EOG Resources Inc (EOG) 2007 Q2 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources second-quarter 2007 earnings release conference call. As a reminder, this call is being recorded. At this time, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second-quarter 2007 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. Reconciliation schedules for these non-GAAP measures to the comparable GAAP measures can be found on our website.

The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates on this conference call and webcast, including those for the Barnett Shale play, may include other categories of reserves. We incorporate by reference the cautionary note to US investors that appears at the bottom of the investor relations page of our website. Updated investor relations presentation statistics were posted to our website this morning.

With me this morning are Leiker, Senior EVP Exploration; Gary Thomas, Senior EVP Operations; Bob Garrison, EVP Exploration; Tim Driggers, Vice President and CFO; Maire Baldwin, Vice President Investor Relations.

We filed an 8-K with third-quarter and full-year 2007 guidance yesterday. We increased our estimate for 2007 production growth from 10% to 11.5%, all organic, which is unusual for a company our size that is not issuing equity. Increase from the previous target is emanating from higher domestic crude oil and NGL production.

We anticipate strong oil production in the second half driven by continued success in the North Dakota Bakken horizontal oil play that we highlighted in the press release. The increase in NGLs is coming from the Barnett Shale. We are processing richer gas from this area and it is driving up our NGL production.

Our production mix for 2007 includes both 17% organic North American gas growth and 17% total North American growth.

Yesterday's 8-K filing reflects a CapEx increase from 3.4 to $3.6 billion. The extra $200 million is primarily devoted to increased North Dakota drilling and infrastructure and Barnett infrastructure.

In Appalachia, we made a decision to put up for sale our shallow gas assets, in order to focus our CapEx and efforts on larger potential plays. We plan to maintain an active exploration effort looking for shale gas in Appalachia. The shallow gas assets represent a small piece of our portfolio. They account for approximately 1% of total Company production and a little over 200 Bcf of proved reserves. These are very low decline rate reserves, and this is a time when the market is looking for these type of assets to put into MLP structures.

We should receive more from these assets in the marketplace than is being reflected currently in our stock price. Our intention would be to close on this sale in late 2007 or early 2008. Given our increased CapEx and the probability of lower-than-expected second-half 2007 gas prices, the proceeds from this asset sale, together with a modest increase in our debt, will allow us to execute our capital program while maintaining by far the lowest net debt ratio of any company in the peer group as we move into 2008.

As we stated in the press release, this asset sale and our higher 2007 growth target won't affect our previously disclosed 2008 production growth target of an average of 9%.

I will now review our second-quarter net income available to common and discretionary cash flow. Then I will give an operational overview. Tim Driggers will then discuss capital structure, and I will close with some gas macro comments and a summary.

As outlined in our press release, for the second quarter EOG reported net income available to common of $306 million or $1.24 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common, to eliminate mark-to-market impacts outlined in the press release, EOG's second-quarter adjusted net income available to common was $290 million, or $1.17 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 $736 million, or $2.98 per share, versus $621 million or $2.53 per share a year ago.

I will now address some of our operational highlights. In the second quarter we generated 13% organic year-over-year production growth, highlighted by 24% organic gas growth in the US, driven primarily by production in the Barnett. For the second quarter, domestic oil production was up 20% year-over-year. Additionally, our first-half North American ex-Barnett growth averaged approximately 7%, indicating that EOG is not just a Barnett story. You will recall that our full-year goal for the ex-Barnett assets is 6%.

I will commence our operational review with our North Dakota Bakken horizontal oil play, then I will shift to the Barnett and to other North American areas, and I will close with Trinidad.

In North Dakota, the new news during the quarter is that by applying our Barnett Shale completion techniques to this play we have raised the relative play economics to a standard that now exceeds those of the Barnett Shale. That puts it in the top class of high-return plays in North America. Before these improvements, our wells were coming on at initial rates of 400 to 500 barrels of oil a day. Now we are routinely getting initial rates of 1,500 to 1,600 barrels of oil per day.

Our typical well in North Dakota now costs $5.25 million, recovers 700,000 barrels of oil a day net, and generates a 100% direct after-tax rate of return. For those who don't have your calculators handy, that is a $7.50 barrel net direct finding cost.

We started the year running one rig in this play. We are currently running four rigs and anticipate ramping up to eight rigs in early 2008.

This play has a lot of characteristics of the Barnett Shale. I.e., a large amount of oil in place per section -- actually about 9 million barrels of oil in place per section; only about 9% recovery even using horizontal drilling; and production decline curves that mirror the Barnett. We expect this asset will increase EOG's oil production throughout 2008 and 2009, and you will be hearing more about this play in future quarters.

Now I will switch to the Fort Worth Barnett, where our results continue to outperform expectations and we expect to exceed our previously stated production target of 280 MMcfe per day for the year, all organic. As an overall statement, I will simply repeat what I said last quarter. The Barnett continues to overachieve regarding our expectations, and we have met or exceeded every promise we have made to the investment community regarding this asset.

I will also add that the Barnett is likely the highest ROR large natural gas asset in North America, and EOG has a higher proportion of this asset relative to our total size than any other large cap independent. We believe it is the highest ROR large natural gas asset in North America because of the unique ratio of well cost to reserves and decline curve characteristics.

As I stated on the last call, we continue to believe the intrinsic economics in all parts of the Barnett Shale, including the western extension counties, are superior to the Fayetteville Shale and the Oklahoma Woodford Shale play.

Key takeaways and our current stage of development in each area is as follows. First, in Johnson County, using baseball parlance, we are in about the third inning of our development stage. We continue to see noticeable improvements in completion technology and well spacing that will potentially net us a higher recovery factor. We continue to generate a higher proportion of monster wells than we had initially expected, several of which we articulated in our press release. The bottom line is that Johnson County results continue to exceed our expectations.

Secondly, in the western counties of Jack, Erath, Palo Pinto, and Hood, and in Hill County which is to the south of Johnson County, we are in the first inning of development. In Hill County, we have drilled each wells this year, completed four wells for sales, and the reserves per well are within our forecasted range.

In the western counties, we are underway with a 22-well development programs in Erath and a 15-well development program in Hood. We highlighted a few of these western county wells in our press release. Although they don't have the eye-popping initial production rates that Johnson County has, they represent the bread-and-butter results that typify these areas.

The third and last point I will make is that we are currently running 23 rigs, 16 in Johnson County, one in Hill, and six in the western counties. Of these 23 rigs, 11 are new automated rigs. By early '08, we expect to have 19 new automated rigs in our fleet. The importance of these new rigs is that they have been proven to reduce the drilling days by approximately half the days of a conventional rig.

This is the first step in our cost optimization program. We will unveil the second step at our November analyst conference.

The other of EOG's large scale plays is our Utah Uinta Basin Mesaverde asset. In the past, we have probably underpublicized this play. It has been one of our main drivers of our ex-Barnett growth and is a consistent high ROR play. In my opinion, this was one of the key assets involved in the recent Kerr-McGee transaction. Ours is the same asset as the one that was involved in the Kerr-McGee transaction, except ours just has a lower cost base.

We are currently running nine rigs in this play. The key attribute of this asset is, similar to the North Dakota and Bakken assets, a very high reinvestment rate of return. Typically, our Uinta Basin direct after-tax rate of returns have been 30% to 40%.

Before I leave North America, let me mention midstream infrastructure. EOG has elected to build its own intrastate gas pipelines and, in some cases, gas processing plants, in part of its Barnett Shale development as well as its North Dakota oil play. This is a new strategy for EOG as we have not previously been in the plant or pipeline business for gathering pipelines of this size.

We have done it for two reasons. First, it makes business sense to build and control infrastructure if it is not already in place around new, large assets. Second, the MLP market offers a possible arbitrage opportunity farther down the road once these assets are established.

Now I will turn to Trinidad. During the second quarter, we exceeded our contract takes in Trinidad, and we have increased our full-year production estimate in yesterday's 8-K. Additionally, we finalized the gas contract for our Block 4(a) discovery a few weeks ago, and we are in the final stages of platform design for this project. Sales under this project will boost overall Trinidad production by about 60 million a day net commencing in early 2010.

I will now turn it over to Tim Driggers to review CapEx and capital structure.

Thanks, Mark. For the second quarter, total exploration and development expenditures including asset retirement obligations were $925 million with less than $1 million of acquisitions. Capitalized interest for the quarter was $6.8 million. Year-to-date, total exploration and development expenditures including asset retirement obligations were $1.827 billion with $1.5 million of acquisitions.

At June 30, total debt outstanding was $884 million, and the debt-to-total cap ratio was 12%. At quarter end, we had $59 million of cash on the balance sheet.

The effective tax rate for the quarter was 34% and the deferred tax ratio was 80%.

Yesterday, we filed a Form 10-Q for the second quarter and a Form 8-K with third-quarter and updated full-year 2007 guidance. For full-year 2007, the 8-K has an effective tax range of 34% to 36% and a deferral percentage of 70% to 90%. The CapEx budget for the full year is $3.6 billion.

Now, I will turn it back to Mark to discuss gas macro and concluding remarks.

Thanks, Tim. Regarding the North American gas macro, it is apparent the second-half 2007 gas prices will be disappointing due to higher than expected LNG imports (inaudible) surprising domestic production growth. The question now becomes -- what happens in '08?

It appears to me that in '08 industry production will continue to decline in Canada and we will likely have less LNG impacts than previously thought because of the Japan earthquake. Likely higher oil prices will discourage fuel switching, so the '08 wildcards will be winter weather and domestic supply growth.

Because of the power of the Barnett Shale, I have become less pessimistic regarding the domestic supply growth. I would say 1.5% domestic growth is possible in '08, while total Canadian supply will likely fall another 2.5%.

For 2008, EOG will likely hedge gas more heavily than in 2007, market permitting. That doesn't indicate nervousness about the '08 gas market, but it reflects the reality that our stock has apparently been punished more heavily than others this year because of our unhedged position. In my opinion, I will say a relatively unhedged position.

In my opinion, our superior per-share production growth, low debt, low unit costs, high returns, and quality asset base have been subsumed by short-term concerns regarding natural gas prices; and perhaps a heavier hedge position in '08 would diminish those concerns. Our financial hedge position was articulated in yesterday's 10-Q filing. For 2008, we already have about 12% of our North American gas production hedged at an $8.79 Henry Hub price. We would like to have about 30% to 35% of our 2008 gas production hedged before year-end.

Regarding oil, we are much less likely to hedged forward any volumes as long as the market is in backwardation.

Now let me summarize. In my opinion, there were five important points to take away from this call. First, the organic production growth machine is running better than ever, and our incremental volume growth from 10% to 11.5% is comprised primarily of domestic oil and NGLs.

Second, we have a burgeoning new domestic oil play in North Dakota that is generating high-rate wells and 100% direct reinvestment rate of return, and will drive increases in EOG's total oil production through at least 2009.

Third, even with the current low gas prices, EOG has devised a capital plan to take advantage of the MLP arbitrage, have high '07 and '08 production growth rates, and still keep net debt by far the lowest of the peer group.

Fourth, and I think most important, EOG has collected a stable of premier high reinvestment rate of return domestic assets that we believe are second to none. These are characterized by two parameters -- large size, and much higher than typical upstream reinvestment rate of returns created by a unique mix of well cost to reserves and production rates generated. These are the Barnett Shale, which is the premier gas asset in North America, the North Dakota Bakken, and the Uinta Basin. These assets give EOG an edge in generating superior returns as well as production growth.

Which leads me to my fifth and final point. Fifth, even with low gas prices and a relatively unhedged 2007 position, we again expect to be a peer group leader in 2007 ROCE, as we have been for the past eight years.

Before I turn it over to Q&A, I will mention that our 2007 analyst conference is scheduled for November 13 in Houston. Additional details will be forthcoming. Thanks for listening and now I will turn it over to Q&A.

(OPERATOR INSTRUCTIONS) Tom Gardner, Simmons & Company.

Good morning, everyone. With the recent success you have had in increasing your Bakken oil production and the rig count there that is going up, is there any desire within your Company to create a more balanced product mix? Can you give us your views on the outlook for oil versus gas?

Yes, we are pretty sanguine about the outlook for crude oils in terms of just looking at overall worldwide supply and demand. I guess our outlook for the next five years is that we think that most predictions that are out there are genuinely -- or generally -- where they may be missing the boat is on the non-OPEC supply growth. I think most people that have predictions, every year they are overly optimistic on what is going to happen with non-OPEC supply growth.

So it is our feeling that oil prices have a pretty fair chance to be pretty robust as we go forward. So yes, we are optimistic on the oil side. So we have sent signals to all of our operating divisions to certainly see if we can shift the balance of our portfolio organically to a bit more oil mix.

I believe this North Dakota Bakken play is going to do that. The question is, how big is this play going to be? But obviously, we are starting the year with one rig; as we get into early next year, we are going to be running eight rigs. So you're going to see our oil production ramp up considerably.

The real movement of that is going to occur in '08 and '09. You are just seeing the beginning of that movement in the second half of the year as far as our oil production growth. But I think it's going to become more marked when you see our forecast come out for '08. We will put those forecasts out in our analyst conference as we typically do in November.

Okay. I would like to get a little more color on this completion technology that is leading to higher rates and recoveries in the Barnett.

Yes, it's -- again conceptually, we don't disclose a lot of information on our Barnett completion technology. Again, I guess the point I will make on the Barnett completion technology, for example, these monster wells, you don't see a lot of our peer companies touting monster wells in Johnson County. That is simply because they don't have them. That is because we believe we have a competitive edge on our completion technology in Johnson County. They're completing wells in identical [lock] to us, but they're not getting the quality of wells that we have. Wells that are, say, north of 6 or 7 million a day in initial production. So it's a technical edge that we have that we believe other companies don't have.

Is any of that proprietary? Or do you think that through the service companies that leaks out rather rapidly?

None of it is proprietary that we have some patents on or anything like that. But it is just application of existing technology, really.

But what we have done is taken just some those concepts to North Dakota. Some of them are, I would say, known by everybody. It is staged fracing. It is basically fracing multiple elements along the lateral in North Dakota. But it is just how we do that, really, is where it has happened.

But basically, we have just taken some of those conceptual elements and simply pull it. When we started the year, we thought we had a play in North Dakota that the average net recovery per well was going to be something like about 250,000 barrels of oil, and a well would to come on initially at a rate of 400 or 500 barrels a day. And at 250,000 barrels of oil reserves per well, and roughly a 5 or $5.25 million well cost, you had a play that was marginally economic; but not anything that you could do backflips over.

So we knew there was a whole bunch of oil in place, but we had to do something to get the recoveries up or we really didn't have a play that was that great. That is why we started the year running only one rig. But after we applied some of these Barnett techniques, suddenly we got the wells up where we are recovering now roughly 700,000 or so barrels net, which is closer to about 900,000 barrels, 850,000 barrels gross, which is what most other companies would quote you. Now we have taken a project that now has turned into a 100% rate of return project.

I see, I see. That's great. Quick question on the Appalachia sale, then I will let someone else hop on. Are you planning on keeping the deep rights on that asset sale?

Yes.

Okay, thank you.

Gil Yang with Citigroup.

Good morning, Mark. Could you comment on, going to the Bakken for a second, what the well costs were for the 400 to 500 barrel per day wells? Was the decline rate a Barnett-like decline rate as well?

I'm not -- the well costs were about the same for the wells earlier in the year than they are now, roughly. So that the issue is really we just improved the well quality quite a bit.

The decline curves are, I would say, approximately similar to the Barnett. So these high rates, the 1,600 barrels a day rates that we put in the press release, those are not consistent rates. You have a very high decline. I can't quote you that they're specifically identical to Barnett decline rates. But they are typified by high declines in the first couple years; then the wells will level out and have relatively low declines after the first year or two, and relatively long lives. Which is kind of typical of all horizontal wells.

The 400 to 500 barrel per day wells were also horizontal, or are those just vertical?

No, they were horizontal also. All the drilling we have done -- this play is very identical to Johnson County in that the bottom line is in Johnson County vertical wells were totally uneconomic. The same thing is in this Bakken Play. Vertical wells were totally uneconomic and the only way to commercialize this play was horizontal drilling.

Okay, so the horizontal wells have gotten a lot better in the last year?

Absolutely, yes.

At what point do these wells need to be put on some kind of pump? Given that gas probably comes out more easily at low pressure, but oil won't because it's got to lift itself up. At what point -- how many years out do you need to start putting lift on these?

On some of the earlier horizontal wells, we put them on pump after about six months. We would anticipate with the way these wells are flowing that it might be a year before they would be on pump.

The newer wells.

How does that affect the operating costs?

We're bringing electricity in currently to this part of North Dakota. It will just be a slight increase on operating expense (inaudible) costs.

What is the basis versus WTI for oil in that region?

Yes, it is not any big huge differential [WAC] on there. The oil ends up going through a refinery in Minnesota via pipeline, so it is not a $4 or $5 differential. I can't quote you exactly what it is. Perhaps Maire can look it up and get back to you, Gil. But it is not like Canadian [crudes] or some of that stuff.

Okay. With Trinidad, Block 4(a), I think you called it Toucan?

Yes.

Can you comment on the pricing you're getting on that new contract?

It will be linked to a basket of commodities such as ammonia and methanol, primarily. But it is linked to the Caribbean FOB prices for some of the indigenous items down there.

I think in the past you have hinted that the pricing is more favorable than the previous contracts. Could you quantify that a little bit?

Yes, I can't -- I don't want to quantify it on there. But it is more favorable than some of our previous contracts that we have down there. But it is tied to a basket of those kind of commodities.

But once this contract comes on line, your average Trinidad price should rise?

Yes, yes.

All right, thank you.

David Snow with Energy Equities.

Yes, I think you have got all my questions now. Thanks.

Brian Singer, Goldman Sachs.

Thank you. Good morning. In the Bakken, can you provide a little more color on over what portion of your acreage you have tested, and any opportunity to lock up additional acreage surrounding what you already have?

Yes, Brian, we said at our analyst conference back in November of last year, when we had only drilled about four wells, that we thought this thing was 30 to 70 million barrels of oil. Currently we have about 13 wells drilled; and we have also shot about 300 square miles of 3-D. So we do have a little better feel for that size; and we have increased that estimate from the 30 to 70 million to 50 to 70 million.

But we're really not ready to say much more about it than that. We do feel very good about the well results we have had, well by well. We are in that middle Bakken zone, the same zone we had on the other side of the Basin.

We are drilling a few stepout wells, but primarily in one area, in that partial area right now, and getting these very good results.

The risk still remains for the overall play -- how will those sweet spots be distributed within the overall oil accumulation? That is something that we think we're understanding better from a structural and a stratigraphic point of view both. Both have impacts on where those sweet spots are. We feel like we do have a competitive advantage in understanding that.

But we're really not ready to say how much of our acreage -- of that 130,000 acres that we talked about at the conference last year -- is going to be really good. I would say that we are optimistic about that, and we are still accreting acres in the area.

Just to be clear, did you mention that most of the wells that you have just so far are in one specific part of the acreage? Or were there any wells that were tested over a wider?

No, I would say all the wells -- the 13 wells are really in two specific areas. The vast majority of those are really in one specific area at this point.

Great, and do you see an opportunity here to expand that position?

Yes, we do.

Great. Now switching to Canada, any updates on Canadian shale drilling over the last couple of quarters?

We mentioned again at the analyst conference last year, Brian, that we had about 80,000 acres in a Canadian shale play. At that time we attributed somewhere between 1.2 and 2.4 Tcf net reserves to that play. Obviously, improving.

At that point, we said that we were completing a vertical well and had planned to drill a horizontal well in the first quarter of this year. We do plan to update the community on what we're doing in that play at our upcoming analyst conference in November. But I mean you must realize it is a very competitive play right now for acreage, and so we're just really not ready to talk about it any more than that until November.

Okay, thanks.

Brian Kuzma with JPMorgan.

Good morning, guys. What is the average lateral length you guys are running in the Bakken play?

4,000 feet.

Do you have any updates on your conventional exploration program, either in Trinidad or an update on the Cotton Valley play? Are you guys running any horizontals in the Cotton Valley play?

No, we don't have any updates for you in Trinidad on any exploration. In the Cotton Valley play, we don't have any active horizontals going on. We may drill one sometime late this year or early next year. But nothing -- that is not an active area for us as far as horizontal at this particular time.

Okay. Then to clarify, in Appalachia, you are still going after the Marcellus Shale Play? Is that part of the deeper acreage?

Yes, that's correct. In Pennsylvania and New York, we have about 230,000 net acres including some net acres that are earnable within our Seneca National Fuels joint venture. We are still planning to have by the end of the year about 10 wells drilled. Most of those will be vertical, some horizontal. We should know a lot more by the end of the year as to the efficacy of that play.

Okay, that's it for me. Thanks, guys.

Bob Morris, Banc of America.

Good morning, Mark. You mentioned taking advantage of the MLP arbitrage. On the midstream side, don't think you have a whole lot as far as assets right now. So going forward this year, next year, and beyond that, how much annually do you expect to spend capital-wise as far as building that midstream infrastructure?

Yes, this year, we probably are going to be spending in the range of $150 million or so probably on midstream assets. What is getting us into the midstream here is primarily -- we have got, I would say, brand-new assets here in North Dakota and the Barnett where there was no infrastructure. Basically, the choice there is do we have a third party build the infrastructure, or do we build it ourselves? [Where] it's just flat brand-new assets with no infrastructure existing.

So obviously, as we develop some of these assets in the Western Barnett and Hill County, we will be putting in our own infrastructure as opposed to having a third party do it. Depending on how big the North Dakota play gets, we will see how much infrastructure we put in there.

So how much we spend in '08 and '09 will depend on how big some of these plays develop out to be and whether we would ultimately spin them off into an MLP. That one would probably be an in-house MLP.

Just to make a side comment on MLPs, we are in the camp that, as far as doing an E&P-based MLP, that is something we would definitely not do in-house. We're very strongly in that camp.

But as far as doing some sort of a pipeline plant MLP, if that arbitrage existed a couple years down the road, we would seriously consider that.

Right, so it will probably be a while before you have got enough critical mass to have something of size to be able to do that.

Yes, the bottom line is exactly that, yes.

Okay, second question. You noted that Barnett Shale production is exceeding expectations. You will probably exceed the 280 million a day you had mentioned before. The midpoint of your full-year natural gas production guidance dropped just slightly. So if you're going to be higher now in the Barnett, where is the shortfall going to be overall then?

Yes, the shortfall is going to be in gas in the ex-Barnett. But where that is going to be made up is in liquids in the ex-Barnett. Said net-net what we're doing is the ex-Barnett is still going to achieve its 6% growth, but it's going to come through NGLs and crude oil instead of natural gas. So that is how everything works out.

So you have got an arbitrage that didn't exist before for the liquid stripping. Is that essentially what you're saying?

Yes, that is part of it, yes, that is basically it. What we have done is we have -- I will say we have displaced some of our gas drilling in some of the ex-Barnett areas and replaced it by funding more money into the Bakken play.

Okay.

That is just basically our view of the second-half gas prices versus drill prices.

Just last question here, you had mentioned that part of your budget would be funded with the proceeds from selling Appalachia. Of course, earlier in the year the concern was that if nat gas averaged below 7.25, which at this point it appears it probably will, that you might reduce spending.

Is that just not an option now, given the Appalachia sale? Or is that still something that you're keeping an eye on, that might cause you to scale back spending?

Yes, we probably will not scale back spending. Basically, we have supplanted that plan with the plan of the Appalachian way to do it. Where our net debt at year end will be a function of when we elect to close the sale. That is a bit dependent on kind of some of the tax issues we have, as to when it would be more beneficial to close the sale of the Appalachia property.

So what I would say is we view our net debt as -- where is our net debt going to stand at the end of the first quarter '08? Because we may or may not close the sale before December 31. So we are trying to target a net debt ratio in the range of about 13%. We think would be in the range of about 13%, if we closed the sale by year-end.

What is your tax basis in those Appalachian assets you are selling?

Yes, it is fairly low, unfortunately.

Okay, great. Thanks, Mark.

[Ted Zott] with Bear Stearns.

Good morning, everybody. Thanks for the call. This may sound a little surprising coming from a debt analyst, but when I look at your debt-to-capital 12%, which is really strong obviously, and your stock Price, I guess the question that comes to mind -- would you guys think about taking other actions to help boost this stock price, other than just implement your plan, which is sort of what we're hearing on the call today?

Yes, getting to more conceptual discussion here, you know, we have got -- the long-term plan is not to keep our debt at these extremely under-geared levels. You know, it is kind of an open secret that we are pursuing horizontal drilling opportunities in places like Appalachia and Canada that we have previously disclosed, and other places also, looking for big accumulations. We're keeping the debt low because, if indeed we find some of these, we are going to have to do essentially startup funding to get those plays off the ground. We will do that with internal funding.

We certainly wouldn't be issuing equity or anything to it. That would likely raise the debt-to-cap into the low 20 range, perhaps, until we get those plays running, until they became self-funding.

The backup plan on that would be that, if indeed we are not successful on finding any of these huge new shale gas plays, and we conclude that they just don't exist out there, then it is certainly a strong consideration that we would use some of that balance sheet to just do a share buyback.

Right. What is sort of the time frame again? I mean you may have said it and I didn't hear it, on those big plays in terms of when you would know?

I think we are probably within -- 2008 will be a critical year on that. It is not years away.

While we are on the subject of some of these bigger plays, I will make one comment. I will just preempt the question that is almost certainly to be asked before I get off the Q&A here. Someone is going to ask us about these big plays, about some of them like a West Texas play.

We always get a question about Culberson County, and ever since our November analyst meeting last year, I purposely downplay Culberson County. I said that was one of our lowest ranked plays. Then on our last earnings call I also significantly downplayed it. Just so we don't get any questions on it, I will tell you that we have disposed of our acreage in Culberson County, simply because we felt that that one did not meet the criterion that we had set up to be a successful play. So hopefully that will preempt any future questions on that.

Okay, thank you very much.

John Herrlin, Merrill Lynch.

Yes, three quick ones. Loren, with the Bakken, do you have the dolomitic zone? Also, from what Mark was saying, it sounds like you have similar organic and thermal maturity compared to, say, the Montana side. So this is really a completion difference for the results you're getting, or what are the sweet spots?

Yes, John, that is the big question in the whole play. That is the competitive advantage that we currently hold, is that by drilling these dozen-plus wells that we drilled on that side, and taking a lot of core, and doing a lot of work with 3-D, we feel like we understand what those sweet spots are. But we're going to keep that under our vest for today, certainly.

I would say that there are structural aspects, there are stratigraphic aspects of that, that we feel like we understand. We are in the middle zone, John. You have got the shale above and the show below that are fantastic oil source rocks. Maybe 20, 30 feet thick each. Then you got the middle Bakken between those two, which is where all that oil is going, and that is the zone that we're targeting.

It has various lithologies, and that is part of the trick. That is why we are going to keep that close to our chest for now.

Okay, that's fine. One for Mark. You said that traditionally as you pointed out, you have been kind of hard asset light, in terms of your development strategies for infill plays. Now you are adding more [GTPM] assets. Kind of on a going-forward spend basis, how much do you think GTPM would be of the total budget?

What is the acronym?

Gathering, transmission, processing, what you were talking about.

It will probably be something like 5% or so, 5 to 10%, John. Something like that.

Okay, last one for me is kind of the devil's advocate question. You're delivering differential growth; you're outspending your cash flow, which isn't giving you much incremental cash flow gain, especially in a lower price environment. Are you faced with any sort of lease expiration issues to keep drilling so aggressively, if prices are going to stay weak?

Also, regarding hedging, how high would you hedge? What kind of volumes would you hedge in total?

Yes, on the hedging question, we said we would target 30 to 35%. But we would, for example if we got some price spike or so, we would go up to maybe 45%, maybe up to 50% on natural gas.

In terms of the lease expiration question, the only area where we have a lease expiration issue that would -- is in the Barnett where we have roughly the 600,000 acres. So it is a situation there where we could not just stop drilling in the Barnett. A lot of our acreage would indeed fall apart.

But in other areas, if we chose to, for example places like our Uinta Basin, we could easily slow down there and not worry about leases falling apart if we didn't like the gas price scenario for '08 or '09 or whatever. So we have flexibility in certain of our areas to ramp up or slow down.

What is the average term in the Barnett that is expiration susceptible, near-term?

You know, the typical lease term there is between three and five years. So this year, we plan on drilling roughly about 400 wells. Next year we would plan on drilling about 500 wells.

You know, that is also the highest reinvestment rate of return gas asset we have in the Company, so that is probably the last place we would turn off for a couple of reasons.

Okay, thank you.

Adam O'Laughlin, BMO Capital Markets.

My questions were answered. Thank you.

David Heikkinen, Pickering Energy Partners.

Good morning. In the Bakken, it sounds like you are finding fractures that are both generated by hydrocarbon generation and structural fractures. Is that fair for the sweet spots? Is that a fair characterization?

David, I would not dissuade you from that or confirm it. I think, as we said a few minutes ago, the sweet spot game is both structural and stratigraphic. It is something that we're not willing to comment on at this point. It is an active play with active leasing going on.

So we shouldn't think of only structural needs, but you are also seeing other reasons that fractures would be generated across your acreage?

It is a complex problem. It is one that we have put a lot of work into on both sides of the Basin now, with a lot of core work, a lot of geochemistry. We feel like we have a better understanding of that than maybe some others, and we would like to keep that.

That's fair enough. Thinking about the strategy of EOG it sounds like you are wanting to get a little more oily. Focusing your operations in each region a little more on oil. Would we expect over the next 12 to 18 months to see more oil projects coming up at analyst days, Mark? Is that a fair way to think about things?

It is really hard to find oil in North America. That is the issue. I think we may have, with this horizontal drilling, we may have found a pretty sweet oil project in North Dakota. The question is how big is it.

We basically think right now it is 60 million barrels net, which basically what I would leave you with is we have got 60 million barrels net of 100% rate of return project in North Dakota. I will stack that up on a net basis against some of these deepwater discoveries that people are touting, which probably are turning out to be 5 to 10% after-tax rate of return when we clear away the smoke and mirrors.

Whether we can find more of these with horizontal drilling in the onshore US, we are looking for them. That is all I can say. But I would not say it is going to be a radical shift away from our gas weighting. But it will be more of an at the margin shift, really, David.

Okay. Kind of thinking about if you could snap your fingers today, and obviously, you can't change your oil and gas weighting, so this is very rhetorical, would you want to be higher oil weighting today? I mean your gas macro sounded more negative than I have heard you in a while. I just wanted to think about that a little bit.

Oh, I'm still bullish on the gas side. But as I look at things right now, if I can find more of these 100% rate of return projects, that is even better than the Barnett. So I will take some of those.

On the gas macro side, I think where we are looking at is that we have to face up that the Barnett I think by itself is powering some of this supply growth in North America. And the supply growth in North America has surprised me. I didn't think it would be as robust as we are seeing.

But I still think we have got a generally bullish story from North American gas, albeit it is probably in the less bullish than I would have said a year ago.

I appreciate the comments. Thanks.

Joe Allman with JPMorgan.

In terms of the North Dakota Bakken, I know you don't want to say a whole lot, but -- and I missed some of your earlier comments. But the two main areas where you are finding good success, would both of those be east of the Nesson Anticline?

Yes, Joe, they are both east.

Okay. Then with the -- it sounds like your completion technique that you have transferred over from the Barnett is a big help here. Some of the stuff that is west of the Nesson Anticline that doesn't seem to have the natural fractures, and where industry has not yet had success in North Dakota, do you think you might be able to take those completion technique and make that part work? Do you have any interest over there?

I would say not currently. We are looking at the entire Basin, again, from an overall geochemical point of view and stratigraphic and structural point of view. Looking at the whole piece, and we like where we are.

We think the southwest side where the big Elm Coulee field was discovered a few years ago obviously worked very well. We think the flank that we are on now will work very well, also.

Okay. Again, your ability to and your desire to get more acreage, do you think you'll be picking up some more acreage as we move forward?

Yes, I think we will be picking up additional acreage as we move forward.

Okay. Then the completed well costs, in your presentation you're saying $5.25 million. I guess that is a gross number. Confirm that. Then, have recent wells been better than that?

Yes, we think that within six months we will probably be at a $5 million average, maybe beat that. But for right now, use $5.25 million and you get that ridiculously low direct finding cost we quoted to you there of -- was it $7.50? That is a pretty good number. Of course, we will try and beat it. But that is a pretty awesome number there.

Sure, understand. Can you give me your average working interest and net revenue interest over there?

I think overall in that whole play, it is probably going to average maybe about 75%, 80% working interest. And net revenue interest, net revenue interest will probably be 80%, 85% of that number.

Okay, that's helpful. Mark, you spoke fairly strongly about not doing an MLP. Can you just give the reasons for that?

Yes, we just feel that if you do an in-house E&P MLP you are just creating a potential conflict that may bring on subsequent litigation there -- is one thing. In that you try and apportion assets supposedly with no upside, and put them in one pot of net assets with upside in another pot.

The second thing is just the fact of an MLP, which is by nature a declining asset, and then having that tied to a commodity price, which is very volatile, and then having attempt to commit to the purchaser of the MLP that you're going to give that person an ever-increasing dividend stream, if you will. That is something we probably don't want to get involved with.

Okay, are taxes and kind of potential changes in the laws an issue for you as well?

That is something you would have to look at. But we just think it is kind of inherently something we just --. The other two items I quoted are probably more critical in our minds as to why we wouldn't want to do it.

Okay, that's helpful. Then, ex-Barnett on the gas side, did you have any disappoint results that caused a little shortfall there?

No, it is just more of a redirection of capital away from gas in the second half and towards the oil.

Okay. In West Texas, do you have anything, after selling the Culberson County, do you have anything left over there? Previously you talked about kind of having a sweet spot. Also, I guess I thought maybe a bit more time would pass before we really knew the results over there.

Yes, Joe. That's true. In our conference last year we did mention that we had two separate plays there. Another one in West Texas where we had 32,000 net acres at that point, and we thought that was maybe about a 400 Bcf kind of opportunity. That one is still cooking off. We still do not have results to talk about there, but it is still an active play for us.

Okay, can you tell us where that is?

I'm sorry, we can't.

Okay, that's okay. Lastly, and maybe you did this earlier and I apologize. But the horizontal Wolfcamp, can you give us a little update there?

Yes, that is just one of our active plays out there that is kind of one of our bread-and-butter plays in that area. Again, we're running a couple rigs out there. But we have always said that that is a play that is a steady play for us. It is working. But it is not one that we try and bang the drum over, because it is not one that is going to make or break the Company. But it's kind of a steady play where we are running two rigs and making decent money at.

Okay, very helpful. Thanks for your comments.

John Mansfield with S.A.C. Capital.

Yes, good morning. I wanted to ask about the Uinta. Have you drilled and tested in the Uinta to this point, yet? (multiple speakers) I mean the Manco Shale, have you tested that?

We have drilled a Manco Shale well or two. We are involved with another operator there in testing the Mancos. I would say that we are not convinced at this point that it is a Basin-wide kind of play. But certainly there appears to be some sweet spots in the Mancos, and we will continue to try to evaluate that play.

Okay, can you give us any indication of what the rates were on those wells?

I think it is a little early to do that. I mean, really, most of our activity in the Mancos has been nonoperated; and we would prefer that the operator handle that.

Okay, thank you.

Marshall Carver, Pickering Energy.

Yes, just one quick question. How many wells per rig per year in the Bakken? What should our expectation be there?

Probably 10 wells per year per rig.

Okay, that's it for me. Thank you.

Gil Yang, Citigroup.

I'd just ask one question about Culberson, but it's more of a broader question. In your divestiture of Culberson, was that a decision based on the feeling that that would never work? Or was it more an issue that you didn't have the time and manpower to spend on it? In other words, that it was a testament that you had other things to do that were more promising?

It is the latter, Gil. Just on our priority list of the shale plays we were working, we just had others that looked more promising.

Okay, thank you.

At this time, there are no further questions. Mr. Papa, I will turn the conference back to you for closing comments.

Okay, we just want to thank everyone for participating in the call, and we will talk to everyone three months from now.

Ladies and gentlemen, this will conclude today's conference call. We do thank you for your participation and you may disconnect at this time.