Hey everyone, welcome to EOG Resources' first quarter 2014 earnings results conference call. As a reminder, this conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the conference over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead.
Thanks, April. Good morning. I'm Tim Driggers, CFO. Thanks for joining us. We hope everyone has seen the press release announcing first quarter 2014 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 in EOG's SEC filings. We incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies, in their filings with the SEC, to disclose not only proved reserves, but also probable reserves, as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's 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 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, and Moira Baldwin, Vice President, IR. An updated IR presentation was posted to our website yesterday evening. We included second quarter and full year guidance in yesterday's press release. This morning, we'll discuss topics in the following order. I'll first discuss our 2014 first quarter net income and discretionary cash flow. Then Bill Thomas and Billy Helms will provide operational results. I'll then review EOG's financials and capital structure. Finally, Bill Thomas will cover EOG's macro view and hedge position and provide concluding remarks.
As outlined in our press release, for the first quarter 2014, EOG reported net income of $661 million, or $1.21 per share. EOG's first quarter 2014 adjusted non-GAAP net income, which eliminates the mark-to-market impacts and certain non-recurring items as outlined in the press release, was $768 million, or $1.40 per share. Non-GAAP discretionary cash flow for the first quarter was $2.2 billion. At March 31, 2014, the debt to total cap ratio was 27%. Due to a build-up of cash on the balance sheet, the net debt to total cap ratio was 21%, down from 23% at December 31, 2013. I'll now turn it over to Bill Thomas to discuss operational results and key plays.
Thanks, Tim. We started 2014 by delivering excellent first quarter results. Our total oil production was up 42% year-over-year. In the U.S., oil production was up 45% year-over-year and 10% sequentially. Total company production increased 18% compared to the first quarter 2013. Based on these first quarter production results and our confidence in the remainder of the year, we are raising our full year 2014 oil production growth estimate from 27%-29% and total growth estimates from 11.5%-12%. Our actual unit cost came in lower than guidance, particularly for LOE and transportation, with DD&A also at the low end.
In yesterday's press release, we announced we're adding 735 high rate of return net drilling locations in the sweet spots of four plays, with estimated reserve potential of 770 million barrels of oil equivalent gross or 400 million barrels of oil equivalent net to EOG. We've identified approximately 10 total years of drilling inventory in these four plays. Two of these plays are in the DJ Basin, primarily in Laramie County, Wyoming, and extending into Weld County, Colorado. I'll first discuss the Codell play. This is a sandstone play that we have thoroughly defined geologically and with recent horizontal drilling results. We've identified the best acreage and are making very repeatable, consistent wells.
We have 72,000 net prospective acres in the sweet spot of this play in Laramie County, Wyoming, where we've identified 225 net well locations with estimated reserve potential of 125 million barrels of oil equivalent net to EOG. Last year, we drilled three net Codell wells, and this year, we completed four net wells. All of them have long 9,000-foot laterals and IPs in excess of 1,000 barrels of oil per day. The wells average 78% 36-degree API oil. We noted a few of these wells in our press release. This year, we plan to drill 26 net wells. These wells have an expected average gross EUR of 695 MBOE per well. Once we optimize well productivity through EOG technology and sourcing of completion materials and meet our target well cost of $7.3 million, this play should yield after-tax rates of returns greater than 100%.
The second play in the DJ Basin is the Niobrara Shale in Laramie County, Wyoming, and Weld County, Colorado, where we have 50,000 net acres in the sweet spot of this play. We have studied the Niobrara for a number of years and have found this part of the basin is quite consistent. We drilled three net wells in the Niobrara last year. The reserves are 71% 35-degree API oil with expected average gross EURs of 430 MBOE per well. Target well costs for a 9,000-foot lateral are $9 million due to larger fracs and yield a direct after-tax rate of return of approximately 40%. We are currently completing our first long lateral. As we've done in all our resource plays, we expect to improve well productivity and decrease well costs and improve the rates of return on this play. We see plenty of room for upside.
We've identified 235 net drilling locations with an estimated net reserve potential of 85 million barrels of oil equivalent. We plan to drill a total of 39 net wells in the DJ this year, 26 in the Codell formation, and 13 in the Niobrara. We are currently operating a two-rig drilling program and plan to add a third rig later this month. We expect crude oil production growth from these two plays beginning this year. We also highlighted two plays in the Powder River Basin. In the Powder River Parkman, we have 30,000 net prospective acres of high-quality pay. Last year, we drilled 10 net wells, and this year, so far, we've completed six net wells. Initial production rates from shorter length laterals exceed 1,000 barrels of oil per day, and the 90-day cumulative oil production looks good. We expect results from longer laterals to be even better.
The 7,300-foot lateral wells have expected average gross EURs of 850 MBOE per well, of which 69% is 41-degree API oil. With $5 million completed well costs, direct after-tax rate of returns exceed 100%, making the Parkman the highest rate of return play of the four discussed today. We are already seeing improved drilling times and cost savings with regard to completion materials. Estimated net potential reserves are 75 million barrels of oil equivalent. We have identified 115 net drilling locations. Much like the Niobrara, EOG has been drilling in the Turner formation for several years, so this play is not so new, but our results have improved significantly. Today, we have a much better understanding of the geology in the area and are now drilling in the best areas of the play. Through longer laterals and focused targeting, our wells are improving.
They are yielding higher EURs and higher oil mix. The wells we drilled in 2011 had 26% oil mix versus 34% today. Last year, we drilled eight net wells. Lateral lengths in the Turner will vary from 4,600 to 9,000 feet. The average gross EUR for an 8,200-foot lateral is 860 MBOE per well. The returns here average 100% direct after-tax, with a $7.5 million completed well cost. The estimated potential reserves are 115 million barrels of oil equivalent net on our 63,000 net acres in the Turner. We have identified 160 net drilling locations. Running a two-rig program, we plan to drill a total of 34 net wells in the Powder River this year, 28 in the Parkman formation and six in the Turner. Regarding exploration, we continue to actively search for additional new plays.
As we previously mentioned, a new discovery the size of our estimated 3.2 billion barrels equivalent net Eagle Ford potential reserves would be difficult to repeat. However, the plays announced in yesterday's press release are significant, and three of the four plays are oil plays with very strong direct after-tax rates of return. We are currently completing our first long lateral in the Niobrara and are optimistic on the overall economics of this play. We plan to continue to add these types of high rate of return both on oil plays to our portfolio. We set a high threshold at EOG with plays like the Eagle Ford, Bakken, and Leonard. Other plays that compete for capital require the same rate of return metrics. The plays we've announced today are certainly in that category. In the Eagle Ford, we've increased activity compared to last year.
We're on track to drill 520 net wells this year. We're currently running 26 rigs in the play. The Eagle Ford was the biggest contributor to our first-quarter oil growth and the reason we exceeded our first-quarter oil production guidance. We continue to make improvements in well productivity. As our press release cited, a number of recent Eagle Ford wells have IP rates in excess of 4,000 barrels of oil per day. The Eagle Ford continues to be our largest growth asset with the highest after-tax rates of return. By midyear, the vast majority of our drilling obligations for 2014 to hold our 564 net thousand acres position in the crude oil w indow will be essentially complete, giving us much more flexibility to efficiently manage our drilling and production operations. We've modeled our Eagle Ford production for the next 10 years.
If we increase this year's 520 net wells by a modest amount and hold that number flat through 2024, our Eagle Ford oil volumes increase every year. The Eagle Ford will throw off free cash flow this year and every year through 2024. In our model, we haven't assumed any improvements in well productivity or well costs. We've maintained the status quo. We've talked about the 6,000 net remaining locations on our acreage. We use a 60% direct after-tax rate of return cutoff point in moving these locations into our inventory. We still have a large number of locations that don't meet this threshold. We continue to make improvements in well productivity and economics and are working to move these locations into our drilling inventory. I'll now turn it over to Billy Helms to discuss other areas.
Thanks, Bill. Last year, we increased the drilling density in the Bakken from two to four wells per spacing unit. Due to tighter spacing and configuration of leases, the majority of our 2013 drilling in the Core and Antelope extension was based on 1,300 feet between wells. With successful 1,300-foot spacing across our acreage, we are now testing 700 feet and tighter spacing between wells in the Core and Antelope extension areas. Hoping to repeat what EOG achieved in the Eagle Ford, we will continually test down spacing until we've maximized the net present value in the overall play. We are early in the life of these tests. We will monitor production history to determine optimal spacing for development. If tighter spacing proves successful, a number of years would be added to our Bakken drilling inventory.
The majority of our 2014 development program is in the Core area, where we already have pad drilling and completion infrastructure. We are currently operating six rigs in the Williston Basin, with plans to add a seventh this summer. During the first quarter, we completed a number of wells on our Core acreage. Our Wayzetta 28-1424H, 29-1424H, and 38-1424H were completed at initial oil rates of 1,060, 1,295, and 1,000 barrels of oil per day, with 105, 125, and 100 barrels per day of NGLs, respectively. These wells were drilled off the same pad. Less than 2,000 feet from these wells, the Wayzetta 39-1424H and 40-1424H were completed at 1,760 and 2,220 barrels of oil per day with 170 and 215 barrels per day of NGLs, respectively.
In the Permian, our 2014 activity is focused in the Delaware Basin, where we've more than doubled the number of wells we plan to drill this year compared to last year's total. In the Leonard Shale, we continue to test various spacing patterns across our acreage to determine the optimal development program. Recent tests were drilled with 660 feet or 80 acres and 430 feet spacing, 60 acres between the wells. The Dillon 31#1H, #2H, and #3H were drilled with 430 feet between wells. This is our most dense same-zone spacing test to date. The wells came online with 1,225, 1,395, and 1,315 barrels of oil per day, respectively. Based on these successful results, we plan to test tighter spacing, both between wells and across zones throughout our 73,000 net acre position. We are currently testing 32-acre spacing across different zones.
Through an active development program, we continue to better define our acreage. In the Delaware Wolfcamp, we've drilled eight wells this year. The wells produce at lower initial oil rate than the Leonard but have a very flat production profile, which generates a very strong after-tax rate of return. To date, we have tested three liquids-rich zones within the Delaware Basin Wolfcamp and are testing various spacing patterns as tight as 50 acres between wells as we develop these zones. We're seeing improved well productivity in both the Leonard and Wolfcamp plays. Because we've now moved into development mode, our drilling operations are more efficient, resulting in decreased drilling days and cost.
We are currently operating a four-rig program in the basin. Completion costs have also decreased with the integration of EOG-sourced sand and other materials. Further enhancements in our geoscience and completions work continue to improve our two Delaware Basin plays. We are confident we'll realize ongoing improvements and additional success in the basin. In Trinidad, we have a three-well development drilling program planned for 2014, which will allow us to maintain flat natural gas production in later years. In the East Irish Sea, the Conway prospect is still expected to be online in late 2014. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, Billy. For the first quarter, capitalized interest was $14.2 million. Total cash exploration and development expenditures were $1.8 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $166 million. EOG made $4 million of acquisitions during the quarter. During the first quarter, net cash provided by operating activities exceeded financing and investing cash outflows. At the end of March, total debt outstanding was $5.9 billion. At March 31, we had $1.7 billion of cash on hand. The effective tax rate for the first quarter was 36%, and the deferred tax ratio was 63%. Yesterday, we included a guidance table with the earnings press release for the second quarter and full year 2014. For the second quarter and full year, the effective tax rate is estimated to be 35%-40%.
We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. Now I'll turn it back to Bill to provide EOG's views regarding the macro environment, hedging, and operations.
Thanks, Tim. With regard to oil, we believe we are in a continued tight supply-demand situation globally. Last year, the U.S. was the largest oil growth area in the world. The rate of oil growth in the U.S. is beginning to slow, and 2014 non-OPEC supplies have been revised downward, while global demand for oil from non-OECD countries continues to increase. We expect to see strong oil prices for the remainder of this year, barring a global recession. Regarding North America gas, taking into account current storage levels and assuming normal weather, we expect prices to remain stable in the $4.50-$5 range through the summer of 2014. This is with the caveat that E&P companies stay disciplined at these gas prices and don't ramp up drilling activity. Once we enter the storage withdrawal season, we expect to see upward pressure on gas prices.
Late next year, the first LNG plant at Sabine Pass is scheduled to begin exporting natural gas. This could signal the beginning of a structural change in natural gas demand. In 2016, a number of new petrochemical plants utilizing natural gas feedstock are expected to be commissioned. The remainder of the LNG commission plants are scheduled for startup in 2018. For May 2014, EOG has crude oil financial price swap contracts in place for 181,000 barrels of oil per day at a weighted average price of $96.55 per barrel. For June 2014, EOG has crude oil financial price swap contracts in place for 171,000 barrels of oil per day at a weighted average price of $96.35 per barrel.
For the period July 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 74,000 barrels of oil per day at a weighted average price of $95.37 per barrel. These numbers exclude options that are exercisable by our counterparties. For the period June 1 to December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 million British thermal units per day at a weighted average price of $4.55 per million British thermal units. For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtu per day at a weighted average price of $4.51 per MMBtu. These numbers exclude options that are exercisable by our counterparties. As it relates to EOG and the overall macro environment, EOG's marketing and midstream investments again proved invaluable in the first quarter.
In the U.S., EOG realizations averaged $1.97 over West Texas Intermediate index prices. However, we continue to sell the majority of our oil index off LLS pricing. Let me conclude. There are five important takeaways from this call. First, EOG continues to demonstrate its ability to organically grow. Yesterday, we announced the addition of 735 high rate of return net drilling locations with 10 years of drilling inventory from the sweet spots of four high-quality, high oil content onshore U.S. plays. This is proof of our very disciplined approach to adding new plays. First, we identify the potential. Second, we capture the acreage. Third, we apply technology to the play until results meet our rate of return criteria. What's significant is that these are predominantly oil plays that compare favorably with our current highest rate of return plays.
Our goal is to increase EOG's ROE and ROCE, and by adding these high rate of return plays, we are doing so. Second, we increased our oil production growth target for the year from 27% to 29%. We've said all along that EOG has the best horizontal crude oil assets in the U.S., and they continue to deliver. Third, the Eagle Ford continues to demonstrate improvements in well productivity from ongoing refinements and completion techniques. In modeling production from the Eagle Ford, we are on a growth track for the next 10 years. I want to repeat, in modeling production from the Eagle Ford, we are on a growth track for the next 10 years before we even begin to see production level out. Fourth, we are testing additional down spacing patterns in the Bakken, Leonard, and Wolfcamp plays.
We will continue to test down spacing until we've reached maximum optimization for each of these plays. To wrap it up, EOG turned in another outstanding quarter. Our U.S. oil plays continue to deliver. We continue to make improvements in completions, even in our most mature plays, the Eagle Ford and Bakken. EOG is running like a finely tuned high-performance engine. Thanks for listening, and now we'll go to Q&A.
Thank you. If you would like to ask a question, simply press the star key followed by the digit one on your telephone keypad. Also, if you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touch-tone telephone to ask a question. If you find your questions have been answered, you may remove yourself from the queue by pressing star two. We'll pause for just a moment to give everyone an opportunity to signal for questions. We'll first hear from Douglas Leggate of Bank of America, Merrill Lynch.
Hi. Yeah, good morning, everybody. I love the pronunciation on these calls. Thanks for all the color, Bill, on the new plays. My question's on slide nine in your presentation. You show how they stack up on a relative basis with the IRRs. What I'm really trying to understand is, how should we think about capital allocation here as we go forward, as you grow your cash flow? Specifically, I wonder if you could address the 60% threshold in the Eagle Ford that you haven't included in your inventory. What's it going to take to get those into a competitive position, and how would that theoretically change your capital allocation? I've got a follow-up, please.
Yeah, Doug. On the capital allocation as we go forward, we've given guidance in the past, and we want to reiterate this. Number one, the first priority is to the dividend, and we want to continue our 15-year history of a healthy dividend increase. Next, the focus is on reinvesting that capital back into the highest rate of return plays. Now we have more of those to offer up. First, certainly, the Eagle Ford is the highest rate of return play we have, and so the biggest amount of capital will go to that. The Bakken Three Forks next, the Delaware Basin Leonard, and now we have opportunities to reinvest at high returns in the DJ Codell, the Parkman and Turner play. That's where we will focus our capital as we go forward.
On the Eagle Ford and the remaining inventory that we haven't included, because it has not made our 60% after-tax rate of return cutoff, we are focused on that, and we have a pretty significant number of wells that we could drill. We're doing like we do in all of our plays. We're working on the cost to reduce the cost as we go forward. I think most importantly, we continue to see improvements in the well completions, in the frack technology. We're hopeful that we go forward that those wells will get those returns up above 60%. Down the road, as the years go down the road, we'll be able to include those in our inventory. The reason we haven't listed those right now as part of our 7,200 well locations is we're just not really focused on those.
We're not drilling a lot of those right now, so we just didn't include them.
It's pretty clear. My follow-up hopefully is quite quick. I assume by the fact that you've revealed these four additional plays that you're done leasing. I'm just curious as to, do you have any additional opportunities to expand your position, or have you moved on from those now in terms of new acreage? I'll leave it there. Thanks.
Yeah. On the new plays, we wouldn't talk about them unless we had felt like that we captured the sweet spots. We've done a very thorough geological evaluation. We have a lot of data. We have really narrowed down the acreage to what we believe are the highest return areas of the plays. The acreage numbers listed for each play are really the sweet spots where we think we have the best chance to make the best wells. We think we've captured that. There's probably additional zones, there's probably additional areas that would be productive, but we're really focused on the sweet spots, and we have those captured.
Appreciate the answers. Thanks, Bill.
Next, we'll hear from Leo Mariani of RBC.
Hey, guys. You made some interesting comments about the Eagle Ford here. Wanted to delve a little bit more into your comment about holding the Eagle Ford by production by mid 2014. Once you guys are able to achieve that, what type of efficiency gains do you think you'll be able to capture through the drilling program? Maybe you can speak to how you might manage the development differently post that.
Yeah, Leo. In the first quarter and then some in the second quarter, we drilled a lot of retention wells. That means they're the first wells on a unit to hold that acreage. As we complete that process, it gives us the flexibility to go back in and really focus on each unit and begin to pad drill wells on pads, multiple wells on pads, again, to optimize our costs, to continue to focus on making the better wells and getting the spacing right and the completions right. Just able to, I think, have more efficiency and perform better as we go forward.
Any kind of big picture quantification? Could we see a 5%-10% efficiency gain as a result over the next few years?
Yeah, Leo, I'm going to let Gary Thomas address that question.
Yes, Leo. With us now having the majority of our acreage HBP here second half and ongoing, not having to spend money on roads, location quite so much. Also, the facilities, gathering, all that will be much reduced. It just improves our overall operations. We drill some of these wells in as little as 5.3 days, so our days per well will continue to decline with pad drilling. We'll see certainly the 5%-10% cost reduction.
Okay. That's helpful. I guess just quickly on the DJ Basin here. You obviously talked about some sweet spots. I guess historically, there's been a decent amount of variability in parts of the DJ in both the Codell and the Niobrara. I guess, you laid out some of the wells that you guys have drilled here. What are you guys using for well controls in your own programs? Are there other industry wells out there and other data that you're seeing that convinces you that the acreage positions you've laid out are not all that variable at this point?
Yes, Leo. We have quite a bit of subsurface well data. I believe it's about 130 wells that are located near our acreage or on our acreage that have defined these sweet spots in the Codell and in the Niobrara also. We believe you're correct. The DJ Basin historically has been very variable. There are sweet spots that really set up by the basin architecture, and it varies. We really believe with our good results that we've had from the drilling in this area and with our geologic mapping that we have a spot, a sweet spot that will give us very consistent results. That's why we're focused on these areas.
Thanks, guys.
Our next question comes from Brian Singer of Goldman Sachs.
Thank you. Good morning.
Morning, Brian.
I wanted to try to juxtapose a little some of the macro comments you made with just how you're thinking about your investment and growth at the EOG level. Maybe we'll start with gas here first. The outlook you delivered, I feel like is a little bit more bullish on natural gas than what you've delivered previously. Obviously, weather has probably played a role in that. You highlighted that it is contingent on producers being disciplined. Given your free cash flow and the gassy acreage you identify on one of your slides, how does EOG stay disciplined, and what would it take, if anything, to allocate some capital to gas? Not necessarily taking out of oil, but just allocating more capital to gas.
Yeah, Brian. I think we're mildly bullish on near term gas, that we think it'll be in the $4.50 to $5 range. We are really not prepared and we really don't want to invest any additional money at this time in any dry gas drilling. The reason is because we want to really see what the long-term gas price is going to do, and that's going to depend a lot on what operators do at $4.50 and $5 gas prices. There's so much gas potential out there that it could easily drill a lot of wells and the price of gas would decrease. We really want to wait and be patient on that.
You're right, we have tremendous amounts of very high-quality gas assets, and we really would need $5.50 or better price, and we would need to believe that that $5.50 or better price would hang in there for multiple years before we'd even think about drilling dry gas.
Got it. Thanks. My follow-up is going to oil. Big picture, you highlight your accelerating oil production per year on a barrel a day basis. I think it's slide 14 of your presentation. The midpoint of this year's guidance is about 64,000 barrels a day of growth. If we exclude the impact of the Conway project, do you expect that this level will continue to accelerate in future years? How does that juxtapose with your more optimistic macro view in terms of U.S. light oil prices?
Well, we remain bullish on light oil prices. Certainly, as we talked about from the macro view, we continue to see a tight supply worldwide, we do not see any pending crisis on overloading the system, the U.S. system, the refinery system, to be able to process all that oil. Our focus is going to be to reinvest back into the highest return plays. The highest return plays, we fully believe in the next few years, will be our oil plays. We will continue to, as they prove up and continue to give us high rate of returns, we will continue to add capital back into those. Of course, the focus will be Eagle Ford, Bakken. Now we have a good set of plays that we have a lot of opportunity to reinvest in.
Our focus is going to be oil for quite some time.
You likely won't need 64,000 barrels a day of oil growth per year to have above tier average type growth. Do you see that 64 rising as a rate of growth?
No, I wouldn't say it would rise. We think it'll be fairly consistent.
Great. Thank you.
Next, we'll hear from Charles Meade of Johnson Rice.
Yes, good morning, thanks for taking my question. Bill, when you were talking about those four new plays, you talked about applying technology to the plays, and I can think of at least three things that that might mean. Might be the D&C cost, it could be high-grading the acreage and locations, and it could be improvement of completion designs and associated well productivity. Can you give a sense for at least maybe the newer plays, the Codell and perhaps the Parkman? What progress have you made that brought those into the portfolio, and what do you think the opportunity is going to be for continued improvement on those dimensions going forward?
Charles, that's a good question. It starts with the sweet spot. We drill quite a few Parkman wells, with that data and the other geologic data available, we've really narrowed down this acreage in the Parkman to the very sweetest spot. We're focused on the best pay. That is a start. Then we brought in the completion technology. As we've learned on all these horizontal plays and shale plays, the completion technology continues to advance, and we're now seeing, even in the more conventional rocks, like sandstones, that the improvements that we've seen in the shale plays also apply to those, too. The completion process, I think, has allowed us to increase the initial productions on the rates on the wells and the reserve potential on the wells.
That, along with EOG being able to come in and apply our kind of shale cost reduction efforts in these plays to reduce the overall cost, it's really improved the rates and returns on all these plays. It's a threefold thing, really. It really fits into EOG's strength.
Got it. Then if I could go back and try one more time on the Eagle Ford inventory question. The inventory that's not in your number right now, is this in the oily window where perhaps the reservoir's not as productive, or is this down dip in gassier acreage that maybe comes into the inventory when gas is at $4.50 or $5?
No, Charles. No, it's all in the oil window, and it's in areas where we may have a bit more geologic geo-hazards, faulting and things like that, and it takes a little bit better effort on our part to get frac containment. We have to change maybe the direction that the well's drilled in. We also have to work a bit hard at getting the frack more evenly distributed along the lateral. It's all oil and I think we have confidence as we go forward that we're going to be able to continue to make improvements in those areas.
Thank you, Bill.
Next we'll hear from David Heikkinen of Heikkinen Energy Advisors.
Morning, Bill. I liked your comments on your 10 years of growth in the Eagle Ford. Given that you've modeled that, can you talk about how many years of growth you see in the Bakken?
Yeah, David, we have not done that extensive model in the Bakken yet because we're really in the initial stages of downspacing. I'm going to ask Billy Helms to make some comments on that.
Yeah. David, for our Bakken, as we illustrated there, we're still very satisfied, very pleased with our 1,300-foot spacing test. We realized that our NPV and net present value was not maximized. We're going to be doing lots of additional testing. We did talk about a 700-foot spacing pattern, we'll be testing some various spacing patterns as we try to define how to maximize net present value. This is a similar approach that we've done in most of our shale plays across the company. Until we really find out what that formula looks like, we're really hesitant to state what the upside might be there. Certainly, we'll provide some more effort on that as we go forward in the year, we're very confident that we're going to have success there.
On the maximizing NPV, one of the things we've talked a lot about is your IRR doesn't change much, your EUR may decline per well as NPV goes up. Is that a fair characterization of how your downspacing could actually roll forward?
Yes, that's correct. Naturally, as you push wells closer together, you're going to end up having some sharing between wells. That's just inevitable. Our rate of return is still very high as you stated. What we end up doing is adding a lot more recoverable reserves and thus a lot more net present value to each spacing unit that we drill. That's our overall process and we're still early on in the stage, certainly in the Bakken as we try to define that.
Just, if I may, one more follow-up on, as you talked about NGLs kind of 2016+, how does your significant combo play exposure factor into your out-year plan? We think we've seen a floor for NGL prices due to supply, demand, and exports. Would you agree with that as you start thinking 15, 16+?
David, I think NGLs go along with the gas, and we are hopeful that the NGL demand will increase enough to firm up the price. Again, I think from a capital standpoint, we still are very focused on oil, and really oil for the next several years is going to be where we're going to think we're going to get the highest return. As we get better NGL prices and gas prices, those combo plays will become competitive with our oil plays down the road, and we'll put capital on those. Near term, we're still focused on oil.
Thanks, guys.
Irene Haas, Wunderlich Securities, has our next question.
Hello, everybody. You guys have been super quiet and super stealth about these Rocky Mountain plays, and congratulations to your new drilling inventory in Wyoming and Colorado. My question for you really has to do with the Powder River Basin. Can you help me with the 35,000 net acres? Is it just one layer or is it two? Do they overlap? Really parallel to this is, can we have some color on the geology? Are these really real continuous play or you just have nailed the sweet spot? Lastly, transportation differential things of that nature to ship the oil out of Powder River Basin.
Irene, the Parkman is about 30,000 acres in the net sweet spot, then the Turner is about 63,000 net acres in the sweet spot. Much of that acreage does overlap, but not all of it, each of those are both sandstone plays. So we have quite a bit of subsurface data, we've mapped the thickest parts of those sandstones and the most productive parts of it. So that's what those two acreage numbers take into consideration, those obviously are where you're going to make the highest return wells on each one of those. Let me ask Gary Thomas to answer your question on takeaway for the Powder.
Irene, yes, we've been real pleased with the various midstream companies. We're working with several, they're looking at putting in a crude line that would come down from North Dakota through Wyoming to be able to pick up our DJ and our Powder River oil. There's also processing in place and companies that are interested in, yes, expansion as well as put in new processing facilities. It's looking very favorable.
Great. Thank you so much. Congrats again.
Thank you.
Our next question comes from Pearce Hammond, Simmons & Company.
Good morning.
Morning, Pearce.
Can you remind us the net resource potential or reserve potential for the Eagle Ford when you first announced that play? Do you see the same thing unfolding with these new plays in the DJ and the PRB?
Yeah, Pearce, the first number, the first one we come out with was 900 million barrels equivalent net to EOG. I would say the four plays that we've announced today, they do not have that upside potential. Obviously, we had 564,000 acres in the Eagle Ford, and it's a very continuous shale play. These plays, in particular, the Codell, the Turner, and the Parkman are sandstone plays. They're not really shale plays, so they are more defined geologically. Really, the acreage positions that we've outlined in each one of those is really the sweet spot and probably the best extents of those plays. On the Niobrara, of course, it is a shale play. Again, we really think we've identified a sweet spot in that 50,000 acres there. We believe that we'll get consistent results there.
Outside of that acreage, that's not really proven to be consistent yet. We'll just have to see as time goes on where we can maybe expand that. Right now, we're really focused on these individual sweet spots. I would say, in the Niobrara, there are multiple targets there, and the reserves that we've given in this guidance is just assuming one target, and it's assuming six wells per section. There's downspacing potential, additional targets in the Niobrara. In the other plays, there could be some downspacing potential there, but that's undefined yet, and we're just hopeful on all that. We'll have to test that as we go along. If that becomes clear, we'll certainly talk about it.
Great color. Thanks. My follow-up is, how do you see service costs right now, across all your positions? Are you experiencing any tightness, any service cost inflation?
Pearce, we're not seeing much. We're seeing tightening on our drilling rigs. They've probably gone up in some areas as much as 5%. As you know, EOG's got so much of our services locked in and self-sourced that we're not seeing any pressure otherwise. There's a little bit on just trucking, that's why we're putting in our gathering system, et cetera, just because these are going to be so long-lived properties just to hold future costs down.
Excellent. Thank you very much.
Next, we have from David Tameron of Wells Fargo.
Hi, just a couple of questions. I think you've addressed this partially, but can you talk about your desire to ramp production growth a little faster, one additional way to bring in PV forward? Can you address that as I know you're at the upper end of your large cap here, but just address that, and then I'll have a follow-up on the Powder.
Not sure. Go ahead.
Okay. We're going to continue to drill more wells. It's efficiencies in large part. Thinking of the Eagle Ford, yes, we're going to be drilling more wells this year than last, but with the same number of rigs. We can see us just continuing to improve our efficiencies and drilling more wells each year without a large addition of capital. Even though we plan to spend additional capital on drilling and completion our E&P sector future years.
Yeah, David, I would add to that the company is not so much focused on production growth. We're really focused on capital return, and that is what drives EOG. We're not interested in drilling low return wells to grow production. We're going to very much stay focused and very much stay disciplined in our CapEx plans. The plays have to have a very strong rate of return before we're going to spend money on them.
Okay. That's helpful. Then thinking about the Powder. We've done obviously a lot of work on the play, and just one thing that's always been a hiccup for people is the gas processing, or it seems to be at least in the Powder has been, I guess, maybe more of a hurdle is a better way to approach that. Is that what you guys are running into? If so, are there plans to address I heard you talk about infrastructure specifically. Is it more on the processing gas side, or is it more crude takeaway? I know there's some rail projects out there, et cetera, but can you just give us a little bit better snapshot on the infrastructure?
Yeah, we're working on the crude pipeline takeaway there. We believe that's going to be in place soon enough for us. As far as the gas processing, that's probably the larger concern. There is planned expansions in place. We've got sufficient takeaway at this point, and we think that it's going to keep up with our growth in the area.
Okay. Thanks. I'll let somebody else jump in. Appreciate it.
Next, we'll hear from Amir Arif of Stifel Nicolaus.
Thanks. Good morning, guys.
Good morning.
On the DJ Basin, I know you mentioned in the EUR estimate it's only one zone, but can you let us know if you've tested the different benches or the Codell and Weld, and then similarly, the Niobrara in Laramie County?
Yeah, Amir. On the Codell, you just have one target there. We've had a good number of wells that we've talked about that we drilled in that. We feel great about that. On the DJ, in this area that we're focused on, the sweet spot, we've drilled one target so far, and it's been in the lower part of the Niobrara. That's the target we feel like will give us very consistent results. We do have plans later in the year to drill a couple of patterns. The first pattern will be with four Niobrara wells in the lower target and three Codell wells. That's a seven-well pattern. The second pattern later in the year, we're going to drill six Niobrara wells with three in the upper target and three in the lower target, and then three Codell wells.
That's a nine-well pattern. As we drill those and learn how to continue to improve the completions, and get into this pattern drilling, we'll learn a whole lot more about the different targets, benches in the Niobrara, and then also the Codell, and how all those interrelate with each other.
Okay. Thanks for the color. The follow-up question is, just looking at the four new plays, great returns, great projects to add, but given that the size of 30,000 to 70,000 acres relative to your other plays, can you just provide some color or comments in terms of the minimum acreage threshold you're looking at when you get into new plays and even some color in terms of where you think we are as an industry in terms of the resource capture, and is that part of the reason why you're starting to look at smaller acreage plays?
Yeah, I think we've learned off these plays, all these resource plays, that really to make the highest returns, you really need to focus in on the sweet spots. They're variable in size. Obviously, in the sandstone plays that we've talked about, they're a bit smaller. In the shale plays, they can be bigger. In the case of the DJ Basin, the basin has shown quite a bit of variability in the Niobrara there. You have to be really careful. That's why we focused in only on the 50,000 acres so far in the Niobrara there.
As far as additional play potential in the U.S., we do see opportunities, as we said before, we have plays that we're working on in different stages of identification and testing, we believe that it's going to be very difficult to find another Eagle Ford that has both the size and the quality, another Bakken, which would have the size and quality. We do believe that there'll be additional plays that we can capture sweet spots on that will be additive to EOG's inventory and that will be significant enough for us to focus on. When you have multiple hundreds of wells, that's a nice play size and certainly a kind of thing we want to capture.
That's good. Thank you.
Next we'll hear from Bob Brackett of Bernstein Research.
Good morning. Got a bit of a two-part question. I notice you're carrying fairly wide spacing on some of these new sandstone lithologies. Is that because you think the footprints or the drainage areas are larger?
Bob, they're better reservoirs, so they have better permeability. I think that's to be determined. We will certainly be evaluating the wells as we drill them on these spacings and the frack patterns, and the potential interference between the wells. There could be some room for additional downspacing in the plays as we go forward. It's just typically, EOG, we're very conservative on our reserve estimates when we start these plays out. That'll be our focus is to maximize the NPV, and that's one way to do it is through additional downspacing.
The follow-up, if I think about going back as far as, say, the Jake well, what's your strategy for either avoiding or embracing natural fracture systems out there in the Front Range?
Bob, that's a good question. The Jake well was really targeted in a different part of the Niobrara than we're focused on right now. More within what they call the chalk part. We call it the B Chalk in the upper part of the Niobrara. It's also was very fracture driven. We have done extensive mapping on the Niobrara, this lower target, we believe will give us more consistency, number one, we also have 3Ds to identify the fracturing and identify the faulting. I think the third thing is our completion technology has advanced quite a bit, and those early wells we drilled were very small fracs with different completion styles. We're going to be using our latest completion techniques, and we think that'll be beneficial also.
Would you be targeting areas that are highly naturally fractured, or you avoid those?
I think we want to really avoid those. There's always fracturing that's involved in these plays, but really looking for a resource play that would be consistent to where we can get actual matrix contribution. That's the approach that we're taking.
Thank you.
That does conclude today's question and answer session for today. At this time, I would like to turn the conference back over to Bill Thomas for any additional or closing comments.
Well, thank you for listening. We appreciate all the questions. That's it.
That does conclude today's conference. Thank you all for your participation.