EOG Resources Inc (EOG) 2014 Q1 法說會逐字稿

Good day, everyone, and 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 and EOG's SEC filings, and we incorporate those by reference for this call.

This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.EOGResources.com.

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

Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, Chief Operating Officer; Billy Helms, Executive VP, Exploration and Production; and Maire Baldwin, Vice President, IR. An updated IR presentation was posted to our website yesterday evening, and 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, and 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 impact 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 buildup 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 US, oil production was up 45% year over year, and 10% sequentially. Total Company production increased 18%, compared to the first quarter of 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% to 29%; and total growth estimates from 11.5% to 12%.

Our actual unit costs 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 were 71%, 35-degree, API oil, with the 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 a-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 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 6 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 cost, 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're 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. The 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 6 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 a-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, bolt-on oil plays to our portfolio.

We've set a high threshold at EOG with plays like the Eagle Ford, Bakken and Leonard. Other plays that compete for capital require these 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, and 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, and, 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 mid-year, the vast majority of our drilling obligations for 2014, to hold our 564,000 net acreage position in the crude oil window 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 draw 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 talked about the 6,000 net remaining locations on our acreage. We used a 60% direct after-tax rate-of-return cut-off point in moving these locations into our inventory. We still have a large number of locations that don't meet this threshold. But we continue to improve -- 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 downspacing until we've maximized the net present value in the overall play. We are early in the life of these tests, and 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 drilled eight wells this year. The wells produced 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 costs. 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, and 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% to 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 US was the largest oil growth area in the world. However, the rate of oil growth in the US 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. Therefore, 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 to $5.00 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 feed stock are expected to be commissioned. The remainder of the LNG-commissioned 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 number exclude options that are exercisable by our counterparties.

For the period June 1 through 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 number 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 US, EOG realizations averaged $1.97 over West Texas Intermediate index prices. However, we continue to sell the majority of our oil [index off LLL] pricing.

Now, let me conclude. There are five important take-aways 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, [on shore] US plays. This is proof of our very disciplined approach to adding new plays. First, we identify the potential; second, we capture the acreage; and 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 US, 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. And 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.

And fourth, we are testing additional down-spacing patterns in the Bakken, Leonard, and Wolfcamp plays. We will continue to test downspacing until we have reached maximum optimization for each of these plays.

To wrap it up, EOG turned in another outstanding quarter. Our US 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 will go to Q&A.

Thank you.

(Operator Instructions)

And we'll first hear from Doug Leggate of Bank of America, Merrill Lynch.

Hi, good morning, everybody. I love the pronunciation on these calls.

Thanks for all of the color, Bill, on the new plays. I guess my question is on slide 9 in your presentation. You show how they stack up on a relative basis with the IRR. And I guess, 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?

And 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?

And then I've got a follow-up please.

Yes, Doug, on the capital allocation, as we go forward -- we've given guidance in the past, and we want to reiterate this. That number one, the first priority is to the dividend. And we want to continue our 15-year history of a healthy dividend increase.

And next, the focus is on reinvesting that capital back in to the highest rate-of-return plays. And now we have more of those to offer up. And 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 Leonard -- the Delaware Basin Leonard -- and now we have opportunities to reinvest at high returns in the DJ Codell department and Turner plays. So 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% a-tax rate-of-return cutoff, we are focused on that. And we have a pretty -- it could be a pretty significant number of wells that we can drill.

And we're doing like we do in all of our plays. We're working on the costs -- to reduce the costs as we go forward. And I think, most importantly, we continue to see improvements in the well completions -- in the frac technology.

And so we're hopeful that we go forward -- that those wells will get those returns up, above 60%. And down the road -- as the years go, down the road, we'll be able to include those in our inventory.

So the reason we haven't listed those, really, 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.

That'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. And 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? And I'll leave it there. Thanks.

Yes. On the new plays, I don't think -- we wouldn't talk about them unless we had felt like that we captured the sweet spots. We did a very thorough geological evaluation, and we have a lot of data. And we have really narrowed down the acreage to what we believe are the highest return areas of the plays.

And so the acreage numbers listed for each play are really the sweet spots where we think we'd have the best chance to make the best wells. And so we think we captured that, and there's probably additional zones or 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 will hear from Leo Mariani of RBC.

Hey, guys. You made some interesting comments about the Eagle Ford here. I 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 kind of speak to how you might manage development differently, post that?

Yes, Leo. In the first quarter, and then some in the second quarter, we drilled a lot of retention wells. That means, kind of the first wells on a unit to hold that acreage.

And as we have completed that process -- 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 the -- drill wells on pads, multiple wells on pads -- and again, to optimize our costs. And then to continue to focus on making the better wells, and getting the spacing right and the completions right. And 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% to 10% efficiency gain as a result over the next 2 years?

Yes, 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 of that will be much reduced. It just improves our overall operations.

We've drilled some of these wells in as little as 5.3 days, so our days per well will continue to decline with pad drilling. So we'll see, certainly, the 5% to 10% cost reduction.

Okay. That's helpful.

And just quickly on the DJ Basin here, you obviously talked about some sweet spots. Historically, there's been a decent amount of variability in parts of the DJ, in both the Codell and the Niobrara. 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, other data that you're seeing that convinces you that the acreage positions you have 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.

And so we believe -- you're correct, that the DJ Basin, historically, has been very variable. So there are sweet spots that are really set up by the Basin architecture, and it varies. And 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. So that is why we're focused on these areas.

Thanks, guys.

Our next question comes from Brian Singer of Goldman Sachs.

Thank you. Good morning.

Good morning, Brian.

Wanted to try to juxtapose a little some of the macro comments you made with just how you're thinking about your investment in growth at the EOG level. Maybe we'll start with gas here first.

At the outlook you delivered -- I'd like to say -- is a little 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 gas acreage you identified 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?

Yes, Brian. I think we're mildly bullish on near-term gas, that we think it'll be in the $4.50 to $5.00 range. And we are really not prepared and, really don't want to invest any additional money, at this time, in any dry gas drilling.

And 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 $5.00 gas prices. And there's so much gas potential out there that it could easily drill a lot of wells. And the price of gas would decrease.

So 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.

And 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? And how does that juxtapose with your macro -- your more optimistic macro view, in terms of US 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. And we do not see any pending crisis on overloading the system -- the US system, the refinery system -- to be able to process all that oil.

So our focus is going to be to reinvest back into the highest-return plays. And the highest-return plays, we fully believe in the next few years, will be our oil plays. And 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.

And of course, the focus will be Eagle Ford, Bakken. But now we have a good set of plays that we have a lot of opportunity to reinvest in. So our focus is going to be oil for quite some time.

I mean, you likely won't need 64,000 barrels a day of oil growth per year to have above-peer average-type growth, but do you see that 64,000 rising, in terms as a rate of growth?

No. I wouldn't say it would rise, but we think it'll be fairly consistent.

Great. Thank you.

Next we will 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 be. It might be the D&C cost, it could be high grading the acreage and locations, and it could improvement of completion designs and associated well productivity.

But 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?

Yes, Charles. That's a good question. It starts with the sweet spot. So we drilled quite a few Parkman wells, and with that data and the other geologic data available, we've really narrowed down this acreage in the Parkman to the very sweetest spot. So we're focused on the best pay. That is a start.

And then, we brought in the completion technology. As we've learned on all of these horizontal plays, and particularly, shale plays, the completion technology continues to advance. And we're now seeing -- even in the conventional, more conventional rocks like sandstones -- that the improvements that we've seen in the shale plays also apply to those, too.

So 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. And that, along with the EOG being able to come in and apply our kind of shale cost reduction efforts in these plays to reduce the overall costs, it's really improved the rates-of-return on all these plays.

So it is a three-fold thing, really. And it, really, fits into EOG's strengths.

Got it.

And then, if I could go back and try one more time on the Eagle Ford inventory question. Is this -- the inventory that's not in your number right now -- is this in the oily window where, perhaps, the reservoir is not as productive? Or is this down dip in gassier acreage that, maybe, comes into the inventory when gas is at $4.50 or $5.00?

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. And we have to change, maybe, the direction that the well is drilled in, and we also have to work a bit harder at getting the frac more evenly distributed along the lateral.

So it is all oil. And you know, we have confidence, as we go forward, that we are going to be able to continue to make improvements in those areas.

Thank you, Bill.

And next, we'll hear from David Heikkinen of Heikkinen Energy Advisors.

Good morning, Bill. I liked your comments on your 10 years of growth in the Eagle Ford. Given that you modeled that, can you talk about how many years of growth you see in the Bakken?

David, we have not done that extensive model in the Bakken yet because we're really in the initial stages of down-spacing. And I'm going to ask Billy Helms to make some comments on that.

Yes, David. For our Bakken, as we illustrated there, we're still very satisfied, very pleased with our 1,300-foot spacing test. But we realize that our NPV, or net present value, was not maximized. So we're going to be doing lots of additional testing.

We did talk about a 700-foot spacing pattern, and 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 have done in most of our shale plays across the Company.

And until we really find out what that formula looks like, we're really hesitant to state what the upside might be there. But certainly, we'll provide some more effort on that as we go forward in the year. And 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, but your EUR may decline per well, as NPV goes up. Is that a fair characterization of how your down-spacing could actually roll forward?

Yes, that's correct. Naturally, as you push wells closer together, you are going to end up having some sharing between wells. That's just inevitable.

Our rate-of-return is still very high, as you stated, but 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.

So that's our overall process. And we're still early on in the stage, certainly, in the Bakken, as we try to define that.

If I may, one more follow-up. As you talked about NGLs 2016 plus, how does your significant combo play exposure factor into your out-year plan?

And then, 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 2015, 2016, plus?

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. But 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 returns.

So 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. But 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.

And my question for you is -- 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?

And then really, parallel to those, can we have some color on the geology? Are these real continuous play, or you just have nailed a sweet spot?

And lastly, transportation differentials, things of that nature to ship the oil out of the Powder River Basin?

Yes, Irene. The Parkman is about 30,000 acres in the sweet spot -- net sweet spot. And then the Turner is about 63,000 net acres in the sweet spot. And much of that acreage does overlap, but not all of it.

And each of those are both sandstone plays, and so we have quite a bit of sub-surface data. And we've mapped the thickest parts of those sandstones and the most productive parts of it. And so that's what those two acreage numbers take into consideration, and those -- obviously, if we're going to make the highest return wells on each one of those.

Let me let -- ask Gary Thomas to answer your question on take-away for the Powder.

Irene, yes. We've been real pleased with the various midstream companies. We're working with several. And we are looking at -- they're looking at putting in a crude line that will come down from North Dakota through Wyoming to be able to pick up our DJ and our Powder River oil.

So there's -- and there's also processing in place and companies that are interested in, yes, the 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.

Good morning, Pearce.

Can you remind us the net resource potential, or reserve potential, for the Eagle Ford when you first announced that play? And do you see the same thing unfolding with these new plays in the DJ and the PRB?

Yes, Pearce. The first number -- the first one we came out with was 900 million barrels equivalent, net to EOG. And I would say the plays -- 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 is 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, and really, the acreage positions that we've outlined in each one of those is really the sweet spot and probably the best expense of those plays.

On the Niobrara, of course it is a shale play, but again, we really think we've identified a sweet spot in that 50,000 acres there. And we believe that we'll get consistent results there. Outside of that acreage, that's not really proven to be consistent yet. So we'll just have to see, as time goes on, where we can, maybe, expand that. But 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 have given in this guidance is just assuming one target. And it's assuming six wells per section. So there's down-spacing potential. Additional targets in the Niobrara.

And then, in the other plays, there could be some down-spacing potential there. But that's undefined yet. We're just hopeful on all of that.

We'll have to test that as we go along. And if that becomes clear, we'll certainly talk about it.

Great color. Thanks.

And then 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%.

But as you know, EOG has 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 trucking, but that's why we're putting in our gathering system, et cetera, because these are going to be so long-lived properties. Just to hold future costs down.

Excellent. Thank you very much.

Next we will hear from David Tameron of Wells Fargo.

Hello. Just a couple 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 NPV forward? So can you talk -- address that -- as I know you're at the upper end of your large cap peers, but just address that?

And then, I'll have a follow-up on the Powder.

We're going to continue to drill more wells. It's efficiencies, in large part, and 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. So 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.

David, I would add to that -- 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.

So we're going to very much stay focused and very much stay disciplined in our CapEx plans. And so the plays have to have a very strong rate-of-return before we're going to spend money on them.

Okay. And then -- Okay. That's helpful.

Thinking about the Powder, we've done, obviously, a lot of work on the play. And one thing that's always been a hiccup for people is the gas processing -- or it seems to be, at least in the Powder. It's been a -- maybe more of a hurdle is a better way to approach that.

Is that what you guys are running into? And 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 take-away. I assume there's -- I know there's some rail projects out there, et cetera. But can you give us a little bit better snapshot of the infrastructure?

Yes. We're working on the crude pipeline take-away 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. But there is planned expansions in place. So we've got sufficient take-away at this point, and we think that it's going to keep up with our growth in the area.

Okay. Thanks. I will let somebody else jump in. Appreciate it.

Next we will hear from Amir Arif of Stifel Nicolaus.

Good morning, guys. On the DJ Basin, have you -- I know you mentioned in the EUR estimates only one zone, but can you let us know if you tested the different benches on the Codell in Weld and, similarly, the Niobrara in the Laramie County?

Yes, Amir. On the Codell, you just have one target there. And we've had a good number of wells that we've talked about that we drilled in that. So we feel great about that.

On the DJ, we -- 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. And that's a 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, so that is a seven-well pattern.

And then 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. So that is a nine-well pattern.

So 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 inter-relate with each other.

Okay. Thanks for the color. And then 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 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 resource capture. And is that part of the reason why you're starting to look at smaller-acreage plays?

Yes. I think we've learned off these plays -- all of these resource plays -- that really, to make the highest returns, you really need to focus into the sweet spots. And 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.

But in the case of the DJ Basin, the Basin has shown quite a bit of variability in the Niobrara there, so you have to be really careful. So that's why we've focused in only on the 50,000 acres so far in the Niobrara there.

But as far as additional play potential in the US, we do see opportunities. And as we've said before, we have plays that we're working on in different stages of identification and testing.

And so we believe that it's going to be very difficult to find another Eagle Ford, that has both the size and the quality, and another Bakken, which would have the size and quality. But we do believe that there's going to 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. So when you have multiple hundreds of wells -- that's a nice play size, and certainly the kind of thing we want to capture.

That's good. Thank you.

And next, we'll hear from Bob Brackett of Bernstein Research.

Hello, good morning. Got a bit of a two-part question. I notice you're carrying fairly wide spacing on some of these new sandstone [geologies]. Is that because you think the footprints or the drainage areas are larger?

Bob, they do have -- they're better reservoirs, so they have better permeability. But I think that's to be determined. We will certainly be evaluating the wells as we drill them on these spacings and the frac patterns and the potential interference between the wells, and there could be some room for additional down-spacing in the plays, as we go forward.

It's just typically, we -- EOG -- we're very conservative on our reserve estimates when we start these plays out. But that will be our focus, is to maximize the NPV. And that's one way to do it, is through additional down-spacing.

And 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?

Yes, 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. And it's also -- was very fracture-driven.

And so we have done extensive mapping on the Niobrara, and this lower target, we believe, will give us more consistency, number one. And then, we also have 3Ds to identify the fracturing and identify the faulting.

And then I think the third thing is, is our completion technology has advanced quite a bit. And those early wells we drilled were very small fracs with different completion styles. So we're going to be using our latest completion techniques. And we think that will be beneficial, also.

So you're -- but would you be targeting areas that are highly naturally fractured, or you avoid those?

I think we want to really avoid those. There is always fracturing that's involved in these plays, but really looking for resource play that would be consistent, where we can get actual matrix contribution. And so that's the approach that we're taking.

Thank you.

And 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 of the questions. That's it.

That does conclude today's conference. Thank you all for your participation.