EOG Resources Inc (EOG) 2009 Q1 法說會逐字稿

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.

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 forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at eogresources.com. The SEC currently permits producers to disclose only prove reserves in the security filings.

Some of the reserve estimates on this conference call, including those for the Barnett Shale, North Dakota Bakken, Horn River and Haynesville may include other category of reserves. We incorporate by reference the cautionary notes to the US investors that appear at the bottom of the 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 are Loren Leiker, Senior EVP Exploration,Gary Thomas, Senior EVP Operations, Bob Garrison, EVP Explorations, Tim Driggers, Vice President and CFO and Maire Baldwin, Vice President of 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. Then, I'll review our plans for 2009 and operational results. Tim Driggers will provide 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 of the industry analyst 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. To investors who follow the practice of 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 earlier in the cycle and only after all peer companies reported their full year results we realize that EOG achieved different results regarding 2008 matrix. We finished first among the large peer group in every critical category. Best stock performance, highest ROCE, lowest all in signing costs, highest debt adjusted production growth, lowest unit growth, lowest debt ratio, no significant financial write downs and diminished price effective reserve write downs. They say the past is prolog and we encourage investors to focus on the star performance differences here. It's rare when one Company can claim annual outperformance in every single metric and I hope it gives us shareholders a lot of comfort. Regarding 2009, we raised our projection growth target from 3 to 5.5% while keeping our CapEx estimates 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 entirely of higher North American liquids 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 play begin to have greater impact. The increase in Trinidad gas production is due to quicker turn around on third-part plant maintenance than originally forecasted. I'll also note that the 5.5% production growth tart 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 discussion with Barnett gas and then follow with the Barnett combo. Our Barnett gas activity is going quite well albeit at a reduced level from last year. We'll average 11 Barnett gas rigs this year compared to 24 last year. Like everyone else, we are benefiting from lower service costs and our Johnson County wells are averaging two net Bcf or $2.8 million completed well cost. To date, we only drilled half of our total Johnson County locations, so we have 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 making exceptional 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 Northern 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 NYMEX 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 simultaneously complete groups of four to eight wells to get better frack 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 website. The chart shows 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 equivalence this year to 700 million cubic feet a day equivalence 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 this asset 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 a 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 rejuvenated with horizontals. We have now drilled 29 successful horizontal wells and a typical well yields a 65% after-tax reinvestment rate of return using current prices. We estimate we have 25 million barrels of oil net recoverable reserve 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 net by year end 2012.

Moving to the North Dakota Bakken, we are currently operating an eight rig drilling program compared to last year 10 rigs. We deferred almost all well completions until this summer when the frack jobs can be done more economically and the road continues 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. 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 crude via railcar unit trains from North Dakota to Cushing, Oklahoma or other markets. 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 are seeing currently. We can pursue our own transportation arrangement 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 well results later in the year. We are running two rigs in the Horn River Basin but are referring the completion until this summer. We are confirming up long-term transportation and processing agreement for our Horn River gas. In the Pennsylvania Marcellus, we are running one rig and we have completed 11 horizontal wells on our 240,000 net acres. We've improved that frack technique on our most recent wells with net reserves of 1.6 to 3.0 Bcf per well. We estimate we have two to three net Tcf captured on our Marcellus acreage.

Our standard play 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 frack play where we've captured 800 net Bcf at a $1.65 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 year end. I'll now turn it over to Tim Driggers to discuss CapEx and capital structure.

Thanks Mark. For the the first quarter, total exploration and development expenditures, excluding asset retirement obligations were $872 million. In addition, expenditures for gathering system, processing plants and other property plant and equipment were $65 million. Capitalize interest for the quarter was $12.2 million. Yesterday 8K filing indicates the 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 Form 8-K with second quarter and full year 2009 guidance. For the full year 2009 the 8-K indication effective tax rate greater than 35%. We have also provided an estimated range of the dollar amount 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 foreign and domestic pre-tax income. Now, I'll turn it back to Mark to discuss the macro environment, our hedge position and concluding remarks.

Thanks Tim. Our view in North American oil and gas 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 fall 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 year end 2009 production to be 4.5 Bcf a day lower than year end 2008 assuming a year end gas recount of 650. We expect domestic production to begin to decline in April or May. So we have 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 0.5 Bcf a day in 2010. Recognizing the current gas supply demand imbalance, EOG 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 over supplied 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 both 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, 2011, 2012 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, this oil ores 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 Manitoba. The Manitoba play is similar to the Barnett combo as it generates very strong, after-tax reinvestment rate 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.

Fifth, we have included a chart in the new IR presentation posted on our website showing EOG 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. IE, the combo play will generate aggregate Barnett gas plus liquid growth for many years.

And six, we'll accomplish the above by 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 strong ROCE's. While we are on the subject of returns, I continue to be amazed at both the buy and sell side to treat the large write offs we have seen as one-time events in 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 E&P 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 E&P management? Thanks for listening and now we will go to Q&A.

Absolutely. (Operator Instructions). We'll take our first question from David Heikkinen with 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 2008 as you ramp up pipeline capacity into 2012? How does that ramp-up actually happen?

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 and 150 million cubic feet a day. Our -- it's our belief that the majority of the production and aggregates in the Horn River Basin t will not start to come on until 2012 or latter. 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 earlier than others.

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

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

Okay. Mix and match like Manitoba that would be a year-end rate? The Canada gas, then that 120 would be an exit rate.

That's probably a full year average on that one too. So the one that is an exit rate is the Manitoba one.

Okay. Can you talk about cost as far as, first Barnett gas, Hill County and western county and then Barnett combo just as far as where your well costs are? That's it. Thank you.

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 $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.

One follow up on the combo. So you drill some wells in Palicento County as well. Is that part of the combo play or is that part of the western? Trying to get an idea where the border is for combo versus western.

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 Montay County.

Does that include Palicento?

It may or may not.

Fair enough.

Next we'll hear from Tom Gardner with Simmons and Company.

Good morning, everyone. Mark, I had a question about your rail project. Is there any way that you can give us an idea of the total impact on your Bakken oil differential without giving away Company secrets?

Well, obviously, we are still in negotiations and they haven't finalized it. So I don't want to give a loft details about the current agreement. Just to give you some rough ideas. If you look at the fourth quarter of 2008, and really the first quarter of 2009, this stuff that we were able to get in the pipeline was a reasonable tariff but the stuff that we had to truck out of there, we were paying up to $25 a barrel to get that crude truck to places like Salt Lake City and in some places, we would truck it all the way to Cushing, Oklahoma, which was absurd. As we look at this, we said, well, there is one pipeline up there, it's called the Inbridge oil pipeline.

It's pretty well maxed out and we can't get our 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 truck key. This unit train railcar is an option that we ended up and it turned out to be -- it will considerably lower differential in many cases, it's essentially competitive with the Inbridge pipeline tariff issue.

Thank you. 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?

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 area of the Barnett Shale and it may be one or two years before you can get a pipeline 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 that that inventory will bleed off over time but it's not going to affect our view of the macro. I think that particular aspect of the gas market may have been over stressed. We don't think that is that big of a deal.

I agree. Just from an EOG perspective Company-wide, what is your average time from say the rig moving off a well to the time that is on shale?

I'll ask Gary Thomas to fill that one.

On the Barnett, it takes about 45 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 release to completion is a little stretched through

Do you think that number would hold up Company-wide on at least on the gas side?

Depends on if it's horizontal or vertical wells. If it's vertical wells, it's a matter of weeks. Probably most all vertical wells will be completed within 30 days. The horizontal where where hold up and drill a couple and complete them together, that's when you have the longer period of time between rig release and final completion.

Thank you guys. I appreciate your comments.

Our next question will come from JPMorgan, Joe Allman. .

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 gamig well in east Texas. Could you give us some color on that? And can you just give us some color on the east Texas Haynesville, how results are looking there for what you are doing? I have a couple of follow ups.

Yes, Joe. We can acknowledge that there is a gamig well. We'll share that information. We're currently in the completion and testing phase of that well. We have nothing further to report. We know that it is a very closely watched well. At this time, it would just be premature to give any information on it.

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

I don't want to go there right now Joe.

Okay. Got you. And then 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?

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.

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

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 have room for that to go up, we could be moving on a net basis an incremental 20,000 barrels a day out on unit trains. The good thing about the unit trains is you can upsize or down size it pretty readily just by how many trains you run basically.

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

We are making all the investment at a hundred percent EOG level and once this thing gets up and running it would be a pretty effective third-party business for us in terms of other people coming to us and wanting to access.

All right. Very helpful. Thank you.

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

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

Yes. This is an old field that we defined the geologic limits on it ten or 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 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 up size the capacity of some of our surface facilities there to handle this, but that's a pretty routine deal. So we are -- this one is going to be relatively easy to upscale. A 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, so we kind of have to build the infrastructure from ground up. In this Manitoba play, we are fortunate enough that we have all the infrastructure there essentially.

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

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

Okay. Thanks. 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?

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'll be looking at what happens to this gas rig count.

In other words, if the gas rig count falls below 650 by year end, we would probably be a bit more aggressive in gearing up our gas drilling if the gas 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 we expect to happen in 2010.

I guess at some point though when you think about it from an IR perspective, it would be based on your own internal gas production for that lower rig count would end up leading to. Any sense on what numbers there with what you would need to get an attractive rate of return?

Yes. I don't want to go at it that way but I'm saying until we believe gas prices are going to getting up 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 have a pretty deep oil and liquids inventory and we are going to be attacking that. Don't take that to say we need a $7 gas price to get a decent IR on gas drilling.

What I'm saying is we are seeing a fatter reinvestment rate of return on the liquids 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.

Thanks for the color.

Okay.

Next we'll here from David Tameron with Wachovia.

Good morning. Coming back to the Bakken, if you start talking about (Inaudible) -- they are going to bring that back on April May, if you bring back yours in July, how tight would the infrastructure be between them and first part of 2010 before you get the potential rail project underway?

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 max $35 or so, and now we are looking at something that is 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 goes up, we may just curtail production in September.

So we are going to watch it month by month, but our current estimate is that we think we are going to be okay, but we still be suffering on differential for the stuff that we can't get into the pipeline until February of 2010.

Okay. Let me go back to something else. You said you took off some hedges in the back of -- half of 2010.

That's correct.

Those hedges were $10?

Correct.

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?

That was just a market call not so much object 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 are getting somewhere near that low.

We feel pretty positively that by the second half of 2010 at least we are going to have good prices. I am not predicting $10 but what I'm saying is somewhere near the nadir we believe.

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

Yes. On the gas rig side, there are a number of gas rigs that we had drilling with the exception of the Haynesville, where we have four rigs running and we are 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 that's kind of -- we made a decision that we are not going to try to buy out of contracts just because you pay the contract money and you get nothing in return or at least if you drill you get something in return. So that is one of the guiding factors. As to when we would shut in gas, we had 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 in our, that we released on the IR chart last night on our website 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, three years ago but we expect by 2013. Just to give you an example, in 2006 our North American production mix was 24% liquid 76% gas. By -- currently it's about 35 liquids, 65 gas for this year, and we expect that ratio by 2013 to go somewhere liquids would be 35 to 50% of our total north American production mix. That is a ten to one BTU equivalent ratio.

Thanks. I know you won't give me a price but can you talk regionally and then I'll hang up. But regionally -- if you look at how prices today and service cost and you expect rate of returns, what would be one, two, three, first to be shut in, second and third if you can do that? 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 mid continent because 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. Okay. I appreciate it. Thank you.

Yes.

Next we'll hear from Gil Yang with Citi.

Good morning, everyone. Mark, I'm curious and intrigues by your chart that shows the Barnett gas production beginning to pick up beginning of 2010 or so. A couple of questions around that. You are saying that you would expect to see a supply response in the US on a 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 when -- to get that gas start coming out of the ground faster in 2010 when would you need to step up on the gas to accelerate your drilling program to get that to happen? How much in advance and how much of a delay is there between when you accelerate activity and when that gas starts coming out of the ground?

That's a good question. The predicate for the chart, and this is a chart that is on our IR website again, is that by the end of this year, we've seen enough on the macro picture where we are 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 for gas drilling right now. We ramp-up to something in the range of 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.

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

About January.

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

Within three to four months.

I thought your chart showed a production responding pretty quickly.

Yes. It shows it coming up in about three months. So that is about the same time frame.

All right. Moving on to something else, can you give us an update on what is going on on the Cleveland slide?

Loren Leiker?

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

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

It's actually oil and liquids in the reservoir. Only certain parameters allow that to happen in parts of the field. It's not widespread but we have a strong acreage position and that's where we are focusing.

Can you talk about rates and costs?

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

Okay. Thank you very much.

Moving on we'll hear from Leo Mariani with RBC.

Good morning here. A 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 more cash flow this year?

The answer is Leo on that that we are keeping our CapEx flat, the cash flow estimates have dropped a bit particularly with gas prices. So right now we can't maintain -- we can't say that we are going to stay within cash flow. If you took the prices for the remainder of the year for gas and oil, our -- we are going to slightly over spend the cash flow.

But that's a decision that we've made and we are comfortable with it. It's our feeling that come 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.

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?

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

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

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 Lite area, which is -- we think a big growth area for us, there because of rock quality is a little bit less, the pressures are less, that that will probably end up being spaced on 320-acre spacing.

I guess given that, in terms of your Bakken drilling later this year and beginning 2010, is your activity more in the Bakken Lite area or do you still have remaining 648-acre location to core?

We have something like about 60 to 70 core locations yet to drill, and then we have a bunch to complete this year. So the number would be something like 100 core locations that are yet really to hit the production meter. And then the Bakken Lite is the area, we just don't know the extend of that.

We previously reported that we've got four or five wells outside the core area that surprised us positively with 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 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 Lite is the area that over the next year may allow us to give a big reserve upside but we haven't drilled enough well in a wide enough area to feel good about that and that is where the oil price and the differentials have slowed us down. We were geared up at the beginning of the year to get really serious cranking up in the Bakken Lite area, but then all the activity in the North Dakota area has just slowed down due to this very oil prices in the first half of the year.

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 are seeing on those and are those approved recently?

We've got on our website there the closed about 210,000 barrels of oil equivalent is what our current estimate is on those, and we believe that 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 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 and 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 get to triangulate on it, but you can talk to some other operators there and confirm our results. But this is the one play, where we just are highly dominant and the numbers are starting to show in terms of what we expect for production. We are growing up to 42,000 barrels a day of liquids coming out of the Barnett in not too many years. Clearly, the majority of that will be coming out of the combo play.

Okay. I guess is there going to be any issue on the ramp-up there in terms of the infrastructure? You got your liquid stripping plant there in the first quarter. Is there any plan to put more infrastructure there or is the plan will be able to handle?

We have 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. 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 would go down to 64 gas, 36% liquids.

So you can just see that we are going to become much more of a liquid Company coming out of the Barnett than we currently are.

Okay. Thanks a lot for your time.

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

Thank you. 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 determine by the market for natural gas or for crude oil itself?

Yes. The pricing of NGL and part of our infrastructure issue is that we'll be able to pipe those NGLs to the 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 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.

Okay. Thanks. I just wanted to clarify. In your opening remarks you talked about the nadir of your production of the year to be in the fourth quarter. Are you looking at that total Company-wide or are you talking about your US gas production?

That's North American gas. Yes.

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

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

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

Thanks Ellen.

That is all the time that we have for questions today. We'll turn things back over for any additional or closing remarks.

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.

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