EOG Resources Inc (EOG) 2013 Q4 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources fourth-quarter and full-year 2013 earnings results conference call. As a reminder, this call is being recorded. At this time for opening remarks and introductions I would like to turn the call over to Tim Driggers, Chief Financial Officer. Please go ahead sir.

Thank you. Good morning. I'm Tim Driggers, CFO. Thanks for joining us. We hope everyone has seen the press release announcing fourth-quarter and full-year 2013 earnings and operation 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 for these non-GAAP measures to comparable to the 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 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.

Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, Chief Operating Officer; Billy Helms, Executive VP Exploration and Production; Maire Baldwin, President IR; and Jill Miller, Manager, Engineering and Acquisitions. An updated IR presentation was posted to our website yesterday evening and we included guidance for the first quarter and full year 2014 in yesterday's press release.

This morning we'll discuss topics in the following order. I'll start with fourth quarter and full-year net income and discretionary cash flow, Bill Thomas and Billy Helms will review operational results and year end reserve replacement data. Then I will discuss EOG's financials, capital structure, and hedge position. Bill will cover EOG's macro view, our 2014 business plan, and provide concluding remarks.

As outlined in yesterday's press release, the fourth quarter 2013 EOG reported net income of $580 million or $2.12 per share. For investors who focus on non-GAAP net income to eliminate mark-to-market impacts in certain nonrecurring items, as outlined in the press release, EOG's fourth quarter 2013 adjusted net income was $548 million or $2 per share. For the full year 2013, EOG reported net income of $2.2 billion or $8.04 per share.

On an as adjusted basis full-year net income was $2.25 billion or $8.22 per share. For investors who follow the practice of focusing on non-GAAP discretionary cash flow, EOG's discretionary cash flow for the fourth quarter was $1.9 billion, using the same methodology for the full year 2013, EOG's discretionary cash flow was $7.4 billion.

For the full year 2013, EOG's net cash provided by operating activities exceeded financing investing cash outflows. At December 31, 2013, debt to total cap was 28%. Net debt was reduced by $841 million during 2013. Resulting in an ending net debt to total cap ratio of 23%, down from 29% at year end 2012.

I'll now turn it over to Bill Thomas to discuss operations.

Thanks, Tim. 2013 was EOG's best year on record. Over the course of 2013, EOG increased crude oil production growth targets 3 times and ended the year with total Company oil production up 40% over 2012. This is a 44% average increase over the last three years. Our key assets, the Eagle Ford, Bakken, and Leonard keep getting better.

And we continue to improve well productivities from these plays. The 42% increase in US oil production last year is solid proof of the depth of EOG's drilling inventory. For the year, NGL production increased 17% while natural gas production decreased 11%. For total company production growth of 9%. EOG cost structure is a focus area and for the fourth quarter and full-year unit costs were lower than expected.

The combination of increased growth from high-margin oil with a decrease in cost structure flowed through our income statement and balance sheet further deleveraging the Company and generating a 16% ROE for the year, a big increase from 12% for 2012. We updated the ROE and ROCE charts in our IR presentation on pages 14 and 15, showing our improving metrics and a comparison of our results to our peers. While I'll discuss 2014 business plan in greater detail later on in this call EOG is targeting 27% oil production growth in 2014.

Given the strength of our balance sheet and the depth of our high-margin domestic crude oil drilling inventory we've increased CapEx levels over 2013 to accelerate drilling of our high rate of return oil inventory. Last year we added two new locations for every one well we drilled. With this strong operational momentum in our key areas of activity we plan to keep it going.

The biggest driver of EOG's outstanding crude oil growth during 2013 was the topic -- is the topic of one of today's biggest news items is the Eagle Ford. For the third time since EOG discovered oil in the play at 2010, we have increased the net reserve potential. We now estimate EOG's total net reserve potential on our acreage to be 3.2 billion barrels of oil equivalent. That's a 45% increase from the previous 2.2 billion barrels of oil equivalent estimate.

This is a great example of the value of EOG's exploration focus and organic growth strategy. By being a first mover and capturing the best assets, we are able to grow them through the drill bit and improve them over time with in-house ingenuity and well completions. Our wells across the Eagle Ford continue to exceed our expectations. The Eagle Ford will again be our biggest oil growth driver and our highest rate of return asset in 2014.

Last year our Eagle Ford drilling program focused primarily on two aspects. Number one, improving well productivity in the west. Prior to 2013, we had a drilled very few wells on that portion of our acreage. Suffice it to say, our successful drilling program in the west was a big part of EOG's growth in the Eagle Ford. And the continued high rate of return activity we recorded in the play last year.

During the fourth quarter, the average IP rate of wells in the west exceeded the average IP rate of wells in the east. On a go forward basis, we will talk about one Eagle Ford oil play. As both the east and western areas are contributing more or less proportionately to the remaining reserve potential.

And number two, improving reserve recovery and maximizing NPV. Our goal was to determine the optimum well spacing while increasing well productivity and decreasing well costs. We will continue to work on these two goals. What we concluded was, first, our downspacing efforts proved even more successful than we had previously thought. While the optimum distance between wells will vary across the field depending on various geologic considerations, on average the wells will be drilled on 40-acre spacing.

Second, as a result, we have approximately 7,200 net locations. Taking into account 1,200 net wells drilled to date we have 6,000 net wells remaining. This represents a 12 year drilling inventory at our current activity level. And third, based on our improvements in completions, we've increased by 12% the net recoverable reserve per well, up from our previous 400 MBoe net per well to 450 MBoe net per well.

Multiplying 7,200 net wells by 450 MBoe brings our total net potential recovery reserves for the Eagle Ford to 3.2 billion barrels of oil equivalent. With four years of production history from our early wells and a database of over 1,200 EOG wells, we are confident in the long-term performance and potential reserve estimate of the Eagle Ford. Overall performance from the field continues to surpassed our expectations.

In addition, we've reached an efficient manufacturing mode in the Eagle Ford. While we still have further efficiency and cost reduction goals, we've now reached the point of optimum drilling, completion, and operational logistics in the play. This year we plan to allocate a larger percentage of EOG's 2014 drilling CapEx budget to the Eagle Ford and drill 520 net wells, up from 466 net wells in 2013. We currently have 26 rigs operating in the play.

In summary, EOG's Eagle Ford asset continues to be the largest and most economic horizontal crude oil play in North America. And it's getting better. We've simultaneously increased EURs, reduced costs, and through downspacing identified an additional 1,600 net drilling locations. Although we are increasing the load count this year we still have 12 years of very highly economic crude oil drilling inventory in this single play.

Now I'll turn it over to Billy to discuss the Bakken, Permian, Trinidad, and reserves.

Thanks, Bill. During 2013, we made significant progress with our Bakken and Three Forks completions that dramatically improved well productivity and individual EURs. These enhancements and the ongoing implementation of cost saving measures, including the use of EOG's sand, have turned what was once a mature producing area into a high rate of return oil growth asset.

We continue to see plenty of opportunity on our Bakken core acreage by bringing the latest technology to this area that was initially sparsely drilled over five years ago. Recent Core wells are Wayzetta 30-3230H and 31-3230H, which began production at 2,510 and 2,540 barrels of oil per day respectively. We have 59% working interest in these wells. Though Wayzetta 35-1920H had an initial production rate of 2,240 barrels of oil per day with one 1.2 million cubic feet a day of rich natural gas. We have 60% working interest in this Mountrail County well.

Using the same improved completion techniques in our Antelope Extension area, we are seeing similar enhanced IP rates and EURs. The Hawkeye 2-2501H had an initial production rate of 2,075 barrels of oil per day with 3.8 million cubic feet a day of rich natural gas. We have 80% working interest in this well. In 2014, we expect to again grow crude oil production. Our drilling efforts will be localized in these same two areas, the Bakken core and Antelope Extension, with the majority of activity in the core.

We continue to downspace in both areas and plan to operate a six-rig drilling program. We have existing oil and pipeline infrastructure within the core and with the integration of EOG's sand into our Bakken operations, we will continue our focus on reducing well costs even further while enhancing the productivity and recovery factor of the field. We plan to drill 80 net wells this year compared to 54 last year.

EOG's total drilling CapEx budget in the Permian will be essentially flat in 2014 from 2013. The majority of the Permian drilling dollars however will shift from the Midland Basin to our two higher return plays in the Delaware Basin, the Leonard and Wolfcamp. The largest increase in activity will be the Leonard play where recent wells have had excellent rates of return and we continue to make progress on our technical understanding of this outstanding play. The Leonard is EOG's third best play in terms of rate of return.

To date we've drilled in the A and B zones and have identified additional pay zones in our 73,000 acre -- net acre position. During 2014 we plan to develop the A zone with 8 to 10 wells per section. This base development program in a single zone will drive volume growth for the Leonard. We have exploration opportunities in other zones on our Leonard acreage and we're testing multiple targets and spacing patterns, both between wells and also between zones. Two recent Leonard wells in Lea County, New Mexico came online with very strong oil production.

The Vaca 24 Fed Com #5H began production last month at 1,520 barrels of oil per day with 265 barrels per day of NGLs and 1.5 million cubic feet per day of natural gas. The Vaca 24 Fed Com #6H had an IP rate of 1,380 barrels of oil per day with 170 barrels per day of NGLs and 935 MCF per day of natural gas. We have 89% working interest in these wells. We plan a much more active year in the Leonard with 40 net wells compared to 17 last year.

In the Delaware Basin Wolfcamp, we are gathering microseismic from several wells to further define optimal development for this multi-pay shale play. During 2014, we plan to test a number of spacing patterns across various zones with the goal of maximizing recovery and determining the impact of any communication between wells. We also plan a more active year in this play with 14 net wells. In Trinidad, we expect to be at full contract takes for a full year. We have a development drilling program planned for the second half of the year to maintain stable production in the years following 2014.

I will now address reserve replacement and finding costs. In total, we replaced 264% of production from all sources at a $13.42 per Boe all-in total finding cost. Proved developed reserves increased 19% and net proved oil reserves increased 28%. For the 26th consecutive year, DeGolyer and MacNaughton did an independent engineering analysis of our reserves and their estimate was within 5% of our internal estimate. Their analysis covered about 82% of our proved reserves this year. Please see the schedules accompanying the earnings press release for the calculation of reserve replacement and finding costs.

I'll now turn it back over to Bill.

Thanks, Billy. Regarding new plays we have been saying for some time now that we haven't lost our focus on looking for new domestic liquid plays, primarily oil. In addition to increasing the recovery on our existing plays, we continue to look for new prospects and test new ideas.

In our midstream operations, we are working with our partner rail companies. We have a strong emphasis on safety in our crude by rail operations. On our crude rail -- our crude by rail continues to give us flexibility to access markets with premium prices and plays a role in the ultimate destination of EOG produced crude. To summarize our operations, EOG has captured the best horizontal oil acreage in North America and our high-performance operational teams continue to execute superbly.

Our wells are still getting better, unit costs continue to decrease, and oil production continues to increase at peer leading growth rates. EOG has a long life inventory of crude oil and liquids rich drilling prospects with high after-tax rates of returns. We continue to focus on delivering high-margin oil growth, increasing recoverable reserves in existing assets, and generating new plays to ensure that EOG remains best in class through 2017 and beyond.

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

Thanks Bill. Capitalized interest for the quarter was $15 million. For the fourth quarter 2013, total exploration and development expenditures were $1.6 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment were $93 million. There were $28 million of acquisitions during the quarter. For the full year 2013, capitalized interest was $49 million.

For the full year, total exploration and development expenditures were $6.7 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment were $364 million. For the full year, total capital expenditures for all categories were $7.1 billion, excluding acquisitions. We ended the year below our guidance. Total acquisitions for the year were $120 million.

During the quarter, net cash provided by operating activities exceeded financing and investing cash outflows. We paid off a $400 million bond that matured in October. For the year, total proceeds from asset sales were $761 million, compared to the goal of $550 million. The effective tax rate for the fourth quarter was 37% and the deferred tax ratio was 64%. We announced a dividend increase of 33% and a two for one stock split in yesterday's earnings release. The dividend increase is the largest year-over-year dollar increase in EOG's history.

Yesterday we included a guidance table with the earnings press release for the first quarter and full-year 2014. Our CapEx estimate for the full year is $8.1 billion to $8.3 billion, excluding acquisitions. The exploration and development portion, excluding facilities, will account for 80% of the total CapEx budget.

The largest increase in spending will come from drilling activity, primarily in the Eagle Ford and Bakken. For the first quarter and full year, the effective tax rate is estimated to be 35% to 40%. We have also provided an estimated range of a dollar amount of current taxes that we expect to record during the first quarter and for the full year of 2014.

In terms of crude oil hedges, for March 2014, we have 181,000 barrels per day hedged at $96.55. For April 1 through June 30, 2014, we have an average of 168,000 barrels per day hedged at $96.48. For the second half of 2014, we have 64,000 barrels per day hedged at $95.18. We have a number of contracts outstanding that could be put to us at various terms. For the period April 1 through December 31, 2014, we have 10,000 barrels per day of options that could be put to us at approximately $96.60 on or about March 31, 2014. If it is advantageous for the counter-party to do so.

For June 1 through August 31, 2014, we have 10,000 barrels per day of options that could be put to us at approximately $100 on or about May 30, 2014. For the second half of 2014 we have 118,000 barrels per day of options that could be put to us at approximately $96.64 on or about June 30, 2014. For the first half of 2015, we have 69,000 barrels per day of options that could be put to us at approximately $95.20 on or about December 31, 2014.

For natural gas, we have 330,000 MMBtu per day hedged at $4.55 per MMBtu for the period March 1 through December 31, 2014, excluding unexercised options. For January 1 through December 31, 2015, we have 175,000 MMBtu per day hedged at $4.51, excluding unexercised options. We also have a number of natural gas contracts that could be put to us at various terms.

If counter-parties exercise all such options the notional volume of EOG's existing natural gas derivative contracts will increase by 480,000 MMBtu per day at an average price of $4.63 per MMBtu both -- each month for the period March 1 through December 31, 2014. For 2015 if counter-parties exercise all switch options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtu's per day at an average price of $4.51 per MMBtu for each month during the period January 1 through December 31, 2015.

Now I'll turn it back over to Bill.

Thanks Tim. Now I'll provide our views regarding the macro environment and 2014 operations activity.

Regarding oil, we're still waiting for the final 2013 EIA US oil production data, but it looks like the rate of growth in 2013 flowed -- slowed compared to 2012. And we expect this trend to continue in subsequent years. The October and November EIA monthly data indicate the rate of annualized production growth was approximately 760,000 barrels per day compared to 1.04 million barrels per day for the same period in 2012.

We're still bullish regarding US oil prices because of slowing domestic oil growth and we are not particularly concerned about a surplus of US light sweet oil. Regarding North America natural gas prices, our long-term view hasn't changed. We've obviously seen some relief this year due to the multiple shifts in the polar vortex this winter. We think natural gas prices will stay around $4.50 level in 2014 and 2015. On the plus side we've taken advantage of some of the recent prospects to layer in hedges.

For our 2014 business plan, is as follows. We plan to focus on high rate of return domestic crude oil growth, we're targeting 27% oil production growth this year and 11.5% total Company growth. We increased our CapEx budget from last year because we have so many high rate of return opportunities to pursue. The greatest increase -- increases are in our highest return plays, the Eagle Ford and Bakken.

The amount of CapEx dollars allocated to midstream infrastructure is also increasing. This year we plan to spend approximately 10% of our total CapEx budget on these types of projects to lay the foundation for future growth and to manage operational costs.

Also for the sixth year in a row we are not growing EOG's North American natural gas production. This is reflective of our view of the low return on natural gas investments. We won't drill any dry gas wells in North America during 2014 because we don't see a change in the gas oversupply picture until the 2017, 2018 time frame. I want to leave you with some important summary points. First, 2013 was an excellent year for EOG. Particularly in our three key plays, the Eagle Ford, Bakken, and Leonard.

In the Eagle Ford, we moved beyond an assembly line of operation to a high precision manufacturing mode of delivering top-quality individual wells. In the Bakken, we created a technical renaissance, not only for EOG but also for the industry. We changed our completion techniques and improved well productivity. In the Permian basin, we are shifting activity to the Leonard where we made exceptionally good wells during the second half of 2013. Our Leonard is our highest rate of return asset in the basin.

Second, in terms of capital discipline, we've boosted our financial returns in 2013 while deleveraging the balance sheet. We generated strong ROE and ROCE numbers last year, 6% and 12% respectively. We think this is a discriminator in a sector not recognized for financial returns. Additionally, we raised the dividend for the 15th time in 15 years.

Third, EOG has captured the best horizontal acreage in North America and our high-performance operational teams continue to execute superbly. In March 2013, EOG became the largest producer of crude oil in the state of Texas and we continue to maintain that position. Today, according to IHS, EOG has become the largest onshore crude oil producer in the US lower 48. With our large high-quality drilling inventory, we expect EOG to be one of the largest crude oil producers in the US by 2017.

Fourth, we ended 2013 with a strong balance sheet. Posted peer leading oil growth rates and increased our high margin oil opportunity set through the drill bit. And finally, the increased CapEx budget and the increased dividend rate are a function of EOG's confidence in our long-term business plan. It's the same business plan we've always had. Capture the best assets, grow organically, and focus on returns.

Thanks for listening. And now will go to Q&A.

(Operator Instructions)

Leo Mariani, RBC.

Can you talk a little bit more about the Eagle Ford in terms of some of the down spacing initiatives. I guess you talked about an average of 40 acre spacing across your position here. Would you expect to see some interference at that level, and is it possible for you guys to quantify that at all?

Yes. Thanks Leo. That's a good question.

The down spacing that we've done across the field has been -- we've found that it's been -- the spacing is very variable due to different geology, different faulting situations, and just different things across the field that we have to deal with. Some places we can drill wells as close to maybe 30, 35 acres per well and in some places it's more like 50 to 60, 65 acres per well. So it is quite highly variable.

The number of wells that we have, again, the 7,200 total wells are based on actual well locations that we have put on a map. In regard to the geology, the individual geology of each unit and the configuration of the leases. So these are not spreadsheet numbers.

As far as the interference between wells, there is some interference in some areas and in some places there's not any interference. Again, it's really highly variable and we've been able to overcome that interference and increase the well EURs with our frac technology, so the frac technology has definitely enhanced the productivity of the wells and it's enhanced the EUR per well. So we have quite a bit of confidence that the average EUR for the 7,200 wells we have is 450 MBoe per well.

Okay, that's really helpful and I guess just jumping over to your thoughts on oil marketing, I guess there is some concern out there amongst investors that too much oil is going to the Gulf Coast over the next couple of years. Can you talk at all about your optionality in terms of moving oil volumes around, are you guys able to access potentially the East and West Coast markets as well with your oil?

Yes Leo. Our crude by rail system gives us a lot of flexibility and we believe that will come into play as we go forward. We have established markets in the East and West Coast.

But really our prime markets still remain on the Gulf Coast or LLS prices and in Cushing, with WTI prices, and so as we've seen, just really over the last few months, there's been some variances in the differentials between WTI and LLS prices, and we've been able to take advantage of that and we've been switching kind of back-and-forth. So again, our crude by rail system gives us a lot of flexibility to get our oil to the highest priced markets.

Okay. That's really helpful. Thanks.

Doug Leggate, Bank of America Merrill Lynch.

Bill, I wonder if I could go back to the 450 EUR outreach. I'm not sure how to ask this question eloquently, so I'll stumble through it probably, but what I'm trying to understand is, that's obviously an average and I'm guessing there's some variability across the play.

So what I'm trying to get to is, where are you concentrating the drilling inventory in the first part of the 12 year spot wells that you've got? In other words are you drilling better wells first, and on average the lower and the lesser wells will be later on in the program, and if so, how should we think about your medium-term growth outlook, and I've got a follow-up please.

Yes, Doug, that's a very good question. Our drilling is very well equally spaced. And really as we look forward, we need to be thinking about the Eagle Ford as one play because the western wells and the eastern wells are relatively the same in the average EUR per well, and there is a little bit of variability, but there's really not much difference across the whole play.

So whether we drill in the west or we drill in the east, our well results we believe will be very consistent going forward and they are certainly not front end loaded with the best wells in the east and then later on we won't drill as good of wells down the road. So I think you can look at the 12 year inventory we have as very strong and very consistent and we'll have good results every year because of that.

Okay. That's very clear. Thanks for that.

My follow-up is really on the midstream spending. I know you guys have said often that there's really no consideration, short-term at least, to maybe do something structural by way of an MLP or something like that, but given the scale of your spending, I just wondered if I could ask you to frame your latest thoughts on that, has there been any change? And if not what -- why is that not a structure that EOG would be interested in, and I will leave it at that. Thanks.

Yes, Doug. On midstream, we're very selective on how we spend our midstream dollars and the midstream dollars we have allocated this year particularly have given us a very strong rate of return and are really focused on getting our oil to the market and increasing and decreasing our future operational costs and transportation costs.

And we are not at all interested in working on forming new MLP companies or making the company very complicated. We want to keep the company financially and structurally simple as we go forward so that it's easy to understand. So our midstream is really just to enhance EOG's acreage positions and getting our products to market and keeping our costs low as we go forward.

I guess if I may, Bill, why then wouldn't you include the midstream costs when you look at your well economics if that is the case?

Well, I mean, certainly the midstream parts are a part of the whole picture but really -- we really focus on getting the wells drilled and getting the direct return of the wells at a maximum, we're focused on that. And then we are always looking at the whole picture, EOG has a lot of scale and we're able to keep midstream dollars down to a minimum when we have a big scale. We're really focused on the company on returns and increasing our ROE and ROCE numbers. So midstream really helps us do that.

Appreciate the answers, Bill. Thank you very much.

Charles Meade, Johnson Rice.

If I could go back to the Eagle Ford spacing question, and particularly the average being 40 acres, I know some other operators in the play are testing -- they haven't confirmed at this point but they are testing offsets down to 175 feet which would get you close to about 20 acre spacing so I'm wondering -- can you share what the closest offset you guys maybe have planned for 2014 or what's the closest you've done today?

Yes, Charles. I think we've done some in the 300 foot range. And that's 200 foot. Maybe down to 200 feet.

And, again, we've pushed them pretty close together and the goal, of course, is to always maximize the NPV of the acreage and as you push them too close together you could start destroying value. So these pilot programs that we put in and tested have given us a pretty solid understanding of the interference between wells and the spacing between wells in terms of feet and distance between wells so we feel pretty solid at this point that, on an average, 40 acres is probably the optimal spacing pattern.

Got it. Thanks for that detail Bill. And then shifting over to the Permian, your slides are very helpful. You really -- it's obvious when you look at the oil cut why the Leonard play is more attractive than the Wolfcamp play because you're pretty gassy there but I'm wondering if your 2014 plans for the Wolfcamp, you might be able to go north and east from Reeves to perhaps even Ward and Loving where you have seen higher cuts oil cuts in that Wolfcamp play, and if that's an option for you and is part of your 2014 plans.

Yes. For the Delaware Wolfcamp, our acreage is located in central Reeves and we do have some acreage up to the north and to the east in the northern part of Loving County, and then into Lea County that we believe are perspective for the Delaware Wolfcamp, and you are correct, it does get a bit oilier as you move that way.

So in 2014, though, we are really probably just focused on this central Reeves County area and then we'll be testing additional Wolfcamp potential maybe later in the year of 2014 and into 2015 as we go forward. But we do have -- we are trying to work the play technically and to increase the oil percentage as we go forward.

Great. Thanks. I'll stay tuned on that.

Matt Portillo, TPH.

Just two quick questions for me. I was wondering if we could get an update to your Bakken down spacing test and how you think about the upside to your inventory depths and then I'll have a quick follow-up after that.

Yes, Matt. On our Bakken, we're continuing with 160 acre down spacing and we are studying very intensely the possible interference between the newer wells and the existing older wells, and obviously the new wells have come in extremely good. We are very pleased with the results so far in our down spacing efforts.

And we will give some guidance on what all this means later down the road. We haven't given any time commitment on that. We really want to make sure that we technically understand where we are going and what this really means to the recovery for our acreage.

Great. And then just a quick follow-up -- in regards to your Midland Basin Wolfcamp position you have a nice footprint there although the asset looks like it doesn't compete on a rate of return basis within the portfolio today. How do you guys think about that asset from a long-term perspective in terms of its strategic nature in your portfolio?

Yes, we want to certainly hold onto it. We are making some progress there in the Midland Basin. Our long-term view is that we can continue to improve the results there, establish the right spacing patterns, continue to reduce costs, and also increase the well productivity and really focus on increasing the rate of return there. And so we're going to leave it in the portfolio right now and see if we can get it up to the point where it can make its way back into our high return inventory.

Thank you.

Amir Arif, Stifel.

Just a first question really on the Leonard Wolfcamp play, I know it's early days there but just curious where you think the 2% to 3% recovery factor that you're putting out there right now could go to as you better test the down spacing and the timing around testing the down spacing to get a comfort on resources?

Yes, Amir, on our Leonard play, we're still doing some testing there, as you might imagine on spacing and testing different target zones to really understand what the productivity and the long-term performance is going to be. We obviously are seeing improvements in that so we're optimistic of what we might see on improvements in recovery factor but we still haven't quantified that yet. That's still a work in progress, so we'll provide more data on that once we have it fully evaluated.

Yes. And then just a follow-up question on the CapEx, the $900 million for facilities, can you just give us some more color in terms of what type of facilities and where that CapEx is going?

Yes. About two thirds of that is going to be in the Eagle Ford and that's on eased facilities with us drilling more wells this year and we're going ahead and putting in our oil and gas gathering lines, putting the oil on the pipeline saves us quite a lot on our transportation, and then we're putting in an oil storage and pipeline facility there for the west. Gas processing facilities, SWDs systems, water reuse facilities, and that also includes artificial lift.

We are putting that on quite a number of wells this year. So all that just to reduce our transportation, our LOE, realize higher prices, all long-term benefits for earnings.

Thank you.

Joe Allman, JPMorgan.

Hey Bill, in terms of the increase in the Eagle Ford EUR and resource, what drove your decision to increase the EUR per well in the resource at this time? And then what could make that EUR or the total resource go up in the future?

Yes, Joe. The EUR per well increase was certainly off a lot of strong historical data. We have over 1,200 producing wells in the play right now and then we've done extensive pilot testing on each one of these down spacing patterns.

And through our completion technology, we've seen a dramatic increases in initial rates per well and then the shape of the decline curve really has not changed. It's relatively the same shape.

It's just that the wells, initial rates have improved over time with the better completions and so that gives you a better total EUR when you have long-term production and you have enough data, like we do, to establish that and be confident in that. So we've got a lot of confidence in that and as we go forward, we are hopeful that we'll be able to continue to improve the well productivity, but we certainly have not proven that yet.

But we are going to obviously continue to work the technology, we're never going to give up and we're never going to quit trying new ideas and new things, and so we are in that process right now, and we'll just see. Time will tell as we go forward. We'll see how it all turns out.

Great, thanks for that. And then on your gas production forecast for 2014, you are now looking at a decline in gas production. A short time ago you were actually looking over the next few years for a flat to modestly up profile for natural gas. So what changed in terms of your forecast for natural gas?

Yes, Joe, we looked at our drilling portfolio and we have continued to shift money to the higher return plays so one of the things we've been reducing is some of our combo plays. So we continue to reduce dollars from the combo plays, which are more gassy because they are just a bit lower return than our high return oil plays. So that's really the shift that we've seen in the gas profile.

Great. Thank you very much.

Pearce Hammond, Simmons & Company.

Bill, some other operators in the Eagle Ford have talked about the upper and lower Eagle Ford intervals being distinct zones within the play. Are you seeing the same thing across some of your acreage?

Yes, Pearce. We do have that. We've recognized that on a decent portion of our acreage and that's certainly an option that we are looking at and exploring and may do some testing on that as we go forward to see if the upper part of the Eagle Ford specifically has not been affected and contacted with the existing frac technology that we're using. So we have got that in mind and we are going to be working on that.

Great. And then my follow-up, Bill, in slide 31 of your presentation you highlight your gas acreage, and while I know right now you're focusing on oil because of the better rates of return, if you were to turn your attention to gas, which of these areas would receive EOG's primary attention?

The best acreage we have are in really probably some of the more wet and combo-ish acreage. The Haynesville combo play is a really strong rate of return play for us. Also the highest quality dry gas that we have certainly would be in Bradford County in the Marcellus.

And then we drill a few selective wells in South Texas in the Frio/Vicksburg area. They are good wet gas and combo and very, also very high rate wells, and give us high rates of return. So those are three areas that probably would be high on the list.

Thank you, Bill.

Bob Brackett, Bernstein.

I'll do a follow-up. You mentioned the Frio/Vicksburg wet gas wells, are those conventional type sand targets or are there any sort of shaly plays you are chasing down there?

Yes, Bob. Those are really conventional plays. They are the typical Gulf coast --

Millidarcy?

Yes. I'd say they're millidarcy, mostly millidarcy type reservoirs and so they are very high rate and very specific prospects. Not regional prospects. They're very specific.

Yes. And then following your language of capture the best assets is one of your strategic goals, can you give us some flavor of what you might be doing this year, next year against that objective?

Yes, Bob, we have a nice working list of new prospect potential that we're working all the time. And we are very focused, of course, right now on the oily type plays and we are focused only on plays that would be additive to our portfolio. And so our portfolio is such a high return portfolio that for a new play to work itself into our system, we are targeting only plays that we think that could generate after-tax rates of returns greater than 50%.

So we're being very selective on that. And we have a nice list working and so we're taking our time to test those and to evaluate those to make sure that they are the kind of quality plays that we want to invest money in as we go forward, but we are confident that EOG's going to continue to be a leader in generating new plays and as we go forward. So that will be certainly a nice part of the additional resource potential for the company as we go forward.

Thanks.

Joe Magner, Macquarie,

With all the updates provided on the Eagle Ford I noticed that references to specific recovery factors weren't in the presentation anymore. I'm just curious with what you're seeing and the understanding of how the reservoir now, are there any changes to your estimates of original oil plays and/or those recovery rates?

Yes, Joe, that is a very good question. The recovery factor is a work in progress. And we are certainly not seeing any decrease of any oil in plays.

We are learning about these resource reservoirs, and learning more the time. Of course there's no textbooks on them so we're trying to get a better understanding of that as we go forward. And as we learn more about that, we'll be able to update you with a bit more stronger technical information.

Okay. And then I guess just to circle back on the spacing and the perspectivity of your Eagle Ford oil acreage, if I apply 40 acres to that entire position, it seems like there'd be more locations than what you've provided. Just curious how you are thinking about risking and the delineation of that acreage position and if there's more work to be done over time. I just want to make sure I've got that sort of discussion right in my mind.

Yes, Joe. The 7,200 locations that we've announced or talked about are actual sticks on a map and so they're very specific locations, not a spreadsheet calculation at all. And those are all very firm locations.

As we look at our acreage, there are other areas of our acreage that could be perspective. But those areas at this moment we feel like all below our rate of return cutoff, and although they would be productive, they would not fit their way into our portfolio right now.

So we've kind of put a cut off on rate of return on anything less than the 60% tax rate of return is not it included in the 7,200 locations. So there could be additional upside. We are hopeful that will be able to continue to reduce costs and improve well productivity in all of the areas and specifically in the areas that are a bit more lower return.

Okay. Thank you.

David Heikkinen, Heikkinen Energy Advisors.

Just thinking about your midstream CapEx this year, how much does the spending this year impact 2014 in your realized pricing and OpEx guidance? And then we should assume further efficiency gains in 2015?

Yes. Some of this will affect 2014 certainly. When we talk about our gathering lines here and on lease and our artificial lift, but you are right, David. This a -- what we are doing here is going to have impact certainly beyond 2014.

And a portion of this, sure, is midstream and also even our sand facilities. Because we're seeing that yes, as we drill more wells, we have a need for additional sand, and we are just ensuring that we have long-term, low-cost sand available to EOG.

That was a perfect segue to my second question, so you saved $500,000 alone Eagle Ford for using your own sand roughly. As you take your sand to the Bakken this year and then the Permian next year, how much would you save per well using sand there? EOG's sand.

Yes. We think that we're going to be looking at the same sort of savings and we are working toward having us self-sourcing all of our sand for the Bakken. We are doing some of that now in the Permian. We believe we'll be able to do that pretty well across the board for EOG.

Okay. Thanks. That was my two questions.

Arun Jayaram, Credit Suisse.

Bill I just wanted to talk a little bit about the increase in the Eagle Ford resource -- you added I believe 1,600 incremental well locations. Can you maybe quantify what drove that between down spacing, versus opening up new parts of the play as you've done additional delineation drilling?

Yes, Arun, that is a good question. I would say the majority of it is really due to down spacing at this time. And that is something we took great care in technically and used multiple down spacing pilots to determine these additional locations, and so we found out certainly that it's very variable across the field.

And so -- but the average is about 40 acre spacing between wells and that gives us the optimal net present value. We have a slide in the IR chart -- in the IR slides that show how the net present value on a per acre basis has increased over time as we've down spaced and added additional potential. So it's a really good solid number but really most of the increase is due to down spacing.

Okay. And then Bill, as you shift towards 2014 and 2015, is the development plan now going to be just 16 wells per section? Is that how you will plan to develop things going forward?

Well, it's variable across the field. So it's not a standard thing. It really varies from lease to lease to lease. But certainly I think on an average 40 acre spacing is how we are proceeding ahead at this time, and that looks like that will generate the best returns and the best NPV.

Okay. And then my follow-up is just on the Leonard, I believe you guys mentioned optimism to do 8 to 10 wells per section in the A interval. Can you just comment on some of your early appraisal testing in the Leonard?

Yes, that's a good question, Arun. Saying it's still early is a good point because we're still testing multiple spacing patterns there as well.

We do believe eight is certainly a very achievable number. We're going to be testing 10s in the A zone and we still have additional zones there to test as well. So we are very encouraged by what we are seeing in the Leonard play based on our latest results, and so we're optimistic that the spacing pattern will prove itself out here as we go forward.

Thank you.

This does conclude today's question-and-answer session. I'd like to turn the call back to Bill Thomas for any additional or closing remarks.

I just want to thank everybody for joining the call this morning and we look forward to a great 2014. Thank you.

This does conclude today's conference. We thank you for your participation.