EOG Resources Inc (EOG) 2008 Q1 法說會逐字稿

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

At this time, I'd like to turn the call over to the Chairman and the 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 first quarter 2008 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 securities filings. Some of the reserve estimates on this conference call and Webcast, including those for the Barnett Shale and the North Dakota Bakken plays may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our Website. An updated investor relations presentation and statistics was posted to our Website last night.

With me this morning are Loren Leiker, Senior EVP Exploration; Gary Thomas, Senior EVP Operations; Bobby Garrison, EVP Exploration; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President Investor Relations. We filed our 8-K with second quarter and full year 2008 guidance yesterday. These forecasts are consistent with the details provided at our recent analyst conference and I'l discuss them in a minute when I review operations. I'll now review our first quarter net income available to common stockholders and discretionary cash flow and then I'l provide an operational overview. Tim Driggers will then discuss capital structure and I'll close with a gas macro overview and a summary.

As outlined in our press release, for the first quarter, EOG reported net income available to common stockholders of $241 million or $0.96 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impacts and to exclude the impact the Appalachian property sale, as outlined in the press release, EOG's first quarter adjusted net income available to common stockholders was $473 million, or $1.89 per share. For our investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the first quarter was $1.1 billion or $4.40 per share.

I'll now address our strategy and operational highlights. Our 2008 strategy can be divided into three elements. First, we want to deliver 15% total Company production growth in 2008 and be set up to deliver similar organic growth again in 2009 and 2010, with a gradual shift towards more liquids production. As indicated by our first quarter results and our guidance 8-K, I believe we're on track regarding the 2008 volume target and we're well set up for 2009 and 2010. Regarding our shifts to more liquids production, our first quarter total liquids increased 38% versus last year. So, this year is occurring as we predicted.

Second, we'd like to maintain our 2008 CapEx, excluding acquisitions at or near our original $4.4 billion estimate and use any free cash flow to further strengthen our balance sheet. We started the year with a 14% net debt to total cap ratio and based on our hydrocarbon price expectations, we'll likely end the year at a much layer ratio. And third, we intend to continue looking for new resource plays, often using horizontal drilling. As I articulated in our recent analyst conference, I believe this is the future of the onshore E&P business, and EOG wants to capture as many of these new plays as possible using our early mover advantage.

Today, we've disclosed the new horizontal resource play that was captured in the midcontinent. We've now drilled 17 horizontal wells in the Atoka Formation in the Texas panhandle and feel sufficiently comfortable on the technical side to declare that we've captured a net 400 Bcf potential. Similar to the process for horizontal success that we reported at our February analyst conference, we've been testing this play and acquiring acreage for the last two years. The typical well cost is $3.4 million for 2 Bcf of net reserves. These wells typically have initial production rates of 4 to 7 million cubic feet a day. We currently have 60,000 net acres here.

I will now provide some brief highlights regarding some of our other plays. I'll remind everyone that at our analyst conference, we noted that most of our recently announced resource plays won't begin to have a volume impact until 2009, or in the case of British Columbia, likely 2011, primarily because of infrastructure issues. Therefore our 15%, 2008 total Company organic volume growth is being generated with essentially no contribution from our new horizontal plays, which shows the strength of our base portfolio.

I'll start with the Barnett gas. We are on track to hit our 470 MMcfe per day average 2008 production target and our year-to-date results are consistent with those shown in late February. We're still drilling excellent wells in Johnson County and are in a manufacturing process with a 17 rig drilling program there. In the Western and Hill Counties, we're running five rigs and have evolved to essentially a manufacturing process there as well. In short, everything is on track regarding Barnett gas development.

Regarding the Barnett oil play, in Montague, Clay and Archer Counties we noted at our analyst conference that we need to construction a gas processing plant and related oil and gas pipeline infrastructure before we can ramp up volumes. This work is underway and we expect that this infrastructure will be in place by early 2009. In the meantime, we're continuing to drill and further optimize our frac technology to determine the optimum stimulation for this oil reservoir. We have determined that you can't simply take a Johnson County frac and apply it per se to the oil play. We recently completed four new horizontal wells in Montague County. The Billy Henderson #2H and #3H, the [Kimas] Unit #1H and the [Sokwell] #2H. And all are producing similar to the model well outlined in February, i.e. initial rates of 150 to 350 barrels of oil per day, with between 500 and 1 million cubic feet a day production of rich gas, giving us 65% direct after-tax reinvestment rate of return. It's too early to provide definitive answers regarding well spacing, drainage radii and recovery factors but I suspect we'll have more clarification regarding these items in early 2009. For the rest of year, we will be working on optimizing the well completions, adding more acreage and installing our infrastructure.

In British Columbia, we continue to feel very good about the Horn River Basin Shale play but we don't have any new EOG well test data beyond that disclosed in February. We plan to drill and complete several additional wells in 2008 to further define the potential of the play. With a focus on costs, we plan to run our completion operations in the summer months. We expect to commence first sales from this asset, this summer, when pipeline infrastructure is complete. But we'll note that available pipeline capacity is low, about 40 million cubic feet a day and we don't expect significant volume growth from this asset until 2011, when a more robust pipeline infrastructure is available.

Similarly, our Colorado North Park Basin oil play won't have a volume impact of any significance until 2009. We're currently drilling an offset to our discovery well and by early 2009, we'll likely know whether this is a 10 million or an 80 million-barrel net asset. Our Mississippi Chalk Play, which we also highlighted in the analyst conference, will also be primarily a 2009 and later impact item. Our eight rig North Dakota Bakken development is proceeding as anticipated and is still averaging 100% direct after-tax reinvestment rates of return. We're consistently making very good wells.

The Austin 8-26H well, that was completed at the end of February, had an initial production rate of 3,060 barrels of oil per day. Recently we completed the Austin 6-15H well that had an initial production rate of 3,630 barrels of oil per day. These are the two best wells in the field today and I will note that those are probably two of the best wells in recent history in the Bakken play at North Dakota in its entirety. Within the Park oil field, very strong initial production rates are now routine, similar to our frequency of monster wells in Johnston County. The more drilling we do, the more confident we are regarding our net 80 million-barrel reserve estimate for this asset.

The upsides to this estimate will be determined in three possible ways. First, by extending the field limits through step-out drilling. Second, by a possible 328-acre downspacing and the third by secondary recovery. The field is currently being drilled on 640-acre spacing and we're currently completing our first 320-acre downspace well. We will need several months of production history from the well in order to determine the impact to any increase in reserve recovery versus acceleration. I expect that by year end, we'll have a definitive idea regarding the Bakken reserve side.

On the facilities side, we just commissioned our first EOG gas processing plant to handle the associated gas volumes and we expect to see increasing natural gas liquid volumes from the Bakken throughout the second half of the year. For brevity, I won't provide well-by-well details regarding the plethora of other plays that are contributing to the 15% production growth in 2008, except to say that these plays, ranging from the Uinta Basin to south Texas, are obviously contributing their part because the new plays won't have the volume impact until 2009 and beyond. I will also note the 15% growth is not a pro forma number. We expect to hit this absolute target without adjusting for our first quarter Appalachian sale.

Likewise, our Trinidad asset is performing as expected and we're still on track for a 60 million a day net volume increase in early 2010. In the North Sea, we won't be active during 2008 but we have a three to five rig -- three to five well exploration program scheduled for 2009. Additionally, we are in the process of finalizing an acquisition from Conoco Phillips relating to a tight gas sand asset in the Sichuan Basin on-shore China. This is an asset that EOG owned back at the late 1990s, before we became a fully independent public Company. We will be partnering with PetroChina again and we have received the necessary approval from the Chinese Ministry of Finance and Commerce.

The Transaction was funded during the second quarter and is expected to close this summer. We are acquiring 130,000 acres and 7 million cubic feet a day of net production. This asset is analogous to our south Texas Wilcox sandstone where we've unlocked about 0.5 Tcf with horizontal drilling. We believe horizontal technology is applicable to the Sichuan Basin sandstones but it will probably be until late 2009 before we know whether it truly works in this area. Strategically, this fits with our goal of adding an international asset that is amenable to horizontal drilling in an energy-short part of the world. I'll now turn it over to Tim Driggers to review CapEx and capital structure.

For the first quarter of 2008, total exploration and developing expenditures, including asset requirement obligations were $1.122 billion, with $29 million of acquisitions. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $88 million. Capitalized interest for the quarter was $9.4 million. At quarter end 2008, total debt outstanding was $1.185 billion and the debt to total capitalization ratio was 14%. At March 31, non-GAAP net debt was $980 million, for a net debt to total cap ratio of 12%. The effective tax rate for the quarter was 35% and the deferred tax ratio was 65%.

During the first quarter 2008, we repurchased the remaining $5 million of our preferred stock. We no longer have any preferred stock outstanding. Yesterday, we filed a Form 8-K with second quarter and full year 2008 guidance and our updated hedge position. For the full year 2008, the 8-K has an effective tax range of 32% to 36% and a deferral percentage of 55% to 75%. Using the midpoint of the updated 8-K guidance, our full year 2008 unit costs for lease and wells, DD&A, G&A, total exploration, net interest expense, and excluding transportation and taxes other than income are forecast to increase only 2% over 2007.

With our current hedge position, as outlined in yesterday's 8-K filing, for every $0.10 change in Henry Hub, EOG's 2008 net income and cash flow is impacted by approximately $20 million. Generally, for every $1 moved in WTI, EOG's 2008 net income and cash flow is impacted by approximately $10 million. Now, I'll turn it back to Mark to discuss the gas macro, hedging and his concluding remarks.

Regarding the North American gas macro, we think prices will remain strong throughout the year because overall 2008 net supply growth will be essentially flat with 2007, while demand growth will be up about 1 Bcf a day. Given the flat overall net supply and current storage, we think that November 1 storage levels may only reach about 3.3 Tcf, which will be a bullish signal for 2009 gas prices.

To me, the most intriguing piece of this equation relates to LNG import levels. To date, this year, we've noted that non-U.S. LNG demand is significantly stronger than most people would have predicted a year ago. Is this a harbinger for stronger than predicted non-U.S. LNG demand in 2009 and later periods? We now know that LNG import terminals are being constructed or considered in Argentina, Kuwait, Dubai, Chile and Brazil. A few years ago, no one would have predicted that these countries would have been importing LNG. This critical area of non-U.S. LNG demand growth, I believe, is something we'll need to watch closely because if this demand growth continues to surprise on the upside, then that's a bullish sign for North American long-term gas prices.

Our 2008 and 2009 financial hedge position is only slightly changed since our February analyst conference, in that we added a few more 2009 gas hedges in late April. For the period June 1 through December 31, 2008, we're about 30% hedged regarding North American gas, at an $8.52 price. For 2009, we're about 24% hedged at $8.80. For the period May 1 to December 31, 2008, we have about 28% of our total Company oil hedged at $92.19. And no oil hedges beyond 2008. At some point, we may consider adding more 2009 gas hedges.

Now, let me summarize. In my opinion, there are five important points to take away from this call. First, we're on track to deliver our estimated 15% total production growth in 2008, or further deleveraging an already underlevered balance sheet. Assuming the futures market is indicative of actual prices, then we may end the year with a net debt to cap ratio below 5%. Second, there's no change to our reserve or production estimates regarding the new horizontal plays we disclosed in February. Also further refinements regarding the reserve size of these plays will likely be an early 2009 event.

Third, using our early mover advantage in horizontal resource plays, we continue to place a high focus on identifying and capturing new acreage and accumulations. Several of the new ideas we're working on involve oil as opposed to gas accumulations. Today's disclosure regarding the 400 net Bcf midcontinent Atoka play underlies our continued focus in this area. Additionally, we plan to apply our horizontal drilling and completion expertise to China. Fourth, we expect that our unit costs will be pretty well controlled this year, allowing us to maintain our position as the low cost Company. And fifth, because of the low front end costs associated with our early mover advantage, we expect to continue to generate peer group leading ROCE's in 2008 and beyond. Thanks for listening and now we'll go to Q&A.

Thank you. (OPERATOR INSTRUCTIONS) We'll go first to Brian Singer at Goldman Sachs.

Thank you. Good morning.

Hi, Brian.

I wanted to focus on the Bakken, with the two wells you talked about and the very strong results there. I know you still need a few more months or through the rest of the year to fully finalize what the resource potential is, but can you add any more color on what you think those rates mean when looking at -- when thinking about recovery rates or thinking about how far the play extends?

Yes, what I would say at this point, Brian is that what we've seen from the drilling that we've done to date in the play is a pretty surprising amount of consistency in terms of pretty much in both the north, south, east and west parts of the play that we've drilled, all have very, very strong wells. Now, these Austin wells that we've highlighted, that I repeated over 3,000 barrels a day, they are toward the north end of our accumulation. And we've now got a group of about four or five of these Austin wells that are uncommonly strong, I'd say. But the surprising thing to me has been that there's a pretty good degree of uniformity in this accumulation. In other words, it's not -- the north end isn't dramatically greater than the south end, although it's slightly better.

In terms of expectations, and I know there's a lot of expectations out there regarding what's going on with our downspacing well and so on and so forth, what I'd say is frankly, we just need some time to evaluate this. As I mentioned, we're drilling our first 320-acre downspacing well. In fact, it's being completed as we speak. But kind of regardless of what the initial rate is on that well, as a reservoir engineer, that's not going to mean a whole lot to us. What's really going to mean to us, are; What are the pressures in the well? And then what's the well look like after three or four months of production and has that affected the rates from the surrounding wells?

I will say also that we're taking a hard look at secondary recovery here. In other words, our estimate of recovery factors in this reservoir, the 80 million barrels correlates to about a 10% recovery of oil. And in most oil accumulations, you can get considerably more than that by a secondary recovery program. So we'll be evaluating that throughout the year but I would really just advise everybody to expect that the next meaningful update we have regarding the size of that accumulation is probably going to be in early 2009.

That's helpful. Taking a step back, when you look at the various oilier opportunities in terms of extending your technology, how vast do you think that potential is? And how price sensitive is it when considering where oil prices have come?

Brian, I'd say that the oil potential for horizontal drilling is large but not as large as for gas and we're taking a page from the same play book that we used for gas. In that we're looking for what we call basin-centered accumulations, areas where oil-prone source rocks have been matured to the oil level but not to the gas level. And that does occur in several basins, probably half a dozen basins around the U.S. Where encapsulated tight rocks can be accessed with horizontal drilling. And we have a number of those kind of plays on our plate right now that we're maturing them from stages of generation to capture. And we'll be talking about those in subsequent quarterlies, I'm sure. But just in summary, I'd say that I think the oil potential out there is substantial and we are moving in that direction.

Yes, kind of just to give you a little more color on that, Brian. We always have in our closet an inventory of potential horizontal resource plays that's kind of our little cheat sheet list, which we never disclose to analysts until they're actually technically proven. But our current cheat sheet list, about 50% of the ones on that list are oil and the other 50% are gas.

Great. And any sense on price sensitivity? Are these products that when you're considering, you're going to need -- or what oil price do you think we generally need for --?

Frankly, at any oil price over about $70 a barrel, these things work.

Thank you.

Next we'll move to Gil Yang at Citi Investment Research.

Hi. Sort of following along with Brian's question about the Bakken and maybe more philosophically. At the meeting, Loren, we talked a little bit about your returns. The Bakken returns are, 100% plus. Given that at some point, downspacing would result in smaller wells, the tradeoff would be that you give the higher volumes at smaller wells and smaller returns. How far down the returns curve would you be willing to downspace to? Would you -- if you could get 40% returns and downspace in the Bakken, would you be willing to go that far? Or would you want to keep it at some higher level rate of return?

Yes, Gil, the best way I'd look at that is we're looking at the downspacing in conjunction with secondary recovery. In other words, pumping some fluid into these wells. And if we technically conclude ultimately that this reservoir is amenable to secondary recovery, then the downspacing is kind of a fait accompli. It will happen. Because you really can't flood this reservoir on 640-acre spacing. So, I would say that we will be looking at the downspacing. The downspacing, if you just ran it on acceleration economics, probably is going to look pretty good but what we need to sort out is; How much incremental oil will we really recover with that? But I would tend to have people focus on -- I think the key question that we have to answer and the sell side, the buy side should focus on; Is this reservoir amenable to secondary recovery? And then the downspacing will be part of that.

My question is, really, what's the interpretation of the word "amenable"? If you could do it -- id you could downspace in secondary recovery at 40% rate of return is that amenable?

Absolutely. Yes.

Okay. That's fair. And second question on China, can you give us an idea of the gas prices you would expect under current market conditions there to receive out of that area?

Yes, the current situation we have in China is this acquisition is funded. It's essentially a done deal but it hasn't technically, legally fully closed. And so until that occurs, we're really under some confidentiality provisions and we can't give any other color other than we've provided, Gil. I know that's not that the satisfactory answer but likely on the next earnings call, we'll be able to provide the color that people want regarding China.

Thank you very much.

Next we'll go to Joe Allman at JPMorgan.

Good morning, everybody. Mark, in terms of the Bakken, are there any other opportunities to branch out further there and get more acreage? Would it be your desire to do so?

Joe, we currently have I think 320,000 net acres in the entire Williston Basin. And the field that we always talk about, Parshall Field, including those 3,000-barrel a day Austin fields, really only encompasses about 110,000 of those 320,000 acres. So, the answer to your first question, is absolutely, yes, we believe that there are other prospective areas within the Williston Basin that we have currently leased and will be testing in the future for oil prospects. And we are continuing to lease. In the Parshall, already, that's a pretty hard thing to do. But other parts of the Basin where exploration prospects are available, we are accreting acres currently.

Okay. That's helpful. And then could you give comments on the dynamics for cost these days? A lot of operators are talking about drilling and completion costs flattening out here. Are you seeing the same thing and could you give us some color on that?

Yes, for the first quarter, here, we've probably seen through cost reductions and improved efficiencies lowering our costs about 5% overall. But with tubular costs increasing, fuel costs being higher, we're seeing that we'll probably give that up overall through the balance of the year.

Can you comment on fracture stimulation costs?

Stimulation costs have not gone up for us. As a matter of fact, in the Barnett area, there are some surplus frac equipment. And we are seeing being pretty flat elsewhere. And another thing that you'll remember, we have in place is vendor agreements through the year 2008. So, they are staying flat for EOG.

Got you. And then on China, I know you talked about comparing that to the Wilcox play in south Texas and you mentioned 0.5 T's, net to you. Is that -- is it somewhere in size net to you as well and can you comment on the potential size net to EOG?

Yes, the 0.5 T's is what's essentially captured in south Texas. It 's really got nothing to do with the China number and we really can't provide a China number probably until the next earnings call, Joe.

Appreciate that. Thank you.

We'll move next to Ben Dell at Bernstein.

Hi. I had a quick questions about the Appalachians. Obviously, there's been a lot of talk about the Marcellus Shale. You've obviously just exited the Appalachians. Have you taken a look at that? And do you have any interest in that or do you think the quality of shale is not as good as other stuff you're seeing?

Yes, Ben, we've talked about the Marcellus some in the past. And really, our position there hasn't changed. We currently have about 230,000 net acres, primarily in Pennsylvania and primarily in northwestern Pennsylvania. We did sell our shallow production in the Appalachians but we maintained our deep rights under those leases. So currently, as I said, we're at about 230,000 acres. We've drilled a total of probably nine wells out there. Four of those are horizontal and we plan to drill another probably five wells in the balance of the year, some of which will be vertical. Some of those will be on 100% EOG land. Some will be in combination with Seneca Resources on a large JV that we've entered into with them in northwest Pennsylvania. I would say we're encouraged by the results that we hear announced by others in the play. Our own results have come fairly slowly. When we get our new rig there in the middle of May, we hope to accelerate those results.

Can you give us an indication of IP's that you've on the wells you drilled, the horizontals?

We're not really prepared to release any IP's at this point. I think -- I would say that the numbers that are being thrown around in the industry, 2.5 Bcf a well, seem a little strong to us. Our own modeling of our own test results would indicate more like 1.5 Bcf, maybe as much as 2 Bcf a well, which is still going be quite strong economically. We hope and expect that the play will work. Although, we do believe that the volumes are going come on fairly slowly from that play, both for us and for industry as a whole, mainly due to just logistical reasons. A lot of topography, a lot of regulatory work, a lack of people and equipment, that kind of thing.

Okay. On a separate subject, historically you've had sort of better returns on your assets within the U.S. than outside the U.S. Specifically, kind of the Trinidad and UK. With China, what's sort of leading you to increase the international expansion and add another country? And it appears as though that money would be better spent at home. Or are you limited in terms of how much you can grow and do in the U.S.?

Yes, I would say, Ben, I'm not sure I'd agree with kind of the predicate of your question there. We look at returns in terms of; What kind of after tax reinvestment rate of return have we gotten on our money that we spent there? And we're very happy with the returns we've gotten in all three of those areas, Trinidad, Canada and the UK over time. And they have been generally quite comparable to the returns we have gotten, certainly in the U.S. except maybe for the last year when U.S. gas prices went up. The idea in China is one that -- where we've looked at areas where there's an energy short part of the world. We believe that this onshore horizontal technology is going to be amenable to places outside of North America in uncovering pretty substantial pools of hydrocarbons. And what I'd say on a reinvestment return in China is that it's the -- if it works, we expect it to be comparable with some of our other investments in the Company.

Okay. Great. And just lastly, a quick one. There's been some talk about sort of Eastern European tight gas basins centered around the Ukraine. Is that another area you've taken a look at or do you see some Europe in the horizons for you?

Specifically the Ukraine, no, we are not looking there, mainly just because of political issues. But we are looking a bit in some portions of eastern Europe, although not that far east. Whether we come up with something, I don't know but I would say that there are parts of Europe that are on our radar screen. And somebody is probably going to find some substantial base incentive gas accumulations that are amenable to horizontal drilling in those areas.

Okay. Great. Thank you.

Next we'll move to David Heikkinen at Tudor Pickering.

I had a question on the comments of defining the Bakken north, south east and west. That is in that 110,000-acre area of consistency around Parshall, not at 320,000 acres, correct?

Yes, that's correct, David. Yes, we've got what I;d call other ideas on acreage outside of that 110,000 acres and we'll likely be testing some of those in the second half of this year.

Okay. And as you think about secondary recovery, what would be a barrier or a reason why it wouldn't work in the Bakken?

Yes, the two biggest potential reasons are that, one, if this thing is -- if we deem that it has in situ high degree of natural fractures, that's a barrier. And then, the second reason is the converse. If we deem it that it's got just shockingly low permeability, that would be a barrier. On a positive side, in a typical oil reservoir -- and I say a typical sandstone or so, you'll usually get something like 15% or 20% on primary recovery to recover the oil in place and in this rock, we're only dealing with 10%. So we've got 90% of the oil that we're not going to get out as it stands now and that's a pretty big prize for us to chase.

Is there a relative permeability to oil versus relative perm for water issue that you've identified or no?

No, we're just looking at all of that stuff.

Okay.

It's probably too soon to comment really.

And then going to the Atoka, you talked about 60,000 net acres and 400 Bcf. Is that -- what's your gross acreage there, ability to continue to expand that, is that a concentrated area and then spacing assumption?

Yes, the rough spacing assumption there is a well every 320 acres.

Yes.

And this particular zone is pretty thin. So it's not obvious that we'll be able to come back to you in a few months and say, wow, we can double that and go 160 acres. But I'd say, on adding incremental acreage, we've got a chance to take that 400 net Bcf up to a number probably like 600, maybe 700 net Bcf.

Okay. And so how much money are you going to spend for additional leasing this year now?

Well, the total number that we have, I think we released that in 10Q last night for all of our leasehold acquisitions this year is about $360 million. And really, we'll stay pretty close to that number.

Okay. So you don't think that leasing is going to be something that has an uptick in your overall $4.4 billion budget?

Well, if it does, it will likely be balanced by other downticks.

Okay. And then final question is, everybody wants to know about Bossier and Haynesville Shales. Can you talk about anything you're doing in Louisiana and Texas trying to test the shales and source there?

Yes, I would say, we've got a position of about 63,000 net acres in that play area. We do not intend to drill any Haynesville horizontal wells this year. We're just going to take a wait-and-see attitude and see if that play develops and comes to us. But we have not that much data ourselves. We really can't shed much light for you, David, on the efficacy of the overall play.

I appreciate that. Thank you.

Our next question comes from Leo Mariani at RBC.

Yes, a quick question here on Bakken for you guys. I'm trying to get a sense of how many wells you've drilled so far and what's in the budget for number of wells to drill in 2008?

I think our total number of date on the Bakken completed wells is about 38. And I think the total number for the year, those are gross wells by the way. On a net well basis, for the total year, we're looking at 50, I believe. On gross, that's probably going to be in the mid-70's. Is that right, Gary?

80.

80 or so gross.

Okay. And what's your current production out there in the Bakken?

It's 12,000, about 12,500-barrels of oil per day net.

Okay. Quick question on your northeast BC play up there. How long you have had your three wells up there on production?

They are not on production. The wells that we have were just extended flow tests that we did during the winter. Our first production is going to commence this summer. So we'll have those wells on production, plus probably one or two others that we are currently drilling.

Okay. And what you guys probably anticipate stepping up your drilling there in 2009?

Yes, the logic path there is that we've got 40 million a day of available pipeline capacity and we'll drill enough wells to fill that up in the relatively short term and then it's probably going to be about an 18 month period to loop that pipeline to allow us to have a significant step up in capacity. So if you kind of play all that out, it translates to maybe mid 2010 before we're really going to have enough pipeline take-away to really see the big volume ramp up there.

Okay. Last question here on the Barnett. Just curious what you guys are seeing these days in terms of EUR's on your Western County extension wells, as well as costs out there and what you guys are seeing in Hill County in terms of costs and EUR's?

In terms of the Western Counties, we would still stay with the number that we've been kind of quoting for the last year, which is about 1 net Bcf per well in the Western Counties. And the well costs out there are running probably $1.5 million or so in terms of that. In terms of Hill County, the reserves there look considerably stronger. I would say, probably 2.25 Bcf of wells is kind of what we're seeing. We're seeing a little bit different set of characteristics in Hill County in that the wells don't come on at the kind of monster initial rates like in Johnson County but they don't decline at the very high rates that the rest of Barnett does. We're really completing at a different facies of Barnett there. And so what we get are wells that have an initial production rates of maybe 2, 2.5 million a day, but they're relatively flat as far as declines.

Okay. And what were your costs out there on the wells.

It's $2.4, $2.5 million range for Hill County.

Okay. And can you just remind us how many wells you guys have drilled in Hill?

I would guess about 12.

Okay. Thanks a lot for your time.

Next we'll move to Tom Gardner at Simmons & Company.

Mark, I wanted to get your recent thoughts on the recent 9-14 data. I appreciate your earlier macro comments but you've 10.5% year-over-year growth. Is this running the risk of oversupplying the future and how is it likely to impact your hedging strategy?

Yes, our current forecast, we're expecting production to be up somewhere in the range of maybe 3.5% this year for domestic production. That's certainly at odds with the monthly EIA data. Although, I think the EIA's annual forecast is 3.0% growth, is what they officially forecasting for '08 versus '07. I would interpret -- I just flat do not believe that we're seeing for full year anything close to the range of 10% growth. I've always felt that the EIA data consistently overstates production growth. But I do think that this sea change relating to horizontal drilling in gas reservoirs has pretty well put us on a path where we're going to see something like maybe 2% to 3.5% annual production growth in the U.S. in '08, '09 and 2010, is the forecast for three years. So I think the sea change with horizontal drilling has changed this from an industry that could barely keep production flat in the U.S. to one that we will have production growth in the U.S. for the next several years at least, in my opinion. I also that think once we get a little more flush production coming out of the offshore fields that's currently offline, I think that we're going to see some pretty sharp declines in that 8 Bcf a day from the Gulf of Mexico probably beginning to manifest itself by the third or fourth quarter this year. Because at the level of rigs that are currently running in the Gulf of Mexico, that's a recipe for some pretty sharp declines that are going to occur. So we will have a counterbalance effect, I believe, in the Gulf of Mexico to this onshore growth.

Thanks for that. On the same theme of government studies, I wanted to jump over to the Bakken and ask you about the USGS study indicating multibillion barrel potential. What are your thoughts on that -- you commented earlier on what you thought the price environment would need to be going forward. Are there issues outside the Parshall area in order to achieve that sort of number or come anywhere close to it?

I think the study that the USGS did is quite well founded technically. Mr. Pollastro did a really good job of estimating reserves in the Barnett a couple of years ago. Maybe that will turn out to be a little bit light. In the Bakken, I think he's taken a good approach, in that he's looked at is as basin-centered oil accumulation, which is correct, believe. Covering a very large area, although it is relatively thin. But the number he comes up with, I think his midpoint number is 3.7 billion barrels of oil recovery, is fundamentally, technically correct but perhaps not economically extractible. And I think because he assumes that the entire shale will work to the tune of maybe 25,000 total locations, wells to be drilled, that's where we think it's perhaps a little optimistic. The basin-centered oil shale may not be intact over that entire area, by our thinking. Portions of it, perhaps large portions of it may not be economic because the shale has been partially breached and so, you may have water issues in some areas. And also, there may be variations. Parshall is such a sweet spot because of fractured [in dee] in the facies of the rock and that will probably not be true in very many of the places within the Williston Basin. So in summary, I'd say that the overall number is not incorrect. It's just perhaps optimistic.

Thanks for that, guys. Appreciate it.

Next we'll move to Monroe Helm at CM Energy Partners.

Congratulations. Actually, my question was on the USGS study, so I've been taken care of. Thanks.

And next we'll go to David Tameron at Wachovia.

Congrats on a nice quarter. Can you give us a feel for what your Barnett gas volumes are doing outside of the NGL impact in the western extensions or just in general, gas volumes quarter over quarter and then sequentially and year-over-year, I should say?

Yes, I don't want to get into -- we got stung two or three years ago on giving quarterly volumes of Barnett where one quarter was less than what analysts expected and our stock dinged. So we've gotten away from giving quarterly expectations and we just have the number of 470 million cubic feet a day equivalent. I'll say that, between what we call Johnson County and then the Western Counties both of them are pretty consistently on track for our forecast to hit those numbers. We have a huge backlog currently of wells in Johnson County to complete. And so what we expect to see is the second half of the year, we're going to see more of an uptick in the Barnett kind of in growth than we saw in the first half of the year. Mainly just due to us clearing out some of the backlog at these huge number of wells that we haven't yet completed. The issue we've run into there, and this is longer and more detail than you probably want. We batch drill and complete these wells, in that if we have a lease where we think we can drill eight or nine horizontal wells in the 35-acre spacing roughly each, what we'll do is we'll drill all of those wells. We won't produce any of them initially and then we'll come back and we'll frac all of of those wells one after another without producing any of it. And so, then when we turn on the production, when it does come on, it's kind of like a batch of say 12 or 15 wells at one shot. And in Johnson County a lot of those wells come on at 6 million a day or so. So our production is kind of lumpy or so. But the overall point I'd make is we're going to deliver by the end of the year the annual average that we promised at the analyst conference and we're on track to do that.

Yes, so -- well, let me delve into what you said on the detail. If you talk about the backlog, is it pipeline capacity, is it gathering, is it processing, is it service equipment? It's not unique to EOG, others?

It's really none of those, David. It's not a logistical backlog in that we're waiting on compressure or pipeline. It's really just our people availability backlog to complete, say 15 wells back to back, to back to back and then get them online. So it's more -- if there's any backlog, it's that we've only got so many people and we can only run so many frac spreads out there to supervise them.

Okay, that's fail. Then let me ask one more question. So, on the gas side, obviously you have some growth with Barnett on the oil side. But big picture macro, a lot of talk about when the Barnett starts to -- when that growth decelerates and starts to flatten out and/or stabilize. When do you think that happens industry-wide?

Yes, it's my feeling that happens in about 2010. I really believe that by year end 2009, Johnson County is going to be pretty well drilled up by everybody in Johnson County, not just EOG. It's being drilled like a pin cushion now because it's such a sweet spot. Ad I think you'll see a shift in 2010 to more companies focusing on the Western Counties but the issue with the Western Counties are you're basically drilling 1 net Bcf well out there that doesn't have the volume impact. And I think in the core area, the same thing is happening there. So I do not expect that, we are going to have another five or seven consecutive years of either year-over-year macro Barnett growth that we've seen the last couple of years.

All right. Thanks for the responses.

Our next question comes from Wayne Cooperman at Cobalt Capital.

Hi, guys. Just kind of big picture question just on -- we had a few on gas prices. It looks like production is starting to ramp up again and just was wondering if you guys had a thought about that?

Yes. I kind of talked to that earlier. It's my sense that clearly domestic gas production is rising but it's not rising as much as the EIA raw gas data who indicate. And by our calculations, I think it's going to be a pretty good pace to get the 3.3 Tcf in storage and to get above that is, going to be a pretty good pace. So we feel pretty good about 2008 gas prices. 2009, to some degree, is going to be a function of whether we start storage at 3.3 or say at 3.6.

Right.

But I think, that as people factor in their supply/demand numbers for 2009 and '10, we need to factor in that there will be maybe 2.5%, 3% growth from the U.S. in '9 and '10. Primarily due to horizontal drilling applicability to resource plays.

That's what your intelligence would say, 2.5% to 3% as sort of the net supply growth?

Yes, this year it may be more like 3.5% but I don't believe it's going to be -- it's not 10% like some of that EIA data is saying, in my opinion.

Right. Okay. Great. That was absolutely helpful. Thank you.

Okay.

And that does conclude our question-and-answer session. And it also concludes today's conference. We would like to thank you for your participation. You may now disconnect.

Okay, everyone. I want to thank everyone for staying on the call and we'll talk to you again in three months.