EOG Resources Inc (EOG) 2008 Q4 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources fourth quarter and full-year 2008 earnings conference call. As a reminder, this call is being recorded.

At this time, for opening remarks and introductions, I would like to turn 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 2008 earning 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 currently permits producers to disclose only crude relatives in their securities filing. Some of the reserve estimates in this conference call and webcast, including those for the Barnett shale, North Dakota Bakken, Horn River and Hainesville 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 last night. With me this morning are Loren Leiker, Senior EVP of Exploration, Gary Thomas, Senior EVP of Operations, Bob Garrison, EVP of Exploration, Tim Driggers, Vice President and CFO, Marie Baldwin, Vice President of Investor Relations and Jim Falconi, Manager of Engineering and Reserves. We filed an 8K with first quarter and full-year 2009 guidance yesterday afternoon. I'll discuss our 2009 business plan in a minute when I review operations. I'll now review our fourth quarter and full-year net income available to common stockholders and discretionary cash flow and then I'll review our year-end reserves and finding costs. I'll follow that with a discussion of our macro hydrocarbon view, our 2009 business plan and an operational review.

As outlined in our press release, for the fourth quarter, EOG reported net income available to common stockholders of $461 million or $1.84 per share and $2.4 billion or $9.72 per share for the full year 2008. For investors who follow the price disp of industry analysts who focus on non-GAAP net income available to common stockholder to eliminate mark-to-market impacts and certain one time adjustments as outlined in the press release, EOG's fourth-quarter adjusted net income available to common stockholder was $186 million or $0.74 per share and $1.9 billion or $7.50 per share for the full year. For investors who follow the practice of industry analysts, who focus on non-GAAP discretionary cash flow, EOG Bcf for the fourth quarter was $911 million and $4.6 billion for the full year. There are three salient points that emanate from these fourth quarter and full-year results. First, on a GAAP net income basis, we achieved a 26% ROCE for 2008. On a non-GAAP net income basis which includes the realized gains from hedging but eliminates the mark-to-market impact and a gain on sale of our (inaudible) assets, we achieved a 20% ROCE. As in past years, we believe we will likely lead the peer group in terms of 2008 ROCE. Second, in February, 2008, we provided 15% as our total company organic growth target, and we hit that number exactly for the full year. And third, we had no significant financial writedowns and as I'll discuss in a minute, no major reserve revisions. In a quarter that contains a lot of meaningful industry financial and reserve writedowns, I believe this is a testament to the way EOG runs its business.

Now I will address 2008 reserve replacement and finding costs. We replaced 228% of our production at a $2.60 per Mcfe all-in cost including total revisions and excluding gathering systems, processing plants and other expenditures. The vast majority of our reserve adds occurred in the US with significant contributions from the Barnett shale and the Rocky Mountain areas. In the US, we replaced 270% of production at a $2.52 per Mcfe all-in cost excluding gathering systems, processing plant and other expenditures. Our total price related reserve revisions were a negative 75 Bcfe and if these are excluded, our finding costs would be $2.50 per Mcfe. I'm very proud to note that our price induced reserve revisions were nominal, particularly in contrast to others. I believe this speaks to the quality and inherent economics of our booked reserves. Total company reserves increased 12% to 8.7 Tcfe.. The ratio of PUDs at year end 2008 was 24%, essentially the same as last year. For the twenty-first consecutive year, the DeGolyer MacNaughton has done a complete engineering analysis of our reserves, and their overall number was within 5% of our internal estimate. Their analysis covered 79% of our reserves this year.

I'll now address our hydrocarbon macro view and then our 2009 business plan. Regarding North American gas, we expect the gas recount to average 950 in 2009 versus 1,500 last year. We expect domestic gas production to begin to decline by mid year, and by year end, we expect it will be down about 2.5 Bcf a day from December, 2008 levels. We also expect Canadian production to decline about 0.8 Bcf a day this year. We think the recession induced industrial demand weakness will override the effect of the gas supply decline during 2009, but we expect the gas price to rebound and average $8 to $8.50 in 2010 as the supply declines and recovery and industrial demand take effect. Regarding oil, we expect prices to be weak in the first half of this year and strengthen during the second half, ending the year at about $60 to $75 as the opec cuts affect inventories. Given that macro outlook and current gas prices, our 2009 business plan is predicated on the following items. First, continue to run the company as a business with returns as the main criterion and not volume growth. Second, don't spend capital to grow volumes and cram them into currently over supplied gas and oil markets. Third, keep CapEx and cash flow roughly balanced and fourth, continue to generate horizontal resource play ideas. Accordingly, we expect to grow volumes at roughly a 3% rate this year, predicated on $5 gas and we're taking particularly critical steps regarding Bakken oil production, which I'll discuss in a minute.

Even with reduced production from the Bakken, we expect to increase our 2009 total company crude oil condensate and NGL production by 14% year-over-year. Based on our sober outlook for 2009 gas prices, we're throttling back our gas drilling and expect to generate minus 1% North American gas growth this year. Last year, we averaged 73 total drilling rigs and this year, we'll average about 45 rigs in our overall drilling program. Given that conceptual framework, I'll now discuss some of our key plays. Our North Dakota Bakken play continues to yield good well results. As indicated in the press release, we are now designating the Parshall field as the Bakken core and the extension beyond the Parshall field we're designating as the Bakken light. Although the operations remain strong, the transportation and crude price differentials have caused us to alter our plan and development regarding this high quality asset. As I mentioned on our last quarterly call, the overall industry Bakken volumes have subsumed the current crude and casing head gas pipeline infrastructure capacity, greatly expanding location differentials. Our current production capacity is about 25,000 net barrels of oil per day from the Bakken. Roughly half of that volume is being piped to Clear Brook, Minnesota. Since this oil pipeline is maxed out, we're currently trucking the remaining half of our production to refineries as far away as Utah and Oklahoma. Given the high trucking costs and low WTI prices, we're receiving an unacceptably low well head net back for this 12,500 barrels of net oil per day. We're currently working on alternate permanent transportation outlets for our crude and casing head gas, and we expect to have those in place by the fourth quarter. Until we get this transportation problem fixed, we have reduced our production to minimize the amount of oil being trucked and the concommittant low well head netbacks. It just doesn't make sense to us to squander the economic value of this asset by producing it at very low well head netbacks, especially when we expect those netbacks to improve considerably later in the year when we solve infrastructure hurdles. I'll also note that absent our Bakken reductions, our 2009 production growth would be 5% to 7%.

On the Bakken capital and drilling side, we expect to maintain a reasonable level of 2009 capital investments in this asset so that we'll have high deliverability later this year. Our recent drilling results in the core area are similar to what I've reported in previous quarters. Simply put, our drilling results from the core continue to be excellent, and even with today's oil price, the core remains economic. In 2007, the average IP rate on all our activity was 1,500 barrels of oil a day with gross reserves per well averaging 880,000 barrels of oil. For 2008, we averaged 1,700 barrels of oil per day as an IP rate with 820,000 barrels on the average gross reserves per well. In the non-core area which we call Bakken light, we now have production tests on three wells and logs from two additional wells that are waiting on completion. Results from these wells indicate typical reserves of 250,000 to 300,000 barrels of oil, and we are targeting a $4.5 million completed well cost. This Bakken light area requires roughly $50 WTI oil to be economic. We're very encouraged by results from these five wells and believe we have a lot of running room in this Bakken light area. Because of low current WTI prices and netbacks, we plan it reduce our 2009 activity in both the core and light areas from 10 to five rigs. To summarize the Bakken, we have approximately 400,000 net acres in the play with the premiere acreage position in what we believe should be recognized as one of the bigger and most economic onshore North American oil plays. We continue to estimate the reserve potential on our acreage to be greater than 80 million barrels of oil equivalent net. I'll note that 48 million barrels of oil equivalent net were booked at December 31, 2008.

I'll now move to the Barnett where I'll separately discuss the gas and oil plays. In the gas play, our drilling and production results continue to be excellent. I was also pleased to read a recent third party report whereby all industry Barnett wells were thoroughly analyzed and the report conclusion was "Based on well performance, EOG should be considered the premiere Barnett shale player in our view." Our 2008 results in Johnson and Hill counties pretty much replicated our 2007 results in that the average per well reserve for the 335 wells that we drilled during 2008 in those two counties was 2.0 net Bcf, exactly the same number as in 2007 even though this play is now more mature and we're drilling wells on closer spacing. I'll also note that our results in the western counties on a per well reserve basis are better than in 2007. So that part of the play is also performing as we expected. Given these consistent results, the only variable is how much capital we deploy into this gas asset during 2009. We intend to drill 200 Barnett gas wells in 2009 as compared to 390 in 2008. We're simply trimming activity based on our macro view of gas prices. In the Barnett oil play, we advise investors that this would be a 2009 and not a 2008 event because of infrastructure issues. Since it's now 2009, we're happy to report that during the past six months, we've completed 22 horizontal wells that have tested with the IP rates averaging 300 barrels of oil a day, 130 barrels of NGLs per day and 940 MCF a day of natural gas, fitting our reserve model. At a $2.1 million to $3.1 million completed well cost depending on depth and using today's hydrocarbon prices, these wells generate a 15% to 50%, 5-0% unlevered after tax, reinvestment rate of return which is a very positive indicator for this project. We've identified a 50 million barrel oil equivalent net, low risk development drilling area for 2009, and we'll also be stepping out to further expand the area. Because of the current sluggish oil prices, we're not planning to jump into a massive 2009 development program for this asset. We intend to drill about 60 wells in 2009. We currently believe the likely accumulation on our acreage is greater than 200 million barrels oil equivalent net, and it's probable that we'll define this piece by piece as we've done with the first 50 million barrel tranch. I'll also note that this represents only about 2% recovery of the hydrocarbons in place be and we're still working on ways to improve the recovery factor.

I want to note two additional items regarding this play. First, we're going to change the nomenclature of this play from Barnett Oil to Barnett Combo because unlike the Bakken where the vast majority of the revenue stream is derived from oil, the revenue and product stream from the Barnett wells is roughly one-third oil, one-third Ngl's and one-third gas, hence the Combo name. Secondly, I'll again reiterate that these are not ultra high rate wells like the Bakken. The typical combo well, IP's at 300 barrels of oil a day with 130 barrels a day of Ngl's and roughly $1 million a day of natural gas. To summarize, we commissioned our gas plant last week, and we're now going into a development mode on this big scope play and expect to have further positive results throughout the year. For the total Barnett gas and combo plays, we averaged 453 million cubic feet a day equivalents during 2008, in line with the target we gave on our November call. We also have positive news to report from our first two EOG operated horizontal Hainesville wells. The Martin Timber number two H and the Bedsol 27 number 1H wells in DeSoto Parish, Louisiana each tested at gross rates of 17 million cubic feet a day. EOG has a 157% working interest in these wells respectively. I'll note that because of pipeline limitations, the wells are currently flowing to sales at a combined restricted rate of 17 million of cubic feet a day. We currently have 116,000 net acres in the Hainesville play and believe we have a three to four net Tcf potential on our acreage. We expect to drill 14 Hainesville wells in 2009.

In the British Columbia Horn River Basin, we intend to continue a steady program and drill seven horizontal wells compared to six last year. We now have six months of sustained production from several of our wells and are encouraged that this program will likely be competitive with other North American shale plays. We're also encouraged that the BC government is considering royally incentives to help offset the challenge of the remote location and associated costs and make the play more competitive with other North American gas plays. We have 157,500 net acres in the play, and it's worthwhile noting that EOG's current activity is on the west side of the play where there is access to a separate gas pipeline infrastructure with current adequate capacity for our near term forecasted volume growth. The pipeline will be expanded to meet increases in drilling activity. We currently believe that take away infrastructure for the overall field won't happen until early 2012. but given our current access for take away capacity, we expect to be able to slowly ramp up production each year so our Horn River production growth profile will be steady year by year rather than a hockey stick slope. Regarding the Pennsylvania Marcellus play, in total we have 220,000 net acres. On our previous quarterly call, we indicated we'd proven up about 40,000 acres in Bradford county by drilling two wells with two net Bcf of reserves each. Additionally, we recently proved up additional acreage we own via an NFG farm out by successfully testing the COP409 3 number 3H well in Elk County which we believe is a 1.6 Bcf net well. We plan to operate one rig in Pennsylvania this year.

Our normal operations in the Rockies, mid-continent and Texas continued to perform very well as evidenced by our attractive overall 2008 finding costs. Because of time constraints, I won't go into play-by-play detail at this time regarding these areas. But I will provide a sense of our downshift in activity in 2009 and several of our core gas plays. In Uinta and Green River Basins, we expect to drill 109 net wells this year versus 271 in 2008. In our Saskatchewan and southern Alberta shallow gas area, we'll downshift from 470 wells last year to 140 this year. I'll also note that we drilled two wells in our Colorado North Park oil project during the fourth quarter that are producing 500 and 300 barrels of oil a day. We're going to defer further significant activity in this project until oil prize recover. Switching to our operations outside of North America, in Trinidad, the third party M5000 methanol plant was down for repairs the entire quarter. Our net contracted volume for this plant is 75 million cubic feet a day and due to the plant down time, we produced less in the fourth quarter than was indicated in the November guidance 8K. The plant is now back on line, and we expect production in Trinidad to increase compared to last year. Although we have several Tcf's of prospects on our existing acreage, we don't intend to drill any wells in Trinidad during 2009 and we'll reevaluate our exploration activity when prices are stronger.

In China, we'll commence our drilling program in a few weeks and run one rig throughout the year. During the fourth quarter, we obtained the rights to a potential oil zone in our rate increase. Now we have at least two target intervals, two gas and one interval. We plan to test both zones with horizontal wells. In the North Sea area, we had no in drilling activity during 2008, but we plan to drill three exploring wells this year, two oil and one gas. Two of these will be in the east Irish Sea and one in the central North Sea. I'll now turn it over to Tim Driggers to discuss CapEx and capital structure.

Thanks, Mark. Capitalized interest for the quarter was $12.5 million and for the year was $42.6 million. For the fourth quarter 2008, total exploration and development expenditures were $1.2 billion. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $156 million. For the full year, total exploration and development expenditures were $4.9 billion with only $109 million of acquisitions. In addition, total gathering, processing, and other expenditures were $477 million. For 2008, approximately 25% of the drilling program CapEx was exploration and 75% was for development. At year end 2008, total debt outstanding was $1.9 billion and the debt to total capitalization ratio was 17%. At December 31, we had $331 million of cash, giving us non-GAAP net debt of $1.6 billion, for a net debt to total cap ratio of 15%, up slightly from 14% at year end 2007. The effective tax rate for the fourth quarter was 37%. The effective tax rate for the year was 35% and the deferred tax ratio was 87%. We also announced another increase of the dividend on the common stock. This is the tenth increase in 10 years. Effective with the next dividend, the annual indicated rate is $0.58 per share. Yesterday, we filed a form 8K with first quarter and full year 2009 guidance. For full year 2009, the 8K has an effective tax range of 35% to 45%, and a deferral percentage of less than 10%. The deferred tax ratio is expected to decline from prior years due to reduced capital expenditures and Idc expensing. The effective tax rate will depend in large part on the relative levels of foreign and domestic pretax income. Estimated exploration and development capital expenditures for 2009 excluding acquisitions are $2.85 billion. Estimating gathering, processing, and other expenditures are $250 million. Now I'll turn it back to Mark to discuss our hedge position and concluding remarks.

Thanks, Tim. For 2009, we had 43% of our North American gas hedged at a $9.73 price a floor including both financial and physical hedges. For 2010, we had 60 million cubic feet of gas a day collared or swapped at an average $9.96 floor. We have no oil hedges, and we do have a small amount of 2009 through 2011 rocky basis swaps.

Now let me summarize. In my opinion, there are five important points to take away from this call. First, we achieved a 26% ROCE for 2008 and likely led the peer group in this regard which further confirms our multiyear ROCE differentiation versus other companies. Second, 2008, we're likely one of the few peer companies that did not have substantial asset impairments or reserve writedowns. Additionally, we posted an attractive $2.60 per Mcfe all in finding cost including price revisions. In my opinion, financial returns matter, particularly in the current environment. Asset impairments are often dismissed as non-cash or non-recurring. But these impairments do reflect cash that indeed was spent and now has to be written down because the investment value has dropped due to lower commodity prices. I'll also note that in my opinion, I think both the sell side and the buy side tend to underestimate the importance of the fact that we have no asset impairments nor any substantial reserve writedowns. Third, we're committed to keeping our debt low. In today's environment, I certainly don't have to remind this audience about the negative consequences of high leverage in any industry. Our dividend increase, although small, signifies our confidence in our go forward game plan. Fourth, as promised, we've now reported substantial tangible results regarding our Barnett combo play. This is important because the prize here is very big. Additionally, we've confirmed our first Hainesville success and noted further success in the Bakken light, Horn River and Marcellus plays. It's important to note that EOG has the premiere position in what we believe are the top two large size oil plays in the onshore US, the Bakken and Barnett. With this lineup in inventory, we expect to generate -- to continue to generate superior reinvestment rates of return compared to others in both up and down hydrocarbon price cycles. And fifth, we're continuing to work on new horizontal ideas and will disclose them whenever we've got acreage positions locked up and tested a few wells. Thanks for listening. And now we'll go to Q&A. Trisha, do you want to hook us into Q&A?

At this time we'll conduct our question-and-answer session. (Operator instructions) We'll take as many questions as time permits. We'll go to Tom Gardner with Simmons & Company.

Good morning, everyone.

Hey, Tom.

Hey, Mark. With respect to your capital expenditure outlays in 2009, are they likely to be somewhat evenly distributed or front or back end loaded?

They will probably be a bit front end loaded simply because we'll be in the process of shedding rigs throughout the year. And so the expenditures in the first half of the year will be likely more than 50% of the total $3.1 billion CapEx.

With that 2010 recovery comes a little early, you think you might pick up CapEx?

Yes. We've certainly got the flexibility to do that, but the plan we're articulating now is one based upon the assumption that gas prices remain pretty dismal throughout 2009.

Is EOG currently drilling but not completing wells in some areas?

Yes. The answer to that is yes, Tom. Particularly doing that in areas that are susceptible to cold weather. For example, in the Bakken play and also in our -- the Bakken oil play and also in our Uinta Basin gas play, we're currently drilling wells and just going to wait until completion -- until release until late spring simply because to frac those wells in the wintertime, you have to heat the water and there's a lot of incremental costs with that. We're just in no hurry to rush production and cram it into a market that currently has signs of oversupply.

Other operators are doing inventory in those drilled but not completed wells, too. Do you think that's going to be impactful to the timing or duration of the gas market recovery when it comes?

I know --Tom, there's been some comments by others relating to the Barnett shale. People have said they're slowing down in the Barnett shale, and -- but they have an inventory of wells yet to be completed. We've done a pretty thorough modeling of the Barnett shale on the gas side and based on what we see with the signs of the rig count dropping and also factoring in that there is an inventory of wells yet to be completed, it's our belief that the Barnett shale is going to peak at about 4.9 Bcf a day the first quarter of this year. And by the end this year, the Barnett shale will be down to about 4.3 Bcf per day. In other words, it's going to drop about 600 million cubic feet a day from the peak. So although there are inventories of completed wells, I think the example in the Barnett shale is that number one, we certainly don't believe it's going to go to 6 Bcf per day, and we think the first quarter is going to be the apogee of the production gross from it. That's not to say that the Barnett is completely tapped out. What it says is that there's a huge amount of people who are dropping rigs in the Barnett and likely moving them -- moving their activity to the Hainesville.

One last question, and then I'll hop off. Just wanted to see how your view of the Hainesville has changed over time. Obviously, those were sweet wells that you drilled. First two at over 17 million a day. What do you think is fundamentally different to your ingoing expectations?

Yes. Our prior position on previous calls of the Hainesville was what I'll call studiously neutral. We said that we're not going to opine on the Hainesville until we get some EOG operated wells drilled on our own. Now that we've got two good wells under our belt, it's our feeling that the Hainesville is a real play. The question is, what's going to be the total aerial extent of it. The other question is as impacts the gas market is what is the short term take away capacity from the overall Hainesville, and at what point in time will there be an expanded pipeline system to take additional gas out of the Hainesville? But bottom line is we moved from neutral to positive on the play based on EOG operated well results.

Thanks, Mark.

Okay.

We'll take our next question from David Heikkinen with Tudor Pickering Holt.

Good morning. Just a question on the rig count dropping. How quickly will you drop rigs, and are you paying any terminations to drop?

The answer on the second part, Tom, is no. We're not paying any terminations to drop. In terms of how quickly we're dropping them, Gary Thomas, you want to opine?

Yes. We had a peak of 82 rigs there in September and we're down to 64 now. We've got about 36 rigs under long term contract. By year end, we'll be down to about 13 rigs under long term. So just us being at 64 now, averaging 45, it will just be like Mark had mentioned on our CapEx, little heavily weighted first half. Probably mid-year or so we'll be down to 40 rigs.

Thanks. And then on the Barnett combo play, just looking at the move toward more gas and NGLs away from oil. Can you talk about how large an area you now think is perspective for the combo play, then the new resource assessment of, kind of 200 million barrels. Where have your wells been and what have you confirmed?

Yes, David. What we feel we've pretty well firmed up by the drilling we did in the second half of 2008 is an area that's got low risk development locations sufficient to generate about 50 million barrels of oil equivalent net to EOG. And what we're going to do this year is basically concentrate most of our drilling in this development area and drill a few step out wells to go beyond that. Now it's our belief that this project will expand or kind of in 50 million barrel tranches. And what our game plan is this year is hopefully to get well into the development of the first 50 million tranch and by year end have the second 50 million barrel oil tranch pretty well firmed up and just kind of step in that particular mechanism. If we would have been in a higher oil price environment, gas price environment, we'd be tramping down on the accelerator on this play. But in the current environment, we're going to just kind of proceed at a moderate pace. But I think what is telling is the fact that we're generating somewhere between a 15% and a 5-0, 50% after tax unlevered investment rate of return at current hydrocarbon prices, which I think speaks well to the efficacy of this play. What you haven't heard probably on too many earnings calls is that the inherent economics in most of these plays in North America, current hydrocarbon prices are very, very weak. On oil plays, I'd say that for all of North America, you've got the Barnett core and the Bakken -- sorry, the Bakken core and then the Barnett combo portion that are economic in today's prices. But I don't think there's anything in the deep water, nothing up in the heavy oil and nothing substantive that I'm aware of in the rest of North America that seems at these kind of prices. So it's a pretty stressed time for oil development and also gas development in terms of returns.

And then in the UK, can you talk about the size of what you're exploring for both in the east Irish Sea and central North Sea? That's my last question.

Yes, David. We have two wells planned, two Wildcats planned in east Irish Sea. One is oil, one is gas. The gas prospect is probably 90 to 100 Bcf gross size and we're 70% working interest. The gross prospect is 15 million barrels, again 70%. And then in the central (inaudible) of the North Sea, we have one oil prospect that we're going to drill as operator. 30 million to 50 million barrel size. We're 43% working interest in that well.

Okay. Thank you.

We'll take our next question from Gil Yang with Citigroup.

Good morning. A couple of oil questions. Mark, you commented that in the Bakken you would be -- you're drilling more than you're putting on line so you have some spare deliverability. Can you give us -- can you quantify that in any way?

I guess the best way to quantify is if we add all our stuff producing full capacity now, we'd be producing roughly 25,000 barrels a day. By the end of the year, that will number will probably be up in the range of 40,000 to 45,000 barrels a day.

40 to 45?

Yes, somewhere in that range.

Okay. And then looking at the combo play, can you -- is the growth that you're going to see for the company as a whole coming from gas liquid coming out of the combo, or are there other regions of significant NGL growth?

Yes, there's two places of NGL growth relative to last year. One place is the Barnett in our western counties, in the gas Barnett there were some limitations on gas processing last year, and those have been fixed. So we'll have a full year of stripping out more liquids from the western Barnett counties. And then of course, we've got in the northern Barnett, the combo play for now commissioning our processing plant, and we'll be stripping out the NGL's for the combo play. And then the last item really relates to the Barnett. And I -- the Bakken, excuse me. The Bakken I said is really challenged on infrastructure issues both on the oil side and also on the casing head gas side. And we're going to fix the casing head gas problem by laying a 75 mile pipeline to tie into alliance pipeline, whereby -- by sometime, we believe, in the third quarter -- early third quarter, we will be able to pipe our gas and extract everything from ethanes and above and sell those in the Chicago market. So for the second half of the year, we're going to see more natural gas liquids coming from the Bakken also.

Okay. Great. And last question is, in today's economics, do you expect there to be less stripping in the mid-continent than in the past year or two?

Yes. Our read is the best barometer on NGL's is that they're generally been a function of crude oil. And our logic is we do that crude oil price to firm the second half of the year, and we expect NGL prices to firm at kind of in line with that, which, you know, would give reasons for -- to maximize stripping certainly in the second half of the year if we're right on our hydrocarbon forecast.

But if that doesn't happen, sort of if you freeze today's economics, what do you think would happen over the next year?

Well, it would be less stripping, but it's just that in the assumptions that one makes as to what's going to happen to relative hydrocarbon prices. And our assumption is that gas for the full year is not going to be particularly robust, whereas hydrocarbons in terms of liquids will be more robust in the second half of the year.

Okay. Thank you very much, Mark.

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

Yes, thank you. Good morning, everyone. Mark, in terms of the infrastructure in the Bakken, you mentioned that casing a gas line, what other requirements do you have there to improve capacity in the Bakken?

Yes. The casing head gas line will fix the gas take away problem. The oil take away problem, we're looking at self options right now, and it's certainly possible that the option we might land on is to rail car incremental barrels out of there, rail car those barrels either to Oklahoma or all the way down to the ship channel, Houston ship channel here. And so we're evaluating those items. But it's our expectation that by the fourth quarter, we'll have something sorted out and in place regarding the crude oil transportation portion of it.

Okay. And as -- it would seem that production would be declining with a lot less activity there and some of that Montana Bakken oil declining. Are you seeing some opening of pipeline capacity as we move through early 2009 here?

Well, we're certainly seeing the number of wells drilling in the Bakken right now, number of rigs operating is dropping pretty precipitously right now. This is by the entire industry. And so there will be some decline in the production, and that will make a little more space in the pipeline. But our view is that long term, there is so much potential up there in the Bakken that there's going to have to be a very, very significant pipeline infrastructure change. And that might be two to three years away, to take away all the pipeline, everything by the pipeline. So that's why we're looking at other alternatives such as rail cost.

Got you. Then moving over to the Barnett combo. What kind of infrastructure requirements do you have there?

We spent 2008 pretty much putting those infrastructure items in place. So we're essentially good to go from this point forward and don't anticipate any infrastructure limitations there. So the question there really is how much capital do you deploy into the play, and what's the relative economics of it and relative to the hydrocarbon prices. And the economics are already there. The limitation we have is we want to be roughly balanced on cash flow and CapEx, and so we're not going to overspend to go hog wild in this play during 2009.

Got you. And Mark, earlier when you talked about current hydrocarbon prices giving you up to a 50% or so rate of return, you were talking about the strip there, right?

Yes. Basically just taking the strip model forward, taking current prices and using the NYMEX and not even -- not to 10 years or so. Not really going, with any big hockey stick on either oil or gas.

Got you. Lastly, I know that you didn't have much in way of impairments or revisions. But in terms of your ability to add reserves, did you have any issue with not adding some reserves because of the low prices at year end '08?

No. Nope.

Okay. All right. Very helpful. Thanks, everybody.

We'll go next to Brian Singer with Goldman Sachs.

Thank you, good morning.

Brian.

You spoke earlier with regards to, I think Tom's question on the evolving Hainesville view. And I wondered if you could also do the same for the Marcellus, characterize how your view on the Marcellus has changed with the recent well result you've seen.

Yes, I'll let Loren handle that one.

Yes, Brian. In order -- we've mentioned that we have the 220,000 net acres. 40 of those in Bradford that we're feeling pretty strong about. Really based on the last two wells we drilled there which look like they're about 2.5 Bcf per well gross, 2 net. That's a pretty -- that's an area that Barnett is quite a bit thicker in and pretty good rock quality. And the other area we mentioned, which is on the NFG farm out and really comprised of the rest of our 220,000 net acres, we've had one well completed that we feel like we put our best foot forward on our frac job with, and that's more like a, probably a 2 Bcf well gross, 1.6 Bcf net, which we think is quite replicable in the area. I guess overall, I'd say that we like the rock parameters we're seeing in the Marcellus. Although relative to the Barnett, it is quite a bit thinner. So the gas in place per square mile is less, the permeability is pretty decent. We still have a bit of a disconnect with maybe some of the rest of the industry on what we think the reserves per drill are going to be. And perhaps that has something to do with the geology north versus geology south. But it's hard for us to see how -- it's relative to Barnett, for example, in Johnson county, we're averaging 2.5 Bcf per well with about twice the gas in place per section and what we would consider to be better frac barriers, and that's on 30 acre spacing. So the question really for the Marcellus is not is it a good play, it's a good play. It's got good finding costs, decent relatives per well. The question is, what is the drainage area going to be and what are the overall reserves going to be because of that? At about 80 Bcf in place per section, which is what we would guess to be an average per Marcellus, you would have to have a 40% recovery efficiency on 80% spacing to make four Bcf wells. We think that's a bit of a stretch, at least in our area.

Got it. That's really helpful color. Switching to just the general CapEx versus cash flow plan, assuming that you increase your spending in rig count to the extent that oil and gas prices move up, what gives you the confidence that gas prices will move to that, I think, 800 to 850 range in 2010 that you spoke of, and on the margin, if gas prices go up, will you use the additional cash flow to drill oil wells or gas wells?

Yes, our feeling regarding 2010 on gas prices are that if just take where we believe the total North American gas production will be by December, it will be roughly 3.3 Bcf a day lower than it started the year at. And the other more important part is that both in the US and Canada, the slope at year end is going to be inflecting downward fairly strongly. So as you get into 2010, even if you get an instant price increase, it's going to take until mid to probably late 2010 just to get that slope inflecting back to neutral and to turn it up on production growth. And we think if you basically have a 3.3 Bcf a day swing in supply for North America indigenously, and we are predicating some recovery in 2010 for industrial demand versus this year, that the market could turn around perhaps pretty violently in a bullish way for producers. So that's kind of our call. As to the question of would we be directing CapEx more heavily toward gas or oil, if you assume we end the year at $60, $70 oil, we get pretty bullish on gas, I'd say that it's fair to say a preponderance of our -- an increasing amount every year of our total CapEx will be devoted toward oil directed projects, is I guess the best way to put it.

That's helpful. I guess lastly, are there areas within your own portfolio or your thoughts on others that as a result of what you're seeing in Hainesville, Marcellus will likely not return from a drilling perspective, ie, are there areas that will be -- that will see secular shifts down in the rig count?

Well, the one that's most surprising to me now is just the overall industry Barnett reaction. And I don't believe it's -- it's my belief you get two things going on in the Barnett. The first is I believe in the urbanized area of the Barnett, I think that people are finding it's becoming increasingly difficult to drill and complete wells in a cost effective manner. Not so much because of reserves are lacking, but just the costs are extremely high. To drill wells, frac wells and then connect them to sales in urbanized area which -- where EOG is not located, and so I think that people are recognizing that that area is a bit more economically challenged perhaps than the street expects and you're seeing rigs move out of the Barnett. I would say that the boom in the Barnett is probably over. But it will be a steady contributor, and we're certainly not saying that the Barnett's going to go on -- in aggregate is going to go in some big terminal decline over time. But I think we've clearly seen the peak of the Barnett. And then the other area that I've commented on very frequently is that the Gulf of Mexico, both the shelf and the deep water for gas, I think is -- in my opinion, it's definitely on a secular decline simply because the economics there just cannot compete with what we're seeing in some of these resource plays.

Thank you very much.

We'll go next to Ben Dell with Sanford Bernstein.

Hi, Mark.

Hey, Ben.

I have just two quick questions. The first was on Trinidad. You mentioned you weren't drilling any exploration wells. Do you have a feeling for whether Trinidad LNG can continue to support the volumes it has been exporting over the next two to three years if the offshore plays don't invest incrementally ?

Yes, that's a -- that's just a tough question, because we're not directly involved in the LNG there. My feeling is that for the existing LNG plants, they're pretty well backed up by reserves. And I would be surprised if over the next short period of time that we'd see any shortfall in feedstock to those LNG plants. I think those reserves are pretty firm. I think the issue in Trinidad is that with no one looking for any new gas, the ability to grow the Trinidadian industry in terms of having sources and supplies, that's the big challenge that is going on there right now.

Okay. And just on another question, for the second year running, I think probably the third year running, your Canadian operations have reported weaker (inaudible) days than your US operations. When you look at your 2009 capital budget, can you give us some indication of how much CapEx you'll be allocating to Canada versus the US and how you stack up the investment in that region versus the US?

Yes. Let me have Gary answer that, Ben.

Yes. In Canada we are, as you probably would expect ,curtailing our activities there, and it will be about 10% of our budget here for 2009. That's the combination of Calgary, Canada shallow gas, as well as BC operations in the Horn River.

Yes. What -- part of the issue that we've had, really in the last year or two relating to the Canadian finding cost has been just the startup investment, the particularly land investment in the Horn River. So it's one of those that once we get it up and running, it will look a lot better on finding cost. But clearly, if you strip out the Horn River for a minute, the relative prospectivity for the rest of Canada is a bit challenged. We're hoping to have further horizontal drilling success up there in other plays over the next year or two, but that's not firmed up yet.

Okay. Thank you.

And due to time constraints, we'll have to take our last question today from Leo Mariani with RBC.

Yes, thank you. Question on the Hainesville. Just trying to get a sense of what your take away capacity is in the area. Do you guys have any firm transportation on those pipelines, and what's your plan for gathering?

Yes, we have firm transportation of $80 million a day coming on here in April of this year. So we don't -- we've got a couple of other outlets that are in the range of $20 million a day, so we don't see us having any curtailment here on volumes, because of capacity restraints for the next year or so.

Okay. Jumping over to Bakken, is there any update on the progress of your 320 acre spaced wells?

Yes, in the Bakken area, in the core area, our current feeling is that most of the core is going to be adequately developed on the current 640 acre spacing. But there's part of the core that kind of borderlines the Bakken light area that probably will be drilled on 320 acres. But I would say the preponderance of the core is just not apparent to us from the evaluation we've done that 320 acre spacing it's going to be widespread across the whole area.

Okay, question on the financial side here. I noticed you had a pretty sizable current tax benefit in the fourth quarter, roughly $69 million. Just trying to get my arms around that a little more and what caused that.

As far as the shift between deferred and current, it's simply a shift in the decreasing gas prices and less taxable income and higher mark-to-markets being reversed out.

Okay. Last question here. You guys talked about, I think $4.5 million well costs in the Barnett -- sorry, the Bakken light area. What do you guys see for well costs in the core? Have those changed at all? Have they come down for you folks at all?

Yes, they've come down. I guess probably last year, we averaged about $5.4 million, and they're down to about $4.8 million now. And we've expect to see the $4.5 million well cost there, really the core as well as the franch. Maybe little lesser on the franch.

Okay, and how about in your (inaudible) play in terms of well costs these days?

In which play?

The BC shale play? The Uinta?

Yes. We've got a goal of getting our well costs down there to $10.5 million, and it's going to take us working pretty well on that. We're in the range of, oh, $13 million right now.

Okay. Thanks for your time.

We have quite a few things in place there, similarly to what we've done there in the Bakken. That's the big advantage of having that play, and they're pretty similar. So we're carrying that technology to BC right now.

Okay. Thanks.

That will conclude today's question and answer session. I'd now like to turn the call back to Mr Papa for any additional or closing remarks.

I have no further closing remarks. I would just like to thank everyone for staying with us on the call. We'll talk to you again in three months.

Thank you, ladies and gentlemen. That will conclude today's conference call. You may disconnect at any time.