EOG Resources Inc (EOG) 2008 Q3 法說會逐字稿

Good day, everyone and welcome to the EOG Resources 2008 third quarter earnings conference call. As a reminder, this call is being recorded. At this time I'd 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 on election day. We hope everyone has seen a press release announcing third 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 proof reserves in their securities filings. Some of the reserve estimates on this conference call and webcast including those to the barn net shale and North Dakota may include other categories of reserves and we incorporate by reference the cautionary notes to US investors that appears at the bottom of our press release investor relation page of our website. An updated investor relations stat ticks was posted to our website last night.

With me this more than are Loren Leiker, Senior VP Exploration, Gary Thomas, Senior VP operations, Robert Garrison, EVP Explorations, Tim Driggers, Vice President and CFO and Maire Baldwin, Vice President of Investor Relations. We believe our third quarter results can be characterized as another consistent quarter. We hit our volume projections and all of our costs were in line or lower than predicted. We signed an 8-K with fourth quarter and full-year guidance yesterday. These 8-K 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 refer our third quarter net income available to common stockholders and discretionary cash flow and then I'll provide an operational review including directional thoughts regarding EOG's 2009 plan. Tim Driggers will then discuss capital structure and I'll close with a hydrocarbon macro overview summary.

As outlined in our press release for the third quarter EOG reported net income available to common stockholders of $1.6 billion or $6.20 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 third quarter adjusted net income available to common stockholders was $588 million or $2.34 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $1.2 billion.

I'll now address our ongoing strategy and operational highlights. The entire energy sector and indeed all industries are currently transiting through a vexatious period. In times like these solid company fundamentals matter more than ever. On the last quarterly call I noted the five components that we believe constitute a premiere independent E&P company all of which have been long standing goals at EOG. Four of these components are measurable and one is subjective. The measurable components are ROCE, debt adjusted production per share growth, low unit costs and debt coverage ratios. In 2008 we believe we will score number one in the peer group in three and possibly all four of the measurable categories. The fifth and more subjective category involves being an early low cost mover in new horizontal resource plays and we believe we score well in this category also. More importantly, in 2009 we expect to achieve the same rankings in all five categories.

Looking out to 2009, there's a large degree of uncertainty regarding future natural gas and oil prices so let me provide some guidelines regarding EOG's 2009 strategy starting with their volume projections. We believe that 2009 North American gas prices will primarily be a function of winter weather severity. 2009 gas prices averaged more than $8. We expect to grow total Company production 14%. If we have a warm winter and we average $7 in the price we will curtail our gas drilling activity and total Company production will grow 10%. In either case the governing factor in our CapEx budget will be the balance sheet. We will target a CapEx program that is approximately in line with cash flow providing roughly flat year-end 2008 and year-end 2009 net debt. We will provide a specific 2009 CapEx number on our next earnings call when we have a better definition of winter weather. In short, we don't intend to dramatically grow North American gas volumes at prices below $8. The different growth paths between $7 and $8 Henry hub does not imply that our gas investments require $8 to be economic. Simply put, we don't intend to cram gas into an oversupplied market if prices average $7.

In either growth scenario there are three items in common. First, in 2009 total Company crude oil condensate and NGLs are expected to grow 33% from this year's 60,000 barely a day level to 80,000 barrels a day next year. Condensate production is expected to grow 43% year over year and natural gas liquids production is expected to grow 10% year over year. The primary growth engine of the liquids will be the North Dakota market with a lesser but increasing contributions for the Barnett oil and other plays. I'll remind you that even at $65 a barrel oil was still selling at an $11 per MMcfe BTU equivalency making our oil investment still attractive. Second we expect only a small year-over-year increase in natural gas production from Trinidad Canada and other international so most of our gas increase will eminate from US. And third, it's unlikely that EOG will pursue a merger significant acquisition, significant disposition or chase high priced acreage in 2009. This is consistent with our belief that organic growth yields intrinsically superior reinvestment rates of return compared to growth through mergers or acquisitions.

In hindsight we are pleased we didn't participate in the high priced acquisition acreage or merger games during 2008 or previous years. Addressing 2009 CapEx, what's the logic behind our capital allocation. Simply put, we've got enough natural gas and crude oil and drilling inventory to last us roughly 15 years. In 2009 we'll give first priority to oil investments because even at $65 a barrel their high ROR hence the 33% year-over-year crude oil condensate and NGL growth. Roughly 40% of our 2009 North American capital budget will be devoted to oil projects. Regarding gas, if we have a moderate or cold winter, we'll pursue a high level of drilling activity to generate 14% total Company production growth. If 2009 gas prices disappoint, we will defer some gas drilling until a more propitious time and target 10% total Company production growth. The key point here is that we don't intend to run up our debt chasing $7 gas, so the production growth numbers I've provided are essentially debt adjusted per share. One likely positive we will have in 2009 is lower per well costs as we are already seeing some decreases in service company pricing.

Now let me refocus you on 2008. In the third quarter we beat our 8-K midpoint volume guidance in spite of hurricane-related shut-ins in the Gulf of Mexico and in southeast and west Texas. In the fourth quarter we curtailed 70 million cubic feet a day of Rocky Mountain Gas for most of October due to low well head prices and we currently anticipate experiencing an unanticipated curtailment of 80 million cubic feet per day net for approximately six weeks in Trinidad due to mechanical problems at a methanol plant. In spite of all that, we expect to increase 2008 production 15.1% which is consistent with the target we announced in February.

I've covered a lot of conceptual ground with you today. For brevity I'm not going to recite a lot of individual well results but I will cover most of our highlight plays. Or North Dakota Bakken play continues to yield consistent overwhelmingly economic results and has overachieved this year versus our forecast. Three recent highlight wells are the Austin 2128H, 1821H and 10-34H, which posted corresponding peak gross production rates of 2847, 3029 and 3477 barrels of oil per day. Our overall average well results continued to be outstanding and the IR presentation that was posted on our website yesterday has a slide showing the quality of EOG's Bakken wells versus offsetting wells drilled by other companies. Generating efficient horizontal completions that maximize the productivity per acre of [rock] in the EOG strength and I would urge you to view a similar chart in this IR presentation relating to Barnett Johnson County completions. These comparisons in my opinion are shockingly stark and are one reason why we generate such strong relative ROCEs and in a time of low hydrocarbon prices I will retain better economics than other companies.

Returning to the Bakken, we now have 370,000 acres captured and last quarter we told you that our 80 million barrels net reserve estimate was contained in the core area and we hope to extend this play into the noncore area where per well reserves are 250,000 to 350,000 barrels of oil equivalent versus 850MBO in the core. Outside the core with 250MBO and $65 flat oil, the economics still yield a 30% direct after-tax unlevered reinvestment rate of return while the core area still generates 100% direct ATROR at $65 oil flat. We have now drilled two successful wells outside the core with initial production rate of 500 to 700 barrels of oil per day extending the reservoir size above 80 million barrels of oil net. However, additional drilling is required to determine how much larger this accumulation will become. Additionally, we have started a pilot CO2 injection program in the core area to see if we can increase overall recovery above the 10% primary level. Results from the CO2 trial won't be available until mid 2009. We still have several years of drilling inventory in the core area and then multiple years outside the core.

Another horizontal oil play we mentioned in our February analyst conference with our Colorado North Park play. We recently drilled a stepout to our discovery well and the early results indicate it's better than the discovery well. Development of this North Park asset will be slow due to sensitivity to surface use and pipeline takeaway issues but we are optimistic regarding this accumulation. We are currently drilling another well and should have these results by the next earnings call.

In the Horn River Basin of British Columbia, you may recall that earlier this year we word encouraging results from two short lateral horizontal shale wells. We have now drilled, completed and tested three full length lateral wells and our results comport with our earlier optimism. These wells IP'd at 16, 12 and 9 million cubic feet per day respectively and have performed well during the first period of sales ranging from 30 to 60 days, confirming our estimates that we have at least six net TCF captured here on our 150,000 net acres. Another reason I focused on the well quality issue in the Barnett and Bakken before is that our early data in the British Columbia Horn River Basin suggests a similar trend. We believe our three wells are among the best wells completed by anybody to date in the Horn River Basin. We still think it will be 2011 before significant pipeline takeaway is available for this area.

In our Barnett operations, our results continue to be consistently good. For the total play we expect to average around 460 million cubic feet equivalence for full year 2008 from this asset, slightly less than the 470 target we articulated in February. The slight shortfall is a result of gas and natural gas liquid pipeline restrictions we noted on the last quarterly call. In the Barnett gas areas, yesterday's press release highlights several new Johnson County monster wells with IPs ranging from 6.5 to 10 million cubic feet per day. I would again call your attention to the Johnson County well completion chart on our website. Simply put as is the case in North Dakota Bakken, we are making better wells in Jonathan County than other companies hands down. The importance of this Barnett well completion outperformance isn't limited to Johnson County.

We are also consistently making respectable wells in Hill, Palo Pinto and Erath County and have found acreage and competition of the cost much lower in the core area because other companies are having difficulty making economic wells in these counties. In Hill County we are averaging 1.65 net BCF per well and our results in western county such as Erath and Palo Pinto are not as spectacular in Johnson County are similar in terms of finding costs to what's been reported by others in the Fayetteville and Woodford plays. Regarding the North Barnett oil play, our natural gas processing plant should be online in February so volumes from this play will begin slowly ramping up late in the first quarter of 2009. Because these oil wells are not high volume like the Bakken, now we are talking here about initial rates of roughly 250 barrels of oil per day plus rich gas compared to roughly 2000 barrels a day in the Bakken. The liquids contribution from the Bakken oil play will provide only a modest portion of our 33% liquids increase in 2009 with an expanding role in later years. We are still working on optimizing the well completion recipe here since we have a time window because of the current limited gas pricing capability in the area. We will provide more specific data regarding this play once we get our gas plant up and running.

In the Pennsylvania Marcellus play we can now report that we have achieved success on a portion of our 220,000 net acres. We have now drilled a couple of wells and delineated about 40,000 acres in Bradford County that we believe will generate 2.0 gross BCF per well for $2.25 net finding cost. Net reserves on these 40,000 acres for EOG are likely 600 BCF. As you know, we have been conscious regarding this play and will note that reports by others regarding reserves per well are considerably more optimistic than our estimate. During the next six months we will be attempting to prove up more of our acreage and we will begin a one rig development program on our 40,000 acres in 2009. I continue to caution that because of infrastructure and regulatory issues the Marcellus won't have an impact on the macro gas supply picture until after 2012 if indeed it develops into an areawide play.

Regarding the Hanesville play, we are currently fracture treating our first horizontal well on our 115,000-acre position so we can't add to the Hanesville body of knowledge at this time. The primary reason why we were able to hit our 15% volume target this year in spite of voluntary curtailments, hurricane interruptions, pipeline restrictions and plant downtime is that simply put we are consistently making good wells both oil and gas, across the board in North America. Although, we highlight the Barnett and Bakken, the rest of our North American inventory is generating great results that will be replicable in 2009 and subsequent years. Our Mid-Continent horizontal Atoka and Cleveland plays continue to perform well.

The Uinta Basin in an area that previously had been drilled with only vertical wells we have recently drilled our first horizontal well with production of five million cubic feet a day with 1800PSI flowing tubing pressure after one month which is much better than we expected. In south Texas we just completed two wells that were directionally drilled under Nueces Bay near Corpus Christi. They are producing at a combined gross rate of 28 million cubic feet a day and 1800 barrels of condensate per day. We have an average 80% working interest in these wells. We think this will be 100 net BCF field. The bottom line is that EOG has a smoothly running North American oil and gas energy.

Switching to Trinidad, I mentioned earlier that we are currently experiencing a curtailment of 80 million cubic feet a day net for approximately six weeks due to an unexpected mechanical problem at a third-party methanol plant. In the North Sea we expect to drill at least three oil and gas exploration wells commencing in the second quarter 2009. In China we will spud our first horizontal gas well in January and it will likely be late 2009 before we know if this program is successful. Between Trinidad, the North Sea and China, I expect we may surprise some people with 2009 positive results outside North America.

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

Thanks, Mark. For the third quarter 2008 total exploration and development expenditures including asset retirement obligations were $1.6 billion with $74 million of acquisitions. In addition, expenditures for gathering systems, processing plant and other property plant and equipment were $124 million. Capitalized interest for the quarter was $10.6 million. YTD total exploration and development expenditures including asset retirement obligations were $3.8 billion with $109 million of acquisitions. Total gathering, processing and other expenditures were $321 million.

During the third quarter we did a bond offering to effectively term out our short-term commercial paper borrowings. We issued five-year notes totaling $400 million at 6.125% and 10-year notes totaling $350 million at 6.875%. Our credit ratings are A3 and A minus and our game plan remains consistent to stay very conservative on the financial side. In terms of liquidity, we have a $1 billion revolver which has never been drawn. We have no exposure to Lehman.

Also, included in the IR presentation this morning is a summary slide taken from the south side. It shows 2009 estimated debt to cash flow -- cash flow ratios using $75 oil and $7 gas, using these metrics and these particular estimates, EOG could pay off its debt in just over three months. At September quarter end total debt outstanding was $1.9 billion and the debt to total capitalization ratio was 17.5%. At September 30, we had $886 million of cash giving us non-GAAP net debt of $1 billion for a net debt to total cap ratio of 10%. The effective tax rate for the quarter was 35% and the deferred tax ratio was 80%.

Yesterday, we filed a form 8-K with fourth quarter and full-year 2008 guidance. We also filed a third quarter 10-Q. For the full year of 2008, the 8-K has an effective tax range of 33 to 37% and a deferral percentage of 65 to 85%. Using the midpoint of the updated 8-K guidance, our full-year 2008 unit costs for lease and well, DD&A, G&A, total exploration, net interest expense and excluding transportation and taxes other than income, our forecast increase 3.7% over 2007. Estimated exploration and development capital expenditures for 2008 excluding acquisitions are $4.55 billion. Estimated gathering, processing and other expenditures are $400 million.

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

Thanks, Tim. I continue to believe that the primary determinant of 2009 gas prices will be winter weather. A cold winter will likely generate $8 to $8.50 average prices and a warm winter $7. I believe 2009 North American net natural gas supply will grow at most 0.6 BCF per day year over year, which comports well with likely electricity demand growth. Our 2009 hedge position was articulated in our 10-Q filed last month. We are about 38% hedged at a $9.71 gas price and are unhedged regarding oil. We also have 60 million cubic feet a day of 2010 gas heads attractive prices and have added some rocky basis hedges from 2009 through '11.

Now let me summarize. In my opinion there are five important points to take away from this call. First, with the focus on the balance sheet, we are going to let the 2009 gas price determine what our overall CapEx and total Company production growth will be. We have easily got the organic capability and high rate of return inventory to grow total Company production 14% next year and subsequent years, but we will only do so in high natural gas commodity environment. Low debt is still a very important criterion for us. Second, we expect to continue to lead the peer group in ROCE and based upon our current inventory quality, I don't see that changing in the future. The most important criteria that gives us consistently higher than peer ROCEs is our ability to grow at high rates organically and not rely on acquisitions or M&A to generate growth and that won't change in the future. Third, we have now verified reserve upside above the 80 million barrels net for the Bakken and have confirmed Marcellus reserves on a portion of our Appalachian acreage. Fourth, we'll continue to work on new horizontal ideas and we'll disclose them whenever we have acreage positions knocked up. And, Fifth our Trinidad, North Sea and China components may surprise on the upside in 2009.

Thanks for listening, now we'll go to Q&A

Yes. (OPERATOR INSTRUCIONS) We'll take our first question today from Tom Gardner with Simmons & Company.

Yeah, good morning, Mark. Good morning. You've been pretty clear on your CapEx comments on the call, so in light of that, can you discuss if you see, you know, the current environment as an opportune time to increase your resource play inventory? It sounds like you're just not going to go there?

I tell you what we are seeing right now, Tom. I mentioned on the call that we are not really going to be, you know, making high acreage acquisitions or making mega producing property acquisitions. That's just not our style. But, we think that what's going to come out in 2009 are lot drill it earn opportunities on other people's acreage, companies that either don't have the horizontal expertise or are so strapped for capital that they can't -- they've got expiring leases and can't go that route so I wouldn't be surprised if you see in 2009 that we shift some of the drilling that we do away from some of our core areas to maybe some acreage that we don't really have captured at this particular time, that belongs to somebody else. In terms of overall resource play focus, we are continuing to be quite aggressive chasing new horizontal ideas of both gas and oil, but our game plan is to be the first in where you can get cheap acreage as opposed to being the second or the tenth in where you're paying big dollars for acreage. So, I expect that we are going to have some upside surprises during the year on some of the resource plays that we haven't disclosed yet.

Well, on that subject, you know, given these large IP's and in Johnson County horizontals, does this change your average outlook for Johnson County reserves for well reserves? I mean, you guiding 1.8 to 2.2 BCFp analysts day.

Yeah, we might be tending for the high end of that side. I don't think it's going to change it up to three BCF or so. I think the key takeaway, Tom, for the Barnett gas is that the Johnson County is very competitive. Every acre is leased there, but the western counties and the southern county, Hill County, have been pretty much left wide open for EOG. People who were competitors out there just haven't been able to make good wells and you can look in that Johnson County chart and that's the reason they haven't been able to. Whereas we have been able to so we have been able to have a fairly wide open field there with not much competition so that's what's really changed in the last year, is that we now view the Barnett, particularly in the western counties and the southern counties, as more of a growth opportunity than we would have viewed it a year ago. Johnson County we are doing we are doing better than we expected but growth opportunities in terms of adding acreage there are very, very limited.

Thanks for that. And one last question I must get your view on sort of the gas gross information that we get. In the past you've indicated some skepticism over 9-14 data. Can you give us your view on accuracy of that data and perhaps your view on base declines in North America X drilling and what it's going to take to balance the natural gas markets going forward with respect to rigs?

Yeah. I mean, we have been skeptical of the EIA914 data and we have devoted a fair amount of effort to analyzing the IHS data versus the EIA data. I do believe the EIA data is directionally correct. I just don't believe it's absolutely correct, and what we have found, for example, our comparison indicates that in the state of Texas the EI estimates may well be overstated by about eight tenths of a BCF a day versus IHS in Michigan, an unusual state, the IHS data can't replicate EIA and it's about six tenths of BCF a day lower and then if you look at the other states, you know, we think there's about a six tenths of a BCF difference there so if you add all that up, it comes out to -- you know, we would say perhaps production growth in absolute terms this year is maybe about two BCF a day less than what the EIA has stated. It's still up considerably and then I think the surprising thing that we have kind of come up with is that our estimate is total US supply growth including LNG, including Canada imports, '09 versus '08 is this 0.6 BCF a day and that's comprised of, you know, just a quick run through the numbers, we think Canada imports will be down about nine tenths of a BCF a day. That's a combination of demand, growth and heavy oil plus the production decline. We think Gulf of Mexico next year drops off half a BCF a day because the recount there has really fallen versus a year ago. Rockies goes up .2 limited by the Rex takeaway capacity. Barnett, only up .3 BCF a day next year and we still believe the Barnett will plateau, you know, and then remainder US on shore up about 1.1 and then L and G up .4. I know everyone is looking at the -- and dreaming, my, gosh, this is a terrible supply and gas prices are in bad shape, but we think with the slowdown in drilling particularly that the big surprise next year will be that the supply growth to the US is considerably lower than probably anybody is predicting today.

What was your embedded rate count assumption in those numbers?

Yeah, we are around -- we were estimating that the rig count goes down somewhere between 200 and maybe three or 400 rigs overall and like I say, we have already seen rigs being moved out of the Barnett. In fact, we are going to slow down a bit in the Barnett and probably remove about three rigs from our fleet in the Barnett.

Great color, Mark. Thank you so much.

Okay.

And we'll take our next question from Ben Dell at Sanford C. Bernstein.

Hey, Ben

I just had one question, It sort of goes around how you look at farm and agreements. Arguably your balance sheet, your financial position is obviously a lot Better than especially some of the small caps and micro caps who have paid high prices for acreage. How do you view farm and agreements? Are you seeing a lot of those in the industry and would you consider those especially if you are more constructive on gas going into 2009?

Yeah, I -- we have already seen some farm ing opportunities and I expect we will see a plethora more of them pretty soon, and the way we would view it is and I'd just give a simple example, if we were going to spend, let's just say, $50 million in our Vernal Utah. Uinta Basin area, that the acreage is locked down and held kind of forever. We may say, well, maybe we will slow down drilling in the Uinta Basin area and spend that same amount of money earning into a new position in a farm (inaudible) and in that instance what we have done is we have still got all of our PUD reserves and potential in the Uinta Basin but we have now acreated additional potential on this acreage that we've earned into. I would say that look for us to be doing some of that at least, maybe a lot of that in 2009 as opposed to taking advantage of a company whose -- needs to sell assets badly and trying to get in a competitive bidding war to buy producing properties. We just don't think that's a good reinvestment rate of return way to go.

Okay. That's all I had. Thank you.

Okay.

We'll take our next question from David Tameron with Wachovia.

Hi. Nice quarter. Mark can you talk about just specific guidance,it looked like the oil differenentials the guidance widened in the fourth quarter. Is that a function of trucking out of the Barnett -- I'm sorry -- out of the Wilson Bakken. Can you talk a little bit more about that, what was driving that?

Yeah. And the answer to your question is, yes, the -- clearly the biggest growth area we have for oil production and it will go into next year is the Bakken and whats happened up there, you know, I don't have to remind you or anybody else, that not only is EOG having success in the backen, but a lot of other companies are having success up there and the oil pipeline infrastructure, the oil takeaway infrastructure has just been subsumed by the EOG volumes plus other company's volumes, and so as a consequence, we are piping about half our oil out and then we are having to truck about the other half of our oil out and I expect that that's, you know, similar case for most other companies who are up there. We expect to get that problem fixed by midyear next year by expanding pipe line capacity, oil pipeline capacity out of there, and but, you know, there will be some trucking differentials that will probably last until midyear '09 and I'll also note that we are -- we are currently looking at a dense phase gas pipeline to get the very, very rich gas that we are stripping out for the oil up there, to get that up into alliance pipeline and get it to a Chicago market and we hope to have that project in sometime late in '09. So --

Is that your pipeline or who's building the pipeline?

Yeah. The gas -- the fence phase gas pipeline will be built by EOG. On the oil side we are in discussions with, you know, several other companies and we are not sure whether we will take an interest, equity interest in it or other parties will. That's still open at this point, but it's a very, very high priority project for us and for other companies that are producing oil up there.

Okay. And is that -- trucking it somewhere in that $12 to $15 range as far as less of differential when all is said and done, is that a good number to use?

Oh, it's probably even a little bit higher than that right now. It may be up to $18.

Okay. And one more question and I'll let everybody else jump in. Getting back to the Barnett oil, how many wells have you drilled? I know you had initially targeted 60 to 80 back in February. But how many wells have you got down and can you talk about -- when you start running the sensitivity as far as oil prices, you know, what kind of number do you need as far as oil to make this thing work?

Yeah. I don't have a count right now exactly of how many wells we have drilled. I've done a lot of experimenting on a lot of those wells, but the question is, you know, how low do oil prices have to go before we get into a situation here that, you know, doesn't look all that good, and the answer is that at today's oil prices and $7 gas prices, we are generating about a 30% rate of return based on our typical wells that we expect, which is 100,000 barrels of oil gross, but .35 million cubic feet of gas and about 45,000 barrels of NGLs. So if oil does drop to 40 bucks a barrel or something like that it's not obvious that this project is going to be economic. On the other hand, if it goes back up to, you know, 90 or $100 a barrel, we think it's going to be tremendously economic.

But you said 30% at current -- kind of current debt.

Current debt, yeah.

All right. All right. Thanks.

Okay.

And we'll take our next question from Brian Singer with Goldman Sachs.

Thank you. Good morning.

Hey, Brian.

What are your current thoughts on 320-acre downspacing potential in and out of your core Bakken properties?

Yeah. At this juncture we drilled one 320-acre down space well and we are monitoring it and where we sit at this point in the core area is that we would say that if the CO2 injection turns out to be a viable opportunity, then it's a slam dunk that we go to 320-acre spacing. If we find that, we are not improving the recovery above that 10% with 320-acre spacing in the core area, then it's more of a close call and it's not obvious that 320s are necessary to drain the wells, in other words, you put in the capital but the incremental reserves you get are not -- not all that much. As you go outside the core area and some of this area that we said is now made the reserves bigger than 80 million barrels, because of the well quality, the rock quality is not quite as good there, it looks like that will pretty well certainly be on space -- 320-acre spacing. Does that give you some direction on that, Brian?

Yeah, it does. Thanks. And then in the Marcellus, what would you say changed over the last few months that has given you more confidence, at least on that, I think, 40,000 acres you mentioned and when you think about the $2.25 in do you see that as a starting point from which you would expect decreases or do you feel that's a firm number?

Right now that's a program number. I mean, it may improve with time. We haven't drilled a large population of wells there. The biggest thing that's changed there and gotten us over the hump is kind of the completion efficacy there. We think now that we are getting a higher degree of our fracs focused in the Marcellus shale as opposed to going outside the Marcellus shale, in the Marcellus as opposed to the Barnett or the Bakken, the risk appears to be greater just on relative rock strengths that you can frac out of zone, at least your frac energy but doing some tweaking to our fracs, we think on at least this 40,000 acres, we have got that pretty well resolved. But it is fair to say that, you know, so far we haven't been able to replicate, you know, the numbers that some other companies have put up, which I've seen numbers of four BCF gross, 3 1/2, four BCF growth for a typical Marcellus well. I'll be a little surprised if that turns out to be the number across a wide area. But our number is more like the two right now.

Great. Thank you.

Okay.

And we'll take our next question from Joe Allman with JPMorgan.

Yes, thank you. Good morning, everybody. Hey, Mark, could you talk about -- you mentioned that you're planning on dropping maybe three rigs in the Barnett shale. Could you talk about the reasons for that and could you talk about whether or not you're slowing down anywhere else at this point and are you transferring rigs to another location?

We have kind of confined our activity to our planned budget for 2008 and we are more efficient with the number of rigs that we have, so we are drilling more wells with less rigs and we have just reduced there and Barnett thus far, we are dropping a couple of other rigs. We have declined from 80 rigs down to 71 just throughout EOG: Also that's just the efficiency. You probably see on a couple of the charts in our presentation, where yes, we reduced our days substantially. For instance, in the Bakken we were requiring about 37 days in 2006. Now we are down to 25 days for the average of 2008, record wells down in the 15 day range.

Okay. And is economics a factor here or are you seeing any areas where, you know, given the 9X prices, given wide well differentials, the economics just don't work out?

Oh, it -- you know, I think almost everything we have is economic, down to $6 or 650 in MCF. It's a case do we want to put our drilling in 40% projects or 15% projects. So,it's not a case where anything has gone under water economically today but it's just a case as we said that if we really have $7 gas and a warm winter, we are not going to bust our butt as a company to go push in a lot of gas into a $7 gas market so we will just sit on some of our ideas and wait for better gas times.

Gotcha. And where are you seeing this service(inaudible) decline and what particular service (inaudible) basin at this point?

We have seen some decline in just the drilling rigs, quite a number of our rigs are not long-term committed, some of the completion units, directional surveys services, some of that. Overall probably just 5% decline. We are talking to quite a number of service providers, expecting to see tubulars and of course fuel has gone down quite a lot as well. There's -- the tubular inventory is increasing and there's several are saying that, yes, we will be seeing declines here at least first quarter '09.

That's helpful. And then in the Bakken play, can you comment about the (inaudible) and what you're seeing there?

Yeah. We are still sending the Three Fork [Sanish] outside the partial area as we said in the past. In the Parshall area we don't see too much prospectivity at a time there we have 370,000 net acres in the total Williston Basin of which about 110,000 are in that Parshall/Austin area and so that big shrug of acreage outside of that we think is highly perspective for particularly three forks.

Okay. Very helpful. Thank you.

And we will take our next question from Gill Yang with Citigroup.

Good morning, Mark.

Good morning, Gill.

Would the change or the -- your sort of variable capital spending budget between $7 and $8, I guess the question I have is on one hand if you slow down, does that free up spare capacity among your people and what happens and what do those people end up doing? On the other hand if you accelerate, so to speak and I guess you're already seeing this in the Bakken, does it tax infrastructure either on your people or take away infrastructure and maybe sort of address this already, but how do you deal with the accelerating and decelerating downstream impacts to infrastructure both people and, you know, the hard infrastructure in those areas?

Yeah. The four areas where we are seeing infrastructure-related issues around Williston Basin Bakken where we are being proactive and in a lot of cases building our own infrastructure and the Barnett oil where there was essentially no infrastructure for the rich gas processing and we are building our own plant and infrastructure there and then up in Canada in the Horn River basin area where infrastructure is pretty limited and we think pragmatically that we will have a third-party install that infrastructure as opposed to EOG but it's probably going to be 11 before that happens and then in the Marcellus that is highly, highly infrastructure challenged and we are not sure how we are going to address that really but it will probably be third party there. So as you find these resource plays, what really sorts out is many of them are in areas where you never had significant hydrocarbons accumulations and the resource plays in aggregate have turned out to be bigger than anyone expected. I think if you just take the Bakken, for example, or the Barnett and what people thought it would be four, five years ago and then what it is today and I'm talking about not only for EOG but the rest of the industry, they have turned out to be considerably bigger and hence we have got those issues. So what we have had to do as a company is devote more effort than we have in past years to infrastructure work and on the people side I'd say that, you know, for 2008 we were probably operating at about 120% of capacity on our people side. If we go for $7 gas and 10% production growth, maybe our people will only be working at 95% at capacity or so for next year, but it's not -- it's still a people short business in terms of engineers, geologists, land men, et cetera and we -- we think we can flex easily with our staff between the 10 and 14% volume growth.

So it's not like there's going to be freed up capacity to move them onto other things necessarily?

Yeah. I'd say, you know, it's not -- not obvious that we can say, okay, if we are going to grow 10%, we can reallocate people to something else. No, I don't think that's anything we can really do.

Okay. And, I think I know the answer to this second question, but you're interested in maybe taking an interest some of these farm outs, potential farm outs, does that in any way suggest that all of the -- or many of the important new resource plays have already been discovered in North America and that you need to go back and look at these farmout potentials or, you know, do you still see there's a nice slew of undiscovered resource potential?

Yeah, you were right and you know what the answer to that question is. We still think there's a considerable more resource potential attacking these plays with horizontal drilling and so we are focused heavily on that. the drill to earn things, the farm ins, they will be nish things that come up but the way to view it is we have a chance to capture acreage that a year ago we would have never had a chance to capture, where someone else has perhaps paid a high price for it or maybe they just intended to drill it themselves and they can't now and so those are pretty good opportunities for us. And what gets us into those opportunities are those well completion charts that I referred to in our -- what's posted on our website in the IR presentation. We can show people that for an acre of rock, we will make a better well than our competitors and we have proven that clearly in the Bakken, clearly in the Barnett and early time in the Horn River and people are aware of this. They say, well if I'm going to farm out, I think I'll do it to the one that's going to generate the most production from that acre of rock and that certainly appears to be EOG.

Okay. Thanks a lot, Mark.

Okay.

We'll take our next question from Leo Mariani with RBC.

Yeah, good morning here, folks. Quick question on your CapEx plans for next year. Could you guys kind of go ahead and sort of try to prioritize your key plays in terms of what you would drill? I'm curious to how some of your gas plays prioritize next year.

Yeah. The first priority is that, you know, we will be looking at the oil side and we said that 40% of our CapEx, North American CapEx will go to oil. That's up from probably 30% of our CapEx, North American CapEx this year that was devoted toward oil. So, you know, we will be shifting a significant movement there. In terms of the gas side, the way we will prioritize things, the difference between the 14 and the 10% volume growth is, one, we will look at areas that -- where we have no lease termination or lease life issues and those would be areas that we would likely throttle back most readily and just a couple that come to mind, Uinta Basin area we have got our leases secured and so we could accelerate or decelerate drilling there and not lose any acreage. Our Mississippi Chalk play is another one that's pretty much in the same state. So a large determinant will be -- and really to some degree our Barnett is now in pretty darn good position where we don't have to drill a zillion wells to meet lease expires. We have now got that pretty well locked down. Those are just some examples of where we -- if we cut back drilling, it would be more on the basis of how do we hold together all of our acreage as opposed to turning loose some of that and ranking in some other (inaudible).

Okay. Just jumping over to your [Gootlaw] play. Obviously you've had some wells on stream for a little while here. Could you just give us a sense of what type of decline rates you guys are seeing on those wells?

We have had wells on now for -- we have got two categories of wells. We had a couple well that we mentioned in February that were short laterals, we say short laterals. Maybe they were 1500-foot lateral lengths and those wells, you know, kind of gave us a tantalizing hope that, you know, if we could get a lateral length about twice that long we would end up with pretty good wells and indeed that's what's happened. We now got wells, the best well there where we have had on now about 60 days for the first 30 days it averaged over 10 million a day average rate for the first 30 days. That probably translates to a well that's roughly a 10 BCF well. So if you go back to what we articulated in February at the analyst conference, we gave a matrix and said the economics would be X and Y under cases of four and six BCF per well and from what we are seeing now, we think those reserves or well estimates are probably going to be extremely conservative and we are going to be able to beat those pretty readily. The other thing is that, you know, our experience in the Bakken, experience in the Barnett is it takes about 20 or maybe 30 wells to get the frac recipe right before you have something you can kind of rubber stamp. And we are getting these pretty darn good wells up there in Canada with just roughly our fifth and -- fourth and fifth wells. So we think there's probably going to be a lot of improvement coming from that. So net, net out of all of that, I think it's strongly reaffirms that, you know, we said we thought we had minimum of six net BCFs on this acreage back in February and I think the data we generated strongly reaffirms that.

I guess given that back drop, what are your drilling plans there this winter?

Yeah, we will be -- oh, Gary, you want to address that?

We are going to go ahead and contract one, probably 1 1/2 rigs. We will drill 13, 14 rigs here in 2009.

13, 14 wells.

Or wells, yeah.

In 2009. Yeah.

And the reason for that too is we are just watching our capacity. We have got a firm capacity at somewhere around 35 million a day and there's 45 to maybe 50 million capacity available on the line. So we will drill complete to fill available capacity.

Okay. Last question here on the Hanesville play. It sounds like you guys got your first wall, you're going to frac it pretty soon here. Can you give us a little bit of color in terms of where your acreage is located in the play and maybe what your potential plans are there?

Really, of our 115,000 net acres, it's pretty relatively evenly split, maybe heavily weighted towards Texas and probably about 40% of it, maybe 45% of it is HPP. And it's spread throughout what others and we have mapped as the core area. It's a pretty big core area and we are pretty well represented in all parts of it.

Okay. And I guess any thoughts to drill any follow-up wells or you want to analyze your first results first before you move on?

We are drilling follow-up wells as we speak. We have our second well drilling now.

Okay. Thanks a lot, guys.

And we will take our next question from David Heikkinen with Tudor Pickering Holtz.

Good morning. Just first a macro question, thinking about L and G and Asian weakness. What are your thoughts going into the next couple of months around LNG imports?

Going into the next couple of months, David I think the only way incremental L and G would come here is if there's just absolutely no capacity in Asia or Europe for it. So I'm not -- we are programming just guessing that LNG '09 versus '08 goes up by about four tenths a BCF a day and that's just on the assumption that these (inaudible) come on and it turns out to be a little bit extra LNG, but I still foresee that, unfortunately, the lowest price net backs for LNG all through 2009 is going to be North America and so we would only get whatever -- whatever the other markets absolutely cannot digest.

Okay. Then onto the Bakken. Your gas plant and gas line capacity, is that 30 million a day or do I have my notes wrong?

When we -- the gas line that we are going to be installing, it's going to have the capacity for, oh, goodness, 80 million a day.

Okay.

The one that we've got installed now in that plant is good for 20 million a day.

Okay. So you'll have akum of a hundred million a day.

No we are going with the 80 million a day dense phase or refrigeration unit and pipeline.

And the reason for this dense phase again is one of the issues we have is that this gas in the Bakken is extraordinarily rich in propane, butanes and heavier components and right now we are stripping it out basically on location there in western North Dakota and that's just not a good place to sell that product. I mean, again, you suffer a location differential and so the game plan there is, is to get that -- all those rich liquids to Chicago where you have a much more pleasant market price and you don't take a big ding on the differential. So, again, it's just a lead time issue there, but that's as in the oil, you'll notice our NGL differentials are not as great as we had hoped and the more NGLs we bring on in North Dakota, the more we have to get this problem fixed and we expect we will by mid next year.

And as you think about NGL, the little bigger picture, both southern region and what you have in the Bakken and Mid-Continent is you've had this blowout and big drop-off in NGL realizations, what do you think about going into fourth quarter and then into next year as far as where NGL prices will be?

Oh, we penciled in that they are going to be about 55% of crude oil on a dollar per barely basis.

So the 40% we are seeing now in Mid-Continent, that's ano one lus?

We think so but we can't purport to be NGL market experts. We can't even purport to be natural gas. Neither can we.

And our last question today will come from Ray Deacon with Preached Capital.

I was wondering if you could talk about your plans for Bradford county next year and what kinds of wells will you be drilling, horizontal or vertical and then maybe some thoughts about Horn River and, you know, what your CapEx might look like there next year.

Yeah, on the Horn River, you said previously that we are going to average probably about one, 1 1/2 rigs there next year so we will have I'll say a modest level of activity and it's really more of kind of a learning curve activity, a fillup what gas pipeline takeaway space there is so it's definitely not going to be in a hyper ramp-up phase. In the Marcellus it will be fairly similar. We will probably have one rig running year round in the Marcellus most of the time it will be spent on that 40,000 acres and then the rest that we have proven up and then the rest of that will be drilling on some of the other acreage trying to prove it up. But, we are -- in our 10% or 14% volume forecast, neither the Marcellus, certainly not the Marcellus and to not much degree the Horn River are we really counting on significant volumes in 2009.

When you said you thought that volumes wouldn't be meaningful in the Marcellus until 2012, did you mean you felt like forestry or for you specifically or --

Yeah, I would say what I meant was for the macro industry. The -- it's clearly the most complex logistical area that we have had anywhere. It makes British Columbia look simple for comparison. And some of the recent I'll say legislation or regulations that have been proposed in Pennsylvania are likely to slow down things even more. So we just can't be that we are going to have a ton of gas and macro coming from Appalachian anytime soon. of gas and macro coming from Appalachian anytime soon. been watching what ha bid week prices drop over the last five or six weeks.

Is there anything you're doing specifically that protects you from some of that basis issue and with your Barnett gas and does the sort of demise of these midstream MLPs affect any projects that you would have liked to have seen gone forward?

Yeah, the Barnett gas, we have got pretty well covered with firm transportation to get it out of the Fort Worth area, so we are not really prone to getting beaten up on the differentials there because we really get it moved out of the area. Where we are more at risk is in Rockies and in the Rockies we have got, I'm talking about now plus the next four or five years, we have got firm transportation on about half our volumes there on CIG or kinder Morgan lines, but the other half we are exposed on the differential and that's why we are putting some Rocky spaces in place for 2009 and 2010.

Got it. Got it. Thanks very much.

Okay. All right. Thank you. Any last questions?

And there are no further questions at this time.

All right. Well, thank you very much for listening in and we will talk to in another three months.

Thank you. That does conclude today's conference. We want to thank you for your participation today and you are now free to disconnect.