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EOG Resources Inc. (NYSE:EOG)

Q1 FY08 Earnings Call

May 2, 2008, 9:00 AM ET

Executives

Mark G. Papa - Chairman and CEO

Timothy K. Driggers - VP and CFO

Loren M. Leiker - Senior EVP, Exploration

Gary L. Thomas - Senior EVP, Operations

Analysts

Brian Singer - Goldman Sachs

Gil Yang - Citi Investment Research

Joe Allman - JPMorgan

Ben Dell - Bernstein

David Heikkinen - Tudor Pickering

Leo Mariani - RBC

Tom Gardner - Simmons & Company

Monroe Helm - CM Energy Partners

David Tameron - Wachovia

Wayne Cooperman - Cobalt Capital

Operator

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 would like to turn the conference over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Mark G. Papa - Chairman and Chief Executive Officer

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 in 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 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 last night.

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; and Maire Baldwin, Vice President, Investor Relations.

We filed an 8-K with second quarter and full year 2008 guidance yesterday. These forecasts were consistent with the details provided at a recent Analyst Conference. And I'll 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'll provide an operational overview. Tim Driggers will then discuss capital structure, and I'll close with the 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 to focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impact and exclude the impact of the Appalachian property sales 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 investors who follow the practice of industry analyst to focus on non-GAAP discretionary cash flow, EOG's Bcf 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 toward more liquids production. As indicated by our first quarter results in our guidance and 8-K, I believe we are on track regarding the 2008 volume target and we will set up for 2009 and 2010. Regarding our shift to more liquids production, our first quarter total liquids increased 38% versus last year. So this shift 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 lower ratio.

And third, we intend to continue looking for new resource plays often using in horizontal drilling. As I articulated in our recent Analyst Conference, I believe this is a future of the onshore E&P business, and EOG wants to capture as many of these new place as possible using our early mover advantage.

Today, we've disclosed a new horizontal resource play that was captured in the Mid Continent. We have 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 rate 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 place. I will 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 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're in track to hit our 470 Mmcfe per day average 2008 production target and our year-to-date result 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 5 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 construct 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 4 new horizontal wells in Montague County, the Billy Henderson 2H and 3H, the Keemas [ph] at 1H and a Soakwell 2H [ph], 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 500,000 and 1 million cubic feet a day production of rich gas yielding a 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 expect we'll have more clarification regarding these items in early 2009. For the reset of this year, we'll be working on optimizing the well completions, adding more acreage and installing our infrastructure.

In British Colombia, 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 the focus on cost, 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 growth from this asset till 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're likely to know whether this is a 10 million or an 18 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 8-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.

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 in North Dakota in its entirety.

Within the Parshall field, very strong initial production rates are now routine, similar to our frequency of monster wells in the Johnson County. The more drilling we do, the more confident we are regarding our net 80 million barrel reserve estimate for this asset.

The upside to this estimate will be determined in three possible ways: First, by extending the field limits and step-outs really; second, by a possible 320-acre downspacing; and the third, by secondary recovery. The field is currently being drilling on 640 acre spacing, and we are 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 yearend, we'll have a definitive idea regarding the Bakken reserve side.

On the facility side, we just commissioned our first EOG gas processing plant to handle the associated gas volumes, and we expect to see increasing natural gas liquids 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… South Texas, excuse me, are obviously contributing their part, because the new plays won't have a volume impact until 2009 and beyond.

I'll 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 are still on track for 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 exploration -- three to five wells, excuse me, exploration programs scheduled for 2009. Additionally, we are in the process of finalizing an acquisition for ConocoPhillips relating to a tight gas sand asset in the Sichuan basin onshore China.

This is an asset that EOG owned back in 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're acquiring 130,000 acres and 7 million cubic feet a day of net production. This asset is analogous to our South Texas' Wilcox sandstones.

While we've unlocked about a half of Tcf with horizontal drilling, we believe horizontal technology is applicable to the Sichuan basin sandstones, but it will probably be 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.

Timothy K. Driggers - Vice President and Chief Financial Officer

Thank you, Mark. For the first quarter of 2008, total exploration and development expenditures including asset retirement 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 or 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 remaining $5 million of our preferred stock. We no longer have any preferred stock outstandings.

Yesterday, we filed our 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 cost for leasing wells, DD&A, G&A, total exploration, net interest expense, and excluding transportation and taxes other than income, our forecast increased 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. Similarly, for every $1 move 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.

Mark G. Papa - Chairman and Chief Executive Officer

Thanks, Tim. 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 1st 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-US, LNG demand is significantly stronger than most people would have predicted a year ago. It's a harbinger for stronger than predicted non-US LNG demand in 2009 and later periods. We now know that LNG import tunnels are being constructed or considered in Argentina, Kuwait, Dubai, Chilly, and Brazil.

A few years ago, no one would have predicted that these countries would have been importing LNG. This critical area of non-US, LNG demand growth, I believe, is something we need to watch closely, because if this demand grows continues to surprise on the up side and that is 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 and that we added a few more 2009 GAAP hedges in late April.

For the period June 1st to December 31st, 2008 we are about 30% hedged regarding North American gas at an $8.52 price. For 2009, we are about 24% hedged at $8.80. For the period May 1st to December 31st, 2008 we have about 28% of our total company oil hedged at $92.19, no oil hedge is beyond 2008. At some point, we may consider adding more of 2009 gas hedges.

Now, let me summarize, in my opinion there are five important points to take away for this call. First, we are on track to deliver our estimated 15% total production gross in 2008, while further de-leveraging an already under levered balance sheet. Assuming the future's market is indicative of actual prices then we may end the year with a net debt to total Cap ratio below 5%.

Second, there is 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 high focused on identifying and capturing new acreage and accumulations. Several of the new ideas we were working on involve oil as opposed to gas accumulations.

Today's disclosure regarding the 400 net Bcf, Mid-Continent, 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 a low cost company.

And fifth, because of the low funding cost associated with our early mover advantage, we expect to continue to generate peer group leading ROCEs in 2008 and beyond. Thanks for listening and now we will go to Q &A:

Question and Answer

Operator

[Operator Instructions]. We will go first to Brian Singer at Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Mark G. Papa - Chairman and Chief Executive Officer

Hi, Brian.

Brian Singer - Goldman Sachs

Wanted to focus on the Bakken, with the two wells you talked about, and very strong results there. I know you still need a few more months, 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?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. I guess what I would say at this point, Brian is that what we've seen from the drilling that was done to-date in the play is a pretty surprising amount of consistency in terms of pretty much in both north, south, east and west parts of the play that we've drilled, all have very, very strong wells. Now these Austin well that we highlighted, I repeat it, over 3000 barrel per day, they are towards the north end of our accumulation. And we've now got a group of, I guess about, 4 or 5 of this Austin wells that are uncommonly strong, I would say. But the surprising thing to me has been that there is a pretty good degree of uniformity in this accumulation, that's in other words is 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 is a lot of expectations out there regarding what's going on with downspacing well and so on and so forth. What I would say is, frankly we just need some time to evaluate this. As I mentioned, we are drilling our first 320 acre downspacing wells, and 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 more to us is, what are the pressures in the well and what's the well look like after three or four months of production, and has that effected rates for the surrounding wells.

I will say also, that we are taking a hard look at secondary recovery here. In other words our estimate of recovery factors, 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 will 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.

Brian Singer - Goldman Sachs

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

Loren M. Leiker - Senior Executive Vice President, Exploration

Brian, I would say that the oil potential for horizontal drilling is large, but not as large as for gas. We are taking the plays from the same place that they use the gas and we are looking for what we call basin centered accumulation, areas where oil from 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 US, were 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 were maturing from the stages of generation to capture and we've talking about those in subsequent correlations. I'm sure. In some we have to say… I think the oil potential out there is substantial and we are moving in that direction.

Mark G. Papa - Chairman and Chief Executive Officer

Yes, kind of that, 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 cheechee list, which we never disclose to analyst until they're actually technically proven , but our current cheechee list, about 50% of once on that list are oil and the other half of gas.

Brian Singer - Goldman Sachs

Great. And then, any sense on price sensitivity or these projects that when you are considering, you are going to need or what oil price did you think you generally need for?

Mark G. Papa - Chairman and Chief Executive Officer

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

Brian Singer - Goldman Sachs

Thank you.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

Next we move to Gil Yang of Citi Investment Research

Gil Yang - Citi Investment Research

Hi, so following along Bryan's questions about the Bakken and may be 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 resulting in smaller wells. The trade off would be that you get the higher volumes at smaller wells and so smaller returns. How far down the returns curve would you be willing to downspace to? Would you… if you get a 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 levels of rate-of-returns?

Loren M. Leiker - Senior Executive Vice President, Exploration

Yes, Gil, I guess 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 fate accompli, it will happen. But you really can't flood this reservoir 640 acre space. So I would say that we'll be looking at the downspacing… the downspacing, if you just run it on acceleration economics, probably its going to look pretty good. But what we need to sort out is how much incremental oil do we really recover with that, but I would tend to have people focus on, I think the key question that we have to answer in it that the sales side, my side should focus on is, is this residual amenable to secondary recovery. And, then the downspacing will be part of that.

Gil Yang - Citi Investment Research

I guess my question is, really what's the interpretation of the word amenable, if you could do it at, if you could downspace and secondary recovery at 40% rate of return-of-return, is that amenable or?

Loren M. Leiker - Senior Executive Vice President, Exploration

Absolutely, yes.

Gil Yang - Citi Investment Research

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

Loren M. Leiker - Senior Executive Vice President, Exploration

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 are really under some confidentiality provisions and we can't give any other color other than we provided you. So, I know that's not a satisfactory answer, but wisely on the next earnings call we'll be able to provide the color that people want regarding China.

Gil Yang - Citi Investment Research

All right. Thank you very much.

Operator

Next we'll go to Joe Allman of JPMorgan

Joe Allman - 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?

Mark G. Papa - Chairman and Chief Executive Officer

Joe, we currently have I think 320,000 net acres in the entire Williston Basin and the field that we always talk about, partial field including those 3000 barrel a day, Austin wells, really only it comes to about a 110,000 of those 320,000 acres. So, answer to your first question is absolutely, yes. We believe that there are other perspective areas within the Williston Basin that we have currently leased and we will be testing in the future for oil prospects. And we are continuing to lease in partial area that's a pretty hard thing to do, but other parts of the basin where exploration prospects are available we are accreting acreage curve.

Joe Allman - JPMorgan

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, could you give some color on that?

Timothy K. Driggers - Vice President and Chief Financial Officer

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

Joe Allman - JPMorgan

Can you comment on fracture stimulation cost?

Timothy K. Driggers - Vice President and Chief Financial Officer

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're seeing being pretty flat elsewhere. Another thing you know that… you'll remember, we have in place these vendor agreements through the year 2008, so they are staying flat for EOG.

Joe Allman - JPMorgan

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 Ts net to you. And so, is it similar in size net to you as well, and can you comment on the potential size net to EOG?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. The 0.5 Ts is what we think we 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 till the next earnings call, Joe.

Joe Allman - JPMorgan

Okay. I appreciate that. Thank you.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

We'll move next to Ben Dell at Bernstein.

Ben Dell - Bernstein

Hi, Mark.

Mark G. Papa - Chairman and Chief Executive Officer

Hi, Ben.

Ben Dell - Bernstein

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

Mark G. Papa - Chairman and Chief Executive Officer

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 North Western 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 9 wells out there. 4 of those are horizontal. And we plan to drill another… probably 5 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 Northwestern Pennsylvania. I'd say we're encouraged by the results we hear announced by others in the play. Our own results have come fairly slowly. When we get our new rig there in middle of May, we hope to accelerate those results.

Ben Dell - Bernstein

Okay. Can you give us an indication of IPs that you've had on the wells you drilled the horizontal?

Mark G. Papa - Chairman and Chief Executive Officer

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

Ben Dell - Bernstein

Okay. On a separate topic, historically, you've had better returns on your assets within the US than outside the US, specifically Canada, Trinidad, UK. With China, what's sort of leading you to increase the international expansion at another country? And it appears that money would be better spent at home. Are you limited in terms of how much you can grow and do in the US?

Mark G. Papa - Chairman and Chief Executive Officer

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 we've 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 comfortable to the returns we've gotten in certainly in the US, except maybe for the last year when US gas prices went up.

The idea in China is one that where we've looked at areas where there is an energy short part of the world, we believe that this onshore horizontal technology is going to be amenable to places outside North America in uncovering pretty substantial pools of hydrocarbons. And what I'd say on the reinvestment return in China is, if it works, we expect it to be comfortable with some of other investments in the company.

Ben Dell - Bernstein

Okay, great. And just lastly, a quick one, there's been some talk about sort of Eastern European type gas basins and the gas strictly around Ukraine. Is that another area you're taking a look at or do you see Eastern Europe in the horizon for you?

Mark G. Papa - Chairman and Chief Executive Officer

Specifically, the Ukraine, no, we're 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 basins centers gas accumulations that are amenable to the horizontal drilling in those areas.

Ben Dell - Bernstein

Okay, great. Thank you.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

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

David Heikkinen - Tudor Pickering

Good morning. I had a question on the comments of finding the Bakken North, South, East and West. That is in 110,000-acre area of consistency around Parshall, not the 320,000 acres. Correct?

Mark G. Papa - Chairman and Chief Executive Officer

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

David Heikkinen - Tudor Pickering

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

Mark G. Papa - Chairman and Chief Executive Officer

Yes, I mean the two biggest barrier… potential reasons are that: One, if this thing if we deem that it has in-situ, high degree of fractures, natural fractures, that's a barrier. And then the second reason is on the converse, if we deem that it's got shockingly low permeability, that would be a barrier.

On the positive side, in a typical oil reservoir and I'm saying a typical sandstone or so, you usually get something like 15% or 20% on primary recovery or the recovery of the oil in place and initially we are only dealing with 10%. So, we've got 90% of the oil that we are not going to get out as it stands now. And that's a pretty big prize for us to chase.

David Heikkinen - Tudor Pickering

Is there a relative permeability to oil versus relative terms of water issues that you have identified or --?

Mark G. Papa - Chairman and Chief Executive Officer

No, we're just… yes, we are just looking at all that stuff.

David Heikkinen - Tudor Pickering

Okay.

Mark G. Papa - Chairman and Chief Executive Officer

Now, it's probably too soon to comment really.

David Heikkinen - Tudor Pickering

And then just going to the Atoka, you talked about 50,000 net acres and 400 Bcf. Is that… what's your growth acreage there, ability to continue to expand that? Is that a concentrated area or and then spacing assumption?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, I guess, I mean the rock spacing assumption there is well every 320 acres. And this particular zone is pretty sand, so it's not obvious that we will be able to come back to you in a few months and say, "Wow, we can double that to 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 maybe 600, maybe 700 net Bcf.

David Heikkinen - Tudor Pickering

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

Timothy K. Driggers - Vice President and Chief Financial Officer

Well, the total number that we have that we released in 10-Q last night for all of our leasehold acquisitions for this year is about 360 and really will stay pretty close to that number.

David Heikkinen - Tudor Pickering

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

Timothy K. Driggers - Vice President and Chief Financial Officer

But if it does, then it will likely be down by other downticks.

David Heikkinen - Tudor Pickering

Okay. And then final question, as everybody wants to know about Bossier and Haynesville Shale, can you talk about anything you are doing in Louisiana, Texas trying to test the shales on floors there?

Mark G. Papa - Chairman and Chief Executive Officer

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 essence on the overall play.

David Heikkinen - Tudor Pickering

I appreciate that. Thanks you.

Operator

Our next question comes from Leo Mariani at RBC.

Leo Mariani - RBC

Yes, a quick questions here on the 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?

Mark G. Papa - Chairman and Chief Executive Officer

I think our total number to date on 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 2008, we have like 50, I believe. And on the gross, it's going to be in the mid-70s. Is that right, Gary?

Gary L. Thomas - Senior Executive Vice President, Operations

80.

Mark G. Papa - Chairman and Chief Executive Officer

80 or so, gross.

Leo Mariani - RBC

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

Timothy K. Driggers - Vice President and Chief Financial Officer

It's 12,000 to 12,500 barrels oil per day net.

Leo Mariani - RBC

Okay. A quick question on your North East B.C. plant there, how long did you hedge your three wells that there are on production?

Mark G. Papa - Chairman and Chief Executive Officer

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

Leo Mariani - RBC

Okay. And I guess would you guys probably anticipate stepping up your drilling there in 2009?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, the logic path there is that we've got 40 million a day of available pipeline capacity, and we're drilling up wells to fill that up in a 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 takeaway to really a see big volume ramp-up there.

Leo Mariani - RBC

Okay. Last question here on the Barnett, just curious what you guys are seeing these days in terms of EURs on your Western County extension well, as well as cost out there, and what you guys are seeing at Hill County in terms of cost in EURs?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. 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 well cost out there are running out 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 well is kind of what we're seeing. We're seeing a little bit different set of characteristics in Hill County and the wells don't come on as they kind of monster initial rates, like in Johnson County, but they don't decline at the very high rate that the rest of the Barnett does. We're really completing in a different facies of the Barnett there. And so, what we get per wells that have initial production rates of maybe 2, 2.5 million a day but they're relatively flat as far as declines.

Leo Mariani - RBC

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

Mark G. Papa - Chairman and Chief Executive Officer

$2.4 million, $2.5 million range for Hill County.

Leo Mariani - RBC

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

Mark G. Papa - Chairman and Chief Executive Officer

I would guess about 12.

Leo Mariani - RBC

Okay. Thanks a lot for your time.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

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

Tom Gardner - Simmons & Company

Good morning, guys.

Mark G. Papa - Chairman and Chief Executive Officer

Hey Tom

Tom Gardner - Simmons & Company

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

Mark G. Papa - Chairman and Chief Executive Officer

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 like 3.0% growth is what they're officially forecasting for '08 versus '07. I just flat do not believe that we're seeing from 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 the 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 US in '08, '09 and 2010, it's the forecast for three years.

So I think that the sea change with horizontal drilling has changed this from an industry that could barely keep production flat in the US to one that we will have production growth in the US for the next several years, at least, in my opinion. I also think that once we get a little more flush production coming out of the offshore field that's currently offline, I think that we're to see some pretty sharp decline 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 as the level of the rigs that are currently running in the Gulf of Mexico have some recipe for some pretty sharp declines that is going to occur. So we will have a counterbalance effect I believe in the Gulf Mexico to this onshore growth.

Tom Gardner - Simmons & Company

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

Mark G. Papa - Chairman and Chief Executive Officer

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 is taking a good approach in that he has looked at it as basin-centered oil accumulation, which is correct we believe, covering a very large area although it is relatively thin. For the number that he comes up with, I think its midpoint numbers, maybe 3.7 billion barrels of oil recoverable. It's fundamentally and technically correct, but perhaps not economically extractable.

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, and that's where we think it's perhaps a little optimistic. The shale may not be intact. 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, so you may have water issues in some areas. And also, there will be variations. Parshall is such a sweet spot because of fracture density in the facies of the rock and that will probably not be true in very many other places in the Williston Basin.

So, in summary, I'd say that the overall number is not incorrect; it's just perhaps optimistic.

Tom Gardner - Simmons & Company

Thanks for that guys. Appreciate it.

Operator

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

Monroe Helm - CM Energy Partners

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

Operator

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

David Tameron - Wachovia

Hi. Congrats on a nice quarter.

Mark G. Papa - Chairman and Chief Executive Officer

Thanks, Dave.

David Tameron - Wachovia

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

Mark G. Papa - Chairman and Chief Executive Officer

Yes, I don't want to get into -- you know, we got stung two, three years ago on given quarterly volumes on Barnett where in one quarter it was less than what the analysts expected and our stock got down. So we've gotten away from giving quarterly expectations. And we just have that number of 470 million cubic feet a day equivalent.

I'll say that between what we call Johnson County and then Western County, 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 in the second half of the year, we're going to see more of an uptick in the Barnett kind of in gross than we saw in the first half of the year, mainly just due to us clearing out some of the backlog of these huge number of wells that we haven't yet completed.

The issue we run into there and this is the longer, in more detail, than you probably want is we batch drill when we complete these wells and if we have at least where we think we can drill eight or nine horizontal wells in a 35-acre spacing roughly each, what we'll do is we'll drill all those wells, we won't produce any of them initially, and then we'll come back and we'll frac all 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 in Johnson County. And all 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 are going to deliver by end of the year the annual average that we promised at the analyst conference, and we are on track to do that.

David Tameron - Wachovia

Yes. Let me delve into what you said in detail, if you talk about the backlog, is it pipeline capacity or is gathering, is it processing, is it service equipment? I mean it's not unique to EOG or others?

Mark G. Papa - Chairman and Chief Executive Officer

It's really none of those, David. It's not a logistical backlog in it, waiting on the compressors or pipelines. It's really just a people availability backlog to complete phase 15 wells back to back to back to back and then get them on line. So, it's more… if is there any backlog, it's… we have only got so many people and we can only run so many frac spreads out there to supervise.

David Tameron - Wachovia

Okay, that's fair. And then let me ask you one more question. It's on the gas side. Obviously, you have some growth in the Barnett on the oil side, but big picture macro, a lot of talk about when the Barnett starts to… when that growth accelerates and it starts to flatten out and/or stabilize, when do you think that happens industry-wide?

Mark G. Papa - Chairman and Chief Executive Officer

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

David Tameron - Wachovia

All right. Thanks for the responses.

Operator

Our next question comes from Wayne Cooperman at Cobalt Capital.

Wayne Cooperman - Cobalt Capital

Hi, guys. Just kind of big picture question, just on… you got a view on gas prices, it looks like production starting to ramp-up again and I just was wondering if you guys had a thought about that?

Mark G. Papa - Chairman and Chief Executive Officer

I kind of talked that earlier. I guess it's my sense that clearly domestic gas production gas is rising. But it's not rising as much as the EIA raw gas data would indicate. And by our calculations, I think it's going to be a pretty good race to get to 3.3 Tcf in storage and to get above that. It can 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 play at 3.6. But I think as people factor in your supply/demand numbers for 2009 and 2010. We need to factor in that there maybe 2.5%, 3% production growth from the US in '09 and '10, primarily due to horizontal drilling applicability of resource plays.

Wayne Cooperman - Cobalt Capital

So you guys and your intelligence would say 2.5% to 3% as sort of the net supply growth?

Mark G. Papa - Chairman and Chief Executive Officer

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

Wayne Cooperman - Cobalt Capital

Right. All right, great. That was absolutely helpful. Thank you.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

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.

Mark G. Papa - Chairman and Chief Executive Officer

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

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Source: EOG Resources, Inc. Q1 2008 Earnings Call Transcript
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