EOG Resources Inc (EOG) 2008 Q2 法說會逐字稿

Good day everyone and welcome to the EOG Resources 2008 second quarter 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.

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 prove reserves in their Securities filing.

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 US investors that appear at that 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 Lauren Leiker, Senior EVP, Exploration, Gary Thomas, Senior EVP, Operations, Bob Garrison, EVP, Exploration, Tim Driggers, VP and CFO, and Marie Baldwin, VP 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 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 any 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 investor who's 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 long standing goals for EOG. Four of these components are measurable and the fifth is more subjective.

The four measurable components are, ROCE, debt adjusted production growth per share, overall unit cost 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 a demonstrable track record in this category and even if we are not first mover in potential play such as the Hainesville and Marcellus we still have a 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 curtailments 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 514H., 2433H., and 911H, wells, which had peak rates of 3,744, 1880, 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 invested rate of return exceeded 100%.

I think a 1732 barrel oil per day average initial rate, allows us to deem these as oil monster wells. We have 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 gros.

EOG is by far the dominant acreage holder in this sweet spot and this constitutes our 80 million barrel of oil net reserve estimate. Also as mentioned on the last quarterly call, we're monitoring results from our first 320-acre downspace well which was drilled in the core area and are also evaluating the potential for secondary recovery of the field. Around part of this core area, we believe there's an extension area where wells are still very economic with 250 to 450,000 barrels of oil gross 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 waiting 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 awhile 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 to 50 million cubic feet a day, until we have full pipeline take away 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 take away capacity at the processing plants, we are not able to strip the operate optimum natural gas liquids out of the gas stream. We expect the gas take away 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 pick up in the fourth quarter be 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 easter Johnson County Martin wells that IP'd at gross production rates of 6.1 to9.2 million cubic feet a day each, all gas monster wells by my definition. We are also 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 drilled the Hawks Number 1H which tested at three million cubic feet a day and anticipate drilling 12 offset wells by year end. We already drilled 49 wells in this Erath County development area. In Hood County with drilled 25 wells to date that have averaged one Bcf per well net and we are drilling additional wells. We recently completed the Black Ranch number 9H at a rate of two 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 factors. In the meantime we are testing various techniques for optimum development. I've had some feedback from Wall Street noting that people would like to see data from peer company's 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 foot hold. 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, Mississippi Chalk, Mid-Continent Atoka and the Colorado North Park oil. During the quarter we further confirmed two of these plays. In the Mississippi Chalk we completed the [Gainesville] 24.8, and the 2315 number four wells for 4.1 and 2.7 million cubic feet a day net, respectively. These are 70% after tax rate of return wells.

In the Mid-Continent Atoka we are ring a three rig drilling program and during the second quarter we completed five horizontal wells. The apple 438 number 3H and Landers 522 number 3H wells tested rates of 4.7 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 Verde area in the Unita 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 Hainesville and Marcellus. We have approximately 100,000 net acres in Hainesville 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 will be have some results by year end. If the Marcellus works this will be a very slow developing play in the macro sense because of 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 continue to like both the 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 1, we finalized our China acquisition of 130,000 acres from Conoco Phillips. This is a tight gas asset in the Sichuan Basin onshore China that's currently producing approximately eight million cubic feet a day net.

The rock formation is a low permeability natural gas sand similar to our soft Texas Wilcox play. The prior operators, Burlington and Conoco Phillips, attempted to develop this asset with vertical wells. And that was not very successful.

We plan to use our soft Texas analogy where we half a 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.

Thank you, Mark. For the second quarter 2008 total exploration and development expenditures including asset retirement obligations were $1.150 billion 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 $2.270 billion with $35 million of acquisitions. Total gathering, pipeline and other expenditures were $196 million. At quarter ends 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 dividends increase of 12.5%. This is the second dividend increase this year and the ninth time the Board of Directors has increased the dividends in nine years. Yesterday we filed a form 8-K with third quarter and full year 2008 guidance.

We also filed a 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 $0.10change 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 55 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.

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, out stripping 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 likely affected by the July 4th holiday. As we mentioned last quarter we still expect November 1st storage to reach 3.3 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 the macro sense. We see the overall total Barnett field gas production peaking in 2009 at about five Bcf per day and then plateauing in 2010 and 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 plays is more than 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 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 floor by $12 dollar cap. The 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 ends 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 '10 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 Unita 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.

(OPERATOR INSTRUCTIONS) First question, Ben Dell, Bernstein.

Hi, Mark. 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?

Ben, 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] basis 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 we would see as long-term prices in Trinidad right now. And gas demand as we see it is definitely increases with China with time.

Gases 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.

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

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

Great. 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 you moderate activity in those plays? I think, Mark, you commented before that you believe the economics are still pretty good at $70 per barrel. Is that a number that you are looking for before you would change your activity set?

Well, $60 dollars per barrel, something like that would Ben, would be a number where we would start to think twice about it. At the current $120 per barrel we are making extremely high reinvestment rates of return on all of our oil shale plays. There's a lot of fat in there is the way I would describe it. Economic fat.

Great, thank you.

We'll go next to Tom Gardner, Simmons and Company.

Good morning. Hi, 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?

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 as an E&P company 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 the 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 a about 35 acre spacing. And that's going to remove a lot of the thrust. There will be continued drilling in [Terrin] county but that's in an urban area and the rate of drilling there is not going to be anything to right home about. 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.

Great. 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 320,000-acre down spacing and you have 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 in the play?

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 to 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 that 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 you.

Great Thank you for that. Just one last question on the Horn River Muskwa. And 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?

We provided an IR presentation sort of a slide that has logs from Barnett in fact the [fallor] log from Barnett that we normally show in our typical to the Muskwa in which we points out that the thickness is actually great in the Muskwa. Average thickness is about 530 feet and the Barnett, the thickest part of the Barnett in the central John Johnson County, at least the thickest part that we control acreage on, is about 350 feet.

So it is quite a bit thicker. Permeability is about the same in the 300 Nanodorci range which is quite good for a shale. [Gasioprosity] is roughly equivalent, maturities are roughly equivalent. Silica content which is quite important we think in determining fracacbility of a shale is actually slightly better in the Muskwa than it is in the Barnett.

So bottom line when you add all those together and also the fact that the [Muskwa] is over pressure to the greater extent than the Barnett is you can pack more gases molecules per square mile in the Muskwa than you can in the Barnett to the tune of about a two X multiplier from our best Barnett to the Muskwa acreage over our 840,000-acre position.

So the bottom line is it's a really good quality rock and there's more of it at higher pressure than in Johnson County.

Thanks for that.

We'll go next to Joe Allman, JPMorgan.

Good morning, everybody. Mark, what do you think about the prospectivity of the Three Fork [Sanish] on your acreage and do you have any plans to test the Three Fork [Sanish]?

We have tested the Three Fork [Sanish] in a couple of wells in our Parshall area and a couple of our step out wells around Parshall. We recognize it is an additional reservoir potential in the area on our 320,000 net acre position.

But I'd say in the Parshall area itself we have not found it to be a quality reservoir and are not targeting it. It's kind of spotty in its distribution around the basin we believe. It's probably part of the same basin centered oil cell as the Bakken and so we will be exploring for it as we go forward on the remainder of our acreage.

Do you think, in your Parshall Field wells and Austin wells do you think you are getting contribution from the Three Fork [Sanish]?

I don't think we are. We have penetrated in the in a couple of places and as I said, the perocity development, particularly the permeability development in that particular zone is pretty spotty.

And I don't believe that it extends to any great extent 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.

Got you. I might have missed what you said, the tests that you've done outside of Parshall have they been more promising?

We are not going to comment on the [Sanish] potential in wells we drill outs of Parshall at this point. I think it's still too new to draw any conclusions and we would probably muddy the waters more than we would clear it up if we tried.

Got you. The strong well that you reported recently in the Austin area are you using the same techniques that you've always used, just a single, I think you've done a single lateral on 640s and using small tackers?

Yes, that's directionally correct, 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 the, in fact I think you put out something on the best wells completed in the Bakken. I think whatever we are doing it seems to be much better than most other companies up there in terms of initial rate and we think also in reserves.

Okay. And then the wells you're drilling outside of the core area are those on the border of Montreal and Burke County?

We are not going to divulge anything other than they are outside the core area right now because there is still additional acreage we may attempt to pick up.

Got you. Appreciate it. So that was my next question, you are buying some more acreage?

Yes.

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 then following that would be the Horn River basin growth?

Yes, if actually we had a chart in our February analyst conference that kind of showed 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 mix is going to be more toward liquids going forward.

Just another comment, when I brought this item up about the Barnett peaking in '09, people say, well, couldn't you go in and refrak or couldn't you drill on 15-acre spacing? We believe particularly in Johnson County the refraks are not likely to the work and so you are not going to get any big surge from that. And we also believe that drilling the wells on even more concentrated spacing is probably also not going to work.

So our view of the Barnett clearly in Johnson County is it's kind of a one time shot and until we get some new technology that we are not aware of is not necessarily going to be a second round there. We think that also applies to other parts of the core area.

That's helpful. Then lastly. Could you comment on the recent trends for drilling and completion costs and also comment on the availability of steel to develop your various programs?

Yes, Joe our costs have been fairly flat for the first half of '08 and we are starting to see a little bit of increase, it's through tubulars and fuel costs. That's basically it. That's in East Texas.

Rocky Mountains we are starting to see a little bit of increase in stimulation costs because the sand shortage there. Fort Worth area, the costs are pretty flat. Rigs 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 costs increase slightly here in the second half giving up some of those gains.

Again, on the tubular question, the tubular situation is about as tight as we've seen it in the last 20 or 30 years. We are literally in a mode on many of our wells and kind of just in time delivery to get the pipeline there to the well site. 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 to it remain tight, but not to be a pinch point where in a macro sense people are laying down rigs because they can't get the pipe. But we are not an expect on the tubular market.

Very helpful. Thank you.

We'll go next to Brian Singer, Goldman Sachs.

Thank you, good morning.

Good morning, Brian.

I want to do 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 at 2009 and more importantly 2010 and '11?

Yes. In terms of, and I know people would love to hear a lot more details on the oil play or have some other peer company confirming the oil play. As we mentioned, this is the one play where we pretty well locked up the 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 our analyst call and attempted to gain an acreage position and then pulled out after several months when they realized it would be very difficult for them to get any sizeable acreage position. So 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 the 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 will look at horizontal wells, we will look at vertical here since there is a track record of successful vertical wells.

But the problem we have is we can't get any sustained tests 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 have to wait until we get our plant built before we can really do much with these things.

I would just say the reason we are so excited about the play is that we continue to confirm that the oil in plays per square mile there is huge. Over 30 million barrels per square mile in some of that area and if you just get a small percentage of that, 2% or so you can come up with some pretty big numbers. But everybody is just going to have to be patient until year end or first quarter before we can provide any more specific details on it.

Can you just refresh us from your analyst meeting whether and I apologize for not recalling this. Whether it's just for now an oil in plays call or is there any even initial production rate data or initial decline data to speak of that gives you the confidence?

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

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

Most of them have been constrained. Most all of them basically have been constrained. With just intermittent production at best. But the very limited production data we have still confirms those kind of estimates.

But we are really suffering from a porosity of data pause is the of data until we get more infrastructure up here. And I will know when we presented this to everybody in February we said this is a 2009 event, it's not a 2008 event. So that's kind of our information that we can provide to you at this time I recollect.

That's great. Separately on the higher CapEx which seems to be on the increase leasing can you provide nor color on whether that represents acreage acquisitions in plays you discussed versus bulking up on new resource play? I think you mentioned you saw sharp increases in leasing costs so should we interpret that that represent Bakken, Hainesville, and Marcellus, I'm don't know if there is any color you can provide there?

In the Marcellus specifically we are 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 is that every E&P company wants to have a stable full of resource plays and so the acreage costs even for first movers on potential resource plays the acreage costs have gone up dramatically.

And so what we are doing is we are trying to be, to not chase the hot plays per se, but even the front end costs in some plays that we thought would be kind of undercover plays it's costing us more to get acreage there than we would have thought. A big majority of that money that we are talking about is in play that is we really haven't currently disclosed. We will be evaluating over the next year or two.

Great. Great. Thank you.

We will go next to David Tameron, Wachovia.

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

I'm pretty darn confident in the number. I don't 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 of that growth really are, we've got a sustained drilling program in the vernal area there basin would be one more year kind of the standard program.

The Bakken is currently outperforming the estimates that we provided in the February analyst 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 time frame as well as the rest of our plays.

So the only absent from extraordinary events such as unavailability of rigs, unavailability of steel, some unusual collapse in hydrocarbon prices, I think we are pretty well set up for the production growth for 2009. And really we 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.

And we sit back and say, if we just to look at the inventory we have in hand today even if we never added another resource play, we are 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 go out there and literally spend billions and billions of dollars on chasing some of these assets and so it's extremely unlikely that we will do that either this year or 2009.

Okay. Thanks. And then along those lines so you do obviously net debt to cap targeted sub 10%, any more commentary on what your thoughts are with cash balance that you're going to be building or are you projecting around a breakeven cash CapEx over the next couple of years?

I mean our preliminary thoughts for 2009 would be if you just, if you just took today's NYMEX prices for 2009 that we probably ends up with a 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 will continue to have the best ROCEs in the peer group and lowest unit cost as well as the lowest debt.

And then 2009, '10 debt adjusted growth production per share we may not be in first place in that, but I believe we will be in the top quartile every single year. And frankly we just don't see the need to, for if we are 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'd much rather have an extremely low debt and high ROCEs and be growing the company at nominally 14, 15% per year.

Okay. Refreshing view. Last comment. A lot of talk on the sell-side and by side as prices trend down on the natural gas side have collapsed over the last month. What do you believe the marginal cost of supply is right now in the US, kind of for the natural gas standpoint?

Well in the Gulf of Mexico it's probably currently $8 to $9, I would guess with the way marine equipment costs have gone up and in the onshore areas you are probably looking at 7.50, something like that, maybe $8. So the issue I think on, comment on gas prices a month or so ago they were $13, $13.50.

And personally I was wondering why they were going up so much. Because I couldn't see any fundamental supply demand situation that would drive them up towards 13, $14.

So my sense is they were just over priced a month ago and now they are back in my mind the price of $10, maybe $9 is probably a more rational price assuming the kind of a normal winter for this coming winter. So I view the collapse as a collapse from a price that was more an emotional price there at 13.50.

Alright. Thanks, nice color.

We will go next to David Heikkinen with Tudor.

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

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 is -- are in areas that some other companies have deemed that would be prospective. And like I say we just have no firsthand results ourselves about the Hainesville and so we just, and I know it's kind of a big argument going on in the industry, is the Hainesville a really big play or is it a localized play or is it a play at all. And we just would as soon stay out of that whole kind of argument until we get some data on our own.

And if we look at your existing production in those fields, you have some legacy fields between[Macadocious] and [Macadish]. If you just take that line, is that the majority of the acreage you're talking about? Is it mostly held anything or is it new leasing?

The majority, the vast majority of the 100,000 acres is just legacy acreage. But maybe about half our acreage is kind of in that area that you just described there.

I've driven that road 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 not even want to get into the direction of the extension areas you're still leasing, but we thought of a crescent sort of as the Bakken has developed. How do you think about where we should think about that extension area heading?

We would like to leave that as murky as possible regarding the just geometry of that extension. And frankly the geometry of the core area. We think we understand now, primarily what the boundaries are on the high quality core area. But as we said before 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 the rind area particularly will expand and we would rather not comment on what directions that might go.

Okay. And everybody is keeping their eye on Barnett oil and it backs like the majority of your permits are more in Montague County as opposed to Clay and Archer. Is that 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?

I'd say that the -- there is a similarity between Montague County which is the farthest east and then you go to Clay and then you go to west, go to Archer as you move west. There's a similarity to the Barnett gas in that as you move out of Montague county going west the zone gets thinner and you loss the viola which insulates you from the Ellen Berg of water.

So out of reserve estimates that we've kind of put out so far the biggest single contributor to that by far is Montague County. And so we've done some drilling out to the west but like I say more wells in Montague then in the west and that's whereas this oil play develops I think Montague will be the name you're hearing a lot more frequently than Archer and Clay.

That's helpful. Then on the balance sheet side. Do you guys think at all about how would you you think about share repurchase programs or where that would fit into your capital allocation process?

Yes, I mean -- allocation process I recollect the stock price decline we've kind of puts that back on the table with some of that we have in our arsenal. I'd say that at this point it's still more likely that we will run the company with low debt as opposed to attempting to kind of lead anyone to belief that we are going to be jumping into a big share repurchase program in the future.

Our preference would be to just run the company at very low debt, 2009, '10, '11, and to have kind of a balanced program cash flow versus CapEx post-2008. But depending on how the stock reacts and whether it corrects further in a negative direction we will certainly have the fire power to do something about it in terms of repurchases. We will just be watching it every day.

Just one additional thing. On the Barnett gas peaking in 2009, make sure we are all measuring from the same point. What is current Barnett gas production as you're measuring it to compare versus the five Bcf per day?

If you take a current June, July number we think it's something in the range of probably 4.2 right now. We think it will peak at about five, something like that.

And how much liquids? Are you including liquids in that or is that just straight gas?

It's just gas really, yes.

Okay. Thanks a lot, guys.

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

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

Yes, we don't want to get into specifics on that because and the main reason we don't is if we give a specific volume now then somebody will ask for it next quarter and if it happens to be 500 barrels per day lower than what somebody has projected it at then is something will write a cell-side write up on Bakken less than expected for third quarter.

So we just don't want to -- kind of like the Barnett we will give an annual goal and we provided an annual goal in the February analyst conference for this year for the Bakken and what we can tell you is, we are going to beat that number but we are not going to give specifics.

Great. Thanks. The other question I have is on the Marcellus, besides infrastructure issues and permitting and whatnot. Is there anything in terms of the geology or consistency of results that makes you more negative or more measured on the play?

Yes, we are a little more measured on the play than perhaps some other that is you are reading out there in that the thickness is quite a bitless than we see and obviously than we see in the Barnett. And it's a good quality rock. And it's well distributed over broad areas.

But as I said the thickness is an issue and in some cases pressure is an issue. Probably the most unknown risk factor that we and others are dealing with right now is frak efficacy, frak barrier containment in the Marcellus itself. The kind of results that we are hearing about in parts of Pennsylvania that are showing three to four Bcf a well, that really does not comport well with the kind of IPs that we are seeing in the rest of the play and really the way we model the play is a one or two Bcf a well kind of play. Particularly if you are looking at big program average it's really, really difficult to average three to four Bcf a well over a whole play.

Okay. In terms of that fraction efficacy are you is it the lack of a frak barrier in certain areas that you can't contain the frak or is there some imbedded shale that's under fearing with fraks? Any more color you can you provide in that possibly?

That's as specific as I would care to get. There are differences in the frak barriers throughout the play from geographic area to geographic area and that's I think the biggest unknown in the play right now amongst the operators.

Thanks for that color.

We'll go next to Leo Marioni, RBC.

Yes. Thanks, the question on the Bakken here, you guys talked about some peak rates in your press release from three new wells, 3.7, 1.9 and 3.2 million barrels per day here. Just trying to get a sense of what the term is on those rates. Are those one day peak rates or how are you measuring that here?

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

Yes.

Okay. Yes, you quoted some numbers there I'm not sure where those numbers came from, 3.7 -- that's thousand barrels per day, okay. Yes, those are just initial rates. Those are probably the first three or 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 or anything like that.

But what they do, if you kind of compare those initial rates with what we've seen from some of the other peer company's up there you will find that they are considerably higher and in many cases double, triple, five times initial rates from some of these other companies. And it just shows that the, there is a correlation between the initial rates and the ultimate reserves on wells, the higher the initial rate, the more reserves you are going to get out of the well.

Okay. Do you guys have enough data in the play for what you expect in your first year annual decline rates?

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 do call my [Moira] later on we will dig it out but the answer is, yes, we have a pretty tight curve on that.

Okay. Jumping over to the [Utla] play you guys mention stood 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?

Again, British Columbia?

Yes.

They have been producing without restriction. Like I say, they've only been on about two weeks. We really don't want to give any flow rates on them other than to say we are 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.

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 are going to peak in 2009? Are you guys going to be a little bit more legs in there?

Well, in terms of the Barnett gas volumes, yes, we expect they will probably peak and then plateau in 2010 and '11 and then we expect to have the oil volumes layered in but generally we think we will be similar to the industry in the Barnett gas portion.

Okay. Thanks a lot.

We'll go next to Gil Yang, Citi.

Hi, a couple 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 sensibility to earthquakes?

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.

And, Loren, you commented the [Muskwa] is over pressured, did I hear you right that you said it's two times pressured or overall between all the things it's twice as good? I recollect that's an overall twice as good twice as much gas in play per square mile.

No, that's an overall. Twice as much gas in place, per square mile.

What is the core pressure in -- pour pressure grading in [Muskwa]?

It ranges from the east to west side of the basin but all of that basin is over pressured by gradient than is the Barnett. Barnett might be in the 4.8 to 5.2 range and the [Muskwa] is substantially higher than that.

Like in, .7 range?

I'd rather not give an actual number for that as it does vary across the basin and that is kind of one of the controlling parameters for gas plays.

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

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

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

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

Now in 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 that's within the realm of accuracy but I don't recall ever saying 3.2.

Well, okay. So you are seeing no major change there?

Yes. We really don't think there's a major change. I think as everybody notice the comps there in August are going to be really tough to beat 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 storage injection reports in my mind we've had one disappointingly bearish report which was the 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 other are over, some under but it doesn't indicate to me that we've got this massive over supply situation. I think it's just more psychology right now that oil prices are falling a bit.

People know that last August was so hot that this August it will be really doubtful that it's as hot. So push the sell button for gas futures is what some people appear to be saying but I don't think the fundamentals are particularly weak at all really.

Given your generally bullish outlook can you just maybe you said this early and I missed it can you give some rationalization for why you've taken your hedges for '09 in hedges, your hedges, above '08?

We have 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. We view that as a kind of a reasonable price.

We are not in the camp that that says gas next year is going to be $12, we have $10, $9, 9.50 is a more reasonable gas price unless you have a really, really cold winter. So that's, that's why we've locked in some of it is we've locked it in at what we think is a rational gas price for next year.

Thank you very much.

Okay.

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

Actually my questions have been answered. Thanks.

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

Yes, a couple of questions on the Marcellus. I didn't catch your acreage position there.

220,000 net acres.

And the 1.5 to two Bcf per well -- is that, do you think that you can get higher recoveries in certain areas? I know other operators have talked about three to four B's a well in Northeast Pennsylvania and southwest Pennsylvania.

I mean a 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 a well, it's less than that.

And so when you are dealing with the Marcellus which is less geo-pressured and much thinner it just doesn't make good reservoir engineering sense that you are going to get recoveries of four Bcf a well when it hasn't been an average in Johnson County.

So we just think that that number is probably a number that we believe is unrealistic. And then you clearly do have a problem with containing the fraks within that relatively thin zone. You have more of a problem in the Marcellus than you do in the Barnett. And so that's another reason for caution.

Okay. That's helpful. Thank you.

We have no further questions in the queue at this time. I will turn the conference back over to Mr. Papa for additional or closing remarks.

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

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