EOG Resources Inc (EOG) 2005 Q4 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources fourth-quarter 2005 earnings release conference call. As a reminder, this call is being recorded; and 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 fourth-quarter and full-year 2005 earnings, operational and reserve results.

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

This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to 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 in 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 U.S. investors that appears at the bottom of the investor relations page of our website.

We posted an updated investor relations presentation and statistics to our website this morning. With me this morning are Ed Segner, President and Chief of Staff; Loren Leiker, EVP Exploration and Development; Gary Thomas, EVP Operations; Bill Albrecht, Vice President Acquisitions and Engineering; and Maire Baldwin, Vice President Investor Relations.

We filed an 8-K with first-quarter and full-year 2006 guidance yesterday afternoon. You'll note from this 8-K that we expect to achieve 10.5% organic 2006 production growth, and that we expect our per unit DD&A, G&A, interest, and LOE costs to increase only 7% over 2005 levels, where our 2005 year-over-year increase was among the lowest in the peer group.

Additionally, we're pleased to announce a 50% dividend increase. As you know, we have a reputation as a consistent Company, and this is our sixth dividend increase in the past seven years. As we discuss our operational results in a few minutes, you will note our game plan also remains consistent, with the same hallmarks of high returns, strong organic growth, and low debt.

I will now review our fourth-quarter and full-year net income available to common and discretionary cash flow. Then I will discuss operational and reserve highlights.

As outlined in our press release, for the fourth quarter EOG reported net income available to common of $462 million or $1.88 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 and the other onetime items outlined in the press release, EOG's fourth-quarter adjusted net income available to common was $483 million or $1.97 per share.

For the year, EOG reported net income available to common for the full year of $1.252 billion or $5.13 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 and onetime items, EOG's full-year adjusted net income available to common was $1.272 billion or $5.21 per share, as compared to $577 million or $2.42 per share adjusted for the stock split a year ago on a similarly adjusted basis.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the fourth quarter was $813 million or $3.31 per share, versus $480 million or $1.99 per share adjusted for the stock split a year ago. For the full year 2005, non-GAAP discretionary cash flow available to common was $2.507 billion or $10.28 per share, versus $1.575 billion or $6.61 per share in 2004.

I will now address some of our operational highlights. We finished the year with a 16.2% daily organic production increase, which was above our 15.5% target. North American natural gas production increased 12.2% over 2004. I will first talk about where we overachieved on fourth-quarter volumes; then I will discuss details regarding how we expect to achieve 10.5% organic growth in 2006; and I will close with a review of 2005 reserve replacements.

Regarding fourth-quarter production, our North American and UK volumes were on target with our 8-K midpoint. So our fourth-quarter overachievement was entirely attributable to Trinidad, where we had high December feedstock levels into both the M5000 Methanol Plant and Atlantic LNG Train 4, and also increased sales to the indigenous market.

During the last three weeks of December, we averaged a high level of net sales to the LNG plant. We expect to increase -- excuse me; we expect to continue a high sales level until mid-February, where we will likely be ratcheted back to our contracted level of approximately 20 million a day for the remainder of 2006.

EOG's 16.2% overall 2005 daily production growth was partially driven by a 40% year-over-year growth from Trinidad and the North Sea. But this dynamic changes rapidly in 2006 because of cost recovery and a large government reversionary interest in our Trinidad Ua production-sharing contract [while].

We expect to grow total EOG production 10.5% in 2006, but the growth component will be heavily skewed toward the higher margin U.S. volumes. We expect Trinidad and North Sea 2006 volumes to be roughly flat year-over-year, while Canadian volumes increase about 5.5% and U.S. volumes increase roughly 16%.

The domestic growth will of course be spearheaded by the Barnett Shale, where we exited the year at 100 million cubic feet a day net, which was our original goal set in early 2005. Our current Barnett sales level is 110 million cubic feet a day net.

To summarize the Barnett, all areas are working as well or better than we expected; and based on our positive results, we have decided to channel more 2006 capital into this asset than we originally had intended. Our press release highlighted several new monster Barnett wells that we completed since our last earnings call. Two of these wells are in Northeast Johnson County, while one of them is in Western Johnson County.

But rather than focus on individual wells, the four key trends regarding the Barnett that I want to highlight to you are, first, we're continuing to generate very consistent Johnson County results. The vast majority of the last 55 wells have generated a direct 100% AFIT rate of return. This consistency is obviously important, since we are planning on drilling about 1,500 wells in Johnson County.

Second, we have accumulated enough data to divide our 90,000 Johnson County acres into two trends. Our Western 55,000 acres are merely excellent, while our Northeast 35,000 acres are outstanding and are generating most of our monster wells. Our Western Johnson County wells are averaging about 1.9 net Bcf for about $1.8 million completed well cost; and that generates about greater than 100% reinvestment rate of return. While our Northeast Johnson County wells are averaging about 2.9 net Bcf for about $2.9 million well cost; that also generates greater than 100% reinvestment rate of return. We have also drilled several Western Johnson County near sinkholes during the quarter without encountering Ellenberger water, indicating our original 50% acreage deration or karsting factor may be conservative.

Third, the 500-foot down-spacing results continue to look attractive to us. We now have four Johnson County 500-foot spacing patterns in place, and we're continuing to implement 500-foot spacing throughout the County. Additionally, during the second quarter we will initiate a 500-foot pilot in Erath County.

Fourth, during the past three months, we spent a lot of time optimizing completion techniques for our Western acreage, where the Barnett is thinner and shallower. We have positive results to report from this optimization. Seven out of our last eight of these completions have met our success thresholds in Erath, Hood, and Jack Counties. Our confidence regarding development of the Western areas has gone up considerably based on results of the past three months. We expect pipeline tie-ins by late February, and we will be ramping up from two rigs to four rigs in those areas during the first quarter.

Our overall drilling activity in the play and recent breakthroughs in completions have led to improvements in our Western reserve results. I again want to stress that these Western counties will not yield monster wells like Johnson County. It will be more of a nonflashy bread-and-butter 60% reinvestment rate of return business in those areas, generating about 0.8 to about 1.0 net Bcf wells for about $1.2 million well cost.

To summarize the Fort Worth Barnett, we drove 93 wells in 2005 and expect to drill about 210 wells in 2006. We are currently running 12 rigs, and expect to exit the year with 22 rigs, all of which we have or will have in hand.

We slightly increased our estimate of the potential overall Barnett reserve range that we have captured on our acreage, going from a range of 2.7 to 4.6 Tcf to a new range of 3.0 to 4.7 Tcf. I believe our estimate of EOG's net Barnett reserves will continue to grow throughout the year.

I previously mentioned that we have captured acreage positions on other shale plays that may be economic using horizontal drilling. We have some preliminary results to report regarding our first horizontal Barnett Shale test on our 125,000-acre West Texas Culberson County acreage position previously called our Texas Stealth shale play.

After only a few days flowback after fracture treatment, this well is testing at a 2.25 million cubic feet a day gas rate. It is way too soon to make extrapolations from this data, but we are cautiously optimistic with this result. It will be midyear before we get a pipeline connection to get some sustained production history, so it will be the second half of the year before we have a more specific technical assessment of this well. This well targeted the Barnett zone at about 9,400-feet vertical depth and was an 1,800-foot-long lateral.

Additionally, we are currently flowtesting a vertical Barnett well in a different part of our Culberson County acreage block, but we don't yet have any results to report. As previously noted, we expect to test additional new domestic shale gas plays in addition to Culberson County throughout the year.

Now I will switch to the North American ex-Barnett portion of our portfolio, which we expect to grow about 7.5% in 2006 on the back of 7% growth in 2005. Our two biggest production growth drivers here will be our Rocky Mountain and East Texas-North Louisiana operating areas.

In the Rockies, we plan to drill or participate in 370 wells, up from 220 wells in 2005. We will continue to exploit our Eutaw, Mesaverde, Chapita Wells/Natural Buttes development drilling, primarily spaced drilling 40-acre spaced wells this year. During the fourth quarter of 2005, we tested a 20-acre pilot well which showed essentially no depletion in these intervals. Based on Piceance trend analogs, we believe our Eutaw acreage will likely be developed on at least 20-acre spacing, providing enough development locations at least through 2010. We expect our overall Rocky Mountain production to increase about 13% in 2006.

We expect a 9.5% year-over-year increase from our East Texas-North Louisiana operating areas, generated by production increases from our East Texas, Branton, and Cotton Valley areas, and our North Louisiana Vernon, Driscoll, Driscoll Mountain, and Sligo Fields. During the year we will also be testing two potentially large North Louisiana expanded Cotton Valley exploration prospects, one of which should be decisioned by the next earnings call.

Our South Texas production should increase about 6.5% year-over-year as we continue our success from our standard Roleta, Reklaw, Frio, Lobo, and Wilcox drilling.

Our Canadian shallow program is targeted for over 1,200 wells, about 250 more than last year. Additionally, we have recently spudded two Northwest Territory exploration wells. One is a delineation well from our discovery last winter that tested 10 million a day and 3,000 barrels of oil a day each from two separate zones; and one is testing a new geologic structure. We expect our other areas in North America to achieve positive 2006 growth, contributing to the overall 7.5% ex-Barnett number.

In Trinidad, during the fourth quarter we commenced production under the contract to the ALNG for plant at volumes greater than our 20 million today net contract rate. Our price for this gas is linked to Henry Hub via a contract formula. During December, cost recovery was achieved on our Ua block, and our net revenue interest declined from approximately 80% to 43% based on forecasted production levels and current prices.

Because of this lower working interest, our overall net 2006 Trinidad volumes will be roughly flat with 2005, even though gross volumes will be up year-over-year. This is nothing new. We had expected this to occur, although it did occur about several months sooner than we had previously expected.

On the drilling front, our first well on our 90%-owned Block 4(a) was successful and encountered 399 feet of net pay predominantly in four sands. No water zones were encountered in the well. We plan to immediately drill a second well into a different fault block; and if it encounters pay as we expect, this will be a 200 to 400 net Bcf discovery. We are already discussing a gas sales contract for an indigenous market, and we would expect to have this discovery on sales by May 2009.

Regarding the Deep Ibis project, we expect BP to spud this well in April of this year. This well should take about 150 days to reach total depth.

In the North Sea, the Arthur 3 well is scheduled to spud in March. Beyond that, we expect only a modest activity year because of the difficulty in obtaining a jackup rig. I expect we will participate in only one to two wells during 2006 depending on rig availability.

Now I will address 2005 reserve replacement and finding costs. Our overall reserve replacement was 204%. Note that the Trinidad Block 4(a) discovery I mentioned earlier is a 2006 reserve booking event. During 2005, we did essentially no drilling in Trinidad; so the vast bulk of the Company's 2005 reserve replacement was accomplished in the U.S. In fact, our U.S. reserve replacement rate was 287%.

From drilling alone, we added just over 1 Tcf in North America. We achieved that at a very competitive finding cost, very similar to 2004. Please our website for supporting reserve data.

For the 18th consecutive year, DeGolyer and MacNaughton has separately analyzed our reserves; and their estimate was within 5% of our estimate. This year, we increased the amount of reserves evaluated by D&M. They did a complete independent engineering analysis of 82% of our reserves, up from 77% last year.

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

In terms of cash flow, total non-GAAP discretionary cash flow for the full year was $2.5 billion. For the full-year 2005, exploration and development capital expenditures were 1.858 billion, so 1-8-5-8, including $56 million of acquisitions. So a very low year for acquisitions.

Of the drilling program expenditures, approximately 28% was exploration spending and 72% was development. For the fourth quarter, exploration development capital expenditures were 539 million, with only 30 million for acquisitions.

Capitalized interest for the quarter was $3.8 million, and for the full year it was $14.6 million.

For 2006, as indicated in yesterday's 8-K, our estimated capital expenditure budget is $2.5 billion excluding acquisitions.

With respect to capital structure, at December 31, 2005, total debt outstanding was $985 million; and the debt to total capitalization ratio was 19%, down from 27% at year-end 2004. At year end, we had $644 million of cash on the balance sheet resulting in a non-GAAP net debt to total capitalization ratio of approximately 7%. A majority of cash at year end was U.S.-based.

During 2005, we paid down $93 million of debt and took a onetime interest expense charge of $4.9 million after-tax in the fourth quarter, related to the early retirement of our 2008 notes.

The effective tax rate for the year was 36%, and the deferred tax ratio for the year was 38%. These taxes reflect a onetime $23.6 million charge in the fourth quarter for choosing to repatriate $450 million in foreign earnings under the American Jobs Creation Act of 2004, which allowed us to take advantage of this opportunity at a lower tax rate of 5.25%.

For 2005, the return on equity was 35.5%, and the Return on Capital Employed was 30%, which obviously are excellent metrics. A schedule with the calculation of these metrics is included in our press release.

EOG's Board of Directors increased the cash dividend on common stock by 50% to an annual rate of $0.24 per share. This is the sixth dividend increase in seven years.

Guidance for detailed modeling of the first quarter and full-year 2006 as well as detailed for our current hedge position was provided in yesterday's Form 8-K. You'll note the increase in G&A expenses from 2005 actuals. The 2006 guidance includes an anticipated $25 million pretax for the expensing of stock options, as required now. We plan to file our 10-K with full financials and footnotes for 2005 in late February.

Now I will turn it back to Mark to discuss our hedge position and concluding remarks.

Thanks, Ed. I think we can conclude that what may be the hottest nationwide January on record has eviscerated much of the natural gas heating season. It appears to me that 2006 will be a year marked by relatively high oil prices and high natural gas storage levels.

Accordingly, as indicated in our 8-K, we have changed from our normal, totally unhedged natural gas position; and we have locked in prices at about a $9.77 Henry Hub, for about 25% of our March through August volumes for North America. All the fundamentals for the bullish long-term North American gas story are still in place. We just have to deal with an aberration of probably the hottest January in history.

We have no financial hedges beyond October 2006, and remain totally unhedged for 2007. We have no oil hedges in place at this time.

Now, let me summarize. In my opinion, there are six important items to take away from this conference call. First, we continue to be primarily focused on returns. In 2005, we achieved 35.5% ROE and 30% ROCE, both of which I expect will lead the peer group. Our seven-year track record, which definitely leads the peer group, averages 29% ROE and 19% ROCE, which I believe compares well in any industry and shows our consistency. A schedule with the calculations of these metrics is included in our press release.

Second, during 2005 we increased daily production organically 16.2% and reduced our net debt to total cap from 26% to 7%. We ended the year with $341 million of non-GAAP net debt and intend to keep our debt at this relatively low level during 2006. Depending on the level of 2006 gas prices, we intend at a minimum to repurchase shares, to keep our share count flat and hopefully reduce our share count with free cash flow.

Third, in a rising cost environment we think we're doing a better job than most in controlling year-over-year unit cost increases. Using one sell-side analyst's report, our 2005 unit cost increases were the lowest of the peer group. Our 8-K guidance shows that we can expect these costs to be up 7% in '06, which I expect will compare favorably with our peers.

Fourth, our Barnett Shale play continues to develop better than expectations, and our confidence in the Western counties has improved to move us into a development mode in Jack, Erath, and Hood counties.

Fifth, our North America ex-Barnett growth engine continues to run very well and still has multiyear legs. With our gas discovery in Trinidad we're also seeking additional markets there.

Finally, we believe we can generate an average 9% organic production growth in 2007 through 2010, while we maintaining very low debt, generating high ROEs and ROCEs, and depending on the level of hydrocarbon prices also generating free cash flow. Thanks for listening and now we will go to Q&A.

(OPERATOR INSTRUCTIONS) Benjamin Dell, Sanford Bernstein.

I just had two questions really. One was on a comparison between your Canadian and your U.S. business. The U.S. business appeared to perform very well in terms of reserve replacement and F&D, versus the Canadian business in 2005. Are you looking to direct more capital into the U.S. relative to Canada, going forward from here, in terms of sort of scaling back the relative investment?

My second question was really around Trinidad and what type of reserves you really thought you would need in Deep Ibis, to justify development and maybe sort of building a new [train five].

Yes, in your first question there, Ben, regarding the Canadian versus U.S. business, the real differentiator there between the Canadian and U.S. businesses is obviously we have got several nonconventional plays that are working very well in the U.S.. Working extraordinarily well, highlighted by our plays -- obviously the Barnett Shale play and our play up in the Natural Buttes/Chapita Wells area in the Rocky Mountains.

Whereas in Canada last year, our activity level was slow to bit by adverse weather, so we really didn't get to do as much as we wanted to do. I would say on a set -- we still replaced over 100% of our reserves in Canada, so I would say we had a decent year in Canada, but not an outstanding year.

As we look into 2006, I would say that I expect we will have a decent year in Canada and an outstanding year in the U.S. We will continue to drill mainly biogenic gas and coalbed methane in Canada. So I would not look for us to have a 300% or 400% reserve replacement in 2006 in Canada. But I think we will have clearly over one 100% reserve replacement again in Canada.

Whereas we are just hitting multiple home runs in the U.S. right now, obviously. Perhaps we have got lucky and have another one out there in our Stealth play in West Texas.

In your second question there, the Deep Ibis play. We are really -- we are targeting in the Deep Ibis play an LNG market there. The hope is our reserve range, we believe, on a net basis, that we're going to be targeting there is about 0.75 to 2 net Tcf on that.

In terms of timing on this thing, we will probably have some definition on the well, hopefully, by the third quarter. But this one will play out pretty slowly in terms of really how we go and how the market development goes. But there is no secret that one of the reasons we are in there with BP is that we hope we can jointly develop a market, an LNG type market with BP, if we're lucky enough to make a discovery there, Ben.

If I could just have one follow-up on the cost side of it. [We are seeing] some indication from private operators in Texas that they have started to offer longer drilling contracts, possibly because the market is softening a little bit. Are you seeing any evidence of that, or is it still cost going through the roof as it has been through 2005?

The cost, as far as drilling contractors, has slowed some, but we are still seeing cost increases on our cost of services. And we would expect, yes, to see those costs increasing [were] 15% to 20% through '06. However, we are locked in on some of our services, somewhere between 40% to 50%. So we are anticipating our cost increases to be somewhere in the 10%, 15% range.

Gil Yang, Citigroup.

A couple of questions. Can you comment on -- obviously Johnson County is fairly different depending on East versus West. In the Western (technical difficulty) you're talking about very large distance (technical difficulty) do you think Erath, Jack, and (technical difficulty) are going to be?

Gil, you were cutting in and out. Could you try again?

Sorry. Could you comment on -- obviously Johnson County is very diverse depending on East versus West over a relatively small. With Erath, Jack, and Hood, you're talking about large distances. How uniform do you think those acres are going to be?

I guess the honest answer is, we haven't drilled a sufficiently dense population of wells to know yet. What we do know is that we have those areas partially shot with 3-D, and it looks to us like the degree of faulting and karsting on the areas that we have shot with 3-D is less intense.

So that on the charts we got up in our IR presentation we got a 50% acreage deration factor. That is probably too severe, but we have chosen not to adjust it right now. In other words, likely more than 50% acreage is probably drillable in those Western areas.

In terms of the relative quality of the wells, it is almost certain we're going to see some variability, and it is not all going to be totally uniform. But whether it is going to be as extreme a variability as we have seen between East and Western Johnson County, we probably don't know enough to know right now, Gil, is the honest answer.

Okay, turning to Trinidad for a second, just two quick questions. After you drill the two wells that you have talked about, is there a possibility to drill more wells and maybe raise that 200, 400 even higher?

Secondly for the price -- for the contract discussions for the gas, do you have any pricing indications at this point? Has the marking looked higher since you renegotiated your existing contract last year?

We are going to do at least two, possibly three wells, in the 4(a) structure here back to back. As we speak today, it looks more like a three-well program.

I think the 200 to 400 Bcf range that we have given you is a fair range to represent the total structure. It's maybe a little bit down from what we had said at the analysts’ conference in October when we had more, I think, --

350 to 500.

(multiple speakers) and part of that is gas price. We believe we're in 470 feet of water and this ranges from 3,500 feet to about 6,500 feet objectives, maybe a little deeper than that in part. It is going to be a fairly complex development, and we believe that we're going to need the gas price a little higher than we have had on our previous contracts. Not an LNG kind of price, but a higher price that does affect our profit splits and our net revenue interest.

So our assumptions have come down on that revenue interest, and that is really why we said the lower range today. But I think the range we put in there today is a fair estimate of that structural prospect.

So that also means that your expectation of the net prices will be higher too?

Yes.

Thank you.

Shannon Nome, JPMorgan.

You referred to Northeast Johnson County being kind of the monster area. You cited, if I got this right, a 2.9 Bcf average, EUR at a $2.9 million cost. That strikes me as conservative relative to some of the initial production rates that you're citing. I guess I am wondering what the production profile looks like.

Is it different than what your original expectation was? For example, where are those monster wells you talked about last quarter, where are those producing now? That would probably help frame this.

Yes, some of the monster wells are indeed wells that on a gross reserves basis are likely to be 5 Bcf, maybe 6 Bcf gross reserves type wells. Remember, the reserves we're quoting you there are net; so got have got to derate that by 0.75 to 0.8 on there. You have to compare that. Most everybody else quotes reserves to you on a gross basis. We're quoting them to you on a net basis.

There is a -- when you blend it in, of course, we're quoting you the best wells. Some of our other wells are less than these sterling wells; they are only perhaps 2 or 3 or 3.5 gross Bcf per well. Sorry wells, terrible wells.

But there is a possibility. Again, the trend that we're seeing is that particularly in Northeast Johnson the more wells we drill, the more -- the higher percentage of monster wells we seem to be generating. Right now, we're giving you that 2.9 number; there is a possibility that number may move up to more wells that we drill. But again, we're trying to give you what we think is a reasonable average for the population of wells.

So that is just the 35,000 acres in that quadrant is inclusive of more than just the sort of monster area, if you will?

Yes, yes. There are some areas that are not quite as good as the monster in that acreage area. We are seeing some variability even -- I have broken it into two acreage tranches. But as we mentioned to Gil, as we drill we see that in, for example, that 35,000 acres, there is some of that acreage that is really I will call it golden acreage, and some of it that is less than golden acreage in terms of the quality of the Barnett Shale, so.

Okay, I guess the other question. What was the cost of that one well that came on at 10 million a day is doing 8 now, the Raam or however you pronounce it; what was the cost of that?

It was probably about standard cost. I would say probably $3 million, 2.9 million. It was typical average that we quoted there.

Okay, thank you, Mark.

Bob Morris, Banc of America Securities.

On the West Texas Culberson well that tested 2.25 million a day, how long a flow test was that? What was your flowing tubing pressure on the test? And what was the pressure drop during that period of the test?

I guess the best way to explain it is in correlation to a Barnett Shale, to a Fort Worth Barnett Shale well, and that is all we really have to tie this to. What we know is we have only been flowing the well literally just four or five days after frac. We just barely got this frac done; in fact we were not even sure we would have any data by earnings time on this thing.

The well has surprised us in a positive manner, in that with just a very small portion of the frac water flowing back, the well has turned to gas. In fact, it is making gas at a much earlier stage in the flowback than your average Fort Worth Barnett Shale well has done.

So in other words in the Barnett, you'd typically have to get roughly 30% of your load water back that you pumped in during the frac before you start getting gas of any quantity. Here we started getting gas at about 9% of the load water back.

So now we don't know if that is a characteristic of this Delaware Basin area, or whether -- we don't know what to measure it against because were in a different area. But it's a good sign.

So we just have a few days' flowback on this thing and it's flowing back up the casing; it doesn't have any tubing in there. It is flowing back at between 800 and 900 PSI, which flowing up 4.5-inch casing is a pretty strong well. It's also flowing a whole bunch of -- continuing to flow a bunch of the frac water with it.

So at this stage, measured against a Barnett Shale well, it measures up or stacks up very, very well. But we obviously don't have any sustained period on it. Unfortunately, this area is pretty remote from any gas pipeline connection, so it is going to take us literally five or six months to get this thing connected. Probably June or July to get it connected to sales where we can really get a sustained flow test. And that is really what we're going to need.

But if you just would compare this to our early starts in Johnson County, I would say it is quite encouraging. We obviously were able to leverage off our knowledge from the Fort Worth Barnett. But frankly, this is better than we had expected from the first well in this area, but it is way too early to make extrapolations as to commerciality or areal extent or anything.

Right, now when you kicked out this horizontal you did not first test in the vertical section. The other well you are drilling elsewhere in this basin, why are you testing the vertical section there, instead of just kicking off horizontally initially, like you did with this well?

It's a little bit removed from the first well. This first well is probably in maybe 12 miles away from the second vertical where we're drilling. We like to get core, we like to do some vertical testing before we go to the horizontal stage. So it's really just the first effort in that second area.

Okay, but you didn't flow test this vertically before you drilled it horizontally?

We had the original well, the [Rector] number 1 well, and we did vertically test (multiple speakers) this area.

Okay. Second question, Mark, on the 500-foot space laterals in Johnson County, have you yet determined whether that is acceleration reserves or if we are going to -- I know your new guidance you don't still put in any additional recovery reserves for those down-spaced wells. Have you determined whether or not you're going to be able to book additional or recover additional reserves on the down-spacing versus the 1,000-foot laterals?

Yes, there is no doubt we're going to book additional reserves for the 500-foot spaced wells. The amount of additional reserves is probably going to be -- by year end, we will have some estimate on that, Bob. It is going to take us a while. We're still trying to model this whole puppy.

The 500-foot wells will have some degree of acceleration and some degree of new reserve booking. But we are just going to be cautious before we throw out any numbers on what some of those numbers are.

Okay. Am I correct in that it looks like in your new guidance there is nothing still in there for those additional reserves from the down-spacing?

That is correct, yes.

Okay. That's it for now. Thanks, Mark.

Greg Pardy, Scotia Capital.

I guess just to come back to the Barnett for a second; and I haven't worked through all of your reserve adds. But how much did you book in the Barnett in '06? Then relative I guess to production levels, that 110 million a day rate now, where would you expect to exit in '06, give or take? Thanks.

In 2005, we booked 359 Bcf through drilling, which put our year-end reserves in the Barnett at just shy of 0.5 Tcf. We are at 471 Bcf at year-end '05.

Okay.

As far as the Fort Worth year-end exit rate, we're not going to try and give specific numbers; and we are not going to give quarterly results from this point forward as to how much we're producing in the Barnett. We just now consider that part of our North American asset base. But what we will tell you is we expect to exit 2006 at north of 150 million a day net from the Barnett this year.

Okay, that's perfect. Thanks very much.

Ellen Hannan, Bear Stearns.

Just a couple other questions for you. One, Mark, you mentioned an exploration test that your planning on the Cotton Valley. Could you give us any more color on that?

Yes, last year at the analyst conference in October, we talked about the Driscoll Mountain discovery, which is about six or seven miles west of Vernon Field. At that time we said that field was probably in the 100 to 175 net Bcf to EOG.

We talked about two prospects at that conference also, one called Eros that we said was 75 to 150 Bcf net, and one called Cheniere in that same volume range.

Currently, we have two rigs running at Driscoll Mountain, and I would say that the upper end of that 100 to 175 range is going to be the most likely number. I think we're getting very good results there from these wells.

On the two prospects, at Eros we did shoot the 3-D; and it turned out that the structure looked very, very robust. We are drilling a well currently, a non-operated well. We don't have results from that well yet, but I would say that what we're seeing so far looks very, very encouraging.

The second prospect, Cheniere, we have captured 50% of that as well; and we're planning a 3-D probably in the second quarter.

Just one follow-up question, Mark. In terms of your outlook for your U.S. gas production to ramp up through 2006, it looks like you're looking really for a pretty strong quarter-over-quarter growth rate. Are there any issues in terms of takeaway capacity, whether it's in the Barnett Shale or elsewhere, that could kind of cloud that at all?

No, we don't believe so, Ellen, although as we go through the year there may be some issues up in takeaway capacity up in the Natural Buttes, the Vernal, Utah, area there, and that Chapita Wells area there and just getting some of the gas out.

We're working with Questar on some plant takeaway and everything, but the numbers we have in the 8-K estimate are the numbers we think we will be able to work with and get out of there. But there are a couple places where we potentially have some bottlenecks. Curiously enough, the Barnett is not one of them. So we've got a few things, but we believe we have got pragmatic estimates of what we will be able to get moved in the 8-K.

Very good, that's it for me. Thanks.

John Herrlin, Merrill Lynch.

Hi, a couple of quick ones. You said earlier -- or Loren said earlier or someone did -- on the Barnett Shale what your ending reserves were. That looks like about 43% of your U.S. adds. Where were the other adds distributed on your reserves in the U.S.?

John, we had significant adds in the Rockies, in the deeper Mesaverde. That was about 239 Bcf. That was the other big booking area. We also added 100 Bcf in East Texas out of our Tyler division, and we had another 110 in Calgary. And then the rest were fairly small compared to that.

Okay. Regarding Canada, the finding costs weren't the best and you talked about the seasonality. We could have another early breakup year now. So Mark Papa, I believe, indicated that things may be kind of flat operationally. Is that really the case?

Yes, operationally, we got a little less than 1,000 of the shallow wells drilled last year, mainly because of the weather. This year, we're targeting about 1,300. Obviously, if we have another extremely wet season up there, we could have some issues on that. So just kind of in the hands of the weather, but expecting a significant ramp-up in our operational execution unless the weather intervenes.

Okay. The last one for me; Mark, you talked about hedges. Say we stay unseasonably tropical here in New York, would you hedge more?

Yes, we might go up to the level of perhaps 35% hedged, depending on what we see as far as our alleged crystal ball, John.

Okay. I guess the very final one; in the Barnett Shale, what is your percentage of PUDs, if you don't mind?

Right now, at year end, John, we're 66% undeveloped.

Thank you.

David Snow, Energy Equities.

Yes, could you give us some estimate of what percentage recovery you're now getting with this Barnett Shale completion method? I have heard it said that you characterize it as just rubblizing the zone. And what percent do you think you're getting out?

David, that is still -- we still think we're somewhere in the range of perhaps 10% recovery or so. That is still something we are wrestling with quite a bit, how much gas is really in place, how much recovery. But it's a very, very low number relative to the gas in place.

I'd figured at 30 to 35-acre spacing, there's 20 wells per section, and you're getting 1.9 to 2.9 Bcfs a well. That is 25% to 35%. What is the matter with that calculation?

Well, it just doesn't jibe with what we think is the gas in place is what is the matter with it.

You don't think there is a lot more, in other words, than 160 Bcf per section?

In parts of that trend, the Barnett is thicker than in other parts, and richer than in other parts, so the recovery factor on a gross basis like that is a pretty hard number to get at.

So there is a lot more still to go, I guess.

We think so, yes.

Okay, thank you.

Joe Magner, Petrie Parkman. He disconnected; we will now hear from Andrew Coleman, Friedman, Billings, Ramsey.

I had a question for you. Can you walk me through, I guess, the plan that you have in place to, I guess, in the 12 to 22 rigs in the Barnett in '06?

Well, we are operating with 12 rigs now, and we have got new builds coming out through the year. We will probably average somewhere 16 to 18 rigs throughout '06. Then as stated earlier, we will end the year at 22 rigs operating in the Fort Worth Barnett.

Okay, are you still seeing a finding and development cost of about $1 for the Barnett?

Yes, it will be $1 except in the Western counties it's going to be a little bit higher than $1. If you look at what we've got posted on our website this morning, we are saying it's probably going to be more like $1.25, $1.50 out in the Western counties for the finding costs.

Okay. In the capital numbers that you talked about today, earlier on the -- where was it? It was [on the order of] 2.9 [Bs] for 2.9 million in Northeast Johnson County. Those well costs include completion as well as drilling, right?

Correct.

The last question is, what is your PUD booking philosophy when you're drilling these wells? If they are 66% undeveloped now, it's kind of like you're going to drill two to prove the book one, (inaudible) drill three, book two PUDs as well?

Andrew, we follow the SEC guidelines, obviously. We don't book a proved undeveloped location until we have established commercial production from a PDP location. So we're generally averaging anywhere from one to two PUD offsets per PDP location.

Okay. Then on the Culberson County well, that is an 1,800-foot lateral which is larger than the laterals that you are using in the Fort Worth Barnett. Are you roughly just scaling the frac size? Or was that a larger or smaller frac you used out there?

That is generally a smaller lateral than we're drilling in the Fort Worth Barnett per lateral. The frac size was smaller than a typical frac size for a typical Fort Worth Barnett well. Basically, what we drilled out there was kind of a test well, smaller scale than a Fort Worth well, just to see if the well would make any gas, really. So one would hope that we can optimize from this first well and improve.

Okay, excellent. Thank you.

David Heikkinen, Pickering Energy Partners.

I just have a question on your hedging program. Did you lock in any basis hedges as well?

No, we have not done anything on basis, and we are probably not smart enough to do anything on basis. So it is not likely that we will try to do anything on that, David.

Okay. Then can you remind me, the New Mexico Wolfcamp play, the development activity, 100 to 200 Bcf, some of the average well performance? Then moving to development, what that means, number of rigs, activity, that type of detail?

Yes, we call it in-house our [Tems] play. The typical well economics there are about 30% to 44%; typical well cost I think is about $1.7 million for maybe about 1.5 or so roughly Bcf per well.

We are currently running out there with I believe it's about two rigs in that area. When we say moving to development, you're probably looking at that big target list on our (multiple speakers) relations page. What that moving to development is supposed to mean there is that the big target list are items that are -- that is supposed to be kind of a potential list.

When we say moving to development, it means that it is now moved from a potential play to a real play, and we will probably shifted that over to -- and it will move from the big target list to a development list. In fact, if you look on the IR page there under the one that says North America ex-Barnett plays, you will see that we have added that under West Texas plays.

Okay.

So it basically says it is no longer a pie in the sky dream; it's a real deal now.

Okay, perfect. Thank you.

[David Cowen], Loomis Sayles.

I was just wondering if you could give me your well cost for the West Texas shale play? The well you drilled out there.

Yes, we probably -- in rough, rough terms, we are probably looking at a well cost of maybe $2.5 million for those things.

You had mentioned an F&D of about 1.25 to 1.5, I believe. So -- ?

No. That was for the Western counties.

Oh, that is for the Western counties of --

The Fort Worth Barnett.

Forth Worth, okay, all right. Do you have a guess at how big these wells are going to be?

No, we really don't. We don't really have an estimate of an F&D cost or anything yet on this stuff out in West Texas.

Okay, all right, thank you.

Joe Allman, RBC.

Could you talk about the thickness in the Delaware Basin Barnett Shale compared to what you were expecting there? Can you talk about any Woodford Shale that you might have seen or not have seen?

We probably are not going to get into thickness, because that is still a competitive issue out there, as to how you pick Barnett and what is real Barnett and what is not. I would say that on our 126,000-acre position we do have both shales present. Unlike a Fort Worth Basin we don't have this karsting deration, so it's 126,000 good acres.

I think what we have done is try to pick that position. We feel like we got in early, so we got in at a much lesser cost per acre than most of the others out there. But we also got in the right place. Not all acres are going to be equal out there.

We high-graded our leasing effort early on to find where it was the right maturity, the right thickness, not so much topography, which is a problem locally out there. But we also high-graded it on depth. Our depth range there we think is the optimal range for the kind of wells these are likely to be in the Barnett, and hopefully Woodford as well, relative to the costs of drilling of those wells.

So we're at a shallower depth than maybe some others with big acreage positions out there, and we are in a mature window relative to some others. We think that is the right place to be for the economics of that play.

Were you searching for the Woodford in this number 1 well that you announced results on this morning?

We did drill pilots in this area, so we know the Woodford is present. But the completion that we talked about this morning is Barnett only.

Then the 2.25, is that an EUR? Could you -- I didn't quite catch what your rates were for the three or four days that you flowed it.

No, the 2.25 is purely a test rate early in the flowback, 2.25 million cubic feet a day.

Okay, so you're not making any guess of what the EUR might be based on kind of those initial flow rates? Or is it just too early?

A bit early for that, yes.

Thank you.

Arjun Murti, Goldman Sachs.

Mark, I think you mentioned in the Culberson County you are waiting for the pipeline hookup at midyear to get more results. Are you going to do any more drilling before that, or will that be second half?

Yes, we will probably drill another one or two wells, horizontal wells, Arjun, so that when we do get the pipeline connected we will likely have three wells that we will be able to connect to sales at that time, just to get more data points.

Got you. Then on the -- I think you said 210 wells in the Barnett this year, did you have a split between Johnson County and the Western counties of those (multiple speakers) ?

Yes, we have a split, I am not sure -- the majority of them will be in Johnson County. If I had to guess I would guess -- I don't know; [Bill], do you?

It's got 150 in Johnson, Mark, and the rest in the extension wells.

All right, so maybe 150 in Johnson and 60 in the Western counties.

That is great, thank you very much.

Gil Yang, Citigroup.

Just going back to Culberson for this question. You had mentioned that there was a bail-out zone above the Barnett. Could you comment on what you saw there? Are you thinking about completing that zone as well?

No, Gil, that relates to our Western counties and Fort Worth area. What we have there are some, in the counties such as Erath, such as Hood, we have some shallow gas zones that we have seen on 3-D seismic, bail-out zones that are above the Barnett.

We estimate that there is probably a couple hundred of Bcf in some shallow gas zones that just we will ultimately drill some wells just for those shallow targets. So that is what that relates to, not the Culberson.

Okay, all right. Thanks.

David Snow, Energy Equities.

I am wondering, what is the gas in place that you're looking at in the two parts of Johnson County? What acre spacing are you assuming on your Bcf per well figures?

David, that gas in place is kind of complex, I would rather not get into that on a conference call here. It is too technical there. So it is probably best not to get into -- it is too complex and technical to get into right now.

What acres are you using for the 1.9 or 2.9 Bcf per well?

The acres are ultimately going to be drilled on [about] 35 acre spacing, so we will be draining something like 35 acres per well.

But the assumptions that are in our charts are based on 100-acre spacing, and 50% of the acres not being good.

Okay, thank you very much.

David Cowen, Loomis Sayles.

You guys had drilled two 160-acre pilots on the Wolfcamp. I'm wondering if you could comment on the results you're seeing. Also you had spoken about the possibility of going to 80 in your spacing there; I am wondering if you still think that is a possibility.

Yes, that is the stuff in this Tems area, this New Mexico Wolfcamp we have mentioned on the Q&A.

I would say we have two of those 160-acre spaced wells fracced, completed now, and both are on flowback and both look economic at this point. 160 probably is the right spacing for that play, at least as far as we know now.

You are still optimistic about 80 acres?

It's too early to say that. We need to watch these flowbacks and drill a few more 160s first.

Thank you.

Tom Covington, A.G. Edwards.

A quick question on the Greater Natural Buttes area. You mentioned, Mark, that you have enough inventory to last you through the end of the decade. What kind of run rate in terms of wells drilled per year are you talking about there?

We are probably looking at drilling 150 wells a year.

Is that on a mix of 20s and 40s, given your sort of analogy with the Piceance?

That will be -- for this year and probably for next year we will be on 40s; and then we will be going to 20s after that, Tom.

What is the well cost out there these days in terms of a well?

1.2 million.

1.2? And the per well reserve estimates are still in the 1 to 1.5 Bcf range?

That's correct.

Thank you very much.

Benjamin Dell, Sanford Bernstein.

Sorry to drag your call out, but I just had a couple of questions. One was really on the Appalachians. You have not really discussed much about that. But I understand you're continuing to build an acreage position. I was really wondering whether Chesapeake's entry into the area has started to pull in oil services, and whether you're planning on picking up activity out there in that region?

Yes, we have a small position in the Appalachians, Ben. At this stage, we talk very little about it. I guess what we will say is when we have something notable to say about it, we will say something about it. At this stage, we are just looking into several geologic plays there but we don't have anything notable to say.

Whether Chesapeake comes in and pre-empts a lot of the services and everything, that is quite possible. It is too soon to see whether that really occurs, though, Ben.

Okay, great. Maybe just harping back to your West Texas, would I be correct in saying the Woodford Shale is about half the thickness of the Barnett? Have you got ambitions to actually try and drill a well where were you could frac both of those in the same well?

First of all, we never would have admitted that it was in Culberson County if we wouldn't had so many sell-side analysts that already pinpointed our wells. We prefer just to call it the Stealth play.

I think you need to talk to the Texas Railroad Commission about that.

The Woodford is the target area there. Some of our initial data and testing says that it certainly has prospects for commerciality in our area. But we just have focused, I guess, initially on the Barnett, not -- mainly because our initial thoughts base are that the Barnett appears to have more gas in place per square mile than the Woodford under our acreage.

We would consider the Woodford to have the capacity to produce gas pretty analogous to the Barnett. But it is just we went after the one that appears to have more gas in place. So we are not down on Woodford at all.

Whether we -- we probably would not try and drill one well to target both zones, because these are horizontal wells and that would have to be a stack lateral. So we would probably, it and when we really did a horizontal specifically for the Woodford, it would probably be a single well at a single target of the Woodford, Ben.

Okay, great. Thank you very much.

Andrew Coleman, FBR.

Just one data point here. What was the number of wells you drilled in the Barnett last year and the capital you spent for that?

93 is what we drilled last year.

I don't know if we have, offhand, the capital.

We can get (multiple speakers) close.

Give us a minute, we will dig out what the capital was we spent there. Let's go to the next question if we have one. We will come back to that and answer it.

We spent a total of about just over $300 million in the Fort Worth division, and that we did have land acquisition cost included in that number.

And G&G as well.

And G&G. So your development drilling is more in the range of about $170 million.

Okay.

There are no further questions. Mr. Papa, I will turn it back over to you for closing remarks.

Okay, I want to thank everyone for staying with us through that lengthy Q&A. I think as you can see, pretty much everything that we had promised over the last two quarters we have delivered on, in terms of production, in terms of leading the league in ROE and ROCE, in terms of paying down our net debt to under 10% net debt to total cap.

And we intend to continue delivering on our promises. So thank you very much for paying attention, and stay tuned for the next few quarterly analyses.

That concludes today's conference. We do appreciate your participation. Have a great afternoon.