EOG Resources Inc (EOG) 2012 Q3 法說會逐字稿

Good day, everyone, and welcome to this EOG Resources third-quarter 2012 earnings results conference call. As a reminder, this call is being recorded.

And at this time for opening remarks and introductions, I would like to turn the call over to Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for taking the time to join us on election day. We hope everyone has seen the press release announcing third-quarter 2012 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 also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary note to US investors that appears at the bottom of our press release and Investor Relations page of our website.

With me this morning are Bill Thomas, President; Gary Thomas, Chief Operating Officer; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website last night, and we included fourth-quarter and updated full-year 2012 guidance in yesterday's press release.

This morning I'll discuss topics in the following order. I'll initially review our third-quarter 2012 net income and discretionary cash flow. Then Bill Thomas and I will provide operational results. Tim Driggers will discuss financials and capital structure. I'll then follow with our macro view, our preliminary 2013 business plan, and concluding remarks.

As outlined in our press release, for the third-quarter 2012 EOG reported net income of $355.5 million, or $1.31 per diluted share. For investors who focus on non-GAAP net income to eliminate mark-to-market impacts and certain non-recurring items as outlined in the press release, EOG's third-quarter 2012 adjusted net income was $468.7 million, or $1.73 per diluted share. Our third-quarter non-GAAP earnings versus guidance was a result of a pleasant trifecta -- higher oil volumes, higher oil price realizations, and lower unit costs. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $1.6 billion.

I'll now address our operational results and key plays. For the third quarter, all three of our production components met or exceeded the high end of our guidance. Our total-company crude oil and condensate production was up 42% year over year, and total liquids were up 40%. Total EOG production increased 12.4% year over year for the third quarter. North American gas was down 10%, as predicted, but Trinidad gas increased 17% due to higher-than-expected contract takes. I'll also note that essentially all of our unit costs were below midpoint projections, and several, such as LOE and DD&A, were below the low points of our guidance range.

The benefits of high volume growth on our unit costs is showing up in the numbers. We are also pleased to note that our G&A per $1 of revenue is one of the lowest in the peer group. As we did following both first- and second-quarter results, we are again increasing our full-year total-company liquids production growth target, this time from 35% to 38%, boosting our crude oil growth target from 37% to 40%, and our NGL growth target from 31% to 33%. Our total-company growth target has also increased from 9% to 10.6%. These increases are the result of continued out-performance from our top oil plays.

As we have repeatedly stated, we are not interested in growing hydrocarbon volumes simply for the sake of growth. In fact, we have purposely shrunk our North American gas production for four straight years, simply because it is a money loser. We are, however, very interested in growing our financial metrics, such as EPS, adjusted EBITDAX, and DCF. In the third quarter, our year-over-year increase in non-GAAP EPS was 108%. Adjusted EBITDAX growth was 39%, and DCF increased 37%. We believe we are one of very few large-cap E&Ps who have shown a substantial increase in these financial metrics in both 2011 and 2012.

The biggest single driver for this growth in our financial metrics has been our high organic crude oil growth rate -- 35% in 2010, 52% in 2011, and projected 40% this year, in spite of $3.3 billion of total asset sales over this same period. On a go-forward basis, we expect to continue to have the best organic oil growth rate of any large cap independent, although the year-over-year percentage numbers will be smaller, as we become a larger oil company.

I'll now discuss the plays driving our high organic crude oil growth rate starting with the Eagle Ford. The play was again the biggest driver of our quarterly oil growth out-performance, as it has been all year. We are the largest crude oil producer in the play with 109,000 barrels of oil equivalent per day net after royalty for the quarter, 75% of which was oil, and 13% was NGLs.

I'll now discuss four key points regarding the Eagle Ford. First, during the August call, I may have caused a flurry of comments among sell-siders when I mentioned that during the second quarter we completed 16 monster wells, which I defined as having IPs between 2,500 and 4,800 barrels of oil per day, plus gas and NGLs. This reflects the quality of our acreage, plus our completion methodology. During the third quarter, we added 12 additional monster wells, one of which, the Baker-Deforest Unit 4H, tested at 4,598 barrels of oil per day with 4 million cubic feet a day of rich natural gas at a normal choke rate flowing into production facilities. We have 100% working interest in 10 of 12 of these monster wells, several of which are outlined in our press release.

Second, we have drilled and are flow testing several multi-well pilots spaced more densely than our current 65- to 90-acre spacing. We expect to have some spacing conclusions and the effect on the recovery factor from these pilots during the first half of 2013. Third, the majority of our Eagle Ford crude is currently priced off an LLS premium market index providing an advantage over WTI pricing. Additionally, with the cost advantage of our self-sourced frac sand and further efficiencies, our average well costs have been drifting back down towards our $5.5-million-per-well target instead of the $6 million I reported last quarter. Together, the LLS indexed oil price and the lower well costs have further improved the excellent economics of the play. And fourth, we are currently running 20 rigs, and expect to drill 320 net wells this year. Our current average drilling time has decreased to 13 days per well.

Overall, we have significantly slowed our total-company capital activity to stay within our capital budget. We are currently running 52 rigs across the Company, compared to an average of 70 in the first half. To even further slow capital activity, we have dropped the number of completion crews and the number of days per crew. This is the primary reason we expect fourth-quarter total EOG liquid volumes to be slightly down from the third quarter. Besides, 40% year-over-year oil growth is plenty strong for a company our size. We have to catch our breath, so we can come out of the starting gate strong in January.

I'll now turn it over to Bill Thomas to discuss other North American plays.

Thanks, Mark. We continue to be particularly upbeat about the Bakken and Three Forks potential on our acreage in the Williston Basin. In the Bakken Core area, the 320-acre downspacing has proven to be successful, and two recent wells further confirm this trend. The Fertile 46-1608H tested at 1,732 barrels of oil per day with 90 barrels per day of NGLs and 363 Mcf per day of natural gas. The Fertile 47-0712H tested at 1,258 barrels of oil per day and 83 barrels per day of NGLs and 332 Mcf of gas. We have 92% and 78% working interests in these wells, respectively. We'll be testing 160-acre downspacing in the Core late this year, and we hope to have some results from our pilot water [fluid] project by February.

In the Antelope area, we are applying improved frac technology to our current well completions. We recently completed an outstanding Antelope Three Forks well, the Hawkeye 100-2501H, for 3,196 barrels of oil per day with 5.5 million cubic feet per day of rich natural gas. EOG has a 73% working interest in this well. Other recent Antelope wells are listed in the press release.

In 2003 through 2015, we plan to spend most of our North Dakota capital in these same two areas, primarily downspacing in the Bakken Core, and further development of both the Bakken and Three Forks targets in the Antelope Extension area. We plan to develop our Bakken Lite and Stateline areas in subsequent years.

Shifting our focus to the Permian Basin Wolfcamp and Leonard horizontal plays, we are seeing Wolfcamp results similar to previous quarters. But in the southeast New Mexico Leonard, we are seeing improved results. We previously said the returns on these two plays were equal, but we now rate the Leonard above the Wolfcamp. The Wolfcamp well quality hasn't declined, it is just that the Leonard has improved.

Three recent Leonard wells are the Diamond 8 Fed Com 3H, 4H and 5H, which tested at 962, 1,148, and 1,162 barrels of oil per day with approximately 1 million cubic feet of rich natural gas each. We have 96% working interest in these wells. Our press release lists several recent Wolfcamp wells, and we continue to feel comfortable with our 430 MBoe per well gross type curve. Most of our Wolfcamp completions are in the middle zone, with several good wells noted in the press release. We completed the Mayer SL 5013LH in the lower Wolfcamp with an initial production rate of 1,290 barrels of oil per day with 946 Mcf per day of rich natural gas. We have 77% working interest in this well. This is our first long lateral completion in the lower zone, and we are encouraged by the results. To date, we have completed three long laterals in the upper zones with mixed results. We continue to evaluate the economic extent and productivity of the upper and lower zones across our acreage.

Overall, both the Wolfcamp and Leonard are good plays, but they are combo-type plays and are inherently less economic than the Eagle Ford and Bakken, which are black oil plays. The same is true of the Barnett Combo. Her results continue to be consistent with past quarters. This typical combo well recovers 80,000 barrels of oil, 140,000 barrels of NGLs and 850 million cubic feet of gas gross for $3.4 million completed well costs, and yields a 25% after-tax rate of return at current product prices. This year, we drilled a number of successful step-outs, extending the productive acreage of the play. In addition to these plays, we have smaller levels of horizontal activity in the Mid-Continent, Powder River Basin and Southern Manitoba. Also, we continue to test new greenfield horizontal oil ideas in North America.

Now I'll turn it back to Mark.

Thanks, Bill. Outside North America, we expect our 100% working interest, East Irish Sea Conwy crude oil development project to start up in the second half of 2013. In Argentina, our horizontal Vaca Muerta oil well yielded lower-than-expected results. The production results were similar to a nearby vertical well we had completed, indicating no multiplier effect for the horizontal versus the vertical. We are still evaluating results, and plan to proceed cautiously during 2013. In Trinidad, our third-quarter gas takes were higher than expected due to incremental short-term market demands. There is nothing new to report on the Kitimat LNG project.

I'll now address two other EOG differentiators -- oil margins and sand plants. You'll notice that for the third quarter, our US crude oil price realization was $5.45 over WTI. Considering where our crude is produced, this is likely the most advantageous realization of any similarly situated company. Our two biggest production areas are the Eagle Ford and Bakken. As I previously mentioned, our Eagle Ford crude is currently priced off an LLS index. In the Bakken, almost all of our crude, plus some third-party crude, is being railed to our St. James, Louisiana terminal, and receiving LLS prices. Additionally, we are railing a portion of our Wolfcamp crude to Louisiana.

On the well cost side, our sand plants continue to function smoothly and provide the frac cost savings we have described in previous quarters. EOG success is based on a simple equation -- higher crude oil volumes at higher crude oil price realizations, combined with lower well and unit costs, and less money-losing North American natural gas volumes, equals more net income.

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

Thanks, Mark. Capitalized interest for the quarter was $12.7 million. For the third-quarter 2012, total cash exploration and development expenditures were $1.6 billion, excluding asset retirement obligations. In addition, cash expenditures for gathering systems, processing plants, and other property, plant and equipment were $161 million. Year to date, total cash exploration and development expenditures were $5.5 billion, excluding asset retirement obligations. Cash expenditures for gathering systems, processing plants, and other property, plant and equipment were $477 million. Acquisitions costs year to date total $435,000.

Through September 30, proceeds from asset sales were $1.2 billion. Our goal is to close on an additional $100 million prior to year end for a total of $1.3 billion of asset sales for the year. At September 30, 2012, total debt outstanding was $6.3 billion, and the debt-to-total-capitalization ratio was 31%. At September 30, we had $1.1 billion of cash on hand, giving us non-GAAP net debt of $5.2 billion, for a net debt-to-total-cap ratio of 27%. The effective tax rate for the third quarter was 37%, and the deferred tax ratio was 52%.

Yesterday, we included a guidance table with the earnings press release for the fourth-quarter and full-year 2012. Our updated 2012 total CapEx guidance is approximately $7.6 billion, excluding non-cash items. For the fourth quarter and full year, the effective tax rate is estimated to be 35% to 40%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the fourth quarter and for the full year.

Now I'll turn it back to Mark.

I'll now provide our views regarding macro, hedging, and concluding remarks. Regarding oil, we think the current NYMEX plus $2 to $3 per barrel reasonably reflects likely 2013 prices. We continue to believe that US shale oil won't flood the global markets for the reasons I articulated on our previous earnings call. Likewise, we think any meaningful supply effect from shale oil outside North America is many years away, and will be very slow to develop. For the first half of 2013, we have 98,000 barrels of oil per day hedged at $99.39 per barrel. And for the second half, we have 68,000 barrels per day hedged at $99.45 per barrel. We also have some options next year that may be exercised, and would increase our hedge position by an average of 42,000 barrels of oil per day at an average price of $102.16.

Regarding gas, we expect 2013 prices will be better than 2012, but not good enough to provide a cost of capital full-cycle return on North American gas well drilling. Our current 2013 hedge position is 150,000 MMBtu per day at $4.79 per MMBtu, excluding unexercised options. Please see the table that was included in our earnings press release for the details of our hedging contracts.

Now let me provide a brief outline of our 2013 business plan. As usual, we'll provide our specific 2013 plan with volumes, CapEx, et cetera, in our February call. But today we can provide four directional guidelines. First, we expect our overall 2013 CapEx to decline below 2012 levels, primarily because we have accomplished our goal of converting our dry gas resource play acreage to held-by-production status. This year we spent roughly $700 million, primarily in the Haynesville, Marcellus and Horn River, converting leases to held-by-production, and we expect to spend only about $100 million next year on dry gas drilling. This 2013 reduction in dry gas CapEx will also boost our 2013 overall reinvestment rate of return.

Second, our 2013 pattern of volume growth by product will continue to be dictated by returns, and the trend will be similar to the past several years. In 2013, we expect another peer-leading oil growth year, although the year-over-year percentage increase won't be as robust as in the past, since we are becoming a bigger oil company. We expect decent year-over-year NGL growth, but at a lower rate than our higher-rate-of-return oil trajectory. We also expect another year, our fifth year, of declining North American gas production since it's unprofitable. In Trinidad, we'll likely have flat year-over-year gas production since this year we sold at close to maximum deliverability.

Third, in 2013 we'll continue to fund North American greenfield oil ideas, as well as concepts to improve recovery factors. Because NGL prices have weakened relative to oil, we'll likely shift capital from the Barnett and Permian Combo plays toward the Eagle Ford and Bakken. And fourth, if one assumes that 2013 oil prices -- WTI oil prices -- average in the low $90s, then our preliminary plan of combined lower CapEx and increased oil volumes essentially shrinks our 2013 funding gap to a very manageable amount. This is important because for the past three years one recurring theme from investors has been EOG's significant outspend of our organic cash flow, ie, would we blow up our balance sheet while developing our oil reserves?

Today we sit at 27% net debt to total cap and A-minus A3 credit ratings. And, unless oil prices drop significantly, in 2013 we'll approach neutral from a cash-flow-versus-CapEx point. Since our strong oil growth will continue past 2013, this cash-flow-versus-CapEx trend is positive for 2014, and should potentially allow us to return more cash to stockholders post-2013.

Now let me conclude. In summary, I want to leave you with one thought -- in this business, there continues to be a lot of hype. The advent of oil resource plays has allowed many companies to talk about capturing billions of barrels of oil, or billions of BOEs, as if they are talking about apples on a tree. Be careful of the hype. Go with the company that is putting the points on the board quarter after quarter, year after year, whether it is financial metrics or operational metrics such as organic oil growth. Results matter, and they are easy to measure.

Thanks for listening. And now we'll go to Q&A.

(Operator Instructions)

Pearce Hammond, Simmons.

Good morning, and fantastic quarter.

Thank you, Pearce.

In the Eagle Ford and the Bakken, what inning do you think we are in regarding drilling efficiency improvements? Essentially, are there more substantial leaps ahead in drilling efficiency?

Yes, there are. To give you an idea, last quarter we said that our average drilling time is 14 days. This quarter it is 13 days and we are now -- some of our fastest wells we are drilling at 8 days. So we have room to beat the 13-day average time frame. If you would have asked me 18 months ago, whether we'd be able to drill our fastest wells in 8 days, I would have frankly told you, no way.

So, I would expect that we are going to see further improvements over the next 12 months in the average time to drill the wells, which is going to give us a good chance to drive the average well cost down even further. I mean, right now, the direction we are seeing is, the rig costs are trending down, some of the service costs are trending down. So, I think that the average well cost of $5.5 million for 2013 is eminently achievable for our wells in Eagle Ford. And that's -- that probably beats the industry average in the Eagle Ford by $2 million a well.

Great. And then a follow-up. In the Eagle Ford and the Bakken, do you think we are getting to a point of diminishing returns on the number of frac stages, or do you think we will see the average number of frac stages per well gradually increase?

Oh, we are getting close. We have continued to increase the number of stages. We may do it slightly more here in 2013.

Yes. I don't see us going -- doubling the number of frac stages over the next two or three years from where we are today if that's the direction of your question, Pearce.

Yes. That is. Thank you very much.

Leo Mariani, RBC.

Hey, guys, how are you doing here? Wanted to see if I could get a little bit more color on the rig drops that you talked about. You talked about going from 70 to 52 rigs here. I think in your slide deck you mentioned going from 5 to 4 in the Wolfcamp and from 7 to 5 in the Bakken. But, just a little bit more color on other areas that you have sort of dropped rigs. If you can give us any numbers around that, that would be great.

Yes. Let me segue that into kind of the production targets that we've given you for the fourth quarter, specifically the oil production numbers. The simple way I would explain it is, we spent about $6 billion through the first three quarters of the year. And, you know, we gave you an estimate that basically says that we intend to spend about $1.6 billion in the fourth quarter. So we have, very roughly, a $2 billion-a-quarter prime rate and then we are telling you we are going to spend $1.6 billion in the fourth quarter, roughly. The growth rate of the Company -- the oil growth rate, I would say, is very similar to a coin-operated machine.

EOG right now is very similar to a coin-operated machine. You put dollars in, and you have 100% efficiency. There is no inefficiency due to exploration and there is essentially no operational inefficiency. So, our growth rate for the fourth quarter and a -- is essentially going to be a function of how many dollars we spend. And, that is why our growth rate in the fourth quarter is going to be less than it was in the first three quarters. We basically are just curbing our spending to stay within our capital budget and we are just slowing down pretty severely, really, in all of our plays. But the most severity is going to be in the Eagle Ford, where we are cutting completion units, cutting rigs, and just slowing the process down.

So, and I have also seen -- I have seen a couple of early comments there, on our -- where people are saying, well, you are probably sandbagging on your oil volumes in the fourth quarter. I know we have beaten the volumes in the first three quarters on the guidance, but don't assume that we are sandbagging in the fourth quarter, because we are putting the brakes on quite hard on the CapEx spending. And, frankly, I expect we'll hit about the midpoint of our 8-K target for the fourth quarter on oil volumes, and not over achieve. It's not due to lack of prospectivity, it is not due to well quality, it is just flat due to a coin-operated machine and we are putting less coins in there in the fourth quarter. Does that -- ?

Yes. That is very helpful. I guess can you maybe just kind of address, you know, how that might ramp up in the Eagle Ford? I mean I guess obviously you are pulling back to stay within your budget this year. But, if you do spend slightly less, and you are spending quite a bit less on gas, might you start ramping Eagle Ford back up kind of next year? Just any color on sort of directionality and how to think about that?

Yes. The directionality is -- what we intend to do, specifically in the Eagle Ford is, the last two weeks in December, we are going to start dropping coins back in the machine at a pretty heavy rate. It is not going to show up in any December volumes, but it is going to give us a head start in January. It will start showing up in early January volumes. And, you know, we've got this ground into our numbers. So, our intention is to get a pretty fast start out of this, the gate, in early January. So I wouldn't -- don't assume that because we are losing momentum in the fourth quarter, that loss of momentum is necessarily going to carry over into the first quarter of 2013. We are adjusting for that and will be reversing that momentum in December. And it should show up in the January volume numbers.

All right. That is really helpful. I guess in terms of the Eagle Ford, looks like your step out wells away from Gonzales County were really strong this quarter. I know that you had kind of said that the overall average in the play may be lower. We have had a lot of wells that are 700,000 to 800,000 BOE, in and around Gonzales. But it looks like they are pretty strong. Does this kind of maybe bias the EURs up a little bit in the Eagle Ford?

Yes. Are you talking about the wells in the west there, Leo, that we highlighted on that map?

Yes. The La Salle and McMullen stuff that you guys announced.

Yes. The -- I would still say that the direction that we hope to be heading with the downspacing, if the downspacing is successful, is more likely to be that we end up with more locations at the 450 MBoe net reserve average, as opposed to increasing the 450 MBoe average. So, you know, although certainly in certain areas, the wells are greater than 450 MBoe, but what we would hope the downspacing does for us, is give us more locations with an overall aggregate average of 450 MBoe as opposed to raising that average across the entire acreage. And that's what we hope the outcome is some time in the first half of next year.

And where we stand on the downspacing is, we have got multiples, tighter spacing pilots than the 65 to 90 acres already drilled. We have initial tests on those tighter spacing pilots. They look good, and what we need now is time. We just need some time to observe the performance of those tighter spacing pilots to just see how they do and then cross check them against our computer models. And that is the phase we are in now, is just some time to watch the production history on these tighter pilots.

Thanks a lot, guys. Appreciate it.

Brian Lively, Tudor Pickering.

Mark, the operating results this quarter were substantially better than the expectations you laid out in Q2. Just curious on the LOE side, could you kind of bucket some of the categories where you are seeing the biggest improvements?

Yes. Gary?

We are seeing improvements in our SWD, salt water disposal, because we have spent money in facilities installing additional SWD takeaway. And also we have made some improvements on chemicals. And that's just kind of across-the-board. Just working all of our efficiencies on lease operating expenses.

There is really no reason to not think that those cost improvements will continue to get better and at least you know, stay the same through 2013.

Yes. They -- we should see that. We're fore -- if you check the 8-K, we are forecasting them to go up a bit in the fourth quarter. That is weather related, particularly for the North Dakota side where you get the snow issues and things like that. But, directionally, particularly on the oil side, as you look at a full year of 2013, with -- we expect to have another year of robust oil growth. I think you are going to see the unit costs trending in a good direction.

Okay. And then, just for my follow-up question, Mark, you made a comment about, in 2014, hoping to return more cash to shareholders. Implication there is you expect to be free cash flow positive. Just wonder if you could put some more color around your expectations. I know we are not even at 2013 yet, but in terms of the free cash flow generation as you get into 2014.

Yes. The overall point I wanted to make is, I consider 2013 to be kind of an important year, because, really, for the previous three years, we have clearly been fighting a large, kind of a chronic, organic free cash flow deficit each year. And it has been a shareholder concern issue. And 2013, I think as long as oil prices are in the low $90s for WTI, I think we are finally going to free ourselves from that burden. And then, as you project 2014, 2015, 2016, we are still going to have, I believe, peer-leading, large cap group oil growth during those time frames.

And, it's going to put us in a position where we are going to have flexibility to do some things that we haven't been able to do in the past., such as consider more significant dividend increases, consider accelerating our oil growth by additional CapEx increases if we wanted to. It certainly would put us in a position where we don't have to sell properties or possibly even buying in shares. So, what I just wanted to note is, that the one shareholder concern that people have had the last three years about us, in my opinion, is going to go away starting next year, and it is going to turn into a positive starting in 2014.

That's great color. Thank you.

Arun Jayaram, Credit Suisse.

Just wanted to talk to you maybe bigger picture. Obviously, you have a giant resource here in the Eagle Ford. You have talked about 1.6 to 1.7 billion barrels of reserves. Just wanted to see if you could provide us on longer term thoughts on how you milk the cow, so to speak, or to develop this resource to maximize value. You know, you have been running this year a little bit more than 300 well completions. Do you plan to accelerate that, Mark? Or how do you think that it is best fit to develop this, in terms of a well count?

Yes. That kind of gets into our 2013 capital allocation situation. The first thing we have to do is get a handle on what is the true resource here. Is it 1.6 billion barrels, as it currently stands, which is our 65- to 90-acre spacing? Or is it some other number, depending on what our spacing tests show? So, that is kind of job one, and we think we'll have that answer, as we mentioned earlier, within six months. And then, based on that, then we decide how -- what is the most intelligent way to develop this thing. But I would say the direction for 2013 is to -- we are more likely to attempt to accelerate development above the 320-well level, as opposed to decelerate the development below the 320-well level in 2013, assuming oil prices stay at current levels.

Right. Interesting. And then, the reduction in year-over-year CapEx, is that just from rig efficiencies or completion efficiencies, plus you know a little bit less spending on gas, plus maybe less infrastructure spending? Is that fair?

Yes. The direction I could give you is, and you know we're -- without trying to give you exact numbers. But it is kind of like filling in the pieces. We are telling you we are spending $7.6 billion this year and, if you say we spent $700 million on dry gas this year, and we are going to spend $100 million next year, that ought to give you a pretty good direction on what we are thinking, at this point in time, our CapEx is going to be for next year. That's all I'll say about it at this point, but you can kind of fill in the blanks there.

Yes. That's very helpful. And last question, Mark. Obviously, the returns have gone down as you have front-loaded spending in your oil plays. And, obviously, given the high reinvestment opportunities in the Eagle Ford, high return opportunities, your return should rise over time. I guess, as you think about the longer-term focus on growing your returns, do you -- where does EOG stand in terms of adding a one or two more unconventional plays? Where are you at in that process?

Yes. Well, again, our position's different than most peer companies. Most peer companies, when they -- it seems like to me, when they acquire acreage on a potential new play they make a big announcement about it, often before they have even drilled a well.

Right.

And our position is just the opposite. Whenever we have a play that we have confirmed through multiple wells that works, and whenever we've tied-up whatever acreage level we want, that is the first time you'll hear about our greenfield play. And so, we are working on multiple ones, and the first time you hear about it is, is when we have everything tied up as closely -- as tightly as we can. So, we are not going to give you an indication of any timeframe or anything related to them, other than to let you know we are working on some.

All right. Thanks, Mark. We'll stay tuned.

Brian Singer, Goldman Sachs.

There's a glass-half-empty and a glass-half-full way of looking at your guidance here. The glass-half-full way is you are disciplined in spending, building a backlog of uncompleted wells, particularly in the Eagle Ford where we should see a sharp step up as you re-engage completions in the first half. And a glass-half-empty way may be, okay, 1 to 6 to -- $1.6 billion to $1.7 billion in CapEx per quarter would drive lower oil production, so therefore your maintenance costs to just have flat production would be higher than $1.6 billion a quarter. Can you just address these? How you think about that backlog shift and what you think is closer to reality?

Well, in general terms, I'd say that you would be a pessimist to say a glass-half-empty view of EOG's earnings report. I'd say the previous quarter and this quarter we've pretty much blown the doors off the earnings, particularly relative to most peer companies. So, I'd -- in a polite way, I'd say I reject the glass-half-empty view. (laughter) We have the advantage of having the poker hand and looking at our cards for 2013. And, what I can tell you, Brian, is, I like the hand we have that we are playing for 2013. I wouldn't change it with anybody else's hand. I feel pretty comfortable.

I would tell you, frankly, that the only thing that can sink the EOG ship in 2013 is a disastrous decline in crude oil prices. That is why we have hedged reasonably aggressively for 2013. So, absent a major collapse in crude oil prices, what I would predict is that if you like what you saw of EOG in 2012, you are going to like 2013 from EOG. So, that isn't a direct answer to your question, but I hope it gives you a feeling of the confidence that I have in our 2013 story.

That's great. And then, separately, can you give us any color on some new venture areas, maybe your thoughts on the Pearsall Tuscaloosa Marine Shale, and whether we should expect you to consummate any new joint ventures as you have talked to a little bit before, either in some of the new venture areas or in the less core plays?

Yes. I would say, in the Tuscaloosa Marine Shale, the only reason we even came public on that was that a trade magazine had basically tracked our acreage position there and published it in a trade magazine. And so, the current status of that is, probably on the next earnings call, we will have a report from our first well. We have drilled a horizontal well and we'll be fracking it soon, and so we'll have some data on it. And, of course, we are in a joint venture on that, and we'll just see what the results are.

And, in the Pearsall, we are aware that the Pearsall zone exists below the Eagle Ford on portions of our acreage. Frankly, we are not as enthusiastic regarding the Pearsall as some other companies are. And so, you don't see any advertisements in any of our IR books trumpeting the Pearsall. And so, at this stage, we are not thinking that the Pearsall is going to be the next big, huge stealth play for EOG.

Great. Thank you.

Biju Perincheril, Jefferies.

Hey, congratulations on a good quarter. Just a couple of questions. In the Eagle Ford, if you are targeting something more than 320 wells next year, does that mean a rig count going back up to sort of high 20s? Or are we looking at something lower because of the efficiency gains you have already achieved there? And also, can you give us some color on the completion crews? How many you are running earlier and what the current number is?

Yes. On the first question there, how many rigs we might run next year in the Eagle Ford, again, I don't want to get too specific on there, but I mean, we -- based on the efficiencies we are seeing in the days per well and the reduction of days per well, we might be in the range of 25 rigs next year or something like that. It doesn't look like it is going to be in the high 20s or anything like that for the Eagle Ford in there. And the completion crews, I think we are running four, right now, completion crews.

And I don't have it to -- right now, what number we would be running to for next year in terms of it. But, like I say, in the next quarter, we'll be giving you a specific well count as to how many wells we would intend to drill in the Eagle Ford, and we can give you specifics on the completion crews and exactly how many rigs we would intend to run, as well as the Bakken, Three Forks well count and the Wolfcamp and so on and so forth. So, we are not trying to be evasive, but you know, February is the time when we provide those level of specifics and give it to you at that time.

Okay. No. That is very helpful. And then, if it's -- look at your current Eagle Ford production. It looks like, roughly, cash flow in neutral if I look at the activities this year. First of all, is that a fair assessment? And, when I think about longer-term development in the Eagle Ford, is it fair to think that you will keep activities up sort of to more or less match cash flows there?

Yes. Your first part of that statement is correct that, you know, in rough terms, we are roughly cash flow neutral, currently, in the Eagle Ford. As far as on a go-forward basis, we don't look at just the Eagle Ford in terms of that our plan would be to run the Eagle Ford 2013 or 2014 on a cash flow neutral basis. We -- our decision on what we do with the Eagle Ford on a go-forward basis is going to be more a function of, what do we think the true total reserves are in the Eagle Ford and what are our alternative investment opportunities and what is the reinvestment rate of return on the Eagle Ford versus other areas. So it's -- we don't look at it just on the Eagle Ford alone, really, Biju.

And one more question if I could. Some of your peers have talked about a restricted [short] program in the Eagle Ford and maybe that is yielding higher EURs. Is that something you have tested? Any plans to test that? And, just the efficacy of a program like that depends on the gas/oil ratio?

Yes. The -- all this stuff about, what size choke and people producing and length of the EURs, we probably have more knowledge than any company, certainly, on the Eagle Ford oil production than anybody. And, what we have found is that the higher the gas/oil ratio, the more sensitivity the choke management, the more importance the choke management is. For example, in the Haynesville and in our Barnett Combo, we actively pursue choke management and we are looking at, right now, a choke management for our Wolfcamp areas. In the Eagle Ford, in the position where our acreage is, which is the black oil area, or, you know, the area where we are fortunately have very high oil portions of the mix, the choke management is not very important.

Where other companies have acreage, where they have higher gas/oil ratios, the choke management may be important to ultimate recoveries. But, we can't speak about their positions and whether choke management works or doesn't work on their acreage. But what we can say is that, on our acreage, choke management, in our opinion, is not that critical to EURs. And that's because we have the preferred acreage, frankly. It is just more oily. So that is -- that would be our response to that issue.

Okay. Great. Thank you very much.

Charles Meade, Johnson Rice.

I wanted to go back to those Baker-DeForest wells in the Eagle Ford that you announced this morning. Could you tell us where on that 65- to 90-acre spacing range those wells are? And, more generally, when you have those monster wells, are they more likely to be on tighter spacing, reflecting more oil in place? Or are they more likely to be on a wider spacing, reflecting more conductivity and better fracs?

Yes. Those are probably -- the Baker-DeForest wells, I don't have the exact numbers, but they would be on the tighter spacing areas. I don't -- I can't tell you whether they were on 65 or 90 acres, but I would say they are probably closer to the 65-acre than the 90-acre spacing, in terms of that. So what, all -- essentially all the 12 well -- monster wells, that we would have related to you here in this particular quarter would be on pretty tight spacing on there.

So, it's -- what's happening is, it's the quality of acreage plus we are giving these wells larger fracs, in terms of pounds of sand and number of stages relative to the fracs we would have given these identical wells say 12 or 18 months ago, and some other tweaks that are proprietary tweaks to the fracs. So, those are the two things that are the keys to these monster wells.

Great. That's great detail. It sounds like I could -- there is just more oil in place and so there is just more to come out there.

Yes. And just a more effective stimulation than we would have given to these high-oil-in-place areas, even a year ago or 18 months ago.

Got it. And then, one quick follow-up. Going -- on the Bakken, going back to your comments, I think they were on the -- your last earnings call, when you talked about the response of the original offset wells to the downspacing -- the subsequent downspacing that when you put a frac in, you saw that sustained response in the original well. Is there any update that you can offer on that? Whether you have seen that, whether you have seen that sustained in wells or whether you have seen that replicated in new areas as you downspaced?

Yes, Charles. We do continue to see that in our downspacing, like in the fertile wells that are on the -- that are in the press release. When we do the aggressive fracs, and we have been working on our frac technology in the Bakken as well as we have in the Eagle Ford, and we are making really good progress here. So when we do the more aggressive fracs in the downspacing, we do see response from the offset -- the older, offset wells. So they -- generally, they come up and they kind of double in production, and they go on a decline, and eventually they'll get back on the original curve that they were on. But there is some, certainly some additional reserves in oil that we are contacting with these more aggressive fracs. So, we are really pleased that our Bakken results are certainly improving because of the frac technology and the downspacing.

That is great detail. Thank you very much.

Bob Brackett, Bernstein Research.

Great. Just in under the wire. Quick question. What assets are relying on salt water disposal that you mentioned earlier on the LOE comments?

That is principally the Bakken.

Okay. And then, the other. Crude-by-rail, what role do you think that ultimately plays? Is that something that simply is run until pipelines come into place? Or is that something that is going to be ongoing as part of the mix forever? And, what's the payout period on those crude-by-rail facilities?

Yes, Bob. I really think that crude-by-rail is going to be around for a long time in EOG's system. I think the lag time on getting pipelines built is really something like five to maybe eight years. So, you know, it's the -- crude-by-rail is not just a stop-gap measure, in my opinion, in other words. And I see the crude-by-rail destinations perhaps changing three years, five years from now, such that perhaps Louisiana is not the optimum destination to deliver the crude to, depending on what market conditions are at that point in time. But, I would guess that 5 years from now, 10 years from now, crude-by-rail is still a significant kind of a market uplift for EOG's crude marketing. And, did you have a second part to the question there?

What's the sort of payback period on a loading terminal?

They are, at least in EOG's experience so far, it's in months rather than years.

Great. Thank you.

And that's all the time we have for questions. I'll turn the call back over to Mark Papa for any further remarks.

Okay. Thanks everyone for listening. And, remember, if you haven't voted yet, get out and vote.

Ladies and gentlemen, that will conclude your conference for today. We do thank you for your participation.