We have tested the Three Forks/Sanish in a couple of wells in our Parshall area and a couple of our step-out wells around Parshall. We recognize that is an additional reservoir potential in the area on our 320,000 net acre position, but I would say in the Parshall area itself we have not found it to be a quality reservoir and are not [inaudible]. It’s kind of spotty in its distribution around the basin we believe. It’s probably the part of the same self… basin centered oil shale as the Bakken and so we will be exploring four days as we go forward on the remainder of our acreage.

Joseph Allman - J.P. Morgan

Okay. Do you think in your Parshall fuel wells and Austin Wells do you think you are getting some contribution from the Three Forks/Sanish?

Mark G. Papa - Chairman and Chief Executive Officer

I really don't think we are. I mean we have penetrated in a couple of places and as I said, the porosity development, particularly the permeability development in that particular zone is pretty spotty. And I don’t believe that it extends to integrate a step under our main Parshall field, at least from the data we have so far. Now, as I said that covers maybe 100,000 of our 320,000 acres. And there is a lot more to explore for you.

Joseph Allman - J.P. Morgan

Gotcha. I might have missed what you said, the test you have done outside of Parshall, have they been more promising?

Mark G. Papa - Chairman and Chief Executive Officer

We are not going to comment on Sanish potential and wells we drilled outside of Parshall at this point. I think it’s still too new to draw any conclusions and we probably muddy the waters more than we clear it if we try.

Joseph Allman - J.P. Morgan

Gotcha. The strong well that you reported recently in the Austin area, are you using the same techniques that you have always used, just a single… I know you have done a single long lateral on 640 and in small factors?

Timothy K. Driggers - Vice President and Chief Financial Officer

Yes. We… that's directionally, Joe. But we haven’t… in the last six months we haven’t further refined our completion techniques there. I think we are obviously, if you look at those effect, I think you put out something on the best wells completed in the market. I think whatever we are doing, it seems to be much better than most other companies out there in terms of initial rate and we think also in reserves.

Joseph Allman - J.P. Morgan

Okay. And then the wells that you are drilling outside of the core area, are those on the border of Montréal and Berk County?

Mark G. Papa - Chairman and Chief Executive Officer

We are not going to develop anything other than our outside the core right now because there is still additional acreage we may tend to pick up.

Joseph Allman - J.P. Morgan

Gotcha. Appreciate that. And then, are you… so that was my next question, so you are buying some more acreage?

Mark G. Papa - Chairman and Chief Executive Officer

Yes.

Joseph Allman - J.P. Morgan

Okay. Got it. And then just on… your comment on the Barnett Shale peaking in late '09. For EOG you need to make up for that growth wedge, do you think the Bakken and the Barnett oil make up for that in the near term and then following that would be the Horn River Basin growth?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. Actually we had a chart in our February analyst conference that kind of show that what happens is our Barnett gas begins to flatten out in 2009, but that's when the Barnett oil kicks in. So, we expect to have many years of continued aggregate Barnett growth but the lift is going to be more towards liquids going forward. And just another comment, when I discussed item up about the Barnett peaking in '09, people say, well can’t you [inaudible] refrac or couldn’t you drill on, let’s say, 15-acre basin. We believe, particularly in Johnson County, the refracs are not likely to work and so you are not going to get any big surge from that and that we also believe that drilling the wells on even ore concentrated spacing is probably also not going to work. So our view with the Barnett currently in Johnson County is it’s kind of a one-time shot and until we get some new technology that we are not aware off is not necessarily going to be a second round there. We think that also applies to other parts of the core area.

Joseph Allman - J.P. Morgan

That’s helpful and then lastly could you just comment on the recent trend for drilling and completion cost and also comment on the availability of steel to develop your various programs.

Timothy K. Driggers - Vice President and Chief Financial Officer

The drilling costs they have been fairly flat through first half of '08 and we are starting to see a little bit of increase. Yes, the tubular and fuel cost, that's in the East Texas. Rocky Mountains, we are starting to see a little bit of increase in stimulation cost because of sand shortage there. Forward area the cost are pretty flat, rates are starting to tighten up a little bit there. So overall, our costs have been lower first half '08 compared to '07. But we may see cost increase slightly here in the second half given some of those gains.

Mark G. Papa - Chairman and Chief Executive Officer

And on that tubular question, the tubular situation not as tight as we have seen it in the last 20 years to 30 years. We are literally in a mode on many of our wells of kind of just in time delivery to get the pipe there to the well side literally hours before we have to run it in the well. Whether this tightens further, which could actually reduce drilling activity, we don't know. We generally expect it to remain tight but not to be a pinch point where in a macro sense people are laying down rigs so they can’t get pipes, but we're not an expert on the tubular market.

Joseph Allman - J.P. Morgan

Fair enough. Well, thank you.

Operator

We will go next to Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Mark G. Papa - Chairman and Chief Executive Officer

Good morning, Brian.

Brian Singer - Goldman Sachs

Wanted to see if you could provide any additional color on the Barnett oil play, you highlighted briefly in your remarks, but I guess what incrementally is driving your level of confidence that this can be a major wedge, I guess looking out into 2009, probably and more importantly 2010 or 11?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, in terms of... and I know people who would love to hear a lot more details on the oil play or at least have some other kind of peer company confirming the oil play. As we mentioned, this is the one play where we pretty well locked up vast majority of the acreage before we went public with it. And we are aware that at least one other peer company went in after analyst call and attempted to gain an acreage position and then pulled out after several months when it realized that it will be very difficult for them to get any sizeable acreage position. So we're... we pretty much control this play at least among the public companies and what we are currently doing is, we are experimenting with the completion techniques on both horizontal and we are also looking at vertical wells, as I mentioned there are some private companies that have completed some vertical wells and they are 100% reinvestment rate of return wells. So, we are open-minded enough to say well we look at horizontal wells or look at vertical here since there is track record of successful vertical wells. But the problem we have is we can't get any sustained test on much of anything there because there is pretty much... pretty close to zero capacity for anybody to take the gas up there in Montague County. And so we just... we have to wait until we get our plant built before we can really do much with these things. So, I would just say the reason we're so excited about the play is that we continue to confirm that the oil in place per square mile there is huge, over 30 million barrels per square mile in some of that area and if we just get a small percentage of that 2% or so, you can end up with some pretty big numbers. But everybody just have to be patient until the year-end or the first quarter before we can provide any more specific details on it.

Brian Singer - Goldman Sachs

And could you just refresh us from your analyst meeting whether and I apologize and I'm recalling just whether it is just really just for now a oil [inaudible] call or are there any… is there any even initial production rate data or initial declined data to speak out that gives you the confidence?

Timothy K. Driggers - Vice President and Chief Financial Officer

At our analyst call in February, we talked about our initial, I think it was eight wells if I'm not mistaken that we did drill eight horizontal wells. And we showed in our first quarter, we talked about the IPs of those wells ranging from 150 barrels to 350 barrels of oil per day and 0.5 million to 1 million cubic feet of gas per day which yielded a direct… a cash rate return of around 65% and that's really all we put it out Brian at this point.

Brian Singer - Goldman Sachs

And have those wells then producing, or are they constrained because of the gas issue and I guess if they have been producing, can you talk about what you've seen?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. Most of them have been constrained, most... all of them basically have been constrained, was just in a minute production is best. But the very limited production data we have still confirms those kind of estimates. But we're really suffering from a positive data until we get more infrastructure out there. And I'll note that when we presented this to everybody in February, we said this is the 2009 event, it’s not a 2008 event. So, that's kind of our information that we can provide to you at this time.

Brian Singer - Goldman Sachs

That's great. And then separately on the higher CapEx which seems to a lot be on increased leasing, can you just start providing more color on whether that represents acreage acquisitions in plays you've discussed versus working upon new resource plays? I think you mentioned you've seen some sharp increases in leasing costs. So, maybe we should interpret that represents Bakken, Haynesville and Marcellus, I don't know if there is any color you can provide there?

Mark G. Papa - Chairman and Chief Executive Officer

Yes… I mean in the Marcellus specifically, we're not chasing any additional acreage up there at this time. What we are seeing though is that as you guys on the sell side are well aware that every peer company wants to have a stable full of resource plays and so that the acreage costs even for first movers on potential resource plays, the acreage cost has gone up dramatically. And so, what we're doing is, we're trying to be... to not chase the hot plays per say, but even the front-end costs in some plays that we thought would be kind of under covered plays. It's costing us more to get acreage there than we would have thought. So. a big majority of that money that we are talking about is in plays that we really haven't currently disclosed and will be evaluating over the next year or two.

Brian Singer - Goldman Sachs

Great, thank you.

Operator

We'll go next to David Tameron, Wachovia.

David Tameron - Wachovia Securities

Good morning, everyone. A couple of questions. If you look at and you have kind of alluded to this, Mark, but if you look at your 2009 growth target that you guys laid out kind of 13% to 15% number, how confident are you today in that number? Is that a P70 number or a P50?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. I'm pretty darn confident in the number. I don't know if I want to put a P specifically on it, but it's a pretty reasonable number and that number was 13% to 15% production growth for 2009. The components for that growth really are... we've got a sustained drilling program in the Burnell area there, Uintah Basin that just beat one more year of kind of a standard program. The Bakken is currently outperforming the estimates that we provided in the February analysts call and we expect the Bakken will continue to outperform throughout all of 2009 based on what we stated already on this call. And then, the Barnett oil should be coming on during that timeframe as well as the rest of our play. So, the only absence from the extraordinary events such as unavailability of rigs, unavailability of steel, some unusual collapse in hydrocarbon prices, I think we're pretty well set up for the production growth for 2009. And really, we've watched a lot of companies’ strategy here over the course of this year and there seems to be a lot of companies that are paying really premium prices for either acreage in hot areas or producing properties in hot areas. We sit back and say, just look at the inventory we have in hand today even if we never added another resource play, we're pretty well set up well past 2010, just developing the assets we already have and have disclosed. So, we just don't see any need to block there and literally spend billions and billions of dollars on chasing some of the assets, and so it's extremely unlikely that we will do that either this year or 2009.

David Tameron - Wachovia Securities

Okay. Thanks. And then along those lines, so you have obviously net debt-to-cap targeted sub 10%, any more commentary on what’s your thoughts on with the cash balance that you have committed there or you are kind of projecting right in the break-even cash CapEx over the next couple of years?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. I mean, preliminary thought for 2009 would be... if you just took today's NYMEX prices for 2009 that we probably end up roughly cash neutral… cash flow neutral program in 2009. So, the game plan will be to continue to have very, very low levels of debt, net debt in 2009 and later. Probably we'll continue to have the best ROCE that appears than the peer group and lowest unit cost as well as a lowest debt. And then 2009, 2010 debt adjusted production gross per share, we may not be in first place in that, but I believe we'll be in the top quartile every single year. And frankly, we just don't see the need to… for growing the company at 14%, 15% per year. We are just not that anxious to lever up the company in a monstrous way so that we can say, we've got production growth in the low 20s per year. We much rather have an extremely low debt and high ROCE to growing the company with normally 14%, 15% per year.

David Tameron - Wachovia Securities

Okay, refreshing view. And the last comment, a lot of talk on sell side and buy side as prices trend down on natural gas side of the costs over the last month. What do you believe that marginal costs for suppliers right now in the U.S. kind of from the natural gas standpoint?

Mark G. Papa - Chairman and Chief Executive Officer

In the Gulf of Mexico, it's probably currently $8 to $9, I would guess, with the way the marine equipments costs have gone up and any onshore areas you probably look at $7.50, something like that, maybe $8. So, the issue I think on the... this comment on gas prices, a month or so ago they were $13, $13.50, and personally, I was wondering why they're going up so much, because I couldn't see any fundamental supply demand situation that would drive them up toward $13, $14. So, my sense is they were just overpriced a month ago and now they're back in the... in my mind, the price is $10, maybe $9 is probably a more rational price assuming the kind of a normal winter for this coming winter. So, our views have collapsed as they collapse from the price that was more of an emotional price there of $13.50.

David Tameron - Wachovia Securities

All right. Thanks, nice color.

Mark G. Papa - Chairman and Chief Executive Officer

Thanks.

Operator

We'll go next to David Heikkinen with Tudor.

David Heikkinen - Tudor

Good morning. One quick question, the 100,000 acres you have in the Haynesville, can you give us any description of where that's located?

Mark G. Papa - Chairman and Chief Executive Officer

It's... I mean, some of it's in North Louisiana, some of it's in the East Texas part, and it kind of just... it's a pretty good spread, but I'd say, the 100,000 acres are in areas that some other companies have deemed that would be perspective. And I'd say, we just have no first hand results ourselves about the Haynesville, and so we just... and I know there is kind of a big argument going on in the industry about, is the Haynesville a really big player or is it a localized player if it play at all. And we just seem to stay out of that whole kind of argument until we get some data on our own.

David Heikkinen - Tudor

And if we look at your existing production in those fields, I mean, you have some legacy fields between [inaudible] if you just take that line, is that the majority of the acreage you're talking about because it is mostly held already or is it new leasing?

Mark G. Papa - Chairman and Chief Executive Officer

The majority... the vast majority of 100,000 acres is just a legacy acreage.

David Heikkinen - Tudor

Yes. Okay.

Mark G. Papa - Chairman and Chief Executive Officer

But maybe about half of our acreage is kind of in that area that you just described there.

David Heikkinen - Tudor

Okay. You've given that already a few times. The other question I had just thinking about the Bakken and defining the extension area, talk about 100,000 acres that are in this primarily core Parshall, how should we think about… you may even want to get into the direction of the extension areas you're still leasing but, we've have thought of the crescent sort of that the Bakken has developed. Is that… how do you think about what or where we should think about that extension area heading?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, we would like to leave that as murky as possible, regarding the geometries, outside expansion, frankly the geometry as a core area, we think we understand now what… pretty well what the boundaries are on a really high-quality core area and as we said before, there are...there is a rind of somewhat lesser quality, but still economic acreage around that core area. And the geometry, as we understand it, is better defined now but it will expand, we believe, in rind area, particularly it will expand in we've driven our comment on what directions that might go.

David Heikkinen - Tudor

Okay, and everybody is keeping their eye on Barnett oil and it looks like the majority permits there more in Montague County as opposed to Clay and Archer. Is that just an indication of where infrastructure is located now, more so than quality of wells or can we read anything into the concentration of EOG permits further to the east?

Mark G. Papa - Chairman and Chief Executive Officer

Well, I'd say that there is a similarity between Montague County, which is the farthest east, and then you go to Clay and then you go to west, got to Archer as move west. There is a similarity to the Barnett gas and that as you move out of Montague County going west the zone gets thinner and you lose the viola [ph] which insulates you from the [inaudible] of water. So, out of the reserve estimates that we kind of put out so far, the biggest single contributor that by far is Montague County. And so we've done some drilling out in the west but, like I said, more wells in Montague in west and that's where as these oil play develops I think Montague will be the name you're hearing a lot more frequently than Archer play.

David Heikkinen - Tudor

And that's helpful. And then on the balance sheet side, do you guys think at all about or how would you think about share repurchase programs and where that would fit in your capital allocation process?

Mark G. Papa - Chairman and Chief Executive Officer’

Yes, I mean with the stock price decline, what kind of puts back on the table is something that we have in our arsenal. I'd say that at this point, it’s still more likely that we'll run the company with low debt as supposed to attempting to kind of lead anyone to believe that we're going to jumping into a big share repurchase program in the future. The preference would be to just run the company at very low debt in 2009, 2010, 2011 and to have kind of a balanced program, cash flow versus CapEx post 2008. But depending on how the stock reaction whether it directs further in the negative direction, we certainly have the fast hour to do something about it in terms of repurchases. We're just still watching that everyday.

David Heikkinen - Tudor

Just one additional thing, on the Barnett gas peaking in 2009, make sure we're all measuring from the same point, what is current Barnett gas production as you guys are measuring it compared with the 5 Bcf a day?

Mark G. Papa - Chairman and Chief Executive Officer

We think it's probably somewhere, if we just took like a current June, July number, we think it's somewhere probably in a range of probably 4.2% right now.

David Heikkinen - Tudor

Okay.

Mark G. Papa - Chairman and Chief Executive Officer

And we think it'll peak out at about five something like that.

David Heikkinen - Tudor

And how much liquids are… are you including liquids in that or is that just straight gas, just trying to make sure?

Mark G. Papa - Chairman and Chief Executive Officer

Gas, really.

David Heikkinen - Tudor

Okay. Okay. Thanks a lot guys.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

We'll go next to Eric Hagen, Merrill Lynch.

Eric Hagen - Merrill Lynch

Hi, good morning. First, thanks for a very measured instead of same view of gas markets in growth. In terms of questions, can you give us an idea of the volumes out of the Bakken currently and how many wells you are producing?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. We don't want to get into specifics on there because... and the main reason we don't is, if we give a specific volume now then somebody will ask for the next quarter and if it happens to be 500 barrels a day lower then that somebody has projected that and then somewhere around sell side right up to say Bakken less than expected for the third quarter or so. So we just don't want to [inaudible] this Barnett, we'll give an annual goal, and we have provided an annual goal in the February analyst conference for this year for the Bakken and what we can tell you is we're going to beat that number but we're not going to give specifics.

Eric Hagen - Merrill Lynch

Okay. Great, thanks. And the other question I have is on the Marcellus, besides infrastructure issues and permitting and what not, is there anything in terms of the geology or consistency of results that makes you more negative or more measured on the play?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. I'd say that we are a little more measured on the play than perhaps some others that you are reading out there in that the thickness is quite a bit less than we see and obviously than that we see in a Barnett. And it's a good quality rock and it's well distributed over a broad areas. But as I said the thickness is an issue, in some case pressure is an issue but probably the most unknown risk factor that we and others are dealing with right now is frac efficacy, frac barrier containment in the Marcellus itself. The kind of results that we are hearing about in parts of Pennsylvania that we're showing 3 Bcf to 4 Bcf of oil that really does not confront well with kind of IPs that we are seeing in rest of the play and really the way we model the plays north of 1.5 Bcf to 2 Bcf of oil kind of play, particularly if you're looking at big program averages. It's really, really difficult to average 3 Bcf to 4 Bcf of oil over a whole play.

Eric Hagen - Merrill Lynch

Okay. And in terms of that… the frac efficacy, is that the lack of a frac barrier in certain areas that you can’t contain the fracs or is there some sort of embedded shale that’s interfering with fracs, any more color you can provide on that possibly?

Mark G. Papa - Chairman and Chief Executive Officer

Really, that is specific because I've cared to get. I think there are differences in the frac barriers throughout the play, from geographic area to geographic area and next I think the biggest unknown in the play right for most of the operators.

Eric Hagen - Merrill Lynch

Well, great. Thanks for that color.

Mark G. Papa - Chairman and Chief Executive Officer

Okay, Eric.

Operator

We'll go next to Leo Mariani, RBC.

Leo Mariani - RBC Capital Markets

Yes. Thanks. The question on the Bakken here. You guys talked about some peak rates in your press release from three new wells at 2.7, 1.9, and 3.2 [inaudible]. Trying to get a sense of what the term is on those rates, those one-day peak rates or where do we have investment in that?

Mark G. Papa - Chairman and Chief Executive Officer

Those rates, I mean for the Bakken, are you asking about the Bakken there, Leo?

Leo Mariani - RBC Capital Markets

Yes

Mark G. Papa - Chairman and Chief Executive Officer

Okay. You quoted some numbers there, I'm not sure where those numbers came from 3.7… I guess that’s 1000 barrels a day, okay. Yes, those are just initial rates, probably the first three to four days rates and these wells will decline at pretty sharp rates and to some degree that's… you can't use that number and say that's going to be a yearly average and anything like that but what they do, if you kind of compare those initial rates with what we've seen from some or the peer companies up there you’ll find that they are considerably higher in many cases, double, triple, five times initial rates from some of these other companies. And it just shows that there is a correlation between the initial rates and the ultimate reserves on wells. The higher the initial rates, the more reserves you're going to get out of the well.

Leo Mariani - RBC Capital Markets

Okay. I am... due you guys have enough data in that play to talk about what to expect for the first year annual decline rates?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. We do and I'm not sure we can quote it and give it to you here. We could probably, if you want to call Maire later on, we'll dig it out, but the answer is, yes we've got a pretty accurate tight curve on that.

Leo Mariani - RBC Capital Markets

Okay. Jumping over to the [inaudible] play you guys mentioned two recent wells that came on production here. Any indication of what those flow rates are and I guess are those producing at this point without restriction?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. British Columbia?

Leo Mariani - RBC Capital Markets

Yes.

Mark G. Papa - Chairman and Chief Executive Officer

Yes. They are producing without restriction. I'd say, they have only been on about two weeks. We really don't want to give any flow rates or anything on them other than to say we're pleased. And I think by next quarter, we can probably give a much more detailed assessment for you of what we are talking about up there in BC.

Leo Mariani - RBC Capital Markets

Okay. Just to clarify on your comments about the Barnett gas here. You talked about industry peaking at some point in 2009, do you also expect that EOG's volumes in the Barnett would peak in 2009? Are you guys going to have I mean do some more lights on that?

Mark G. Papa - Chairman and Chief Executive Officer

Well, in terms of the Barnett gas volumes, yes, we expect they will probably peak in and then plateau in 2010 and 2011and then we expect to have the oil volumes slated in. But generally we think we will be similar to the industry in the Barnett gas portion.

Leo Mariani - RBC Capital Markets

Okay. Thanks a lot.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

We'll go next to Gil Yang, Citi.

Gil Yang - Citigroup

Hi. Just couple of quick questions. In China, did the earthquake have any effect on either the operations there and/or the plans to move forward with that in the future with concerns about infrastructure and susceptibility to earthquake?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. The answer to that is no. It was in an area far enough away from the stuff the field we are dealing with that there was no effect either on the down hole equipment or any on the surface, no pipeline related issues or anything like that.

Gil Yang - Citigroup

Okay and Loren, you commented Muskwa has… is over pressured and I am not sure you said it's two times pressured or was that overall between all the things twice as good?

Loren M. Leiker - Senior Executive Vice President, Exploration

No. That's an overall twice as good, twice as much gas in place per square mile.

Gil Yang - Citigroup

Okay. What is the full pressure in... full pressure grading in Muskwa.

Loren M. Leiker - Senior Executive Vice President, Exploration

It ranges from the East to the West side of the basin but all of that basin is more over pressured by gradient than is the Barnett. And Barnett may be in 4.8 to 5.2 range and Muskwa is substantially higher than that.

Gil Yang - Citigroup

Again 0.7 range.

Loren M. Leiker - Senior Executive Vice President, Exploration

Really not given actual number for that. It does vary across the basin and that's kind of one of the controlling parameters for gas in plays?

Gil Yang - Citigroup

Does that potentially mean that the decline rates are going to be higher, too if it's more over pressured?

Loren M. Leiker - Senior Executive Vice President, Exploration

I think so, I think it just is going to pack molecules into the core structure that you have. The decline rates... we don't have long-term productions. Some others have a little bit longer-term production than we do. And they don't look how ordinary it is.

Mark G. Papa - Chairman and Chief Executive Officer

Our guess, Gil is that the decline rates will be similar to Barnett gas type curve coupon rate.

Gil Yang - Citigroup

Last question, I have sort of a macro question for you, Mark, is, you're saying that maybe gas ending inventory is 3.3, 3.4 and I think you've been saying before 3.2, 3.3, if that's right, what has changed that? It's a little bit... obviously it is less than last year, but still a little higher than your previous estimate, what has changed in that interim?

Mark G. Papa - Chairman and Chief Executive Officer

On the previous earnings call, I did not use 3.2, I said I expected it to be 3.3. So now I'm saying, on average 3.35. So…

Gil Yang - Citigroup

Okay.

Mark G. Papa - Chairman and Chief Executive Officer

That's within around the accuracy, but I don't recall every saying 3.2.

Gil Yang - Citigroup

Right. Okay. So, you are introducing no major change there?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. We really don't think there is a major change, I think as everybody knows, the comps there in August, we're going to be really tough to be relative to last year's August. But I guess, if I just stand back and look and say, okay over the last nine or ten our storage injection reports, in my mind we have one disappointingly various report which was one or two weeks ago. And that may or may not have been affected by the July 4th holiday, but other than that the rest of them have been pretty much in line, some over, some under, but it doesn't indicate the way we've got this massive oversupply situation. I think it's just more psychology right now that oil prices have fallen a bit, people know that last August was so hot and this August will be really doubtful. So push the sell button for gas features is what some people appear to be saying, but I don't think the fundamentals are particularly weak at all there.

Gil Yang - Citigroup

Given you generally bullish outlook, can you just, maybe you said this earlier and I missed it. But could you give some rationalization of why you're actually taking your hedges for '09 about your hedges in percentage terms at least over '08?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. We... on the last earnings call, I believe we were 30% hedged for '09 and we said that we would likely add to those hedges and now we are currently 36% hedged at a $9.71 price, kind of we view that as kind of a reasonable price. We're not at the camp that says, gas next year is going to be $12. We think $10, $9, $9.50 is probably more reasonable gas price unless you have a really, really cold winter. So, that's why we blocked in some of that, we blocked again what we think is a rational gas price for next year.

Gil Yang - Citigroup

Okay. Thank you very much.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

We'll go next to Ellen Hannan, Weeden & Company.

Ellen Hannan - Weeden & Co.

Good morning. Actually my questions have been answered, thanks.

Operator

We'll go next to Marshall Carver, Capital One.

Marshall Carver - Capital One

Yes, a couple of question on the Marcellus. I didn’t catch your acreage positions there.

Mark G. Papa - Chairman and Chief Executive Officer

220,000 net acreage.

Marshall Carver - Capital One

And the 1.5 Bcf to 2 Bcf per well, is that... do you think that you can get higher recoveries in certain areas and no other operators just talked about 3 Bcf to 4 Bcf a well in Northeast Pennsylvania and Southwest Pennsylvania?

Mark G. Papa - Chairman and Chief Executive Officer

I mean, we'll comment in just a general sense there that if you look at the rock it's considerably thinner than the Barnett, and basically in Johnson County, the average in Johnson County is not three to four Bcf well, it's less than that. And so, when you are dealing with Marcellus, which is less geo-pressured and much thinner, it just doesn't make good reservoir engineering stands that you're going to get recoveries of 4 Bcf well when that hadn't been average in Johnson County. So, we just think that that number is probably the number that's we believe is unrealistic. And then, you clearly do have a problem with containing the fracs within that relatively thin zone. You have more of a problem in the Marcellus than you do in the Barnett. So, that's another reason for caution.

Marshall Carver - Capital One

Okay, that's helpful. Thank you.

Operator

And we have no further questions in the queue at this time. I'll turn the conference back over two Mr. Papa for additional or closing remarks.

Mark G. Papa - Chairman and Chief Executive Officer

I just want to thank everyone for listening and we'll continue to just stay on a very consistent game plan. Thank you.

Operator

That concludes today's conference call. You may disconnect at this time. We do appreciate your participation.

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Source: EOG Resources, Inc. Q2 2008 Earnings Call
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