EOG Resources Inc (EOG) 2006 Q4 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources' fourth quarter 2006 earnings release conference call. As a reminder, this call is being recorded.

At this time I would like to turn the call over to Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

The risks associated with forward looking statements have been outlined in the earnings release and the 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 the comparable GAAP measures can be found on our website. The SEC permits producers to disclose only approved reserves in their Securities filings. Some of the reserve estimates on this conference call and webcast, including those for the Barnett Shale play will include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our investor relations page of our website.

With me this morning are are Ed Segner, President and Chief of Staff; Loren Leiker, EVP, Exploration and Development; Gary Thomas EVP Operations; Billy Helms, Vice President, Engineering and Acquisitions; and Maire Baldwin, Vice President Investor Relations.

We filed an 8-K with first quarter and full-year 2007 guidance this morning. You'll note from the 8-K that we expect to achieve 10% organic production growth in 2007. Our production growth target and CapEx levels are linked to 2007 natural gas prices. And I'll discuss this before I commence our operational review. Additionally, we're pleased to announce our second consecutive 50% annual dividend increase. As you know, we have a reputation as a consistent company and this is our 7th dividend increase in the past 8 years. As we discuss our operational results in a few minutes, you'll note our 2007 game plan also remains the same with the standard hallmarks of high returns, strong organic growth, and low debt.

I'll now review our fourth quarter and full-year net income available to common and discretionary cash flow. Then I'll discuss our perception of the macro gas market and the impact on our CapEx plans. I'll follow that with an operational and reserve review and close with a summary.

As outlined in our press release, EOG reported net income available to common of 237 million or $0.96 per share for the fourth quarter and 1.289 billion or $5.24 per share for the full year 2006. For investors who follow the practice of the industry analysts who focus on non-GAAP net income available to common to eliminate the mark-to-market impacts and other items outlined in the press release, EOG's adjusted net income available to common was $252 million or $1.02 per share for the fourth quarter and $1.189 billion or $4.83 per share for the full year. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCS was $748 million or $3.03 per share for the fourth quarter and $2.757 billion or $11.20 per share for the full year.

Before launching operations, let me share my thoughts regarding the North American gas macro. I continue to believe there are no structural problems in the North American gas market. By that I mean that we do not have a situation where supply is growing wildly or demand is collapsing. I think that 95% of the reason for the low 2006 gas price was attributal to the fact that January 2006 was the warmest January on record.

Moving to 2007, the 17% warmer than average first half of winter has placed the gas market in a parlous condition. And I think it's too soon to tell if the current nationwide cold spell can offset the warm first half. If we experience a cold or even an average February, we'll likely have decent 2007 prices. I believe we'll end the heating season with 1.4 to 1.55 Tcf in storage, depending on February weather. And I think 2007 Henry Hub prices will average between $7.25 and $8.50. Again, primarily depending on where storage ends.

Regarding supply, I continue to think that concerns regarding U.S. natural gas supply growth are overstated. We're forecasting Canadian production to go from a plus 1% increase in 2006 to a 2.5% decrease in 2007. We're forecasting U.S. gas production to increase 1.4% in 2007.

How is EOG dealing with this 2007 gas price uncertainty? We've tentatively set a $3.4 billion CapEx budget, but may make downward revisions if February turns out to be warm. Our 10% production growth is predicated on the $3.4 billion CapEx. So if we decide to reduce CapEx, our production targets would likely also drop a few points. I'll note that the Barnett is our highest growth asset with high returns. If we did cut CapEx overall, we would likely not reduce our capital allocation to this asset.

I'll now reduce, excuse me, I'll now address our operational highlights. We provided a lot of specific details at our late November Analyst meeting, so I'm going to go a bit lighter regarding individual well results on this call. We slightly exceeded the midpoint of our fourth quarter 8-K volumes and ended the year pretty much exactly as we'd forecast, up 9% year-over-year all organic.

Regarding 2007, our forecast is almost exactly the same as we articulated at our November 29th Analyst meeting. The [indiscernible] points are 10% overall growth comprised of, first, on a total equivalence basis, North America grows 16% and North America Ex Barnett grows 6%. Second, we generate 18% North American gas growth. Third, Trinidad year-over-year production declines since we expect to be ratcheted back to contract take or pay amounts this year verses the contract overtakes we experienced in 2006.

I'll commence our operational review with the Fort Worth Barnett and then I'll discuss our traditional North American Ex Barnett activities and I'll conclude by discussing Trinidad and the North Sea.

In the Fort Worth Barnett Shale, our overall 2006 results have been better than expected. And the best example is that our year-end exit rate was 208 million cubic feet a day, all organic, compared to our original goal of 155 million cubic feet per day. We expect to drill 400 wells this year and almost double production from an average of 147 million cubic feet a day in 2006 to 280 million cubic feet a day in 2007. There have been no dramatic trend updates since the late November Analyst meeting. Everything is proceeding as we projected and that's good.

Johnson County well results are proving remarkably consistent. I'm very pleased with our ability to drive down costs in the western counties using the first of our automated single rigs. And we expect delivery of additional new build rigs commencing in May. In Hill County, we drilled only one additional well in our central acreage area since the analyst meeting and that well on early flow back appears to be even better than the first two Hill wells we highlighted in late November. Hill County development will commence in the second quarter after pipeline installation, about the same time as our Palo Pinto County development commences.

Now I'll briefly discuss some of our other horizontal shell plays. I previously indicated I'd provide updated information regarding our Culberson County and other west Texas drilling and later in the year our Canada shell play testing. Because a future acreage decisions, competitive issues, and lengthier evaluation periods, I'm going to have to back track on the disclosure time line as we have decided to hold off on disclosing any information at this time. I'll simply say that we are continuing to pursue multiple horizontal plays as a high priority and will disclose results whenever we can do so without effecting our competitive advantage.

Now I'll switch to the North America Ex Barnett portion of our portfolio, which is set up for a very strong year in 2007. We expect to grow this portion of our portfolio 6% this year, driven primarily by 16% year-over-year growth in our Rocky Mountain operating area and the resolution of the two infrastructure items that hurt us last year. In the Rockies, our Uinta Mesaverde program is generating the results we expected and we have at least 1.4 Tcf [runnable] reserves in this area.

In the Williston Basin, our Bakken shale horizontal oil play is continuing to expand and our press release highlighted the Warberg 1-25, a recent new well that IP'd at 1100 barrels of oil a day. We'll be ramping up from 1 to 3 rigs in March in this play as we determine the size of this 30 to 70 million net accumulation. 30 to 70 million barrel oil net accumulation. Regarding the infrastructure issues, we expect the East Texas Branton Field third party gas processing plant to start up mid March, which should allow us to produce 15 million cubic feet a day net, and in the Gulf of Mexico we currently have half of our shut in gas production back online and expect the remainder to be online by April 1st. In south Texas, we're continuing to exploit the Wilcox to horizontal drilling, as we noted in our press release, and mixing in the remainder of our North American operating areas provides the overall 6% year-over-year growth.

Now I'll turn to Trinidad and the North Sea. As we related in our recent Analyst Conference, we project year-over-year Trinidad production to decline verses 2006 levels, as we expect to be ratcheted back to contract sales levels compared to contract over deliveries last year. Our production capacity is considerably higher than contract quantities. So it is possible we can sell more gas this year if called upon. Additionally, we expect to have our Block 4A gas contract finalized about mid year. Sales under this contract will commence in late 2009 or early 2010. In the North Sea, we have a 25% working interest in a fourth quarter gas, gas condensate discovery in central North Sea Block 2316F that will likely come online in 2009. There were no reserves booked in 2006 related to this discovery. Otherwise, we expect a slow year in the UK because of limited rig availability.

Now I'll address 2006 reserve replacement and finding costs. This data is more confusing than usual because of the large change in year-end gas prices between 2005 and 2006. We experienced a $4.44 reduction in benchmark Henry Hub gas prices at year-end 2006 from year-end 2005. And this in turn caused us to incur a 179 Bcf negative tail gas or price related reserve revision on our long life gas wells. In spite of this, we reported numbers that I suspect will look attractive relative to peers after everyone has reported.

Including all revisions, we replaced 205% of production at a $2.50 per Mcfe all in cost. This number is consistent with our 5-year average reserve replacement rate of 209%. In the U.S., we replaced 263% of production at a $2.43 all in cost. If you exclude the price related reserve revisions, our all in reserves replacement was 237% at $2.17 per Mcfe. And the U.S. only number was 296% at $2.16 per Mcfe. From drilling alone, we added almost 1.1 Tcfe in the U.S.

In the Barnett, our approved reserve bookings increased from 471 to 829 Bcf during 2006. And [DNMs] cross check of our Barnett reserves was within .2 of 1% of our internal estimate. Please see our press release for supporting reserve and reserve replacement cost debt. For the 19th consecutive year, DeGolyer and McNaughton has analyzed our reserves and their overall estimate was within 5% of our estimate. They did a complete independent engineering analysis of 82% of our reserves.

I'll now turn it over to Ed Segner to review CapEx and capital structure.

Thanks, Mark. With respect to CapEx for the fourth quarter total exploration and development expenditures, including asset retirement obligations were $924 million, which included $8 million of property acquisitions. For -- for the full year 2006, total exploration and development expenditures including asset retirement obligations were 2 billion $996 million, 2996, with only $22 million of property acquisitions. The property acquisitions added 27 Bcfe of reserves.

For the year, of the drilling capital expenditures, approximately 25% was exploration spending and 75% development. Capitalized interest for the quarter was 5.7 million and 19.9 million for the year. For 2007, as indicated in this morning's 8-K, our current estimate for capital expenditures excluding acquisitions is 3.4 billion. We continue to expect a high level of drilling activity in 2007 with the biggest increases coming from our Rocky Mountain and Barnett Shale operating areas.

With respect to capital structure, at year-end 2006, total debt outstanding was 733 million and the debt to total capitalization ratio was 12%, down from 19% at year-end 2005. At year-end, we had $218 million of cash on the balance sheet for a net debt to total cap ratio of 8%. During the quarter, we also retired 47 million of our preferred stock. We had a one-time charge of 4.1 million of premiums and fees related to the purchase. We now have only 53 million of preferred outstanding, which is not a convertible, it's redeemable. The effective tax rate for the year was 32% and the deferred tax ratio was 63%.

Guidance for the detailed modeling of the first quarter and full-year 2007 was provided this morning in a form 8-K filing. For the full-year 2007, the guidance 8-K has an effective tax rate range of 33 to 37% and a deferral percentage of 65-90% reflecting the wide possibility of gas prices. We plan on filing the 2006 10-K by the end of the month.

Now I'll turn it back to Mark.

Thanks, Ed. Now let me summarize. In my opinion, there are 5 important points to take away from this call.

First, as always the game plan remains consistent with the focus on peer leading ROEs, ROCEs, low net debt, and high organic volume growth. In 2006 we generated a 26% ROE and 25% ROCE, and our 8-year average ROE is 29% and ROCE is 20%. I'll compare the consistency of those 1 and 8-year averages with any S&P 500 company in any industry, which reflects on both our strategy and the effectiveness of our organic game plan.

Second, we think we're doing a good job controlling year-over-year unit costs. And we continue to rank either at or near the lowest in most [self siders] unit cost comparisons. Since we're growing volumes at higher rates than many other companies, we'll expect to remain at or near the low end of the unit cost category. In 2005 and 2006, we likely exhibited the lowest percent unit cost rise in the peer group and our 8-K is projecting our overall 2007 unit costs including exploration will increase only 6.5% in 2007. Given the inflationary environment, we think that's a strong performance.

Third, the Fort Worth Barnett continues to surprise us on the upside and will be one of the main drivers to generate 10% total company organic growth in '07 and average 9% per year in 2008 through 2010. The Barnett is the highest reinvestment rate of return large asset in our portfolio. And, with between 4.5 and 6.7 Tcf net reserve potential captured of which only .8 Tcf has been booked, this will provide high rates return with substantial multi-year production growth at gas prices down to at least 650. EOG is fortunate to have an asset with the potential to be almost as large as our total North American booked reserves that can provide meaningful high return production growth under a wide spectrum of future gas prices.

Fourth, we expect the Ex Barnett portion of our portfolio of the North American portfolio to grow 6% this year.

And fifth, we're continuing to work on new horizontal resource plays and while we'll be more circumspect about the results, until we have all competitive issues nailed down, I expect this to be a big driver of future substantial growth.

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

Thank you, Mr. Papa. [OPERATOR INSTRUCTIONS] Our first question comes from Ben Dell with Sanford Bernstein. Please go ahead, sir. Mr. Dell?

Guess we better go to the second --

and hearing no response, we'll go to the next question. Brian Singer with Goldman Sachs.

Morning, Brian.

Hi, with regard to the Barnett, did you do anything different in how you drill and [frack] the most recent Hill County well that gives you any confidence that the future wells would be closer to that most recent results?

Not really, Brian. What we probably -- probably will find, though in Hill County is that the first two wells, which we talked about at the Analyst Conference will likely not be the average wells. We will probably improve on that. What we found historically is that there are county to county variances in the rock issues. And it'll probably take us, I'd say, 7 or 8 wells before we get the frack recipe and where we locate the lateral and how we drill the length of the lateral to really get the nuances of the county just right. So, I would say it'll probably be about mid year before we kind of get the -- get things tuned right in Hill County, mainly because we're really not going to seriously be drilling there until we get the pipeline connected. But I expect we'll have results, it'll be a bit superior to the earlier results we've reported there. If Hill was like the other counties.

Great. And outside of the Barnett. Could you talk about the current cost environment in the Uinta Basin and how sensitive your drilling program there might be depending on where gas prices -- how gas prices play out?

Yes. I mean the overall cost environment is, I'd say, relatively flattish in terms of escalation of service costs over the last 6 months. Not a lot of movement. There hasn't been a lot of downward movement anywhere except in Canada where we have noticed a downward movement in service costs, clearly in the last 6 months. Pretty much everywhere else it's been kind of flattish.

Now in relation to your question, I think it's more in tune that if gas prices were to take a plunge, i.e. a hot February, where would we likely be cutting some of our activity level? And I think what, what we'd be looking at there would be, as I mentioned, the last place we'd be cutting would be likely the Barnett. Some of the other places where we would be cutting, probably, Canada would be a place we'd be looking at whacking the program a little bit even though the cost base has dropped a bit. I think that the Uinta Basin, we would probably maintain that program, but some of our drilling in Wyoming we would look at probably cutting, and then some of our drilling, perhaps in the Permian Basin and perhaps at East Texas and the mid continent we would look at trimming back a bit, also. But our base programs, Uinta Basin and Barnett would likely be one -- some of the last ones on our priority list to be cut.

Great. Thank you.

And our next question will come from David Tameron with Wachovia. Please go ahead, sir.

Hi, good morning, congratulations on keeping -- managing to keep your returns up year after year. Couple quick questions. You had some addition to the price related revisions. You had some negative revisions that says other than price. Can you talk about what areas? Obviously U.S. and Canada, but can you talk about what areas specifically?

Yes, one of the areas was, I guess the biggest area excluding the price related revisions was in Canada. And bottom line on the Canada revisions was that the -- when we had purchased several years ago some of our shallow gas assets, when we're in the acquisition mode up there buying some of the shallow gas assets, we had, we had bought some, some of those small companies for acquisitions and booked some PUDs there. And what we had done is we probably booked more PUDs than turned out to be there. As we drilled some of those PUDs, we had to revise those PUDs downward a little bit. So that was the Canadian portion. And the rest of it was just dogs and cats kind of things.

Okay, and no other play in the U.S. jumped out as far as a bigger share of that, I guess it was, I don't know what the number was, 60 on the gas side?

Yes.

Was there any else that jumped out in the U.S.? Any basin in particular or just?

No. No.

Okay. All right. And then I'm looking at your production guidance for next year. And obviously a pretty wide range. It looks like just doing the math. I know you kind of said double digit 9 to 10% over the next 3 to 4 years. Kind of what are you, how do you handicap that P50 as far as that range? I mean, midpoint you're right at 10%. I guess what drives you to the higher, what drives you to the lower other than gas prices?

You mean 9 to10% range?

No, what I'm saying is if I think the midpoint of '07 guidance you're at 10%?

Yes.

But the range on both sides looks like it's obviously wider than that. What would drive you to the lower end, what would drive you to the higher end as far as production growth?

Oh, I, I think the range that we've given, basically, is pretty much 10% and we just given an outline there. But I think we, we haven't given a particularly wide range on there. I think you can pretty much pencil in 10%. If we, if we give, if we expand the $3.4 billion budget on there. I think if you look in the past, we haven't necessarily missed the number that much. But we're not going to give you a point number in the 8-K on there. So that would be the input I would give to you on that.

All right. All right. I'll circle back on that. Thanks.

Yes.

Our next question will come from Gil Yang with Citigroup. Please go ahead, sir.

Hi. Good morning. I had a question about the Barnett and can you tell us how many locations -- offset locations you're booking for each successful well?

Probably between 1.1 and 2. In that range.

Okay. Is it different in different parts of the Barnett? Are you being more aggressive in Johnson and less aggressive in the outer counties?

Most of our [pudge] locations are in Johnson county, that's where we have most of our drilling activity. But our strategy or the way we book our pudge is pretty consistent across the entire field.

Okay. Mark, question for you is, if you were to cut your capital spending by let's say 10%, [inaudible] 3. -- 3.1 billion or so. Should we, how should we think about the growth rate that you would be able to generate with that lower CapEx? Would it be, instead of 10%, would it be 9%? Or would it be closer to 6 or 7%?

Yes, I'm not going to get into if we cut it, X the production's going to be Y. But, I think what I would tell you is, if we cut our budgets, we'd probably be looking at maybe a couple percent variance from the 10% in there. I don't think we're looking at dropping production down to 6 or 5% in that kind of a range.

Okay. Let me --

I don't want to point numbers on that.

Fair enough. Let me ask it in a somewhat different way. Should we think about it in terms of the incremental last 10% of the dollars you're spending would be less productive than the -- than the average 3 billion that you would spend? So if you spent the first 3 billion and decided not to spend the extra 400 million, that 400 million's less productive on average than the first 3 billion, is that fair to say?

Oh, Gil, you're sounding like a district attorney now. I'd just say that at this stage we're -- if we cut the capital budget, I don't think I don't foresee us having a 5% growth rate, it's going to clearly be higher than that. But, it'll -- I said a couple points, couple percent. So that's what we'd be looking at production falling by.

Okay. And last question is just your commentary about not giving any commentary about new shell plays. Do you feel that in hindsight you've been disadvantaged by some of the -- your willingness to talk about some of the new plays and hence you're sort of trying to be a little bit more cautious there?

Yes. I think clearly we've seen some -- I think we were very, very open at the November Analyst Conference and we've seen some competitive reaction in some of these plays, i.e. some competitors moving in even though we were somewhat vague on the plays. And we've decided to change our strategy and just be a lot more circumspect about these things. So what we've concluded are there are, there are competitors that were watching our, watching our Analyst Conference. And we're just going to have to be a little bit more careful on what we disclose on these things.

So, the message I'd like to leave everybody is, that our emphasis and priority on this concept of horizontal drilling for resource plays is absolutely undiminished, it's still extremely high in the Company. Number two, we definitely do not expect to bat 100% on these plays. Some of them will be unsuccessful, but we expect that some of them will be very successful. And on the ones that turn out to be successful, we'll want to further exploit them by adding even additional acreage and it really does us no competitive good to talk about them at an early stage or in the mid progress stage.

Right. Okay. Thanks very much.

Okay.

Our next question will come from Robert Morris with Banc Of America.

Good morning, Mark.

Hey, Bob.

Question on when you talk about if February's warm or if prices drop down, you would cut the budget. Can you give us a little bit more color on what price, obviously, it looks like 7.25 to 8.50 you wouldn't cut but what price you would cut in? What parameter is that based on? On spending only say 120% of [inaudible] you don't want to go above that or you don't want to borrow more than X million? How are you looking at that as far as when you would cut?

Yes, in -- in rough conceptual terms, if we felt that the full year '07 Henry Hub was going to end up below about 7.25, we would probably look at whacking the budget some. And some, I wouldn't quantify at this time, but we -- we would reduce the budget some.

Now is that a little bit different thinking than at your analyst meeting? Because then you say, we'll borrow whatever we need to as long as this is not a structural downturn and we see prices up in '08 and we want to take advantage of that with having better production in '08?. Is that somewhat of a change? And is this based on not wanting to borrow beyond a certain level or what is driving that as far as that 7.25 benchmark?

Yes. Yes, the change is -- the change is at the time we talked at the Analyst Conference, I gave a price range there of basically 7.50 to 9.50 for likely prices for '07. And that was based on what I thought was a likely range of a 5% warmer to 5% colder winter. The first half of this winter's been, we believe 17% warmer, which is multiple standard deviations out of normal. The change is that at least the first half of winter is a whole lot hotter than what we thought it would be. And the fundamental driver is, there is a certain limit of which we're willing to run up our debt. But beyond that limit, we are not going to run up our debt beyond that. So --

So what are you saying? You don't want to borrow more than 500 million or?

There's I'd say X million. But we ended the year with an 8% net debt to total Cap.

Thank you, and you're balance sheet is in great shape so you could borrow a lot.

Yes, absolutely we could. The game plan is under any set of circumstances we want to end year-end '07 with absolutely the most pristine balance sheet in the peer group. And so we're not going to -- that's an overriding goal. So there is a limit as to how much, how much debt we want to take on this year. And if gas prices were to, were to not look very good for the full-year, then we would take appropriate action with the CapEx side of things.

Is there any scenario where spending would be less than in '06? Is there price level gas if it's 6.50, 6, 7, whatever, that you might see spending less than '06?

That would be $3 billion. I -- I guess if prices fell to some horrible number. But at this stage, I don't contemplate prices would get that low.

So it's pretty remote that you would be below '06?

Yes, I would hope not, any way. Again, I mean, we would manage that by if prices went into some horrible free fall, we would manage it such that our -- we would not balloon our year-end debt to beyond a certain level.

Just quick question. Guidance on overhead or G&A for '07, good uptick over last year, just a little bit of color on what's driving that? And if you're still assuming very little service cost inflation in your numbers here even though you noted the 6.5% cost inflation on other costs per unit including DD&A.

I don't care there's anything special in the numbers, Bob. Just general -- we've got obviously the higher level of on the DD&A side just from the higher level of costs that we've been incurring over the last several years as an industry coming through the numbers. And of course, obviously, if you would, depleting your base.

From what we're seeing, Bob, on a unit cost basis, our G&A for '06 was $0.29 in Mcfe and it's $0.295 per Mcfe in '07. So --

I was just looking at the absolute, is that just higher salaries and back [offs] in county, or is this strictly you're adding more people?

Yes, it is definitely, a people add that we, we ended the year around 1560 employees globally. And we're looking at somewhere in the 10 to 15% uptick like on that.

Okay. All right.

Yes, but on a, like you say, if you take it on a unit cost basis, it's basically a flat number.

Okay. Great. Thanks, guys.

Okay, Bob.

And our next question comes from Tom Gardner with Simmons & Company. Please go ahead, sir.

Good morning. Mark, what fraction of your rigs are under contract, and what does that look like going forward? Are you expecting cost deflation in the rig market?

We've got 75 rigs operating right now and 29 of those are under longer term contract. And as far as going forward, those that are not under contract, we're seeing rates drop anywhere from 500 to $1,000 per day. So about a 5% decline.

Thank you. And can you discuss if your operations may have been impacted by the unusually cold weather in mid January given some companies reporting freeze offs?

Yes, we were experiencing some freeze offs in Canada, and we had a little bit there in U.S., Oklahoma, they got hit pretty hard. So we did experience some.

Okay. And some service companies are reporting that operators have delayed completions during the last two weeks in December. Does EOG have the flexibility to move or delay services? And is this something you'd consider to optimize pricing or realizations?

Yes, we're, you know EOG well, we're always trying to optimize. So we did do some delays on completions.

Great. One last question, I want to discuss decline rates for a minute. Your graph of U.S. natural gas production history. Base decline is often referenced in industry. Do you all care to make a forward projection of what that might look like 3 to 5 years out?

Oh, yes, I don't have that chart in front of me. I think it's showing about --

32%, I believe.

32% right now. Yes, we think the mix as we move to more resource plays and end up with less Gulf of Mexico is not going to appreciably change that decline rate, although, I often get asked that question. The main reason is the decline rate, certainly for the first several years in these resource plays is as high or higher than Gulf of Mexico decline rates. So our guess is, is that decline rate will probably creep up, continue to creep up a percent or so a year for the next 3 or 4 years. And then, but it's not going to go up 50% over the next 8 or 10 years. You've got some basic laws of reservoir engineering that will kick in. So I think it'll get up to 36, 37% and then begin to kind of just flatten out at that level.

Well, thank you very much.

Okay.

Thank you. And our next question will come from Leo Mariani with RBC. Please go ahead, sir.

Yes, good morning. Hate to belabor the point on CapEx here. But have you folks considered on maybe laying on some more hedges to kind of protect yourself here, 2007, in case of a potential downturn?

Oh, we would look at it. But bottom line is the -- if February -- the only way we'd lay on some hedges is if we have a cold February and the [IMEX]continues to run. And if we have a cold February and we draw it on storage to, what I'd say, decent levels, which should be between 1.4 and 1.55, then that pretty much, I think locks in decent gas prices through, I think, pretty much until the -- until we get into next winter. So I'm not sure there's all that much need for hedges. So I -- we would look at it if the full years trip got up around 850 or so. But it's not a case where we would be that concerned that you could get shafted by a warm winter because the winter will be over by the time the price got up that high, I think.

Okay. I was noticing it looked like you really didn't pay any current taxes in the fourth quarter, if I'm looking at your numbers right here. I was just trying to get a better handle on the tax dynamic there.

That's being driven as much as anything by a filing that we've made to change our accounting method with respect to intangible drilling costs. And as a result, we have received a refund actually here in the first quarter. So that is one of the primary drivers of that. But if you look at the full year taxes, what you do have, of course, is a drop in tax rates and the biggest driver on that would really come out of Canada both at the federal level and at the [prudential] level, driving down rates just a bit there. So, those would be, really the two biggest factors. But you're right, the deferred tax rate was up in the fourth quarter, but for the full year was very much in the kind of indicated area.

Okay. And I guess that, it appears to be kind of trickling over into '07. If I'm looking at it right, I mean, you guys are basically expecting a higher deferred tax rate, but also higher overall gas prices?

The range we've given does have in it some range for variability of gas prices, but there's, without question, we could end up with deferred -- we gave a 65 to 90% deferred range, and we could end up close to where we ended up in '06, which I believe was 63. Or if gas prices are weak and our CapEx levels stay strong, then obviously our IDC generation will also be strong and so we're going to be in a very high shelter range in terms of taxes.

Okay. I guess, just can you, maybe just give me a little bit more color on sort of the change related to the IDC? [inaudible] that's obviously a pretty high deferred rate from my perspective from a company your size. I guess I'm sure that overtime in the years forward that's probably going to come down a little bit. Can you just give us a little bit more detail on what the big change was?

It's also a function of the fact you had low fourth quarter gas prices.

Sure.

So that also has an effect in terms of your annual model, but the IDC change that we filed for simply has to do with the ability to accrue IDCs at year end, whereas in the past we'd only actually filed for cash based IDCs.

Okay. One last kind of financially related question here. It looks like your price realizations in the fourth quarter in Trinidad were real high. I was wondering if there was some kind. I know it's happened before where you had like a contract catch up or something, is that what was going on here in the fourth quarter?

The real driver on fourth quarter realizations in Trinidad is really coming off of our methanol based contracts. And as you may be aware, Caribbean based, Gulf of Mexico based methanol prices have been very, very strong. And our pricing structure in Trinidad for the most part is driven by a basket of ammonia prices and methanol prices. And so the methanol component of that is giving us strength in prices in Trinidad.

Okay. In terms of your Barnett program, obviously you've got really nice production ramp expected here in 2007. You anticipate any potential capacity constraints on process or anything like that? Are you basically drilling sort of behind your infrastructure here as your infrastructure is up and running you drill wells, is that how it's working?

Yes, we don't anticipate any infrastructure issues. We've got more places to drill than we really have, I guess CapEx than we plan to spend this year. Got basically thousands of locations. So we can kind of pick and choose where to go, for example, in Hill County we've got a ton of locations, but the pipeline won't be there until the second quarter. So we're just going to not drill there until the pipeline gets there. So we kind of have planned our drilling such that where there is take away capacity currently is where we're drilling. So shouldn't have a problem at all.

Okay. Well thanks a lot.

And our next question will come from John Herrlin with Merrill Lynch. Please go ahead, sir.

Yes, hey, Mark, just some unrelated ones. With the [Wampart] well, did you do anything different? That seemed like a real good rate? And are you trying to get more acreage in the [bucket]?

No, John. The one, actually this well turned out to be a little bit shorter lateral than the previous well. The one thing we have figured out so far up there is there's a, there's a definite correlation between reserves per well and the length of the lateral there. And so what we're trying to do is get a lateral out, if we can 5,000 feet. If we can get it out to 5,000 feet, we think we can get reserves approaching 1million barrels per well. There, it turned out the Warberg we had some mechanical problems and I think we ended up with the lateral there about 3500 feet or so, so it won't be 1 million barrel well.

In terms of the acreage, we have about 130,000 net acres there. By our guesstimate, we think we have the potential area that this Bakken fieldstone covers. We think we've got all the acreage covered in this. What we've done so far really there, you may remember from the Analyst Conference that we've now drilled 5 or 6 wells in a relatively closely spaced area. We haven't really stepped -- taken any giant step outs yet. And so far, we've -- we've had very gratifying results. And we've only drilled with the 1 rig program on this [inaudible] 1,000 acres. In March we'll be ramping up from a 1 to a 3 rig program and starting to take some bigger step outs to really see, was this thing 30 million barrels or is it 70 million barrels? But we think we've got all the acreage we need on the play.

Okay. Next one and last one for me is Canada. All sources with price revisions, you had about $5 finding costs last year. You said if prices were weak with a lot of these other well services related type cost questions, prices were weak, you'd throttle back in Canada, do you need to kind of reassess your program because you pursued things like [bio-genic] gas et cetera or more marginal stuff in the past?

Yes. We would probably, if prices were weak, we would probably look at scaling back the program. The program in Canada in the past has consisted of primarily drilling roughly 1,000 bio-genic wells a year and then doing an amount of I'd say more conventional things. But, primarily the bio-genic program, what we're hoping to do in Canada is to shift that program over the next 2 or 3 years to one that, hopefully becomes a horizontal Shale gas program with kind of a bio-genic gas program as a support to it. That's going to be to a large function of how well this -- the Canadian Shale gas drilling turns out. And we are drilling right now on our Shale gas program up there. We've got a vertical [inaudible] forward, and we're drilling a, our horizontal well now. And we do expect to have that well drilled and [fract] and tested by April 1st when we'll likely have to be out of there and actually moved out of the area because it's winter access only. And --

Thanks, Mark.

Okay, John.

And our next question will come from David Snow with Energy Equities. Please go ahead, sir.

Yes, hi. Could you tell me in the Hood County, the two off set wells, are they 500 feet apart the same as you've been doing with the Johnson County?

No, David, they're over 1,000 foot apart. We've determined that 500 foot spacing out west is too close. And 1,000 foot spacing is probably the better spacing out west.

500 gives you about 40 acre spacing, doesn't it? So is that right and you've gone to 80 acres with 1,000 foot?

Yes, in rough terms, that's correct.

And what's the reserves per well that you look at now on the Johnson County on the 500 foot spacing and on the Hood in west and the 80 acres?

Well, in the western stuff. What we've pretty much said is, the conservative number to use out there is anywhere between on a net basis is anywhere between .8 and a 1.0 net reserves per well in the western stuff there.

Even though in 80 acres?

Yes.

Okay. And what about the Johnson --

Johnson County stuff, I mean, we've got a lot of stuff laid out on our Analyst Conference there. I mean, it differs between western Johnson County and eastern Johnson County. And I'll probably just refer you to some of the website stuff we had in the Analyst Conference there.

Did you ever get to what percentage of the infill or the closer spaced is acceleration verses reserve ads?

Yes. Yes. Trying to remember exactly what number we gave, what was it, about three quarters or something? I think the infields were about three quarters of the -- the 500 foot wells were about three quarters of the reserves of the 1,000 foot wells.

Sounds terrific.

Okay?

Great.

And our next question will come from Ray Deacon with BMO Capital Markets. Please go ahead.

Hey, Ray.

Hey, Mark. I was wondering if there was any update on the Permian or the Lobo trends in the last quarter?

Yes, South Texas in the Lobo trend, I mean, we're continuing to have good results there. Didn't really highlight that much about South Texas.

Right.

The drivers in South Texas for this year will be primarily the three plays. One will be the Lobo trend where we're continuing to operate several rigs down there and having, I'd say, excellent, excellent results.

Right.

That program is generating anywhere between a 60 and 100% reinvestment rate of return as it did last year, we expect that again this year. The second driver will be the horizontal Wilcox program which has got the most big picture reserve potential, and then the third program is our vertical Frio development program there. So, although I didn't say too much on the call about our South Texas program, it's definitely a program that is one of our main drivers of the North America Ex Barnett area and the Lobo is a big part of that.

Right. Got it. And you had drilled two pretty nice wells in the Permian last quarter that you talked about. I guess what's the activity level there going to be like in '07?

Yes, in the Permian Basin, yes, we drilled the ones I might have highlighted last quarter would be either a horizontal Wolfcamp play out there in what we call the [Tems] area. Or it would have been our play, our oil play out there where we're drilling some reefs out there. And both of those plays will be our main drivers in 2007. Also, [inaudible] over there I would say would be steady. We'll have probably, I'd say, moderate production growth coming out of the Permian Basin area. The horizontal Wolfcamp program out there is one that will be a little more sensitive to gas prices, and so that would be one that would be one on the bubble if we'd be watching more closely if gas prices did take a tumble.

Okay. Got it. Great. And just can you refresh my memory on Hill County? How many wells have been drilled so far?

Basically Hill County, in terms of wells that EOG has drilled, we at the Analyst Conference late November there, we said that we had drilled two wells there. And had gotten initial flow test results from them and really hadn't had them hooked up to sales because there wasn't any pipeline. And that they looked remarkably similar to wells, kind of in, generally I think, kind of in the West Johnson County wells. And then we just report on this call that we have a third well in that same acreage area that we drilled the first two. And that that well is just on early flow back right now but it's looking stronger than the first two wells that we had referenced to you.

Okay.

There's a -- there are other wells drilled down there that have gone through the Barnett by other operators drilled in 10 years ago or so, but not really completed in the Barnett, so we have more data points there. But not really a lot of completions in the Barnett. We do have a 3D seismic survey over the area, though.

Great.

So, a lot more data, but there's not really a lot of well completion data yet.

Got it. Got it. Thanks a lot.

And our next question will come from Ben Dell with Sanford Bernstein. Please go ahead, sir.

Hi, Mark, can you hear me now?

Yes, Ben.

At last. Hey, I just actually had one question because some of my others have been answered. It's really just around the U.S. gas production outlook that you guided down about 1.4%. Obviously the Texas data's come out and that looks pretty strong. Something you're benefiting from yourself. I mean, that looks as though Texas is up either 7 or 10%, depending on which data source, is that a number you believe? And I was also trying to get a feel for how you thought the independents hub in the Gulf of Mexico would impact numbers?

Yes, I think, the number I quoted the 1.4%, no, we're projecting U.S. production this year would be up 1.4%, not down.

Okay.

Yes. And in terms of, I mean, obviously, yes, the independents hub will be coming on, I guess that's the third quarter or so this year. The Texas gas production data -- I've -- I mean, it's a discussion I think we had on the call last quarter about the EIA data versus some of the other data sources out there. I don't want to get too heavily into that. I guess it's something you and I may just agree to disagree on. Our feeling is still that production growth in the U.S. isn't quite as robust perhaps as the EIA data is reporting. Although, we are, we are certainly projecting that U.S. gas production will be up this year by the 1.4%.

Sure. And not to labor a point, but on the capital costs et cetera, if drilling day rates were to drop say 15 or 25% throughout the year, do you believe that would make up most of the difference, and therefore you'd be able to keep your activities set pretty much flat?

Yes. Well, the answer is probably no because we kind of anticipate the costs are going to be sticky coming down. The drilling costs may come down that much whether the fracturing costs and other costs come down and probably they, they, by the time we really see those costs might be the second, third, fourth quarters by the time they really work through the system. So, we're, we'll evaluate everything on a basis of what we think our reinvestment rate of return will be. But I'm, I'm not a big fan of saying that costs are going to fall and we'll be able to get the same activity level done by spending less dollars. I guess I'll believe it when I see it. And we haven't seen a lot of evidence of that yet out there in the field, Ben.

Okay. And then just lastly, if you were to cut CapEx, how does the UK exploration program sort of fit into this? Is that an area you still feel has potential to become a core area? Or is it an area where you see opportunities to scale back CapEx?

Yes, we've already scaled back CapEx there pretty dramatically. And so this year will be another year of likely very scaled back CapEx, there Ben.

All right. Great. Thanks very much.

Okay. Thank you.

And our next question will come from Joe Allman with J.P. Morgan.

Hey, Mark, good morning. Mark, do you expect the three rigs in the Bakken will they be staying east of the [indiscernible]?

Yes.

Okay. And I guess you guys have studied kind of all the activity, it's pretty active up there. And just going forward, that's kind of the area you plan to stick in?

Yes, the three rigs we're talking about will be on the 130 acres we've got captured, basically in this one field that we think we found will be developing that. We've got some other ideas up there for trying to find another field. But that would be more under exploration, ideas there. We think we've found potentially a pretty nice jewel there and the first priority is really developing that.

Gotch 'ya. All righty. Thank you.

Okay.

And our next question will come from Richard Moorman with Capital One Southcoast.

Thanks, guys. Congratulations on a very good well-rounded quarter and especially the Barnett results. I was wondering out in the western hood area, obviously right next to Erath, how do you feel this reflects on your plans in the area? You've had two very good wells there now, do you anticipate increasing the concentration in that area?

Yes. The answer is yes. What's really going to happen in pretty much all the western areas this year is activity level for us will pick up in those areas, but it'll be more second half weighted as we get, as we kind of transform our drilling fleet out there as we get these new build rigs, these automated single rigs mixed into our system. If you kind of look at this thing from 30,000 feet, what we can say about pretty much all of our western areas is that we're now pretty certain we can average on a net basis this .8 to 1.0 Bcf per well across kind of all this acreage, if you will. And we're now pretty certain that we can drive down the costs to about the 1.4 Bc -- $1.4 million per well using these automated drilling rigs and using some [frack] techniques that we'll be introducing about mid year.

So -- and you put those two together and that gives you anywhere from about a [40] to about an 80% rate of return. The missing issue is we're really not going to get the equipment, the frack equipment and the rigs in place until mid year to second half of the year to make all these parts of the equation work. So --

Okay. All right.

That's the missing link.

I appreciate that, thank you. And then on the reserves, just a quick wrap-up there. Sort of my first impression with the lower prices was that you were maybe losing some pods or something, but I think I heard you correctly to say you were really losing the tail end of production. So I guess two thoughts and correct me if I'm wrong. So number one, these would bounce back as soon as your price deck was favorable next year? And number two, that present value impact if these are at the tail end is probably nothing?

Both of those are correct.

Okay. Super, well thank you, and good luck again this year and the next quarter.

Thank you.

And our last question will come from David Heikkinen with Pickering Energy Partners. Please go ahead.

Good endurance guys. The net reserves booked per well on the Barnett in 2006?

I don't know if we -- I'm not sure we have that just handy right now, David.

2.2 growth, 1.7 in Johnson County.

Okay.

Western counties about .8 and .6 net.

Okay.

Yes.

That's perfect. Thank you.

Okay. All right. Well, I'll conclude by saying thanks to everyone on the call and we just hope that we have a cold February and everything will work out just fine for us. Thank you very much.

This concludes today's audio conference. We do appreciate your participation, you may now disconnect at this time.