Good day, everyone, and welcome to the EOG Resources 4th 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 4th quarter and full year 2013 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 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 reserve reporting guidelines. We incorporate by reference the cautionary note to U. S. Investors that appears at the bottom of our press release and Investor Relations page on 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 Moira Baldwin, Vice 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 Q1 and full year 2014 in yesterday's press release. This morning, we'll discuss topics in the following order. I'll start with Q4 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 Q4 2013 EOG reported net income of $580,000,000 or $2.12 per 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 Q4 2013 adjusted net income was $548,000,000 or $2 per share. For the full year of 2013, EOG reported net income of $2,200,000,000 or $8.04 per share. On an as adjusted basis, full year net income was $2,250,000,000 or 8 point $2.2 per share.
For investors who follow the practice of focusing on non GAAP discretionary cash flow, EOG's discretionary cash flow for the 4th quarter was $1,900,000,000 Using the same methodology for the full year 2013, EOG's discretionary cash flow was $7,400,000,000 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 $841,000,000 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 percent over 2012. This is a 44% average increase over the last 3 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 U.
S. 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 Q4 and full year unit costs were lower than expected. The combination of increased growth from high margin oil with a decreasing 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 20 12.
We updated the ROE and ROCE charts in our IR presentation on Pages 1415 showing our improving metrics and a comparison of our results to our peers. While I'll discuss 20 14 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 2 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 13 was the topic of 1 of is the topic of 1 of is the topic of one of today's biggest news items is Eagle Ford For the 3rd time since the EOG discovered oil in the play in 2010, we have increased the net reserve potential. We now estimate EOG's total net reserve potential on our acreage to be 3,200,000,000 barrels of oil equivalent. That's a 45% increase from the previous 2,200,000,000 barrels of oil equivalent estimate. This is a great example of the value of EOG's exploration focus and organic growth strategy. By being 1st mover and capturing the best assets, we're 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 2 aspects. Number 1, improving well productivity in the West. Prior to 2013, we had 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 Q4, 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'll talk about 1 Eagle Ford oil play as both the East and Western areas are contributing more or less proportionally to the remaining reserve potential. And number 2, improving reserve recovery and maximizing NPV. Our goal was to determine the optimum well spacing while increasing well productivity and decreasing well cost.
We'll continue to work on these two goals. What we concluded was, 1st, our down spacing efforts proved even more successful than we have 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. 2nd, as a result, we have approximately 7,200 net locations. Taking into account 1200 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 3rd, 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 recoverable reserves for the Eagle Ford to 3,200,000,000 barrels of oil equivalent. With 4 years of production history from our early wells and a database of over 1200 EOG wells, we're confident in the long term performance and potential reserve estimate of the Eagle Ford. Overall performance in the field continues to surpass our expectations.
In addition, we've reached an efficient manufacturing mode in Eagle Ford. While we still have further efficiency and cost reduction goals, we've now reached the point of optimal 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 five 20 net wells, up from 4 66 net wells in 2013. We currently have 26 rigs operating in the flight. 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 DURs, reduced costs and through down spacing identified an additional 1600 net drilling locations. Although we are increasing the well 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 Force completions that dramatically improved well productivity and individual EURs. These enhancements and the ongoing implementation of cost saving measures, including the use of EOG 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 5 years ago. Recent core wells are the Wayzata 30-3230H and thirty one-3230H, which began production at 2,5102,540 barrels of oil per day respectively. We have 59% working interest in these wells.
The ones that are 35-1920H had an initial production rate of 2,240 barrels of oil per day with 1,200,000 cubic feet a day of rich natural gas. We have 60% working interest in this Montreal County well. Using the same improved completion techniques in our Antelope Extension area, we are seeing similar enhanced IP rates and EURs. The Hawkeye-two-two thousand five hundred and one H had an initial production rate of 2,075 barrels of oil per day with 3,800,000 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 will continue to down space in both areas and plan to operate a 6 rig drilling program. We have existing oil and pipeline infrastructure within the core and with the integration of EOG Sand into our Bakken operations, we will continue our focus on reducing well cost 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 2 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 3rd 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 seventy 3,000 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 our Leonard acreage and we're testing multiple targets and spacing patterns both between wells and also between zones. 2 recent Leonard wells in Lea County, New Mexico came online with very strong oil production. The Vaca 24 FedComm 5H began production last month at 15 20 barrels of oil per day with 2 65 barrels per day of NGLs and 1,500,000 cubic feet a day of natural gas.
The Vaca 24 FedComm 6H had an IP rate of 13.80 barrels of oil per day with 170 barrels per day of NGLs and 9.35 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'll now address reserve replacement and finding cost. In total, we replaced 2 64% 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, the Gaulier and McNaughton did an independent engineering analysis of our reserves and their estimate was within 5 percent of our internal estimate. Their analysis covered about 82% of our proved reserves this year. Please see the schedules accompanying earnings press release for the calculation of reserve replacement and finding cost. I'll now turn it back over to Bill.
Thanks, Billing. Regarding new plays, we've 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 mid spring operations, we're working with our partner rail companies. We have a strong emphasis on safety in our crude by rail operations.
On our crude by 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, and oil production continues to increase at peer leading growth rates. EOG has a long life inventory of crude oil and liquid 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 beyond.
I'll now turn it over to Tim Driggers to discuss financials and capital structure. Thanks, Bill. Capitalized interest for the quarter was $15,000,000 For the Q4 2013, total exploration and development expenditures were $1,600,000,000 excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $93,000,000 There were $28,000,000 of acquisitions during the quarter. For the full year 2013, capitalized interest was 49,000,000 the full year, total exploration and development expenditures were $6,700,000,000 excluding acquisitions and asset retirement obligation.
In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $364,000,000 For the full year, total capital expenditures for all categories were $7,100,000,000 excluding acquisitions. We ended the year below our guidance. Total acquisitions for the year were $120,000,000 During the quarter, net cash provided by operating activities exceeded financing and investing cash outflows. We paid off a $400,000,000 bond that matured in October. For the year, total proceeds from asset sales were $761,000,000 compared to the goal of $550,000,000 The effective tax rate for the 4th quarter was 37% and the deferred tax ratio was 64%.
We announced a dividend increase of 33% and a 2 for 1 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 earnings press release for the Q1 and full year 2014. Our CapEx estimate for the full year is $8,100,000,000 to $8,300,000,000 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 Q1 and full year, the effective tax rate is estimated to be 35% to 40%. They've also provided an estimated range of the dollar amount of current taxes that we expect to record during the Q1 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 dollars For the second half of twenty fourteen, 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 counterparty to do so.
For June 1 through August 31, 2014, we had 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 twenty fourteen, 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 twenty fifteen, 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 on exercise options. For January 1 through December 31, 2015, we have 175,000 millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters Btu 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 counterparties 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 for each month for the period March 1 through December 31, 2014. For 2015, if counterparties exercised Allscripts options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBTU 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 U. S. Oil production data, but it looks like the rate of growth in 2013 slowed compared to 2012 and we expect this trend to continue in subsequent years. The October November EIA monthly data indicate the rate of annualized production growth was approximately 760,000 barrels per day compared to 1,040,000 barrels per day for the same period in 2012.
We're still bullish regarding U. S. Oil prices because of slowing domestic oil growth and we are not particularly concerned about a surplus of U. S. Light sweet oil.
Regarding North American 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 the 4.50 level in 2014 2015. On the plus side, we've taken advantage of some of the recent price box to layer in hedges. For our 2014 business plan is as follow.
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 later return opportunities to pursue. The greatest 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 6th 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 20 14 because we don't see a change in the gas oversupply picture until the 2017, 2018 timeframe. I want to leave you with some important summary points.
1st, 2013 was an excellent year for EOG, particularly in our 3 key plays, the Eagle Ford, Bakken and Leonard. In the Eagle Ford, we moved beyond an assembly line of operation to a high 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 the well productivity. In the Permian Basin, we're 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. 2nd, in terms of capital discipline, we boosted boosted our financial returns in 2013, while deleveraging the balance sheet. We generated strong ROE and ROCE numbers last year, 6% 12 percent 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.
3rd, 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 U. S. Lower 48.
With our large high quality drilling inventory, we expect EOG to be one of the largest crude oil producers in the U. S. By 2017. 4th, 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 dip. 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 we'll go to Q and A.
Thank you. The question and answer session will be conducted And we'll go first to Leo Mariani with RBC.
Hey, guys. 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? 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 found that it's been the spacing is very variable due to different geology, different faulting situations and there's different things across the field that we have to deal with. Some places we can drill wells that's 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. And 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. And 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 fairly 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. And 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 sort of 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. Yes, 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 on 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 price markets.
Okay. That's really helpful. Thanks guys.
We'll go next to Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, everybody. Bill, I wonder if I could go back to the EUR 450 EUR average. 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 1st part of the 12 years by log that you've got? In other words, are you drilling better wells first and the on that average the lower and the lesser wells will be later on program? And if so, how should we think about your medium term growth outlook? Can I have 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're certainly not front end loaded with the best wells in the East and then later on we won't drill as good a 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 and 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, why is that not a structure that EOG would be interested in? And I'll leave it at that. Thanks.
Yes, Doug. On midstream, we're very, very selective on how we spend our midstream dollars. And the midstream dollars we have allocated this year particularly are giving 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're 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's easy to understand.
And 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 though, why then wouldn't you include the midstream cost when you look at your well economics
if that's the case? Well, I mean certainly the midstream costs are part of the whole picture, but really we really focus on getting the wells drilled and getting the direct return of those the wells at a maximum. We're focused on that. And then we're 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 ROEC numbers.
So midstream really helps us do that.
Appreciate the answers Bill. Thank you very much.
We'll go next to Charles Meade with Johnson Rice.
Good morning, everyone. 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 that this work, but their testing offsets down to 175 feet, which would get you close to about 20 acre space. And I'm wondering, can you share what the closest offsets you guys maybe have planned for 2014 or what's the closest you've done to date?
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 pushed them pretty close together start destroying value. So these pilot programs that we 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 in Ward and Loving where you've seen higher oil cuts in that Wolfcamp play and if that's an option for you and it's part of your 2014 plans?
Yes. For the Delaware Wolfcamp, our acreage is located in kind of 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 Lee County that we believe are perspective for the Delaware Wolfcamp. And you're correct, it does get a bit oilier as you knew that way. So in 2014 though, we're really probably just focused on this Central Reeves County area and then we'll be testing additional Wolfcamp potential maybe later in the year in 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. We'll stay tuned on that.
We'll take our next question from Matt Portillo with TPH.
Good morning. 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 depth? 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're 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're 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're 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 on to it. We're 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.
We'll go next to Amir Arif with Stifel.
Thanks. Good morning, guys. First question really on the Leonard Wolfcamp play. I know it's early days there, but I was 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 comfort on resources?
Yes. Nir on our Leonard play, we're still doing some testing there as you can 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 the 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.
And then just a follow-up question on that CapEx. The $900,000,000 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 2 thirds of that is going to be in the Eagle Ford and that's on lease 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 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, SWD systems, water reuse facilities and that also includes artificial lift.
We're putting that on quite a number of wells this year. So all that just to reduce our transportation, our LOE, realized higher prices, all long term benefits for our earnings.
Thank you.
We'll take our next question from Joe Altman with JPMorgan.
Thank you. Good morning, everybody.
Good morning.
Hey, Bill, in terms of the increase in the Eagle Ford EUR and Resource, what drove your decision to increase the EUR per well on 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 of a lot of strong historical data. We have over 1200 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 dramatic increases in potential 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 got a lot of confidence in that. And as we go forward, we're hopeful that we'll be able to continue to improve the well productivity, but we certainly have not proven that yet.
But we're 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're 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're 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 play. 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're 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.
We'll go next to Pierce Hammond with Simmons Yes, Bill, some other operators in the Eagle Ford you 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, Pierce. We do have that. We've recognized that on a decent portion of our acreage and that is certainly an option that we're looking at and exploring and may do some testing on that as we go forward to see if that part 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're 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. We'll go next to Bob Brackett with Bernstein.
Hi. I'll do a follow-up. You mentioned the 3 0 Vicksburg wet gas wells. Are those conventional pipe sand targets? Or are there any sort of shale plays you're chasing down there?
Yes, Bob. Those are really conventional plays. They're the typical Gulf Coast.
Millardarski.
Yes. I'd say they're Millardarsky, mostly Millardarsky type reservoirs. And so they're 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're very, very focused of course right now on the oily type plays. And we're focused on 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're targeting only plays that we think that could generate after tax rate to 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're the kind of quality players that we want to invest money in as we go forward. But we're confident that EOG is 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 additional resource potential for the company as we go forward.
Thanks. We'll
go next to Joe Magner with Macquarie.
Good morning. With all the updates provided on the Eagle Ford, I noticed that references to specific recovery factors weren't in the presentation anymore. 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 in place and or those recovery rates?
Yes, Joe that's a very good question. And the recovery factor is a work in progress and we're certainly not seeing any decrease of any oil in place. We're learning about these resource reservoirs, learning more all 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 prospectivity 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're 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. Of course, the 7,200 locations that we announced or talked about are actual sticks on the 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 And but those areas at this moment, we feel like fall below our rate of return cutoff.
And although they would be productive, they're not wouldn't fit their way into our portfolio right now. So we've kind of put a cutoff on rate of return. Anything less than the 60% ATAX rate of return is not included in the 7,200 locations. So there could be additional upside. We're hopeful that we'll be able to continue to reduce costs and improve well productivity in all the areas and specifically in the areas that are a bit more lower return.
Okay. Thank you.
We'll take our next question from David Heikkinen with Heikkinen Energy Advisors.
Good morning. 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 should we 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're right David. This what we're 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 saying that, yes, as we drill more wells, we have a need for additional sand and we're 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 a well in 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? Do you think?
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 across the board for EOG.
Okay. Thanks. That was a good question.
We'll take our next question from Arun Jayaram with Credit Suisse.
Good morning, Bill.
Hello, Arun.
Hey, Bill, I just wanted to talk a little bit about the increase in the Eagle Ford resource. You added, I believe, 1600 incremental well locations. Can you maybe quantify what drove that between down spacing versus opening up new parts of the plays you've done additional delineation drilling?
Yes, Arun that's 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 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 now based 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 2015 is the development plan now going to be just 16 wells per section? Is that how you 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 acres 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 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, it's a good question, Arun. And saying it's still early is a good point because we're still testing multiple spacing patterns there as well. We do believe 8 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're very encouraged by what we're seeing in the linear play based on our latest results.
And so we're optimistic that the spacing pattern will prove itself out here as we go forward.
Okay. 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.