EOG Resources Inc (EOG) 2009 Q2 法說會逐字稿

Good day, everyone and welcome to the EOG Resources' second-quarter 2009 earnings results conference call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Mr. Papa, please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second-quarter 2009 earnings and operational results. Also included was guidance for the third quarter and full year 2009.

This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call.

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

The SEC currently permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates on this conference call and webcast, including those for the Barnett Shale, North Dakota Bakken, Horn River and Haynesville, may include other categories of reserves. We incorporate by reference the cautionary note to US investors that appears at the bottom of our press release and investor relations page of our website. An updated investor relations presentation and statistics were posted to our website last night.

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.

I will begin by reviewing our second-quarter net income available to common stockholders and discretionary cash flow and then I will review some operational highlights. Tim Driggers will provide some financial details and then I will provide some macro comments and concluding remarks.

As outlined in our press release, for the second quarter, EOG reported a net loss available to common stockholders of $16.7 million, or $0.07 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impacts as outlined in the press release, EOG's second-quarter adjusted net income available to common stockholders was $183.6 million, or $0.73 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 $787.4 million.

Our second-quarter production and costs were in line or better than the midpoint of our previously issued guidance and we expect that trend to continue for the second half of the year. We increased our 2009 full-year total Company liquids production growth goal from 22% to 25% while maintaining a goal of 20% year-over-year liquids growth in 2010.

Our overall 2009 production growth target of 5.5% is still intact, but I will caution investors that this assumes we don't curtail any North American gas in the second half because of market storage issues. As you know, EOG is organically evolving toward a more balanced 50/50 North American liquids to natural gas ratio via our horizontal resource plays and I'll format my North American operational discussion into two categories.

I will first discuss our major North American liquids plays and then I will discuss our gas assets. I will start with the Barnett combo liquids play. This play continues to gain momentum and the pace of development and progress of our learning curve in Montague County is analogous to when our Johnson County Barnett project lifted off from the launchpad a few years ago.

We started the year with three rigs in the combo and expect to end the year with a seven-rig program. Our press release highlighted initial rates on [audible] wells we completed during the quarter. Recent rail costs are running less than $3 million and typical per well initial rates are between 200 and 500 barrels of oil per day with 1 million to 2 million cubic feet a day of rich gas that contains a lot of natural gas liquids. Our working interests range from 89% to 100%. Most importantly, these wells generate a 30% to 60% direct after-tax rate of return using current oil, gas and NGL prices. As in Johnson County, we believe that per well reserves are improving as we gain experience fracture-treating this rock, but it is too early to quantify this improvement. We expect to drill 100 to 120 combo wells this year.

In early July, we closed on a tactical Montague/Cooke County acquisition from a private company for stock and cash whereby we acquired 2000 barrels of the equivalent oil per day of net production and 25,000 net unproved acres that were intertwined with our existing acreage. We now have 194,000 acres in Montague and Cooke Counties with an additional 144,000 acres farther west in Clay and Archer Counties where the Barnett is thinner.

For now, we are concentrating only in Montague and Cooke Counties where the Barnett is very thick and where we have an overwhelmingly dominant acreage position, i.e., this play is ours. We are now in a development mode and our situation is reminiscent of a similar period a few years ago in Johnson County. If you allow me to phrase our current combo status in terms NASA might use, I will say that our combo rocket has left the launchpad and is approaching orbital velocity with the goal of achieving orbit alongside our Johnson County satellite.

Okay, now back to Earth and the North Dakota Bakken. You will recall we drastically slowed down our Bakken activity for the first five months of this year because of low oil prices and high location differentials. In late spring, we restarted our activity in both the Core and Lite areas. To refresh your memory, EOG is the overwhelmingly dominant acreage holder in the Core area, which is the sweetest spot of the entire Bakken and where we hold about 100,000 net acres. We also hold about 400,000 net acres in the Bakken Lite area, which has less pressure and lower per well reserves than the Core.

During the past several months, we have completed 25 wells in the Core with gross IPs ranging between 1100 and 1800 barrels of oil per day at an average 72% working interest. The typical well in the Core area currently costs $4.1 million completed and this yields a direct after-tax reinvestment rate of return in excess of 100% at today's oil prices. We will continue to develop the Core with two rigs during the second half of the year and expect continued excellent results. The Core portion of the Bakken is now pretty well-defined and I think most investors are aware that EOG dominates the Core acreage.

What about our 400,000 net acres in the Bakken Lite? This is the portion of our Bakken acreage where we are now turning our attention. We recently completed two wells in this area. The Sidonia 1-6H and the Ross 7-17H wells recently IPed at 700 and 500 barrels of oil per day respectively. And we believe each well will produce 250,000 net barrels of oil for a $4.4 million current completed well cost, yielding a 30% direct after-tax reinvestment rate of return at today's oil prices. We now have 16 successful tests in the Bakken Lite area and our confidence is increasing that a significant portion of our 400,000 acres will be productive.

To summarize the Bakken, the Core is a given. Investors should now keep their eyes on our Bakken Lite activity. On the previous quarter's call, I outlined our plans to utilize railcars to transport our Bakken crude to Oklahoma and to also lay a wet gas pipeline to move our gas and natural gas liquids to the Chicago market. Both of these projects are on schedule. We still expect our rail car projects to be operational by February 2010 and we expect our gas and natural gas liquids line to be in service by the fourth quarter of this year.

I will close our North American oil discussion with an update on our horizontal Manitoba play in Waskada. We have now completed 13 wells this year and the typical average 30-day production rates are 200 barrels of oil per day per well for an $800,000, that is US dollar, well cost, which is slightly better than expected. So this project is performing just as we told you last quarter. It is a high reinvestment rate of return investment opportunity, roughly 100% reinvestment rate of return and we only wish it was bigger than the estimated 25 million net barrels of oil.

Now I will turn to the North American gas side of the ledger. I am aware that we we've piqued a lot of investors' curiosity regarding the shift in our mix toward oil, but let me assure you we are making that shift because of the unique early mover opportunities currently available to us for horizontal oil resource plays and not because we are running away from North American gas.

In fact, we are bullish regarding the 2010 and 2011 North American gas macro, as I will discuss in a few minutes. We have a powerful arsenal of gas assets, both horizontal and vertical, and I will now address seven of these gas plays.

The first gas play I will discuss is the Haynesville. During the past quarter, we completed five additional Haynesville wells in DeSoto Parish, Louisiana. Individual well rates were outlined in our press release. The key point is that all five wells had IPs between 14 million and 16 million cubic feet per day. I will also note these wells were at pipeline-restricted rates. Each had the capability to produce at higher IP numbers.

EOG has not sought any headlines regarding the Haynesville, but our data indicates that of the larger companies, we and one other operator have the best track record in making successful Haynesville wells by a wide margin. Our past IR presentations have shown welcome performance comparisons to peers for the Bakken and Barnett gas and we have a similar slide for the Horn River. Simply put, these comparisons have shown that EOG consistently makes wells with higher IP rates and consequently likely higher reserves than our peers. In the updated IR presentation posted yesterday afternoon on our website, we have now included a chart using public data of EOG's Haynesville wells compared to peers and the results will likely surprise you.

The chart shows that 90%, 90% of EOG's Haynesville wells have IP rates greater than 10 million cubic feet per day, the highest percentage among the peers, and only 10% of our wells have IP rates of less than 7 million cubic feet per day, the best overall performance of the peers. We are currently running four rigs in the play and expect to average 10 Haynesville rigs in 2010.

Also in North Louisiana, we recently completed our first horizontal Cotton Valley well in the Driscoll field in Bienville Parish. The Davis Brothers' 24#3H IPed at 15.2 million cubic feet per day. We have a 71% working interest in this well and have multiple offsets in this emerging play. This play, along with the Haynesville, will be big 2010 gas volume drivers for us.

Our 2009 Barnett gas program is yielding the expected results, but at a lower level of activity than last year. We're currently running seven rigs in the gas play compared to 20 rigs at this time last year. We continue to be confident about our 2010 to 2012 Barnett total gas production growth from both the combo and gas counties. The charge is included in our IR presentation showing that our year-end 2012 total Barnett production is expected to be over 700 million cubic feet per day equivalents compared to today's 480 million cubic feet per day equivalents.

In the British Columbia Horn River basin, we are in the process of fracture-treating seven wells that we drilled earlier this year and we will have some flow test results on next quarter's call. We are working with the BC provincial government regarding some royalty allowances to make this play competitive with other North American horizontal gas shales and we are pleased the province is taking proactive steps to enhance the economics of this very large asset.

In the Pennsylvania Marcellus play, we have now tested multiple areas on our 240,000 net acre leasehold position. We are generating wells with net reserves of 2.4 to 3.1 Bcf and we expect to commence our first Marcellus gas sales in the fourth quarter of this year once pipeline hookups are completed. We have increased from one to two rigs in this play and will be moving into development mode by year-end. Our 240,000 acres can be divided into two blocks. One 66,000 acre block is located near the Pennsylvania, New York State border while the other 174,000 acre block is where we have a JV with Seneca Resources.

In addition to our horizontal gas portfolio, we have also had positive results in two vertical North American gas plays. In Mississippi, we discovered a new prolific Cotton Valley gas field. The first three wells, the Williams 9-12, Ramsay Williams 9-7 and Shirley 9-14, are currently producing at 10 million, 7 million and 5 million cubic feet per day with 250, 175 and 125 barrels of oil per day respectively.

We logged a fourth well that has in excess of 200 net feet of pay and we will be completing it shortly. We have 100% working interest in these wells. The estimated net reserves for this field is 100 Bcf and 2.5 million barrels of oil. We anticipate drilling 12 additional wells here over the next year.

Also, last quarter, I mentioned we captured 800 net Bcf in the East Texas Travis Peak play. We have continued our activity in this area and two recent wells typical of the play are the [MacFadden] #1 and the [Morrow] #1. These wells IPed at 3.1 million and 2.3 million cubic feet per day gross respectively. We have 45% working interest in each of these wells.

Regarding our activities outside North America, we made a successful oil discovery in the shallow waters of the UK East Irish Sea this past quarter. The well encountered 112 feet of high-quality pay with estimated reserves of 11 million barrels of oil net. We expect this field to commence sales in early 2012 at an estimated initial rate of 16,000 barrels of oil per day net. This project has very good economics and should qualify for the UK small field allowance credits, which would provide favorable tax treatment for this block. We plan to drill two similar structures beginning later this year.

In China, we will continue operating a one-rig horizontal program through 2010. We will have test results from our first well by year-end, but I expect it will be mid-2010 before we can declare whether this project is successful or not. In Trinidad, we don't have any drilling activity planned for 2009, but we will drill one test of deeper horizons under our existing fields in mid-2010. I will now turn it over to Tim Driggers to discuss CapEx and capital structure.

For the second quarter, total exploration and development expenditures were $645 million. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $87 million. Capitalized interest for the quarter was $13 million. We issued a $900 million, 10-year bond in May to term out commercial paper increasing our outstanding debt balance and go-forward interest expense. At June 30, 2009, total debt outstanding was $2.8 billion and the debt to total capitalization ratio was 23%. At June 30, we had $707 million of cash, giving us non-GAAP net debt of $2.1 billion for a net debt to total cap ratio of 18%.

The effective tax rate for the second quarter was 29%.

Yesterday, we included in the press release a table with third-quarter and full-year 2009 guidance. The guidance indicates a total capital expenditure budget of $3.3 billion, including $140 million of acquisitions. For the full year 2009, the guidance indicates an effective tax rate of greater than 35%. We have also provided an estimated range of the dollar amount of current taxes that will be recorded during the third quarter and the full year. Now I will turn it back to Mark to discuss the macro environment, our hedge position and concluding remarks.

Thanks, Tim. Our view of the North American gas and oil markets is consistent with our previous earnings call, except that we have become more bullish regarding 2010 and 2011 gas prices. We still expect North American gas prices to remain quite low through year-end. As you know, we have historically devoted a lot of work to developing domestic gas supply models and we think our current model is the most granular and best we have ever built. It is telling us that December 2009 domestic production will be 4.8 Bcf a day lower than year-end 2008 and this deficit will deepen further throughout 2010.

When added to the Canadian supply drop of at least 0.8 Bcf a day, we expect the gas market to turn sometime early in 2010, almost regardless of what happens to LNG imports. Everybody seems to be focusing on the supply growth from new horizontal plays, but the 800 pound gorilla in the room is Texas vertical gas production. This represents the largest single block of production in the US, 16.3 Bcf a day in December '08 and the rig count here has fallen from 450 rigs in January 2008 to 145 rigs today.

Our model shows production from this large segment of domestic production will fall from 16.3 Bcf a day at year-end '08 to 13.2 Bcf a day by year-end '09 and then to 11.6 Bcf a day by year-end 2010, down 4.7 Bcf a day over two years. In my opinion, this is the most important well population that people should be focusing on if they want to understand what is going to happen to gas supply over the next 24 months.

Our financial hedge position is shown in our 10-Q and it is consistent with our macro view. About 47% of our July through December North American 2009 gas is financially hedged at $9.03 and we have only a small amount of first-half 2010 gas hedged at $10.27.

Based on our macro view, we will likely remain primarily unhedged for 2010. Our oil view is that 2009-'10 NYMEX is reasonably reflective of what oil prices will likely be. We are long-term bullish regarding oil and have no oil hedges.

Now let me summarize. In my opinion, there are four important points to take away from this call. First, both of our big oil plays -- the Barnett combo and the Bakken -- have upside from current levels and we expect to generate impressive liquids growth for many years to come from these and other plays that we are working.

Second, although we have kept a low profile in the Haynesville, our wells to date are the most productive in the industry and we plan to significantly increase drilling activity next year.

Third, our arsenal of North American gas plays is large and we are going to closely watch the gas macro over the next few months as we formulate our 2010 gas drilling strategy. A

And fourth, we will accomplish the above while maintaining the lowest net debt to cap ratio in the peer group and one of the lowest unit cost structures. Thanks for listening and now we will go to Q&A.

(Operator Instructions). Tom Gardner, Simmons & Co.

Thank you, operator. Good morning, everyone. Mark, I am intrigued by your gas macro comments. You mentioned you are encouraged about 2010 and 2011. Do I read from that that, given the steep inventories that industry appears to have, and their ability to grow production, you think we are as poised for a rebalancing and an overshooting going from a short position to a long position in 2012? And is there any thoughts on how industry might smooth out the highs and lows, so to speak, with respect to supply and demand long term?

Yes, I mean that is certainly a possibility. We just haven't forecast past 2011. As you know, trying to forecast the gas market, even more than 12 months out, is a hazardous business and we haven't focused at all on the demand side. We don't purport to be demand experts, but what we have done is really sharpened our pencil on the supply side. And what we do see is that the next 12 to 18 months is, we believe, pretty well already cast in stone really kind of regardless of what happens to the go-forward rig count. And we think the situation is that production is going to be falling quite a bit.

You may recall on our last earnings call -- pretty much exactly what we said is we said that we would have endure another two to three EIA 914 reports and we expect that either the April or the May EIA report to be the first break of a significant decline. And indeed that is pretty much exactly what has happened. So we have got a fair degree of confidence in our model at this point and the model is showing that we are now on the slippery slope.

Unfortunately, what is going to happen with the model is we think the June data, which will be the next data point to come out, will be pretty accurate, but then the subsequent two or three months may well be clouded by storage induced shut-ins or curtailments. So we are not going to have that much accurate data, but we think that it is pretty well inevitable that there is going to be a significant decline over the next 12 months in domestic production.

Jumping over to your comments on taxing in British Columbia, it is my understanding that the government has rolled out an energy stimulus package to attract more investment there. To what degree will EOG be able to take advantage of that both in Horn River and elsewhere and what difference does that make with respect to the well economics?

Yes, I understand that just in the last day or two the BC government has kind of announced a package. We have been talking to the BC government for the past few months and we feel that we have got something that is essentially in place in relationship to our Horn River situation. And we feel it is quite a significant royalty stimulus. I don't want to go into a lot of details, but what I will say is the BC government has recognized that the Horn River gas is competing with the Haynesville and the Barnett and the Fayetteville gas and they have taken very proactive steps and we are very pleased with the situation as it has turned out in relationship to the government royalties and EOG's position up there.

Lower royalties and tax is always good news. One last question on your Bakken operation opportunity, some competitors are encouraged by the prospects of successfully drilling stacked laterals in the middle and the lower. Just wanted to get your sense on whether that is going to work and what your opportunity set is at EOG?

Yes, let me -- here is kind of the way investors need to kind of think about our Bakken situation. Most of what we have discussed and most of the reserves that we've discussed relating to our Bakken so far really are relating to our 100,000 acres in the Core. And 400,000 acres in the Lite we are quite optimistic about and there are going to be lower per well reserves, but that is the area that I think people -- we will be focusing on. We still have a lot of drilling to do in the Core, but the Lite is where we think the significant amount of reserve upside exists for EOG. And that is the area where they kind of keep your eye on that ball for EOG.

Now in addition to that, the Three Forks/Sanish also exist on a, we believe, a significant portion of both our Lite and our Core acreage and we will be doing some testing over the next six to 12 months on that. So you have got two pretty good potential upsides here. One is just on the straight Bakken itself on the Lite area and then you have got on the Three Forks/Sanish.

It is our belief that this entire Bakken area, not just EOG's acreage, but other people's acreage is going to turn out to be a very large oil accumulation over quite a large area. So we're pretty excited about the play just if you look at it from 30,000 feet.

Thank you. I will let someone else hop on. I appreciate it, Mark.

Brian Singer, Goldman Sachs.

Thank you, good morning. Noticed you are projecting a sharp ramp-up in your legacy Barnett gas play of about I think 100 million or 100 million, 120 million a day by May 2010 before resuming a decline. And I wondered if you could characterize how much of that is based on drilled and uncompleted wells. What is based on increased drilling activity and potential price sensitivity around that?

Yes, we have quite a number of wells awaiting on completion and we are going to be ramping that up here the first part of 2010. And we are going to continue to drill as well. As far as just having a percentage of each, we might guess two-thirds of that ramp-up is associated with wells waiting on completion because we are very pleased with our return with current gas prices and our legacy Barnett play. The rates of return are somewhere between 30% and 50% for those wells because we continue to optimize the completions.

And so when you think about the rig count, where do you see your rig count in the Barnett going relative to where it is at now and where it has come down from?

Currently, we are running about 12 rigs in all the Fort Worth Barnett and we are thinking now to ramp up maybe to 15 rigs.

Thanks. And you mentioned earlier, Mark, improvements in some of the results coming out of the Barnett combo plate. I was wondering if you could characterize those in more detail and if there is any disproportionate improvements on the gas versus liquids versus -- or gas versus oil versus NGL side?

Yes. Yes, we really -- if you look at it kind of similar to Johnson County, you kind of say some of the early reserves we reported per well in Johnson County and then you track what we reported maybe a year after we first got into the play and then tracked reserves we reported maybe two years after we got in the play, it is pretty much a steady improvement in reserves. And then after two or three years, we kind of plateaued out and we said, well, they can get better forever. That is pretty much the same track we are seeing. In fact, the initial reserves we first reported in the Barnett combo were 152,000 barrels of oil per well equivalents and then the number that is on our IR presentation now is 210,000 and we are pretty sure that the number we are sitting at right now is higher than that, but we don't want to give you a number. We just have to get some more data. And so it is pretty analogous to what is going on in Johnson County and the proportion of the improvement is pretty much split equally between the oil, the NGLs and the gas. So whatever that improvement turns out to be, a portion of it is going to be oil, a portion NGLs and a portion gas.

But the good news is it is pretty much like we thought. The area is so rich in terms of what one square mile contains in terms of oil equivalents that, in some ways, it is kind of like a mining process. Just give your technology a little bit of time and you are going to find out ways to recover more of those hydrocarbons in place and that is what we are finding.

And that is why we've continued to be very enthused by this combo play. And the good thing about it is is that we totally dominate the acreage position in that play. And the acquisition that we made was essentially a tactical add-on acquisition from a private company of some acreage that was really just intertwined with our acreage. It just helped us even more so dominate the play.

Thanks. Are you seeing any improvements on the cost front or can you characterize those oil assets in the Barnett combo specifically?

Yes, we are down from about -- I think last quarter or so, we were quoting maybe $3.2 million or $3.1 million well cost and I think we are down now to about $3.0 million. So we are seeing a little bit of improvement there on the cost side.

Thanks so much.

Joe Allman, JPMorgan.

Thank you. Good morning, everybody. Hey, Mark, could you talk about activity and results in your acreage position in the East Texas Haynesville, the Granite Wash and the Eagle Ford Shale?

Yes. Well, in the Haynesville, we have got about 116,000 acres and from what we have seen, we believe that essentially all 116,000 acres is good, quite good and as we said, we are going to be ramping up significantly and average about a 10-rig program next year. So one of our big gas growth drivers next year clearly is going to be the Haynesville production. And we were able to kind of get started quite quickly there and run quite well.

In the Granite Wash, we really just have a very minimal acreage position there, so we are not going to be a big player in the Granite Wash play if it really develops into a big play. And in the Eagle Ford, we have an acreage position there, but until we get some well results, we really don't have anything to talk about at this time.

Okay. And then specifically on the East Texas Haynesville, I know like that Gammage well, I don't think you have disclosed that. Can you give some color on East Texas Haynesville results?

Yes. All we are going to do at this time is just acknowledge that there is a Gammage well and let you know that we are holding those results confidential.

Okay. That's helpful. And then Mississippi, that Cotton Valley play, where is that specifically and what kind of acreage position you have and costs and EURs?

That field is the Mechanicsburg Field, that's what it is called over Mississippi. And in terms of -- on the cost side, we are looking at well costs of about $3.5 million, the complete well costs for those wells. And we are looking at really extremely good wells. We're looking at wells that are in the neighborhood of about almost 5 Bcf net EUR per well. The net effect of this is great rate of return and great finding costs.

At what kind of acreage position?

Yes, the acreage is good enough for about 100 net Bcf, so it is not of this resource play scale, but it is just a nice add-on. We added that in the Travis Peak plays into the earnings call here just to let you know that there are still some vertical plays that are still yielding pretty whizbang economics for us here.

Great. And then lastly, how about in the Marcellus Shale, what kind of well costs are you seeing there in the Marcellus?

They are running anywhere -- we think once we get our program basis, they are going to run between $3.5 million and $4 million for roughly between a 2.5 and 3.5 Bcf well and we haven't talked too much about IPs. We have had IPs on some of our wells as high as 6 million a day, but that is -- the IPs are a little bit misleading and they are really not stabilized rates or anything there.

So our read is that the Marcellus is going to look pretty good, but we still think, in aggregate, if you look at this play on a macro basis, it is going to be a pretty slow volume contributor to the macro North American picture just because of the pipeline logistics and the ability to really access a lot of that area in a rapid manner. It is not going to be a fast ramp-up. I think it has gotten a lot of headlines and it is going to be a nice play, but it is really a 2012 through 2018 kind of timeframe before it becomes a big player on the overall North American picture.

Okay, that's helpful. Thank you.

David Heikkinen, Tutor, Pickering, Holt.

Hi, thanks. It's actually Mike Jacobs for Dave. Just wondering in the Haynesville, how much of your acreage is, of the 116,000 acres, is in the DeSoto area?

In total, about 45% of our acreage is in Louisiana; the remainder in Texas. It is a nice significant block we have at DeSoto. I don't have an actual acreage count for you.

Okay. Can we assume that most of the 10 rigs are going to stay on the Louisiana side?

No, they will probably be split about 50/50 Louisiana/Texas.

Okay. And just wanted to follow up on your comments on the Eagle Ford, kind of recognizing that it is too easy -- too early to talk about specific results. But when we think about your acreage position, can you offer any specific color as to kind of where you are at and how that relates to the Garner well?

No, we really don't want to offer any color on Eagle Ford at this time. Not going to get much out of us there, Mike.

Okay. Maybe if I can squeeze in one more then. Just as you think about going to two rigs in the Marcellus on your northeast position versus the JV with Seneca, where do you plan to increase activity over the next few years?

Yes, we are probably going to be running one rig in each acreage block, so one rig will be running up there in the position that kind of is on the Pennsylvania side of kind of the Pennsylvania, New York border and then one will be running pretty steadily on the Seneca, the JV acreage we have with Seneca. And a lot of it is going to be dictated by really where we have and can get pipeline sales access. Because what we have done so far is we drilled a spread of acreage just to really assess -- is this 240,000 acres we have, is it really any good? And we have reached a decision, yes, we think it is all good and now we are basically saying, okay, let's start drilling for production. And so now we are basically going to have some production lines tied in by the end of the year and our drilling is going to be more dictated by, okay, let's drill where we can get wells connected to sales physically and actually start selling the gas in 2010.

Do you care to comment on where you think your acreage position is better?

Yes, it is good in both areas. We think that the acreage is probably slightly better up there near the New York border, but we still think it is certainly quite adequate on the Seneca acreage too. So it is just a slight shade better in one area.

Great. Thank you very much.

David Snow, Energy Equities Inc.

Yes, hi. Do you think the Cotton Valley horizontal is a kind of generic play or is it specific to the one -- I think you had mentioned Driscoll field. And is that the Taylor or what is the concept, if you could, on that?

Yes, it's a Cotton Valley sand play. We have got a lot of locations in this particular Driscoll field. Whether it is going to be a regional play that is going to turn out to be one that is a resource play, I am not sure we can extrapolate it that far at this point in time, David. But what we know is it gives us probably 30 or 40 locations at least that we can chase that we believe each of them is probably going to have an IP of 15 million a day or so. So it is going to give us a lot of volume impact and then we will just see what we can extrapolate from there.

Is that the Taylor sand?

I don't know if -- I don't think we would call it the Taylor sands.

Taylor is really a name that pertains more to the Texas side. It is lower Cotton Valley.

So this isn't analogous?

No, it is not.

Okay. And you can't really say whether this would be applicable to all the Cotton Valley?

Probably not. We would say not at this time, David.

Okay. Thank you very much.

Leo Mariani, RBC.

Hi, good morning here, guys. Could you folks comment on your well costs in Haynesville and what your pipeline takeaway situation is?

Yes on the pipeline takeaway, it is pretty good through 2010 and probably 2011 for us. There was a lot of noise early on just for the industry that the pipeline situation was quite tight. And so when we first looked at it, we went in with the kind of preconception that the pipeline situation was really going to be a restriction. But what we've sorted out is we have got plenty of room for EOG's pipeline volume capacity for a minimum of the next couple years. So we don't see a big problem there for us. As far as the well cost side, I will let Gary Thomas address that.

We have been -- for a new play, we have been drilling in Texas, Louisiana. We are not into program drilling and we are doing some experimenting. So our well cost is just less than $10 million, but like many of our other plays, we expect to get that down quite a lot.

Okay. With respect to your Core Bakken acreage, you guys are obviously doing more in 2009 than you are doing in your Lite area. Just curious as to your running room there. If I sort of flash forward to 2010, would we expect that to essentially flip-flop to try and get a sense of when you guys are going to run out of kind of primary spaced drilling in the Core Bakken?

We have got, what, another --?

For '09, we will be drilling about 60 wells or so in the Core area and probably 15 or 18 wells in the Bakken Lite for 2009. And of course, yes, they will flip-flop. We will be drilling more in the Bakken Lite.

I think we have got another -- at least 2010, we have got enough to drill in the Core area. As you get out to '11 and '12, we are going to have the Core pretty well drilled out. But we still have got a fair amount to go in the Core area.

But the one thing we have found so far is that the proper spacing, at least for the Core area as we would see it, is 640 acres. As you go into the Lite area, it looks to us like the proper spacing there is going to be 320 acres. So you take our 400,000 acres and 320-acre spacing, that is a whole bunch of wells if it all looks good. So that is what we don't know.

What we do know at this time is we are drilling 16 wells in the Lite area and it looks to us like it is pretty pervasive. At least we are drilling the 16 wells. You are averaging about 300,000 -- 250,000 barrels net reserves per well.

Okay. I guess kind of the question along the similar lines in your Barnett Shale gas play, just curious as to what your running room is in Johnson County. Do you guys have inventory to take you through the next couple of years? Are you starting to move kind of West and South out there as we look into '10 and '11?

Yes, we have drilled about half our wells in Johnson County, so we have got quite a lot of running room there yet.

Okay. Any sort of thoughts about the potential European shale gas plays out there on the potential horizon?

It is still on our target list, but we don't have anything we can talk about at this time. So really on the international venture right now, the only one where we are really trying to do a horizontal gas resource play is China really outside North America. And that one is most analogous to what we are doing in South Texas. And we think it will work technically, but we will have our first well result by the end of the year. But like we said on the call, it'd probably be mid-2010 before we really have an assessment, is it really working both commercially and technically or not.

Okay. And what is your sense of the gas market over there locally in China, like any sense of what type of prices you are seeing out there?

It is an insatiable gas market. They need a ton of gas and based on the gas prices that are out there right now and based on the well costs and the reserves we think we can find, we think our project will yield a good rate of return. I don't want to get into specifics on the gas price over there, but what we do know is the government has told us that as much gas as we find, they will take it all and then some.

Okay. Thanks, guys.

David Tameron, Wells Fargo.

Hi, good morning. Can you talk about up in the Bakken just your takeaway capacity and what the limits are? I know there is some transport coming on in 2010, but can you just talk about a snapshot of that situation?

Well, on the oil side currently, about half our oil goes on a pipeline, Enbridge pipeline there and ends up going East to a market hub, which is Clearbrook, Minnesota. And the rest of the oil ends up getting trucked out of there currently. And come February 2010, all the stuff that doesn't get on the pipeline is going -- we are going to rail car it out of there to Oklahoma. And right now, the -- well, right now, the tariffs for trucking are high, but they are not horrible. Last winter, those trucking tariffs were horrible and we expect this winter they might be horrible again. And so because we think we have such a large asset that is going to grow in production and because we think that the other companies are going to grow their production there and that the pipeline capacity is going to expand very slowly, it is our belief that we're going to have a significant amount of our oil long term that it is going to be rail car-ed out of there. So we believe EOG is going to have a permanent fix for the oil issue out of there affective in February. Whereas other companies are going to maybe have a long-term issue there.

The other issue that you have there is even if you get your oil to Clearbrook, Minnesota, that is not a particularly attractive market hub in that the differential there that you suffer is Clearbrook, Minnesota is not a very pretty differential because you have a giant slug of Canadian oil that also comes in there. So your differential off WTI there is not a pretty differential. So we want to get our oil out of that market area into one that is a little more propitious.

Okay, so what I believe -- because Enbridge is full, right, so it sounds like as long as you have the rail and the trucking out, you won't have any constraints on your production growth until we get to 2010, is that correct?

Yes. We are gearing up to have zero logistical constraints, both on getting our gas and natural gas liquids and our crude oil out of there.

But what is your current netback up there average for the play, or differential, however you want to --?

The last quarter, I don't know, we are probably having about a -- what is it, maybe about a $9 differential on WTI roughly, and a pretty significant differential for the gas. I mean there is not a lot of gas, but the gas and NGL, pretty good (inaudible).

All right. Can you guys talk at all about Cleveland and that Atoka formation? Can you just give us more detail what you've done recently, if anything, and what your outlook is there?

Yes, for the Mid-Con we have got a pretty significant reserve in the Atoka formation, the horizontal Atoka up there. We have pretty much slowed down the drilling in that this year, just due to -- what we have targeted for North American gas growth this year is a minus 1%, minus 2% gas growth this year relative to last year, just because of the dismal market prices.

And one of the areas that we have drastically reduced our gas drilling is in that play in the Mid-Continent area. So we don't have a lot of anything to tell you about recent well completions or anything there as we have pretty much slowed that play down considerably.

We've got one rig running in the Cleveland drilling oil wells.

Okay. And then one final question. Mark, you mentioned you're largely unhedged for 2010. What level do you hedge at?

We have got some macro slides that I believe they are out on our website this morning where we believe that the gas price for 2010 is going to average full-year somewhere between $7.50 and $8. And I know that sounds dramatically bullish relative to today's Henry Hub price. So we would have to see a price that amount or higher before we would consider hedging for 2010.

Okay. And then what about on the oil side?

Oil side, you know, I don't know whether we would hedge on oil right now. We are pretty optimistic on oil for the next several years. We believe that non-OPEC oil production is going to slide quite a bit over the next several years. And when you get any economic recovery in the world, you know, we think you could see some pretty interesting things happen on the upside for oil. So don't look for us to be putting any hedges on for 2010 at this stage on either oil or gas.

All right. Thanks, I appreciate the comments.

Biju Perincheril, Jefferies & Co.

Hi, good morning. A couple of questions, first in the combo play. The wells that you highlighted, can you talk about the NGL yield that you are seeing on the gas volumes? I think you mentioned it was gas liquids rich.

Yes, I mean one way to look at it is on the NGL yield if a well -- if we are reporting a well is making, let's say, 1.5 million cubic feet of gas a day, that pretty well translates to about 150 barrels of NGLs a day. So just a horseback number is take the gas yield and just take that on a one-to-one ratio, and that is kind of how many barrels and NGLs you are getting out of it there.

Okay. And then that sort of translates to on similar to what you are showing on the EUR slide also, I think. And then the EURs that you gave, I think, at 210,000 barrels per well, is that at the plant outlet including shrink, or is that --?

That is at the plant outlet including the shrink, yes.

Okay. And then I think you have had some pretty good wells with liquids component in Palo Pinto. Can you comment on that region? Is that similar geology as what you're seeing up in Montague and Cooke Counties, or is there anything different?

Yes, I mean we've found out there some, I would say, somewhat isolated spots where we are finding some oil production that is kind of similar to Montague County, but at this juncture, it is not pervasive. So if you look it up in the Railroad Commission, you'll find we've made some good oil wells out there. But at this juncture, we are not saying the liquids wrap all the way around to Palo Pinto County. It is more structurally controlled there.

So what we would say for investors is really right now focus on the Montague and we have some stuff -- the County just immediately east of Montague is Cooke County and there is kind of -- the Western eighth of Cooke County is kind of the way to look at it where we have acreage. So kind of all of Montague and maybe the Western 1/8 of Cooke County where we have some significant acreage. That is where we are really focusing and that is where the Barnett is extremely thick and rich. And if we -- if we just make our acreage there work, we are going to have a massive oil, gas and NGL accumulation net to us. And that is where we are really focusing.

Okay. So I mean does that imply that the acreage up in Montague and western Cooke Counties, there is less of a structural component? I mean how should we think about risk -- applying some sort of risk factor to that 190 plus acres that you have up there?

Pretty much says that it is very pervasive across all that acreage in that area. And the stuff when you get out out to Clay and Archer County, it is just thinner there, so there is -- it may work there, but it is not obvious that it will work. Whereas there is a very high probability we believe it is going to work in the Montague and the Cooke stuff.

Got it. Thanks. And then a question on Bakken. You mentioned that Three Forks looks [prospectus] throughout -- or I guess portions of both the Lite and the Core areas. I think in the past, you have talked about maybe the Three Forks, that you have had some testing in the Core area and you thought maybe there was some communication between the two zones. Has the concept there changed or is there new data or --?

Yes, we have never commented on that question. I know that is a question a lot of people are working on right now is the communication issue between the middle Bakken and the Three Forks unit and we don't know the answer to that question yet. Others have more data than we do at this point. We are going to be drilling our first actual horizontal test in the fourth quarter into the Three Forks. So we do think it covers a significant portion of our acreage at this point just from mapping of other people's wells and looking at their tests and tying it to some Core data that we have. We are pretty odd optimistic about the potential that we have both in the Core and the Lite area. And economics we think will look pretty close to what the economics are for the Bakken Lite.

Okay, okay. So you say you haven't drilled any Three Forks even in partial yet?

No, we have not.

And then any thoughts -- I mean some of your other operators in the area have had, in the Lite areas, drilling longer laterals and 20 stage fracs. Is that some concept that you are looking at or are you sticking with the shorter laterals at this point?

We are kind of focused on drilling laterals that are 4500 feet long, single laterals and maybe going to 15 stage fracs at the most. So some other people are drilling these tri-laterals and stuff like that, but we are probably not going to change from our methodology. And again, some people are drilling 1280 laterals and stuff like that, but we are pretty comfortable with our methodology. And again, if you look on our website and look at our efficacy of our completions versus peers, we are making the best completions up there. So we are not going to change.

Right, right, right. Okay, very good. Thank you very much.

David Magruder, Longacre Fund Management.

Good morning. Just a quick question regarding your comments around the nat gas storage. Which markets do you expect the storage to be the most tight and then on the production side, where do you expect to see some shut-ins?

Yes, I mean on the storage side, it is obviously going to be real close as to whether we have storage and do shut-ins or not. My own opinion is we are probably going to get to about 3.9 in storage and the question is do we really have 3.9 Tcf of storage out there. It still looks to me like the West is the most vulnerable area since the West is almost full of storage today. So my guess would be that the West is the most vulnerable area and that is where we will see the most pressure, either in deterioration of gas prices or basis blowouts here that could occur in September, October in terms of the shut-ins and everything. So that would be my view on that, David.

Sure. And can you comment on I guess the fields that you think that it would need, in the west, to shut in?

Yes, in our particular company, I think we have significant production in the Green River basin and we have significant production in the Uinta Basin in Utah. And our feeling is if gas prices reach a certain price, I won't say what it is, but if they reach a certain price, we have done it in the past and we will do it again this year. We will just curtail our production.

But what may also happen is, and this may happen more nationwide is, we may just see pipeline pressures kind of nationwide just go up as storage kind of fills most everywhere and as the pipeline pressures nationwide go up, that is going to just put more back pressure on all wells across the nation. And that may just cause an automatic curtailment pretty much across the board and that may happen. And then production would just drop for everybody and that may be what actually occurs here.

But what we are signaling to people is the 5.5% production growth that we anticipate is at some risk depending on this storage situation particularly in September, October and we'll just see how that plays out.

Great. Thank you.

And with that, Mr. Papa, I'll turn the conference back over to you for any closing remarks.

I have no further closing remarks and I want to thank everyone for participating in the call.

Ladies and gentlemen, this does conclude today's conference. We thank you for your participation.