EOG Resources Inc (EOG) 2007 Q4 法說會逐字稿

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

Good morning and thanks for joining us. We hope everyone has seen the press release announcing fourth-quarter and full-year 2007 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call.

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

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

With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bob Garrison, EVP, Exploration; Tim Driggers, Vice President and CFO; 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 2008 guidance yesterday. I will discuss our 2008 volume forecast and business plan in a minute when I review operations. I will now review our fourth-quarter and full-year net income available to common shareholders and discretionary cash flow, and then I will give some gas macro comments and an operational overview. Tim Driggers will then discuss capital structure, and I will close with a summary.

As outlined in our press release, for the fourth quarter, EOG reported net income available to common stockholders of $358 million or $1.44 per share, and $1.083 million -- excuse me -- billion or $4.37 per share for the full-year 2007. For investors who follow the practice of industry analysts that focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impacts and to make certain other adjustments that exclude one-time items as outlined in the press release, EOG's fourth-quarter adjusted net income available to common stockholders was $319 million or $1.29 per share, and $1.074 billion or $4.34 per share for the full year.

For investors who follow the practice of industry analysts that focus on non-GAAP discretionary cash flow, EOG's DCF for the fourth quarter was $865 million or $3.48 per share and $3.058 billion or $12.35 per share for the full year.

I will now address our operational highlights in conjunction with our gas macro view. We had previously provided a 2008 production growth target of 13% to 17% depending on our perception of the 2008 gas market. From our perspective, the North American gas macro situation looks reasonably bullish and we are setting our production growth target at the 15% midpoint of the growth range, which, combined with our CapEx spending program, will enable us to maintain flat net debt year-over-year. I will note that the 15% volume growth is not a pro forma number. We expect to grow volumes 15% without adjusting for the sale of our Appalachian assets.

Regarding the North American gas macro, we think domestic supply will grow about 2% this year. Canadian imports will decline by one Bcf a day versus last year, and because of startup delays in several liquefaction plants, year-over-year LNG imports will be flat with 2007. This provides an essentially flat year-over-year North American supply picture.

Regarding demand, I think the weather during the last seven weeks of the heating season will exert a major influence on full-year prices, which, in my view, are likely to average between $7.50 and $8.50 Henry Hub.

Our 2008 financial hedge position was articulated in yesterday's 8-K. We are currently 33% hedged regarding North American natural gas at an $8.51 per MMBtu average price, and we have 14% of our total company oil hedged at a $90.78 price. For 2009, we have a total of 200 million cubic feet -- 200 million BTUs per day, excuse me -- of natural gas hedged at an $8.50 average price. I will note the 2009 number is 50 million BTUs a day higher than the 8-K we issued yesterday afternoon, since we got another swap executed last night. Market permitting, we may add a few more gas and oil hedges within the next few months.

Our 8-K indicates an overall 15% year-over-year production increase with disproportionately high crude oil and condensate and NGL growth -- 36% and 40% year-over-year respectively. Assuming a $7.50 Henry Hub price, the current count 2008 strip on the Nymex is $8.28. Estimated exploration and development expenditures, excluding acquisitions, will be approximately $4.1 billion. Gathering, processing and other expenditures are forecast to be $280 million. We are targeting flat year-over-year net debt when we take into account the proceeds from our Appalachian property sale, which is expected to close in the first quarter.

This plan allows us to achieve three of our key targets in 2008, which are, one, high overall organic production growth; two, focus on high reinvestment rates of return while maintaining flat net debt; and three, an increase in the liquids portion of our production mix.

My remarks on this call regarding operations will be rather brief, since we will provide a much more detailed rundown of our major plays at our February 28th analyst conference. The key operational points I will note are, first, the primary driver of our overall 15% production growth target will be our US operations, which will grow approximately 23% year-over-year, all organic. We expect our production in Canada, Trinidad and the UK to be essentially flat with last year.

Second, the major driver of our 36% crude oil and condensate production growth target is the North Dakota Bakken play, which is continuing to drill out as we expected. At this time, we continue to feel comfortable with our previous 80 million barrel net reserve estimate, although we are still testing the extent of the play limits and we are also drilling our first down-spaced well on 320 acres.

Nothing significant has changed from our previous call regarding our per well reserve and well cost mix, and we continue to generate greater than 100% direct after-tax reinvestment rate of return economics. I will note that the last 10 wells we have drilled in the Bakken had an average IP of 1700 barrels of oil per day and average net reserves of about 700 million barrels.

Third point, our 40% natural gas liquids growth target is primarily driven by a big increase from the Barnett Shale as we extract liquids from the gas stream in both Western Johnson County and the Western extension counties. Additionally, we will be extracting NGLs from the gas associated with our North Dakota Bakken oil production, and this gas is especially high in NGL content.

And fourth, our US gas growth will emanate primarily from the Barnett, with strong supporting contributions from our Rocky Mountain, Mid-Continent and East Texas areas. During 2007, our Barnett production averaged 284 million cubic feet equivalents a day compared to our goal of 280 million. Additionally, we exited the year at 375 million cubic feet equivalents per day versus our target of 350 million. We expect to average 470 million cubic feet a day equivalents this year. This estimate is up from the 450 million number I provided on the last earnings call. Given these organic growth numbers, we are obviously pleased with the Barnett and Bakken performance.

I will note that the Barnett isn't the only growth contributor. In fact, our 2007 North America ex-Barnett growth was 5%, showing EOG has a strong organic program even without the Barnett. During 2008, we expect our North America ex-Barnett growth to be 7% to 8%, and this is even with the flat Canada production level rolled in and the sale of our shallow gas production in Appalachia.

Now I will briefly turn to Trinidad. As previously stated, we expect flat contract volumes until late 2009 when production will increase by 15 million cubic feet a day net from the methanol plant contract. Another new tranche of production will occur in early 2010 when overall Trinidad production -- with another overall Trinidad production increase of 60 million a day net as a result of sales from our Block 4(a) gas contract.

I note that in the fourth quarter of 2007, our average Trinidad gas price realization was $3.84, about $1.00 higher than the fourth quarter 2006. Our Trinidad gas price is currently being supported by very strong methanol prices, and much of our gas price is linked to methanol. We expect Caribbean methanol prices to soften during the second quarter, so we are forecasting a dip in full-year prices relative to the fourth-quarter 2007. Overall, however, Trinidad gas prices are higher than we would have predicted several years ago, giving us a strong rate of return from this asset.

Now I will address 2007 reserve replacement and signing costs. We have replaced 248% of our production at a $2.24 per Mcfe all-in cost, excluding gathering systems and processing plant expenditures. The vast majority of our reserve add occurred in the US from the Fort Worth Barnett Shale and the Uinta Basin. In the US, we replaced 357% of production at a $1.90 per Mcfe all-in cost, excluding gathering systems and processing plant expenditures. Total company reserves increased 14% to 7.7 Tcfe. I will reiterate that these are drilling additions.

In total, our PUD percentage decreased from 30% in 2006 to 23% at year-end 2007. At year-end 2007, book reserves in our Parshall Field Bakken play were 21 million barrels of oil equivalent. And we booked 1.4 total reserves in the Barnett,as far as reserves that stand there at year-end 2007. Our 2007 Barnett drilling additions were 651 Bcfe. We feel we have a considerable amount of technically-proven, but unbooked reserves in the Bakken, Barnett and also in our Vernal, Utah Uinta Basin play.

For the 20th consecutive year, DeGolyer and MacNaughton has done a complete engineering analysis of 79% of our reserves, and their overall number was again within 5% of our estimate. So you see our press release for supporting reserve and reserve replacement cost data.

This year, for the first time, we have broken out expenditures related to gathering systems and processing plants. These are expenditures and projects that EOG is electing to pursue through EOG and our Pecan Pipeline company. In the past, third parties often incurred these capital expenses. As we move into areas with little or no gathering and pipeline infrastructure such as the Bakken and western counties of the Barnett, we are applying our same organic approach in building these systems ourselves in order to retain the midstream value in-house.

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

Thank you, Mark. For the fourth quarter, total exploration and development expenditures, including asset retirement obligations, were $997 million with $18 million of acquisitions. In addition, expenditures for gathering systems, processing plants and other property and equipment were $73 million. Capitalized interest for the quarter was $8.6 million and for the year was $29.3 million. For the full year, total exploration and development expenditures, including asset retirement obligations, were $3.6 billion with only $20 million of acquisitions. In addition, expenditures for gathering systems, processing plants and other property and equipment were $277 million. For the year, of the drilling capital expenditures approximately 24% were exploration and 76% development.

At year-end 2007, total debt outstanding was $1.185 billion and the total debt-to-cap ratio was 14%. The effective tax rate for the year was 33% and the deferred tax ratio was 79%.

During the fourth-quarter 2007 and early in the first-quarter 2008, we repurchased the remaining $43 million of our preferred stock. We had a one-time charge of $2.7 million in premium and fees related to the repurchase. We no longer have any preferred stock outstanding.

Yesterday, we filed a Form 8-K with first-quarter and full-year 2008 guidance. For the full year 2008, the 8-K has an effective tax range of 33% to 37% and a deferral percentage of 55% to 75%. You'll note an increase in our expected 2008 unit transportation costs, increasing from $0.27 in 2007 to the $0.41 midpoint in 2008. This is related to firm transportation we have taken on the Rockies Express pipeline and several pipelines exiting the Barnett market area. This firm transportation will allow us to receive higher natural gas prices since we are now able to sell more gas closer to market hubs. You will notice that the 8-K guidance also reflects tighter differentials from Henry Hub to U.S. as compared to 2007.

Using the midpoint of the 8-K guidance, our full-year 2008 unit costs released in well, DD&A, G&A, total exploration, net interest expense, and excluding transportation and taxes other than income, were forecast to increase only 2.5% over 2007. With our current hedge position for 2008 as outlined in yesterday's 8-K filing, for every $0.10 change in Henry Hub, EOG's net income and cash flow is impacted by approximately $20 million. Similarly, for every $1.00 move in WTI, EOG's net income and cash flow is impacted by approximately $8 million.

Now I will turn it back to Mark to discuss his concluding remarks.

Thanks, Tim. Now let me summarize. In my opinion, there are five important points to take away from this call. First, we have a 2008 capital and growth plan that provides essentially 15% debt-adjusted per share production growth. Volume growth is predicated on a $7.50 Henry Hub, and we may adjust this target either up or down by modulating our 2008 gas-directed drilling, depending on a read of Henry Hub gas prices.

Second, our liquids mix will begin to shift as total liquids production for crude, condensate and NGL is expected to increase 37% year-over-year in 2008. We expect total liquids production to also grow at a disproportionately high rate in 2009 and 2010.

Third, we continue to be focused on ROCE, and the bulk of our $4.1 billion exploration and development expenditures will be deployed in the high reinvestment rate of return at Bakken, Barnett and Uinta Basin plays.

Fourth, our capital structure is very solid with year-end 2007 debt-to-total cap ratio of 14%. We expect the net debt ratio to decline by year-end 2008. Additionally, we have repurchased all preferred stock, further streamlining our capital structure.

And fifth and last, we continue to be at the forefront regarding emerging technology in horizontal wells and resource plays. Our first-mover results in Johnson County, the Bakken and South Texas attest to this, and we are continuing to focus on new ideas. Thanks for listening. I will remind you that our 2008 analyst conference is February 28 in Houston, and now we will go to Q&A.

(OPERATOR INSTRUCTIONS). David Kistler, Simmons & Co.

Good morning. Just hopping into the Barnett for one second, when you guys look towards 2009 through 2011, in the presentation you highlight companywide 10% growth. What percent of that do you think will be driven by the Barnett, given that you gave us a breakout in '08?

Yes, I can't give you a specific number on that. What I can tell you, David, is that during our upcoming analyst conference in about three weeks, we will give you a pretty good estimate of kind of volume growth and broken out, at least specific regions for 2008 through 2010. But what I can tell you about the Barnett at this time is we expect production to continue to grow through at least 2010.

Okay. And following up on that, when we kind of look at infrastructure issues, etc. with respect to the Barnett and with respect to how much you are growing your liquids production, can you talk a little bit about any potential areas which you might be concerned about as far as bottlenecks of transport, processing, gathering coming out of the Barnett?

At this juncture, we are in pretty good shape. As far as getting the gas out of the Barnett area, we have got some firm transportation deals cut with Gulf South and CenterPoint that basically are allowing us to move the bulk of our production to sell at locations such as Mississippi and Eastern Louisiana. So getting it out of the area and avoiding possible [flat] or depressed prices in the local areas is not a problem. We have got that done with firm FT.

As far as getting pipeline infrastructure out in the western counties, we are ahead of the curve on that. In other words, our infrastructure is -- we are in good shape there.

As far as the processing plants, only in the fourth quarter did we recently start to put a lot of our gas through some of the processing plant, so that is why you saw a big jump in fourth-quarter NGLs. I don't anticipate at this time we are going to have a bottleneck in any of the processing plants either. So we are in pretty good shape as far as downstream infrastructure in the Barnett.

Okay, great. And then just one last question, kind of building off of that stuff. As we look at your company and many of the companies becoming more and more levered to unconventional resources with high decline rates, and we haven't had a whole lot of discussion on this in the last year or so, what do you think that the ongoing trend will be for decline rates and where are you guys kind of mapping that out going forward given that over 47% of our production give or take is coming from unconventionals with multiple time, higher decline rates?

On the macro side, we continue to believe that total North American -- total US gas decline rates are continuing to jump, but probably are higher than the 36%, which is the last time we looked with our EOG chart on there. So we believe that you are going to -- the idea that these plays are going to [leaven] out the decline rate is really not particularly valid. You're going to replace the Gulf of Mexico, which is high decline, with a lot of these resource plays, which is also pretty high decline, at least for the first three or four years of their production life. So that is what I would offer to you there, David.

Yes, I guess I am looking at the recent data that is showing domestic production growth kind of north of 5%, and just trying to get a handle on the deviation between what we are seeing come out of the 914 and your comments on 2% production growth in 2008.

Yes, as I have discussed on some previous earnings calls, the EIA 914 data does not have a lot of credibility with me. I think it consistently overstates actual production growth in the US, and I believe if you look at EIA's 2008 forecast, they themselves are forecasting 1.6% production growth this year. How that gets reconciled internally with the 914s, I am not sure, but what I would say is -- I will make the same comment that I've repeated several times. It is very difficult for me to believe that gas production in the US is growing at the rates the 914s indicate. When we are drawing down storage this winter, it looks to be somewhere between one and two Bcf a day and tighter than last year, and that is after adjusting for the LNG import differentials. So the withdrawals this year have indicated to me that we have got a system that is tighter than a year ago, and that just flies in the face of that 914 data. So we reject the 914 data.

Well, I thank you guys very much for that additional color.

Thank you.

Joe Allman, JPMorgan.

Good morning, everybody. Mark, could you give us some specific data on some of the recent Bakken wells?

Other than just that aggregate of the 10 wells, Joe, I can't give you -- don't want to go through kind of a well-by-well analysis of things. What I will say is, at our analyst conference, we have certainly a portion of it devoted to the Bakken and you will get probably more than you wanted to know relating to the Bakken. But the overview point related to the Bakken is it is delivering exactly what we expected, and you can see that from our oil forecast for this year, and what I will say is this is a multiyear phenomenon. We will expect that our total company crude oil production is going to grow at disproportionately high rates in 2009 and 2010, also still driven by this Bakken play.

Could you at least give us what you have seen as the highest initial production rate in the play?

I think it is about -- 2000 barrels a day is pretty much the best we have seen. The best wells that we have generated so far are in this Austin area. We highlighted the first Austin well on the last earnings call, and we have subsequently drilled -- I believe it is two just pretty much immediate offsets to it, and they are kind of duplicates of the first well. So the Austin area, which is kind of more in the north part location relative to most of our concentrated drilling, this Austin area appears to be a particularly sweet area.

That's helpful. And I don't want to steal the thunder from the analyst meeting, but how about other shales? Could you talk about any other kind of new shales that you are getting some initial results from?

Yes, Joe, and I don't want to set any expectations at all for the analyst meeting. As we have said repeatedly, we are working on other shale plays and let me say unusual rock plays, in addition to shale, that involve horizontal drilling. And we will talk about those plays whenever two things have happened. One is that we have technically proven the play, and two is that we have kind of stealthily leased up all the acreage that we can in a low-key manner, and the example of when we start talking about a play is the Bakken.

Basically, I think as the Bakken plays out, it is going to be pretty well universally acknowledged that it is a very, very big oilfield and EOG has leased the vast majority of that field. So as we go forward and talk about new plays, the keys are not going to be any timing related to the analyst conference; the keys are going to be when have we technically proven a play and when do we have all the acreage that we want.

That's helpful. And then lastly in terms of just the cost environment, what are you seeing recently in terms of drilling and complete costs?

We are seeing a little bit of decline in rig rates and stimulation costs, and that is a function of just the added rigs and also competition in the stimulation market. And I guess overall, we would say costs for 2008 are about -- we are seeing about 5% to maybe 10% less than 2007.

I appreciate that. Thank you.

Ellen Hannan, Bear Stearns.

Good morning. Just a quick one for me. Mark, in the properties that you targeted for sale in Appalachia, are you retaining any deep rights to those properties?

Yes. We are retaining the deep rights in all the shallow gas production areas that we have, including the minerals that we own up there.

Okay, thanks very much.

Gil Yang, Citi.

Hi. Can you tell me for the Western Barnett counties you mentioned, Mark, that you only recently started processing gas there? Do you own the plant or are you processing through a third-party plant at the moment?

No, in the Barnett right now, all the gas that is being processed is going through third-party plants.

Okay. When will you have your own plant running?

We are looking at, you know, starting some plants and maybe in about a year we may have some done, Gil. The only place where we have gotten into the actual plant business so far is up in North Dakota for the casing head gas up there. And there we expect to commence plant startup sometime here in March.

As you look at putting capital into building a midstream plant and other midstream assets, you talk a lot in your presentation about returns. How will bringing capital into those kinds of assets affect your returns on a long-term basis?

The returns that we have run are commensurate with our drilling and production-related investments, and what we are really narrowing our look at these plants to are, one, areas where there are resource plays; and two, areas that the alternatives are either very costly or prohibitive. So basically, what we -- I've been surprised at how high the reinvestment rate of return on these midstream assets has looked for us. Now it may be that it is only because we are picking certain areas, or it may be that this midstream area is just a very, very strong return-oriented area.

I mean you always highlight the Barnett and Bakken being anywhere from 40% to 100% rates of returns. So you're getting incremental rates of returns on that order of magnitude for midstream assets?

Yes, they are not approaching the 100% number, but the range at the 40% number is more realistic.

Okay. And last question is, Gary made the comment that overall 5% to 10% lower costs, yet I think Tim broke out the comment that costs have risen 2.5%. Can you rationalize the differences in those two comments?

Yes, the costs that Tim had mentioned are really our unit costs, which are -- in many cases, those are different from the drilling and completion costs. Gary's response indicated that our expected cost to drill wells in 2008 may be down 5% to 10% relative to 2007, whereas Tim's costs where he highlighted that if you look at essentially all of our unit costs, excluding transportation in '08 versus '07, they will only be up about 2.5%. And one of the reasons why they are up at all, of course, is that our embedded DD&A is increasing each year as we and everybody else in the industry have had higher refining costs over the last four or five years than over the previous timeframe.

All right, perfect. Thanks, Mark.

Brian Singer, Goldman Sachs.

Thank you, good morning. Following up on Gil's question with regards to liquids, you had highlighted the better NGLs coming from western Johnson County and the western extension counties. When you look at the western extension counties, is this different from your initial expectation? Are you seeing any greater liquids content, or is this just in line with your growing production?

I guess the significance of the NGL impact has surprised us in the last year, and the net result of the higher NGLs has improved the economics in the western counties. And if you think about it, NGL prices generally track oil prices, and what we saw last year, of course, was the considerable increase in oil prices, which also carry the NGLs up to higher levels than we previously thought. So if you look back and compare us to a year or two ago, we knew where we were going to be extracting NGLs, but the relative value of those NGLs to the residue gas, that differential was not that great.

Today, the relative value of the NGLs is considerably higher than the residue gas, and we all understand why. The residue gas is trading at somewhere around 50%, the BTU equivalent of crude oil.

So as a consequence, what we see happening here is that the impact of stripping out those liquids has given us an indirect oil price increase, if you will, through the NGLs, which has boosted the economics of western Johnson County and all of the western counties, because we already knew that that was very rich gas up there. That is a long-winded answer to your question.

No, that's helpful. Is it also pushing the play further west in your opinion?

Not further west than what is indicated kind of in our map in the investor relations book. So relative to our expectations of the play moving farther west of a year or two ago, no, the play has not moved farther west.

Okay. So if we look at your better-than-expected performance in the Barnett over the last year, is it these NGLs, the greater liquids content that you would say is the single biggest contributor, or can you talk about what the other contributors were in terms of efficiency or lower declines, etc.?

The single biggest contributor for our Barnett performance, improved performance over time, has been our improvement in well completion efficiency, and this is something we have kind of practiced to a fine art in Johnson County. And at our analyst conference, we will provide what we think are kind of mind-boggling examples of that. So if I would say one thing that has improved our outlook on the overall Barnett relative to a year or two ago, it is that we are continuing to see what I think are pretty dramatic improvements in our well completion efficiency, and this is the strength that I think is a big differentiator between EOG and the other people in the play. There is third-party data. Some of it is on our website we just put out this morning that shows that we are consistently making more better wells than any of our peer companies in the Barnett, which leads me to believe that we truly have a technical completion on shales in horizontal wells.

Great, thank you. My last question is on the Bakken. Any additional thoughts on down-spacing and any results from pilots?

Yes, we don't have anything useful to share for you. We'll shortly be spudding our first 320-acre down-spaced well, but realistically, it is going to be the end of the year, Brian, before we have a technical assessment on whether this field (technical difficulties) by 640 or 320-acre spacing. So that one is going to play out kind of slowly. We are going to have to drill a well, get some data on it and then watch the flow performance of that well relative to the offsets for probably about six months before we can really judge where we go.

What we do know is that under our current scenario, one well every 640 acres, we are recovering a very small percentage of the oil in place under that 640 acres. So our job is, through good engineering and technical input, is to figure out how to get more of it over time.

Great, thank you.

Leo Mariani, RBC Capital Markets.

Just a quick question here. Trying to get a sense on what has been going on in East Texas in the past couple of quarters and sort of what your plans are for 2008.

Yes, I would say we have got a division office in Tyler, Texas, which runs all of our operations in Texas, North Louisiana and Mississippi. And just to give you a sense, production from that area -- and all these are organic numbers and don't hold me to absolute specifics -- but directionally, production last year was up about 12% year-over-year from that division. And for 2008, we expect it to be up another 8% to 10%. So in a low-key way, we are showing very, very good production growth from that portion of our business.

Okay. Has there been any recent sort of increase in horizontal exploitation out there at all?

All this production increase we are generating from our Tyler area is all related to vertical drilling so far, but we are beginning to experiment in a couple of resource plays there with horizontal drilling, and we may have some good results from that in 2008. But right now, it is really all just vertically sourced production growth.

Okay. I was wondering if you guys had any comment as to what your position is in Appalachia, in terms of acreage that you guys own up there.

Yes, the Appalachian area has been a little bit of a high-profile area for us because of all the questions that have come up relating to our deal with NFG. And what we can say is that we are currently drilling and testing wells in the Marcellus Shale in a couple of areas. One area is on the acreage related to NFG, and another is just on acreage that we've leased on our own. And it is just too soon to give you any results. We don't have enough data to have a conclusive answer relating to the Marcellus Shale in Appalachia yet.

Got you, okay. A quick question on your Bakken position here. You mentioned about 21 million barrels at year-end 2007. Any idea what percentage of that is PUDs and what is PDP, and how many wells that that may be related to?

Yes, we are about 56% PUD there, roughly 50/50 PUDs, and reserve amounts probably about, on an oil equivalent basis, about 10 million barrels on the PDP and about 10 million barrels on the PUD.

As to how many wells that is --.

23 producing wells -- 24.

Okay, 24 wells.

Okay, thanks a lot, guys.

Ken Carroll, Johnson Rice.

Hey, guys, good morning. Just a quick question and some detail on the reserve report. Looking at natural gas, you had 127 plus, B, negative revision in North America. Any color on that? Has there any particular area affected that, or is that just kind of spread across the Company?

Yes, Ken, the one area there, and I think it is broken out in the stuff that we sent out yesterday, where we did have a negative reserve revision of some consequence was in Canada where we basically had shallow gas fields, specifically one shallow gas field in Alberta, that the drilling results and production results just haven't turned out as we expected in that particular area. So consequently, we ended up with about a -- I think it's a 57 Bcfe write-down in Canada relating to the shallow gas activities.

The other area as far as the US gas negative reserve revisions, that is essentially completely offset by positive reserve revisions in natural gas liquids if you look under the liquids line.

Got you.

It is just a recognition that, particularly in the Barnett and western areas there, more of that gas, more of the hydrocarbons are going to show up on the accounting statement as natural gas liquids and less as Mcf a day.

Got you. So you are just switching buckets there, got you. Very good, guys, excellent quarter. Thanks.

Brad Pattarozzi, Tudor, Pickering & Holt. Mr. Pattarozzi, your line is open.

Ben Dell, Sanford Bernstein.

I just had one question. It was really around your asset geographic distribution. Obviously, when you look at the reserve replacement rates, it once again looks like Canada is sort of diluting your performance. Have you given any thought whether or not there is a market to spinning those assets off and applying maybe the proceeds back into the US market where your returns are better?

Not really. I mean, yes, we have given it thought, but we have given it thought and then kind of dismissed it, Ben. Our read on Canada is, and everyone knows the macro picture on Canada gas supply, and our picture is not tremendously different in that we are basically forecasting flat Canada production for the last several years, 2006, 2007 and 2008. But our point on Canada is that we think there are several areas there that are amenable to horizontal drilling where that technology is to be applied. And we believe this is a very big deal, and so we are currently looking at several areas in Canada to apply horizontal drilling, in some cases, to a resource play. So our expectations are that we will again have significant growth coming out of Canada as we look to the '09, '10 and later timeframes, primarily driven by resources that are accessible only through horizontal drilling that have been uneconomic through vertical drilling.

And usually that would be a competitive F&D cost to your US business?

Yes, it should be a reasonable cost. Every area is going to have to compete for the same pool of capital, but yes, we believe that there is a good chance that we are going to have significant Canada growth at competitive F&D costs.

And just lastly, in the industry there has been some growing interest in onshore tight gas in Europe. Have you given any sort of look at that? Obviously, Eastern Europe, Ukraine, but also in other areas, people have been sort of showing interest.

Yes, the answer is yes, and I will take it a little bit more broadly than that. It is my belief that the implementation of horizontal drilling to resource plays -- and I'll say a resource play can be a very tight sandstone; it doesn't have to be a shale -- but just the application of horizontal drilling to large hydrocarbon accumulations that don't work economically with vertical wells, we think that is going to be a worldwide, onshore phenomenon. So the way we are looking at areas like Europe are, are there pieces of acreage that are available where you have a huge asset of hydrocarbons that have never been really tested to see if it will work out using horizontal drilling. So we are looking, but we don't have anything specific to talk about, vis-a-vis Europe at this time.

Okay, great. Thank you.

Joe Allman, JPMorgan.

Mark, in terms of your Bakken position, could you give us your net acreage at this point?

Yes, it is still, we would say it's greater than 175,000 acres. We are being a little bit catty on our actual acreage position until we get a couple of other deals done, but again, we will probably disclose something more specifically on our acreage -- exact acreage there at February 28th.

Can you give a comment on -- how about the acreage west of the Nesson Anticline, any -- do you think that improved technology can make that area commercial?

It is possible, but we are really, Joe, focused more on the other side of the Nesson, as you know, and it is a vast pool of oil in the Williston basin, but some areas are going to be more economic, some less. We feel like we have the more economic portion of that scoped out.

I appreciate that. Then lastly, in terms of Canada, I am not sure, are you spending less dollars in Canada in 2008 to get that flat production?

What we are looking at in Canada -- I'll give you a couple of numbers out of this $4.1 billion E&P budget, may be helpful to you. The portion that is going to the Barnett is $1.4 billion. The portion that is going to our Denver division, which would be all the stuff we are doing in the Utah area plus the Bakken, plus our Green River Basin Wyoming area, we are going to dedicate about $1.0 billion there. The Canada allocation is going to be about $400 million, and that is about flat with last year.

Okay, that's helpful. Thank you.

This concludes our question-and-session. I'd like to turn it back over to management for any additional or closing remarks.

Okay, thank you. We appreciate everyone staying on the line and once again, want to remind everyone that we do have an analyst conference coming up here on February 28 in Houston. And our goal with that conference is to have everyone who leaves the conference have a very, very good understanding of what our three-year game plan is and what you can expect in terms of specifics relating to that. Thank you.

Once again, ladies and gentlemen, this will conclude today's conference. We thank you for your participation. You may now disconnect.