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Executives

Mark Papa – Chairman and CEO

Tim Driggers – VP and CFO

Gary Thomas – Senior EVP, Operations

Loren Leiker – Senior EVP, Exploration

Analysts

David Heikkinen – Tudor Pickering Holt

Tom Gardner – Simmons & Co.

Joe Allman – JPMorgan

Brian Singer – Goldman Sachs

David Tameron – Wachovia Securities

Gil Yang – Citi

Leo Mariani – RBC Capital Markets

Ellen Hannan – Weeden & Co.

EOG Resources, Inc. (EOG) Q1 2009 Earnings Call Transcript May 5, 2009 9:00 AM ET

Operator

Good day, everyone and welcome to the EOG Resources First Quarter 2009 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time for opening remarks and introductions I would like to introduce the Chairman and Chief Executive Officer of EOG Resources Mr. Mark Papa. Please go ahead, sir.

Mark Papa

Good morning and thanks for joining us. We hope everyone has seen the press release announcing first quarter 2009 earnings and operational results. This conference call includes forward-looking statements. The risks associated with the 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 Web site at eogresources.com. The SEC currently produces 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, North Dakota Bakken, Horn River and Haynesville may include other categories of reserves.

We incorporate by reference to cautionary note the U.S. investors that appear at the bottom of the press release and investor relations page of our Web site. An updated Investor Relations presentation and statistics were posted to our Web site 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 Marie Baldwin, Vice President, Investor Relations.

We filed an 8-K with second quarter and full year guidance yesterday. I'll discuss this guidance along with our 2009 strategy in a minute when I review operations.

I'll begin by reviewing our first quarter net income available to common stockholders and discretionary cash flow and then I'll review our updated plan for 2009 and operational results. Tim Driggers will provide some financial details and then I'll provide some macro comments and concluding remarks.

As outlined in our press release for the first quarter EOG reported net income available to common stockholders of $158.7 million or $0.63 per share. For investors who follow the practice, the industry analysts who focus on non-GAAP net income available to common stockholders to eliminate mark-to-market impact as outlined in the press release.

EOG's first quarter adjusted net income available to common stockholders was $132.7 million or $0.53 per share. For investors who follow the practice, the industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the first quarter was $732.5 million.

Before I review our first quarter operational activities, it's worthwhile to take a summary look at 2008 final results. We reported our fourth quarter results early in the cycle and only after peer companies reported their full year results did we realize that EOG had achieved differentiating results regarding 2008 metrics.

We finished first among the large cap peer group in every critical category. Best stock performance, highest ROCE, lowest all in signing costs, highest debt adjusted production growth, lowest unit cost, lowest net debt ratio, no significant financial write-downs and the minimum price effective reserve write-downs. They say the past is prolog and we encourage investors to focus on the stock performance differences here. It's rare when one company can claim annual outperformance in every single critical metric and I hope it gives our shareholders lot of comfort.

Regarding 2009, we raised our production growth target from 3% to 5.5% while keeping our CapEx estimate flat at $3.1 billion. This new growth target is notable because we restricted our Bakken oil production for the first six months of this year due to marketing issues. The incremental 2.5% production growth is comprise entirely of higher North American liquid and Trinidad gas.

The largest tranche of the incremental increase is North American crude, condensate and NGLs driven by strong results from our Bakken and Barnett place. This trend of increasing North American liquids production will continue over the coming years as our horizontal oil plays begin to have greater impact. The increase in Trinidad gas production is due to quicker turnaround on third-party plant maintenance than originally forecasted.

I'll also note that the 5.5% production growth target assumes that we don't curtail any gas production in the second half of the year because of market storage conditions. Our North American gas production profile is such that our production nadir will occur at the beginning of the fourth quarter and begin inflecting upward at the end of the year in anticipation of stronger 2010 gas prices. Because of the current low gas prices, we are projecting our North American natural gas production to follow by 1% this year.

I'll start off our specific play discussion with Barnett gas and then follow with the Barnett Combo. Our Barnett gas activity is going well quite well albeit at a reduced level from last year. We'll average 11 Barnett gas rate this year compared to 24 Barnett gas rate last year.

Like everyone else we are benefiting from lower service costs and our Johnson County wells are averaging 2 net Bcf or $2.8 million completed well cost. Today, we only drilled half of our total Johnson County locations so we got a sizable remaining inventory. In Hill County, immediately south of Johnson County, we are consistently making 1.5 net Bcf wells. To our knowledge we are the only company consistently making good wells at Hill County. We are also making acceptable wells in our western counties.

Now I'll switch to the Barnett Combo play which is gaining momentum and it's one of the reasons we increased our North American liquids gross rate. During the first quarter, we completed 12 new wells that would yield an approximate 30% direct after tax rate of return based on current non-ex-prices and well cost. It happened in Johnson County, our Montague County well results are improving with time. We are now pattern drilling similar to Johnson County where we drilled in simultaneously complete groups of 4 wells to 8 wells to get better frac coverage.

The Barnett Combo will be a major 2010 through 2015 production growth driver and this year, we are simply setting the stage for more significant volume growth in later years.

Net liquids production from all of our Barnett activity should average 12,000 barrels per day this year and grow to 21,000 barrels per day in 2010 and reach over 42,000 barrels a day by 2012.

Last night we posted a new chart in the IR Presentation on our Web site. The chart shows our 2009 through 2012 estimated total Barnett production from all of our activity gas and combo. We expect to grow these annual average volumes from 460 million cubic feet a day equivalents this year to 700 million cubic feet a day equivalent in 2012 provided that hydrocarbon prices are reasonable.

As we noted a year ago in our February 2008 analyst meeting, our Barnett gas production will plateau over time and the incremental volume growth would be from the combo.

In summary, we control the vast majority of the combo play acreage and we are now converting that to a high ROR multi-year revenue stream.

Moving north of the border into Manitoba, Canada, EOG has achieved a new horizontal oil success this time in the Waskada field. The rock formation here is not shale; it's a tight silk stone with a water zone immediately below it. This is an old EOG legacy field originally drilled with vertical wells with very low recoveries that would rejuvenate with horizontal.

We have now drilled 29 successful horizontal wells and a typical well yield 65% after tax reinvestment rate of return using current NYMEX prices. We estimate we have 25 million barrels of oil net recoverable reserves after royalty on our acreage and are currently in development mode. We expect this field to ramp up from the current 1900 barrels of oil per day to 9500 barrels of oil per day net by yearend 2012.

Moving to the North Dakota Bakken, we are currently operating an 8 rig drilling program compared to last year's 10 rigs. We deferred almost all well completion till this summer when the frac jobs can be done more economically and road conditions improve, so we don't have any well results to report at this time.

In our last earnings call, I noted that we were restricting our Bakken production because of marketing issues, high location differentials and low WTI prices. Recently, WTI prices have increased and differentials have shrunk. So we plan to bring back our Bakken production in June and be at full production in July.

You may recall the issues with Bakken crude marketing, our limited pipeline take-away from North Dakota and an inferior price at the Clear Brook Minnesota market hub. Because we expect our Bakken production to grow for many years, we are resolving both of these problems by implementing a plan to move our crew via rail car unit trains from North Dakota to Cushing, Oklahoma or other market hubs.

We finalized a strategic transportation arrangement with BNSF railway and expect to have the rail facilities operational by February 2010. I won't divulge specifics regarding the all in transportation and terminal cost except to say that it will provide us a significantly better long-term oil net back than what we're seeing currently. We can pursue our own transportation arrangements due to the scale of our Bakken position, currently about 500,000 total net acres and dominance in the core area.

Regarding two horizontal gas plays, the Haynesville and Horn River, we don't have any specific well results to report this quarter. We are currently running four rigs in the Haynesville and will have specific well results later in the year.

We are running two rigs in the Horn River basin but are deferring the completion until this summer. We are however firming up long-term transportation and processing agreements for our Horn River gas.

In the Pennsylvania Marcellus, we are running one rig and have now completed 11 horizontal wells on a 240,000 net acres. We've improved that frac techniques on our most recent wells with net reserves of 1.6 Bcf per well to 3.0 Bcf per well. We current estimate we have two net PCF to three net PCF captured on our Marcellus acreage.

Our standard plays in North America are all performing well particularly with the efficiencies gained by lower service costs and lower activity level. We are getting the results we expected and these plays are acting as a support base that contributes to our increased volume growth.

We all get caught up in the excitement of the horizontal plays, but we are still finding many successful vertical plays. One example is our East Texas Travis peak stack and frac play where we've captured 800 net Bcf at a $1.55 per Mcf direct funding cost that we'll be developing over the next few years.

On the international front, we are currently drilling the first of two exploration wells in the East Irish Sea and we started our horizontal drilling program in China. As we noted in the last call, we won't have any meaningful results from China until yearend.

I'll now turn it over to Tim Driggers to discuss CapEx and capital structure.

Tim Driggers

Thanks Mark. For the first quarter total exploration and development expenditures excluding asset retirement obligations were $872 million. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment, were $65 million.

Capitalized interest for the quarter was $12.2 million. Yesterday's 8K filing indicates a total capital expenditure budget of $3.1 billion, the same guidance that we gave back in February. The capital expenditures this year will be front-end loaded and will taper off over subsequent quarters.

At March 31, 2009, total debt outstanding was $2.1 billion and the debt-to-total capitalization ratio was 19%. About $220 million of our debt increase versus the previous quarter was due to an increase in working capital and other assets and liabilities.

At March 31, we had $85 million of cash giving us non-GAAP net debt of $2 billion or net debt total cap ratio of 18%. The effective tax rate for the quarter was 40% with a 78% deferred tax ratio. The items driving the effective tax rate during the quarter were lower pre-tax income amount combined with a true-up of state income taxes.

Yesterday, we filed a Form 8-K with second quarter and full year 2009 guidance. For the full year 2009, the 8-K indicates an effective tax rate of greater than 35%. We have also provided an estimated range of the dollar amount of current taxes that would be reported during the second quarter and full year.

The deferred tax ratio on a GAAP basis is expected to decline from prior years due to reduced CapEx and IDC expensing as well as the realization of hedging gains in 2009 that had been taken as mark-to-market income over the course of 2008. Effective tax rate will depend in large part on the relative levels of form and domestic pre-tax income.

Now I'll turn it back to Mark to discuss the macro environment, our hedge position and concluding remarks.

Mark Papa

Thanks, Tim. Our view in North American gas and oil market is fundamentally unchanged from our previous earnings call. Simply put, we expect North American gas prices to remain depressed until 2010 when we expect recovery to the $7 to $8 range. We expect oil prices to trade within a tight range for the next few months and to slowly strengthen in the second half ending the year at $60 to $65.

We expect 2010 oil prices from producers with prices similar to the forward curve or higher. The item to watch in the oil front is non-OPEC production levels which we expect to follow over the course of next year.

For domestic gas we have taken a stab at modeling the impact of the rapid decline in drilling activity and we expect yearend 2009 production to be 4.5 Bcf a day lower and yearend 2008, assuming a yearend gas recount of 650.

We expect domestic production to begin to decline in April or May, so we got another two or three EI914 reports to endure before the decline becomes apparent. Our analysis indicates Texas natural gas production has already begun to decline.

We expect full year 2010 total domestic production to average 3.8 Bcf a day less than full year 2009. In Canada, we expect total production to decline by 0.8 Bcf a day in 2009 and another half Bcf a day in 2010.

Recognizing the current gas supply demand imbalance, EOG's 8-K that was filed yesterday, indicates our 2009 North American gas production would be slightly slower than 2008. This is consistent with our philosophy of not cramping gas into an oversupplied market. Our 3.9 billion CapEx budget this year is being directed toward liquids investments.

I'll note one other thing regarding the North American gas market. Remember that the market resets itself every November because of storage limitation. Our hedge position is consistent with our macro view. We have added to our hedge position for the second half of 2009, about 47% of our April through December 2009 gas is hedged at $9.04.

Based on our macro view, we recently closed out all of our second half 2010 gas hedges swaps and collars that were at a roughly $10 price. We remain lightly hedged for the first half of 2010 at $10.27 per MMBTU. We are totally unhedged regarding oil.

Now let me summarize. In my opinion, there are six important points to take away from this call. First, we've increased our 2009 North American liquids production estimate and we expect further growth in 2010, '11, '12 and later years as the impact of our horizontal oil plays begin to kick in. Each year we expect our ratio of North American liquids versus gas to increase.

In 2007, we produced 43,000 barrels a day of total company liquids. In 2008, this grew to 61,000 barrels a day. This year, we expect to produce 75,000 barrels a day even after limiting our Bakken production. In 2010, we expect 90,000 barrels a day, all organic. We believe this significant organic North American liquids growth is a key differentiating factor for EOG.

Second, we are now at a manufacturing mode in our Barnett Combo play which will generate steady and substantial liquids growth for multiple years. More importantly, these per well investments are currently yielding at approximately 30% unlevered direct after tax reinvestment rate of return at current hydrocarbon prices and well cost. If oil stabilizes at $70 to $90 over the next multiple years, these RORs will be even more advantageous.

Third, our new Manitoba play further confirms EOG's first mover position in the application of horizontal drilling to an oil play. We have now established first mover position in the Bakken, the Barnett and at Manitoba play. The Manitoba play is similar to the Barnett Combo, is it generates very strong after tax reinvestment rates of return even at current oil prices.

Fourth, our 2009 CapEx program is directed toward liquids investments, but we'll note that our North American gas inventory position is particularly deep and geographically widespread between the Barnett, Haynesville, Marcellus, Horn River and Uinta basin.

Practically speaking, we can grow our North American gas production at any annual rate between zero and double-digit per year growth for at least the next seven years by simply deciding what level of capital to deploy each year. We already have the organic inventory captured at early mover cost levels.

We have included a chart in the new IR presentation posted on our Web site showing EOG's total Barnett shale production growth through 2012. Our feelings about the growth power of the EOG's Barnett are consistent with what we noted in our February 2008 Analyst Conference; i.e., the combo play will generate aggregate Barnett gas plus liquids growth for many years.

And sixth, we'll accomplish the above while maintaining one of the lowest net debt to cap ratio in the peer group and keeping our focus on high reinvestment rates of return and concomitant strong ROCEs.

While we are on the subject of return I continue to be amazed that both the buy and sell side treat the large write-offs we have recently seen as one-time event and non-cash charges even though it was cash at the time of investment.

It's my belief, by doing so, investors are sending the signal to EMP management to generate volume growth without regard to investment rate of return and if it doesn't work out, we'll allow you to treat it as a one-time event with essentially no valuation penalty. I'll close with the question to investors. Is that really the signal you want to send to EMP management?

Thanks for listening. And now we'll go for Q&A. Vickie, you want to queue up the Q&A, please?

Question-and-Answer Session

Operator

Absolutely. (Operator instructions). We'll take our first question from David Heikkinen with Tudor Pickering Holt.

David Heikkinen – Tudor Pickering Holt

Good morning, Mark. I had a question thinking about Horn River Basin, first production in July 2008 versus pipeline capacity. What should we expect in July '08 as you ramp up pipeline capacity into 2012? How does that ramp-up actually happen?

Mark Papa

Yes, in terms of production by 2012, we are slotting a rough idea somewhere in the range of about 120 million cubic feet a day by then. Somewhere between 120 million cubic feet a day and 150 million cubic feet a day. It's our belief that the majority of the production and aggregate from the Horn River Basin will really not start to come on until 2012 or later. Because we are on the West side of the basin, we get a little better pipeline access than someone on the East side, so we are going to get a bit more production likely earlier than others.

David Heikkinen – Tudor Pickering Holt

And all your 2012 targets, those are exit rate for 2012 that you mentioned on the gulf?

Mark Papa

The 2012 number, for example, like the Barnett number, that's a full year average number.

David Heikkinen – Tudor Pickering Holt

Okay. It's kind of mix and match like Manitoba that would be yearend exit rate that Canada gas then 120 would be an exit rate?

Mark Papa

That's probably a full year average on that one too. Yes, so the one that to exit rate is the Manitoba.

David Heikkinen – Tudor Pickering Holt

Okay. And going through each area can you talk about cost as far as first Barnett Gas Hill County and Western County and then Barnett Combo? And that's it. Thank you.

Mark Papa

In the Barnett gas, which would be the Hill Johnson County area, we are looking at $2.8 million well cost right now. In the Barnett Combo play, we are looking at something like about $3.1 million, and then in the western areas, it's considerably lower, it's probably about $1.8 million. So the western areas are more shallow that's why well cost is cheaper there.

David Heikkinen – Tudor Pickering Holt

And just one follow-up on the combo, is drills and wells and pallet into county as well as that part of the combo play or is that part of the western? Just trying to get an idea where the border is for combo versus western.

Mark Papa

Yes. When we talk about combo play we are really saying anything that gives us a rich liquid yield on there. So it could cover an area bigger than just Montague County.

David Heikkinen – Tudor Pickering Holt

Does that include Palicento [ph]?

Mark Papa

May or may not.

David Heikkinen – Tudor Pickering Holt

Fair enough.

Operator

Next we'll hear from Tom Gardner with Simmons & Co.

Tom Gardner – Simmons & Co.

Good morning, everyone. Hey, Mark, I had a question on your rail project. Is there anyway you can give us an idea of the total impact on your Bakken and oil differential without giving away company secrets?

Mark Papa

Well, obviously, we are still in negotiations, they haven't finalized it, so I really don't want to give a lot of details about the current agreement. But just to give you some rough ideas if you look at the fourth quarter of '08 and really the first quarter of '09, the stuff that we were able to get in the pipeline, all we can get the pipeline was a reasonable tariff, but the stuff that we had to truck out of there, we were paying an up to $25 a barrel to get that crude truck to places like Salt Lake City and in some cases we truck to all the way to Cushing, Oklahoma which was absurd. And as we look at this we said, well, there is one pipeline out there. It's called Inbridge oil pipeline. The problem is it's pretty well maxed out and we can't get all oil in there because of the upsurge in western North Dakota production, so we said our first priority is to get as much oil as we can in that Inbridge line, but we expect we'll be producing so much incremental oil above that, that we have to find an option over and above the trucking. And this unit rail car is an option that we ended up with and it will considerably lower differential in many cases, it's essentially competitive with the Inbridge pipeline tariff issue.

Tom Gardner – Simmons & Co.

Great. Thank you. And I appreciate your comments on gas macro. I wanted to get your thoughts on this inventory of drill, but uncompleted wells specifically how do you think this inventory has changed over time and what do you think its impact on sort of the gas supply equation will be?

Mark Papa

Yes. I don't think it's really a major factor there, Tom. The people who generally are talking about it at the gas inventory of drill, but not yet completed wells are really the people operating in the urban areas of the Barnett Shale and that's been a chronic problem years and years and years ago. The issue is, you drill a well in the urban areas of Barnett Shale and it may be one year or two years before you can get a pipeline outlet, get it out of there so there's no real reason to hurry up and complete the well. So our read is that particularly in the Barnett urban areas is that inventory will bleed off over time, but it's not going to affect our view of the macro. So I think that particular aspect of the gas market may have been overstressed. We don't think is that big of the deal.

Tom Gardner – Simmons & Co.

Yes, I agree. Just from an EOG perspective companywide, what is your average time from say the rig moving off a well to the time that's on sale?

Mark Papa

I'll ask Gary Thomas to deal that one.

Gary Thomas

On the Barnett, it takes about 45 days to 60 days. And then that depends on how active you are with completion fleets. We've got three completion fleets there in the Barnett that are under long-term contract to us. So we are just utilizing those. So our time from rig released to completion is a little stretched through 2009.

Tom Gardner – Simmons & Co.

Do you think that number would hold up companywide on at least on the gas side?

Gary Thomas

Depends on if it's horizontal or vertical wells. If it's vertical wells, it's just a matter of weeks. Probably most all vertical wells are going to be completed on sales within 30 days. The horizontals where we hold up and drill a couple and then just counting on complete it together, that's when you have the longer period of time between rig released and final completion.

Tom Gardner – Simmons & Co.

Thank you, guys. Appreciate your comments.

Operator

Our next question will come from J.P. Morgan Joe Allman.

Joe Allman – J.P. Morgan

Thank you. Good morning, everybody. Mark, I know you said you didn't want to give any specific details on the Haynesville, or the Horn River, but people talk about that Gammage well in east Texas. Could you give us some color on that? And could you just give us some color on the east Texas, Haynesville? How results are looking there, what you are doing? And I got a couple of follow ups.

Mark Papa

Yes. Joe, we can acknowledge that there is a Gammage well. We'll share that information. We're currently in the completion and testing phase of that well and really don't have anything further to report on it. And we know it's very, very closely watched well, but at this time it would just be premature to give any information on it.

Joe Allman – J.P. Morgan

Any color about the east Texas, any results you have seen to-date?

Mark Papa

I don't want to go there right now, Joel.

Joe Allman – J.P. Morgan

Okay. Got you. And then just in terms of the first quarter results, the oil production was better than guided. Given the fact you shut in half of your Bakken production, can you explain why the oil was better than guided?

Mark Papa

Yes. Some of it is due to just the fact that our Bakken wells are doing a bit better than what we had projected. And the other piece of it is really our Barnett combo production is starting to feed in pretty nicely now.

Joe Allman – J.P. Morgan

Okay. Got you. And then in terms of the question on the Bakken production and the rail and pipeline, when you got that rail system up and running, how much capacity do you have to pipe and then how much capacity will be rail capacity?

Mark Papa

Yes, in terms of the pipeline capacity on a net basis, it's probably something like about 10,000 barrels a day. So on a net basis, the way to look at the rail is pretty much anything we do over 10,000 barrels a day net is likely to go out on a unit train and we got room for that to go up, we could easily be moving on a net basis, incremental 20,000 barrels a day on unit trains. The good thing about these unit trains are really just you can upside or you can downside it pretty readily just by how many trains you run basically.

Joe Allman – J.P. Morgan

Is that unit, is that exclusive to you or there are some other operators going to be moving oil there as well?

Mark Papa

We are making all the investments at a 100% EOG level and we expect once this thing gets up and running it's going to be a pretty effective third-party business for us in terms of other people coming to us and wanting to access.

Joe Allman – J.P. Morgan

Alright. Very helpful. Thank you.

Operator

Our next question will come from Goldman Sachs, Brian Singer.

Brian Singer – Goldman Sachs

Thank you. Good morning. In the Manitoba area can you talk about any infrastructure constraint and what the assumptions and flexibility around the assumptions are for your guidance of 25 million barrels resource and 7,000 barrels a day to 8,000 barrels a day increased production by 2012?

Mark Papa

Yes. This is an old field that we define the geologic limits on it, 10 years to 15 years ago. And we've now drilled enough horizontal wells to give us a pretty good confidence level on what the proper spacing is between wells. So the 25 million barrel net after oil estimate, I would say, we have a high confident factor in that. It's not really potential. It's a stronger than potential situation. In terms of the infrastructure, we'll have to upsize the capacity of some of our surface facilities there to handle this, but that's a pretty routine deal. So this one is going to be relatively easy to upscale. Lot of these horizontal plays where the oil or gas we find such as in the Bakken area that there weren't a lot of infrastructure there or in our Barnett Combo area, so we have to build the infrastructure from ground up. In this Manitoba play we are fortunate enough that we got all the infrastructure there essentially.

Brian Singer – Goldman Sachs

Thanks. And I guess because the geologic limits, that then cap be upside or do you view it, what could happen where that 25 million barrels could end up being much more, if anything?

Mark Papa

Yes, we may add some additional potential extended geologic limits, but this is not one where we're talking about 25 million barrels going to a 100 million barrels or so. The upside potential might be as high as 50, but we don't want to paint this as monstrous upside.

Brian Singer – Goldman Sachs

And then switching to natural gas, when you look at some of the vertical areas you operate in, you went to basin, east Texas, south Texas, what gas price are you looking for given lower well costs where you would consider bringing back rigs when you think about the second half of this year and into 2010?

Mark Papa

Yes. We are pretty negative on the gas price throughout the year, so we are not really going to be looking at signals of gas price coming up to make us kind of add gas rigs. What we are really going to be looking at are the production data that comes out each month and to see whether our estimates are tracking correctly or not. And then also we're going to be looking at what happens to this gas rig count. In other words, if gas rig count falls below 650 by yearend, we probably be a bit more aggressive in gearing up our gas drilling conversely if the gas recount doesn't get below 750, we'd probably be very hesitant to step up gas drilling. So we are going to look beyond what the current gas price is to what do we expect to happen in 2010.

Brian Singer – Goldman Sachs

But I guess at some point though when you think about it from an IRR perspective it would be based on your own internal gas price forecast for what that lower rig count would end up leading to. Any sense on numbers there what you think you would ultimately need to get attractive rates of return?

Mark Papa

Yes. I don't want to go at it that way, but I'm saying until we believe gas prices are going to get backup to $7, we are not going to get very aggressive on our gas activity. Basically from the tone of this call you can tell that we got a pretty deep oil and liquids inventory and we are going to be attacking that. I don't take that to say we need a $7 gas price to get a decent IRR gas drilling. What I'm saying is that we are seeing a fatter reinvestment rate of return on the liquid side than on the gas side and we don't see a big reason to go chasing a bunch of gas drilling, for example, if gas gets all the way up to $5.

Brian Singer – Goldman Sachs

Thanks for the color.

Mark Papa

Okay.

Operator

Next we'll here from David Tameron with Wachovia.

David Tameron – Wachovia

Hi, good morning. Couple of questions. Mark, going back to the Bakken, if you start talking about Marathon and Wyene [ph] also have been out there, so they have shut in production and they are going to bring that back on April, May, if you bring back yours back on July, how tight would the infrastructure be between them and first part of 2010 before you get the potential rail project underway?

Mark Papa

Yes. The answer to that is it will probably tighten a bit more than today, and we just can't really accurately estimate that. What we do know is when we made the decision to cut the production with WTI was selling on a NYMEX $35 or so and now we are looking at something that's considerably higher than that. So one point to note, you bring up a good point. If we bring the production on in July and say in August, the cost to get the crude truck out of there just go up exponentially, we may just curtail production in September. So we are just going to watch it month by month, but our current estimate is that we think we are going to be okay, but we still will be suffering a dime on differential for the stuff that we can't get into the pipeline until February of 2010.

David Tameron – Wachovia

Okay. Alright. Let me go back to something else. You said you took off some hedges in the back half of 2010. Did I hear that correct?

Mark Papa

That's correct.

David Tameron – Wachovia

And those hedges were $10?

Mark Papa

Correct.

David Tameron – Wachovia

Are we just straight surface rig that you expect prices at or near those levels or was there something else financially going on as far as monetizing those hedges and bringing in the cash? Can you just talk about that decision?

Mark Papa

Yes, that was just a market call not so much on bringing the cash forward. It's really trying to call the low of the market for the second half of 2010, and we believe that perhaps we're getting somewhere near that low we feel pretty positively that by the second half of 2010 at least we are going to have good gas prices. I am not predicting $10, but what I'm saying is where we close amount that is somewhere near the native we believe.

David Tameron – Wachovia

Let me ask you one more question. As you think about, you mentioned briefly production guidance assumes no shut-in. Can you walk me through how you think about and how the board thinks about shut-in gas? Obviously, just picks out they are shutting gas and provides a little PP table. You hear last week and says we can drill more wells but we have economic wells to drill today, but we are not going to, because service costs have come down. Can you talk about just how you think about shut-in gas and deciding when to put these rigs back to work particularly on the gas side?

Mark Papa

Yes. On the gas rig side, there's a number of gas rigs that we had drilling with the exception of the Haynesville, where we have four rigs running that were earning acreage or preserving acreage there. In most other areas of North America, for gas drilling, we've reduced our gas drilling to the number of rigs, where we have term contracts. So essentially we've laid down all our rigs that aren't contracted through the year. So we made a decision that we are not going to try and buy out of contracts just because you pay the contract money and you get nothing in return or at least if you drill in you get something in return. So that's one of the guiding factors there.

As to when we would specifically shut in gas, we have curtailed shut in gas the past several years, typically in September, and we have kind of a threshold well head price that in our minds and I won't give it, but basically, we are not too anxious to sell gas below that price. So the overall strategy of the company this year is we are not going to cramp gas into markets that are already full, if storage gets full before November, we'll probably react to it by curtailing some gas, but we'll just have to see how that plays out. But what we are really doing with the company is we are switching the company toward crude oil and NGL production because we think that's going to be a more consistent value basis on a go-forward basis.

There is a chart that we released on the IR chart last night on our Web site that kind of shows the ratio we expect to get to in North America for liquids versus crude and the bottom line of that chart is it was a pretty low level two years, three years ago we expect by 2013, just to give you an example, in 2006, our North American production mix was 24% liquid, 76% gas. And currently it's about 35% liquids, 65% gas for this year, and we expect that ratio by 2013 to go somewhere liquids would be 45% to 50% of our total North American production mix. That's a 10 to 1 BTU equivalent ratio.

David Tameron – Wachovia

I know you won't give me a price but can you talk regionally and then I'll hang up, let somebody else jump up. But regionally if you look at how prices today and service cost and you expect the rate of returns, what would be one, two, three, first to be shut in, second and third if you address that point?

Mark Papa

Yes. Right now, as you look around our asset base, I'd say that the one area that may be the first target would be the Rockies that may have curtailment. The secondary would be the mid continent just because the prices are attracting closer to the Rockies there and Canada prices are holding up a little bit better and the Gulf Coast prices are hanging in there pretty well. So those might be much lower.

David Tameron – Wachovia

Okay. I appreciate. Thank you.

Operator

Next we'll hear from Gil Yang with Citi.

Gil Yang – Citi

Hi, good morning, everyone. Mark, I'm curious retreat by your chart that shows the Barnett gas production beginning to pick up I guess beginning of 2010 or so. Couple of questions around that. You are saying that you would expect to see a supply response in the U.S. on the downward side April, May after rig count peaked back in September. So obviously there's a big delay. So looking at that chart for the incline of production in 2010, the first question is to get that gas start coming out of the ground faster in early 2010 when would you need to step up on the gas so speak to, accelerate your drilling program to get that to happen? How much in advance and how much of a delay essentially is there between when you accelerate activity and when that gas starts coming out of the ground?

Mark Papa

That's a good question, Gil. The predicate for the chart and this is a chart that's on our IR Web site again is that by the end of this year, we've seen enough on the macro picture, where we're feeling pretty confident that 2010 gas prices are going to be, shall we say, “decent” and basically in January of 2010 we ramp-up the gas drilling activity from the current, I believe, I said 11 weeks gas drilling right now that we ramped up to something in the range of about 15 gas rigs. So that production bump is the best estimate we have now. If we become a little less on the gas market for the first half of 2010 that bump might slide a little bit.

Gil Yang – Citi

I'm sorry. When would that bump up in activity start to happen?

Mark Papa

About January.

Gil Yang – Citi

And you think you can get a production response out pretty contemporaneously with that ramp-up in activity?

Mark Papa

Yes, within three months to four months of that I guess.

Gil Yang – Citi

I thought your chart shows a production responding pretty quickly.

Yes. It shows it coming up in about three months. So that's about the same timeframe there.

Gil Yang – Citi

Moving on to something else, could you just give us an update on what's going on the Cleveland slide?

Mark Papa

Loren Leiker?

Loren Leiker

Yes, Gil. We are continuing with that one rig program the Cleveland right now similar to the other stories that you've heard this morning. We're focusing on oil. We found parts of the Cleveland where liquids are higher, liquid, NGLs where crude oil come with the gas. That's really where we are focusing our efforts right now.

Gil Yang – Citi

Is it actually oil and liquids or is it just wet gas?

Loren Leiker

It's actually oil and liquids in the reservoir. Only certain geologic parameters allow that to happen in parts of the field. It's not widespread, we have the Cleveland play, but we haven't had a very strong acreage position where that occurs by design and that's where we are focusing.

Gil Yang – Citi

Can you talk about the rates and costs?

Loren Leiker

Well, the costs really aren't different than what we're doing in a gas play as far as play well cost, the same story in terms of horizontal wells and ex-number of stages per well. In terms of rates, these wells can come on at 200 barrels a day, 300 barrels a day to 400 barrels a day then they fall off like any normal tight reservoir would and of course gas comes with it.

Gil Yang – Citi

Okay. Thank you very much.

Operator

Moving on we'll hear from Leo Marinari with RBC Capital Markets.

Leo Marinari – RBC Capital Markets

Good morning here. Question related to your CapEx. You guys maintained your CapEx at $3.1 billion. Obviously, gas prices have come down a fair bit in the last couple of months. Do you folks still plan to spend cash flow this year?

Mark Papa

The answer is, Leo, on that that although we are keeping our CapEx flat, obviously the cash flow estimates have dropped a bit particularly with gas prices. So right now we can't say that we're going to stay within cash flow. If you just took the NYMEX prices for the remainder of the year for gas and oil, we are going to essentially slightly overspend the cash flow. But that's a decision that we've made and we're comfortable with it. It's our feeling that come at the end of the year we'll continue to have the lowest net debt-to-cap ratio of any company in the large cap independent peer group.

Leo Marinari – RBC Capital Markets

Okay. Jumping over to Bakken here, can you give us an indication of how many barrels a day you currently have shut in up there?

Mark Papa

I don't have a number just off the top of our head on that, Leo, and it really vary depending on what it cost to truck on any given day and what wells we have that are shut in so. I don't want to get into too many specifics on that.

Leo Marinari – RBC Capital Markets

Okay. Any update on your 320 acre drilling up there in the court Bakken?

Mark Papa

Yes. Pretty much where we are is that in the core area we think probably that's going to stay on 648 acre spacing and we are not going to down space that in a large way. When you get outside of the core area, to what we call the Bakken light area, which is we think a big growth area for us, there because rock quality is a little bit less, pressures are less, that that will probably end up being spaced on 320 acre spacing.

Leo Marinari – RBC Capital Markets

I guess given that, in terms of your Bakken drilling later this year and beginning 2010, is your activity more in the Bakken light area or do you still have remaining 640 acre location to core?

Mark Papa

We've got something like about 60 to 70 core locations yet to drill and then we got a bunch to complete this year. So the number would be something like about 100 core locations that are yet really to hit the production meter. And then the Bakken light is the area that we just don't know the aerial extend of that. We've previously reported that we've got four wells, five wells outside the core area that have surprised us positively, an average of about 300,000 barrels of oil per well and we'll be drilling more wells in the light in the second half of the year and evaluating this, but we think that's the big upside over and above the 80 million barrels that we already mentioned for what we think is in the core. We think the Bakken light is the area that over the next year may allow us to give a big reserve upside that, but we just haven't drilled enough well in a wide enough area to feel good about that and that's where the low oil price and these differentials have really slowed us down. We were geared up beginning of the year to get really serious cranking up in the Bakken light area, but then all the activity in the North Dakota area has just slowed down due to this very, very low oil prices in the first half of the year.

Leo Marinari – RBC Capital Markets

Okay. Jumping over to your Barnett Combo play you guys said that you were surprised by the strong results in the first quarter which led to some of the oil production upside versus your guidance in North America. You talked about drilling those wells for $3.1 million. What type of EUR you're seeing on those and are those approved recently?

Mark Papa

We've got on our Web site there quoted about 210,000 barrels of oil equivalent is what our current estimate is on those. We believe that may well improve in time but we don't have any data to really show that now. What we are really seeing on the Barnett Combo play is it's really playing out exactly as we predicted in our February Analyst Conference. We said it would be 2009 before we can really attack this play because we needed to get the liquid stripping plant infrastructure built and here it is 2009 we are attacking the play. So it's a shame in a way that we control the vast majority of the acreage because you as an analyst don't really get to triangulate on it, you can count some of the other operators there and confirm our results, but this is the one play where we are just highly dominant and the numbers are starting to show in terms of what we expect for production when we're quoting, growing up to 42,000 barrels a day liquids coming out of the Barnett and not too many years clearly the majority of that is going to be coming out of the combo play.

Leo Marinari – RBC Capital Markets

Okay. I guess is there going to be any issue on the ramp-up there in terms of infrastructure? Obviously you got your liquid stripping plant there in the first quarter. Is there any plans to put more money into infrastructure there or is that plan can be able to handle lot of the ramp-up in the next year?

Mark Papa

Yes, we've got the infrastructure pretty well sorted out. I'll give you just a couple of other quotes on the combo play just the impact of the combo play you may find interesting. In 2009, out of our total Barnett production we expect 85% of it to be gas and 15% to be combination of oil and NGLs. So 85-15 this career. 2012, that number is going to go down to 64% gas, 36% liquids. So you can just see that we're going to become much more of a liquid company coming out of the Barnett than we currently are.

Leo Marinari – RBC Capital Markets

Okay. Thanks a lot for your time.

Operator

Our next question will come from Ellen Hannan with Weeden & Company.

Ellen Hannan – Weeden & Company

Thank you. Just a quick follow-up on that last comment, Mark, in terms of your liquids output in the Barnett Combo. Can you give us a feel of how much of the liquids would be natural gas liquids versus crude oil and then further on the pricing on NGL in that area is that more determined by the market for natural gas or for crude oil itself?

Mark Papa

Yes, the pricing of NGLs and part of our infrastructure issue is we're going to be able to pipe those NGLs to the mart welding hub which is kind of the Henry hub of NGLs, if you will. So the pricing for the NGL is we expect it to be keyed off from crude. Typically 60% to 65% of crude oil is what the NGL mix typically is. And what we've said about the combo play previously is that if you really look at the production from a typical combo well, it's about one-third crude oil, one-third NGLs, and one-third actual natural gas, just like other natural gas. So a significant mix of that combo play composition is going to be NGLs.

Ellen Hannan – Weeden & Company

Okay. Thanks. I just wanted to clarify. In your opening remarks you talked about the mid-year of your production for the year being in the fourth quarter, are you looking at that total companywide or are you just talking about your U.S, gas production?

Mark Papa

That's North American gas.

Ellen Hannan – Weeden & Company

Thanks. One just final question for you. EOG had any staff reductions?

Mark Papa

No, we have not. In fact we are selectively adding this year and we don't anticipate any staff reductions.

Ellen Hannan – Weeden & Company

Great. That's it for me. Thank you.

Mark Papa

Thanks, Ellen.

Operator

Gentlemen, that is all the time that we have for questions today. We'll go ahead and turn things back over for any additional or closing remarks.

Mark Papa

I don't have any further closing remarks. I just want to thank everyone for being on the call with us and we'll talk again in three months.

Operator

That does conclude today's teleconference. Thank you all for joining. Have a great day.

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Source: EOG Resources, Inc. Q1 2009 Earnings Call Transcript
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