EOG Resources Inc (EOG) 2015 Q4 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources 2015 fourth-quarter and full-year results conference call. At this time for opening remark and introductions, I would like to turn the call over to Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you. Good morning, and thanks for joining us. We hope everyone has seen the press release announcing fourth-quarter and full-year 2015 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 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. Among 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 the Investor Relations page of our website. Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP Exploration and Production; David Trice, EVP Exploration and Production; Lance Terveen, VP Marketing Operations; and Cedric Burgher, Senior VP Investor and Public Relations.

An updated IR presentation was posted to our website yesterday evening and we included guidance for the first quarter and full year 2016 in yesterday's press release. This morning we will discuss topics in the following order:

Bill Thomas will review 2015 highlights and our 2016 capital plan. David Trice and Billy Helms will review operational results and year-end reserve replacement data. Then I will discuss EOG's Financial's capital structure and hedge position and Bill will provide concluding remarks.

Here's Bill Thomas.

Thanks, Tim. EOG is committed to return-focused capital discipline, and we demonstrated that commitment in 2015 with a simple decision. After four years of 40% compound annual oil growth, we slammed on the brakes and decided to defer production growth. It was an easy decision.

Out-spending cash flow to grow oil into an over-supplied market makes no sense. Rather than chasing production growth through the down cycle, we focused on three main goals. First, we concentrated more than ever on resetting the Company to be successful in a lower commodity price environment by reducing costs and improving well productivity.

Second, we wanted to add high quality drilling inventory through organic exploration and tactical acquisitions and most importantly, our third goal was to protect our balance sheet. As a result, EOG had a record year in reducing costs, improving well productivity, and adding new drilling potential to the Company. We accomplished all of this and ended the year with one of the strongest balance sheets in the industry.

Here are a few highlights from the year. We reduced capital more than 40% from 2014 and maintained flat US oil production. Total cash operating costs per unit decreased 17% compared to 2014.

We drilled two industry record wells, one each in the Bakken and Delaware Basin Wolfcamp. We added a company record 1.6 billion barrels of oil equivalent and net resource potential and over 3,000 net locations. That means we replaced more than six times the inventory that we drilled in 2015, and we'd acquired 34,000 net acres in the sweet spot of the Delaware Basin.

2015 changed how we think about EOG's position in the industry long-term. It's no longer enough to be the low cost producer in US horizontal shale. EOG's goal is to be competitive, low-cost oil producer in the global market.

Now, let's talk about our plan in 2016. Our first objective this year is to achieve strong returns on our capital program through sustainable profitability gains. In order to maximize return on capital invested, we are shifting into what we call premium drilling mode.

Like last year, we will concentrate our efforts in capital in our top plays, the Eagle Ford Delaware Basin, Bakken and Rockies. The difference in 2016 is that we have the flexibility to direct capital only towards our large inventory of premium-quality wells. Premium inventory is defined as wells that generate direct after-tax rates of return of at least 30% at $40 oil. We have identified over 2 billion-barrels of equivalent of net resource potential and 3,200 net drilling lotions that meet this hurdle.

At our 2016 pace, and we expect to complete 270 wells this year, that represents 12 years of drilling potential. In addition, we are confident our premium inventory will continue to grow in size and quality. Our proven track record of organic exploration and sustainable gains through technology and efficiency will continue to add premium inventory for years to come. What that means, and this is the most important part, is that between our existing premium inventory and our confidence that we can replace it, EOG will be in premium drilling mode from now on.

EOG's shift to premium drilling in 2016 is not just simple high grading. It is a permanent upgrade for all our future drilling. It's important to realize that this is much more than a small incremental shift in our drilling program. It's a major step change in terms of per-well productivity. For the average 2016 well, we estimate a 50% increase in the first 120 days of production per foot of treated lateral, versus wells we completed in 2015.

Our shift to premium drilling allows EOG to quickly return to triple digit, and I'll say this again, to quickly return to triple digit capital rates of return, as oil prices improve to modest levels. So the next logical question is what becomes of the remaining inventory? Our non-premium inventory is still very high quality.

By any industry standard it is tier 1 quality with tremendous value. Due to the quality, a large percentage of this inventory will be converted to premium through technology and efficiency gains over time. The remaining high quality inventory will add value through property sales or trades as part of our ongoing upgrading process.

Our second objective in 2016 is to protect our balance sheet. Two years in a row, we have cut capital by more than 40%, demonstrating our commitment to capital discipline. In addition, as a result of our ongoing evaluation of our portfolio to upgrade our asset base, we are marketing certain valuable but non-core properties.

EOG prioritizes profitability and a healthy balance sheet to prepare the Company for uncertain commodity cycles and the strategy has paid off. EOG entered 2016 in excellent financial and operational shape. The combination of EOG's high quality assets, sustainable cost reductions and well productivity improvements allow the Company to lead the industry in returns year after year.

EOG is uniquely positioned with a large and growing inventory of high return drilling, even in a $40 price environment. Achieving strong returns in the current environment positions EOG to achieve tremendous returns as commodity prices improve.

Now I'll turn the call over to David Trice who will update you on the Eagle Ford and Rockies plays.

Thanks, Bill. Year after year, the Eagle Ford continues to impress us with the quality of its resource potential. In 2015, we grew production while completing 38% fewer wells compared to 2014.

Six years ago, we estimated that Eagle Ford had 900 million barrels of oil equivalent of net resource potential. We've since updated that net resource potential three times, and the latest estimate from early 2014 was 3.2 billion barrels of oil equivalent. In 2015, we've done a number of things that hold promise for further up side to the Eagle Ford's resource potential.

First, refinements to our high density completion techniques continued to improve well productivity in 2015 as can be seen in the cumulative production charts in our investor presentation on page 10. Second, to compliment high density completions, we made tremendous progress on what we have termed precision targeting. This is one of the most promising developments, not only for the Eagle Ford, but for all of our plays.

Precision targeting starts with first identifying and then mapping the key petrophysical properties that make the difference between a good well and a great well. Once all the data has been integrated, we found that the real sweet spot in any given target can be very narrow. Where we previously landed our wells in 150-foot window, we now precisely steer them in a window as narrow as 20 feet. In addition, this work on precision targeting also revealed that in some areas, we may have two distinct sweet spot targets in the lower Eagle Ford alone.

Finally, we conducted pilot tests by drilling adjacent wells in a W pattern that alternate between the two targets within the lower Eagle Ford. This allows for surface down-spacing closer than the 300 feet used in our current development spacing and resource potential estimates. Early results from these tests are encouraging.

In 2016, we have more program flexibility as 91% of our Eagle Ford acreage is held by production. We plan to complete 150 Eagle Ford wells while continuing to test the W pattern, spacing wells 200 feet to 250 feet apart.

Our advancements in precision targeting and completions along with cost efficiencies may have significant implications on our resource potential and will allow us to continue to upgrade additional Eagle Ford locations to premium status. In our Rockies and Bakken plays, we proactively scaled back activity due to commodity prices. With the lower activity level, we were able to sharpen our focus on sustainable operational improvements. We are very pleased with the progress and in fact, the magnitude of our operational improvements in these plays were the best in the company.

Here are the highlights. First we upgraded our Bakken net resource potential to 1 billion barrels of oil equivalent and added almost 1,000 net locations. Second, we reduced Bakken completed well costs 18% and drilling days over 30%. Third, we built water handling and water pipeline infrastructure that significantly reduces long-term LOE.

Fourth, we drilled several high quality wells in the Powder River Basin, highlighted by the Flatbow 602-1621H that came online in the fourth quarter. This turner well averaged over 1,100 barrels of oil per day and 1.7 million cubic feet per day of rich natural gas in its first 90 days of production.

Finally, we also drilled an industry record well in the Bakken. The Riverview 102-32H produced an average of 2,700 barrels of oil per day over the first 30 days and 2,200 barrels of oil per day for the first 90 days of production. This well was the first high-density completion on our Antelope extension acreage, and it is an industry record even though it is only a 4,300 foot lateral.

Going forward, we will continue to develop this area at a moderate pace as we build out the infrastructure that will allow us to lower the long-term upgrading costs. We're encouraged by these 2015 accomplishments in the Rockies and Bakken, and while the activity level will remain low in 2016, our focus on operational and well performance improvements will continue. We expect to see additional cost efficiencies and well productivity advancements through completions and targeting refinements.

We plan to complete approximately 35 wells in the Rockies in 2016. As we continue progressing technically in reducing costs, we expect the premium location count to grow significantly.

Finally, a quick update on our Conway project in the east Irish Sea. All work for startup has been completed by EOG, and we are working with the platform operator to reach final acceptance, which we believe is imminent. We expect first production by the end of the quarter.

Here's Billy Helms to review our activity in the Permian Delaware Basin.

Thanks, David. Our Permian Delaware Basin team has made tremendous amount of progress last year. Prior to 2015, we developed a successful winter program and had encouraging results with the Wolfcamp and Bone Springs intervals. As we enter 2015, we laid out a specific plan to one, increase our technical knowledge to better understand the potential of these complex plays; two, improve our operational execution and cost performance; and three, expand the scope and impact of the basin to EOG. Our efforts paid off.

Here's a recap of our progress. First, we made tremendous progress utilizing two techniques, precision targeting and high density completions. Our enhanced understanding of the regional stratigraphy of the basin helps us to delineate the most productive target intervals within each formation. This technique requires a significant amount of technical data and data analysis expertise, and coupled with our high density completion technique, generates solid improvements in well productivity as evidenced by our industry record setting Wolfcamp well, the 421 number 702H produced an average of 3,490 barrels of oil equivalent per day over its first 30 days of production.

After 120 days, average production was an impressive 2,100 barrels of oil equivalent per day. Noticeably, the well was completed with a shorter lateral, yet still exceeded the longer lateral wells in absolute production. In fact, on average our 2015 Wolfcamp wells produced 40% more than the next best operator during the first three months of production as displayed on slide 9 of our investor presentation.

Second, we made significant progress generating sustainable cost reductions. For example, in the Wolfcamp wall window, we reduced average drilling time 33% and lowered completed well cost 35%, despite adding incremental cost to each well for high-density completions. In addition, we secured a long-term brackish water supply that as we move into 2016 is expected to save us $200,000 to $300,000 per well.

And finally, we increased the net resource potential for the Delaware Basin by 1 billion barrels of oil equivalent and added 2,200 net locations, essentially adding decades of drilling inventory. This position -- this solidifies a position for the Delaware Basin as one of our high return growth engines. We also executed on another 8,000 net acre acquisition in the fourth quarter, bringing total 2015 Delaware Basin acquisitions to 34,000 net acres. This adds to our sweet spot acreage with significant upside potential through multiple stacked targets.

Thanks to the well productivity improvements and cost reductions achieved in 2015, the Delaware Basin delivers returns that compete for capital alongside the Eagle Ford. A large portion of the Delaware Basin is already considered premium and with our continued advancements we expect to dramatically increase our inventory of premium locations in the next two years.

For 2016, we're continuing the momentum. The Delaware Basin will again be EOG's second most active basin next to the Eagle Ford. We plan to complete the same number of wells as we did in 2015, about 75, and we'll focus primarily on the Wolfcamp. Drilling the Wolfcamp generates excellent returns while allowing us to collect data on the shallower targets at the same time.

I'll now address reserve replacement and finding costs. All in, crude reserves decreased 15% in 2015, driven primarily by price related revisions. Excluding revisions due to commodity price changes we replaced 192% of our 2015 production at a low funding cost of $11.91 per BOE.

For the 28th consecutive year, the gullier at M'Naghten performed an independent engineering analysis of our reserves and their estimate was within 5% of our internal estimate. Their analysis covered about 86% of our proved reserves this year. We see the schedules accompanying this earnings press release for the calculation of reserve replacement and refining cost.

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

Thanks, Billy. I'll begin with a few comments about our capital spending last year and in the fourth quarter. Capitalized interest for the quarter was $8.9 million. For the fourth quarter 2015, total exploration and development expenditures were $737 million, including facilities of $116 million and excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $35 million.

There were $105 million of acquisitions during the quarter. For the full year 2015, capitalized interest was $41.8 million. Total exploration and development expenditures were $4.4 billion including facilities of $765 million and excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property plant and equipment, were $288 million.

For the full year, capital expenditures, excluding acquisitions and asset retirement obligations were $4.7 billion, $200 million below the low end of our original 2015 guidance. Total cash flow from operations was $3.6 billion. In addition, proceeds from asset sales were $193 million.

Total acquisitions for the year were $481 million. At year end, total debt outstanding was $6.7 billion for debt to total capitalization ratio of 34%. Taking into account $719 million of cash on hand at year end, net debt to total capital was 31%.

In the fourth quarter of 2015, total impairments were $168 million. $94 million of these impairments were the result of significant declines in commodity prices during the fourth quarter. For the full year 2015, total impairments were $6.6 billion, $6.3 billion of these impairments were the results of declines in commodity prices and were related to legacy natural gas assets and marginal liquids plays. The remaining impairments for both the fourth quarter and full year 2015 were ongoing lease and producing property impairments.

The effective tax rate for the fourth quarter was 29%, and the deferred tax ratio was 92%. Yesterday, we included a guidance table in the earnings press release for the first quarter and full year 2016. Our 2016 CapEx estimate is $2.4 billion to $2.6 billion excluding acquisitions.

The exploration and development portion, excluding facilities, will account for almost 80% of the total CapEx budget. Our 2016 CapEx estimate represents a 47% decrease from 2015 and is 70% less than 2014. Capital expenditure is demonstrating our commitment to capital discipline.

The budget for exploration and development facilities and gathering, processing and other accounts for approximately 20% of the total CapEx budget for 2016. We plan to concentrate our infrastructure spending in the Eagle Ford and Delaware Basin, to support our drilling programs in those areas and enhance operating efficiency. In terms of hedges, for natural gas we have approximately 60,000 in MMBT per day, hedged at $2.49 per MMBTU in March 1 through August 31, 2016. We currently have no hedges in place for oil. Now I'll turn it back over to Bill.

Thanks, Tim. Now for a few comments on the macro. During the fourth quarter of 2014, EOG was early to respond to the price signals in the market. We cut CapEx, scaled back activity, and focused on returns instead of growing oil into an over-supplied market.

As we start 2016, we are encouraged by the discipline operators are demonstrating around the world. This disciplined capital reduction is rapidly slowing US oil drilling and reducing significant amounts of future supply worldwide. We believe the pace of market correction is increasing in 2016.

Now in summary, I will leave you with a few important points. First, 2015 was a record year for EOG in terms of improving the Company. We had record well and operating cost reductions and a record year in improving well productivity. We also had our best year ever in adding new high-quality drilling inventory.

Second, we are rapidly resetting the company to be successful in a lower commodity price environment. We are focused on improving returns and lowering operating costs instead of growing oil at the bottom of the market.

Third, our shift to premium drilling this year should yield strong capital returns in a low commodity price environment. Premium wells generate after tax rates of return of 30% or better at $40 oil. And over 100% after tax rates of return at $60 oil.

Therefore, EOG is uniquely positioned for tremendous performance as oil prices improve. Fourth, we do not view premium drilling mode as a temporary bridge to get the low oil prices.

With over 2 billion barrels of oil equivalent of premium net resource potential, and 12 years of premium inventory, this is a permanent shift in the quality of EOG's future wells. We believe the company will continue to grow the size and quality of premium inventory for years to come.

Fifth, we remain long-term focused. We continue to do the things that will add significant upside to the future of the company like investments in exploration, secondary recovery, and other new technologies. Our focus is creating long-term shareholder value through sustainable productivity advancements.

And finally, our goal has always been to be the low cost US horizontal oil producer. As we look to the future, that's not enough. Our goal is now squarely set on being one of the lowest cost producers in the competitive global oil market. And we are well on our way to reaching that goal.

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

Operator.

(Operator Instructions)

We will take our first question from Evan Calio with Morgan Stanley.

Good morning, guys. My first question is your premium locations appear higher than most peers' core or comparable locations. Can you discuss what you think differentiates EOG's premium locations and what's proprietary and represent a barrier for peers to achieve similar results? And also if I could, you mentioned upside locations, any color on what percentage of the average locations have already been reviewed?

Evan, this is -- certainly we believe moving into premium drilling mode is a step change in the future of the company. It's a substantial increase. As we said, over the last two years, it's about a 95% increase, the quality of the wells we're going to drill, and a 50% uplift for this year, so we're moving more rapidly than what maybe we might have even thought a few years ago. What's driving that is the quality of rock.

The quality of rock is the most important factor in the productivity of the wells, so we made extremely strong technical advancements in identifying the best rock in the best plays over the years, and certainly we believe we've captured the premier acreage and the premier plays in the US. And then also in each one of those plays, we developed petrophysical techniques, seismic techniques, we have used a lot of core data, and our combined over ten year's experience in these horizontal plays to identify the best target zones in each one of the plays.

And so that is the main driver, the rock quality, capturing it first and then being able to take all the technical knowledge and tools that we have developed over the years and to, in our experience, to be able to pick out the best targets. And then we've developed proprietary techniques to not only identify but to place the laterals in those targets and to keep the lateral in those targets for a long portion of the well. So our goal is to keep those targets, those laterals in the best rock, about 95% or better on the well. And so that's really the main driver. We think that's a very unique, very proprietary ability of EOG, and it will be very difficult to duplicate in the future.

And a follow up, if I might, if I may, you discussed the 55% jump in expected performance per foot in 2016, but since your DC's, your DUCs are completed on largely a FIFO basis, I presume that many of the wells you complete this year are 2015 vintage. My question is, is that right? And would that then mean there's another step change in performance for 2017 as you complete and turn more of those, you know, newly identified premium locations all other things being equal?

Yes, Evan, a large percentage of our wells that we're going to complete in the first half of the year are carryover DUCs from 2015. The majority of those wells are very beneficial to what we have been learning about targeting and identifying the rock, so those will be fantastic wells, and we'll get extremely strong returns on those. But the learning curve is not over.

We continue to refine our knowledge and our ability to execute, and so we see this is really just the beginning of a continuing, we believe, sustainable productivity increase in our drilling going forward. As we said in the opening, we have identified 3,200 locations and over 2 billion barrels of oil equivalent so far as premium, and we expect that to grow over time in numbers and quality, so we're -- this is really a big game-changer for the Company. We think it's very proprietary, and so we think it's going to give us a extremely competitive edge going forward. So we believe as oil prices improve, we will be able to rapidly be able to generate triple digit rates of return going forward, so this is a very meaningful step for the company.

I appreciate that.

Next will be Doug Leggate with Bank of America Merrill Lynch.

Thanks, good morning, everybody.

Good morning, Doug.

Bill, the production range for the year is obviously pretty wide. I guess what I'm trying to understand is there's a fairly large proportion of DUCs I'm guessing, I would have thought that would have given greater certainty to the outcomes, so I'm just wondering if you can help us reconcile the -- are you being relatively conservative with the range that you're giving us or is it something else? And I've got a follow up.

Yes, Doug, I'm going to ask Gary Thomas to give you some color on that.

Doug, I didn't get completely your question there.

So what I'm getting at is, I would have thought if you're completing wells you've drilled but haven't completed, it would have given you greater certainty to the outcome and the production outlook for the year, but the range for the year is still very, very wide. I'm just trying to reconcile those two things.

Okay. On the DUCs, yes, as Bill mentioned, we're going to be completing quite a number of -- about 70 of our DUCs -- or no, we're going to be completing in additional DUCs than that, but we're going to be completing at least a hundred of first quarter wells that we drill as DUCs. And those DUCs are all premium. They generate a 30% rate of return at $40 oil. And, you know, our guidance is very similar to what we've had in previous years.

We're saying anywhere from 260,000 to 280,000 barrels of oil per day for 2016. That pretty well duplicates what we had in 2015. Does that answer your question?

I guess I was talking about the [BOE] guidance which is still quite ]right]. I'll take it offline with [Sedrick]. My follow up is really more balance sheet related, so I think in the past, Bill, in a more robust oil price environment, you talked about a 30% ceiling on your net debt to cap. You're slightly above that right now.

I'm just wondering how you're thinking about that. And this is not in any way disparaging to the industry, but a lot of very strong companies whose very strong balance sheets have taken advantage of their relative outperformance by obviously, issuing equity. I'm just curious as to how you feel about the uncertainty of the outlook, and how you might balance the priorities to reinforce the strength of your balance sheet, given how well your stock has done relative to the market?

Doug, this, first of all, EOG has no current plans to issue equity at this time. Certainly we entered the year, we came into the downturn with a strong balance sheet, and we have been disciplined throughout the process. And so we -- when we look as we go forward for this year, is we have tremendous flexibility to make other adjustments to capital throughout the year. We do anticipate selling noncore properties as we consistently do every year. We're pretty far along in that process.

We have what we believe are very high quality strong buyers for properties. And this is not a small amount of money. It's very significant. So we're quite confident in that process, and so our goal going forward is to maintain a strong balance sheet. And fortunately, our balance sheet right now is one of the strongest in the peer group. So that's certainly a focus for us.

It's certainly been a hallmark, a strong balance sheet has been a hallmark for EOG for years, and we've not taken our sight off that, and we're going to be committed to maintaining a good strong balance sheet going forward.

The next question is from Arun Jayaram with JPMorgan.

Yes, Bill, I was wondering if you could elaborate a little bit more on the premium drilling inventory. You guys cited, I believe, 3,200 premium locations and the 2 billion barrels, I believe, of gross recovery that would equate to an EUR of 625 MBOE if you just kind of average that out. About half of that premium inventory is in the Eagle Ford, so I guess my question is -- you're overall Eagle Ford guidance is for 450 MBOE recovery, and that's after royalties. So I was wondering if you could just maybe comment on the differences in the premium inventory in the Eagle Ford relative to that 450 average.

Yes, the first thing, the two billion barrels is net.

Oh, that's net.

Yes, that's net. So the gross EUR per well would be quite bigger than what you stated. And let me let David Trice comment a little more on the details on the Eagle Ford and kind of what we expect there going forward.

In the Eagle Ford, you know, like we stated in our remarks, we've done a lot of work there, obviously over the years. We've collected a tremendous amount of data. Even this last year in 2015, we drilled quite a few pilot holes where we actually drilled down through the Eagle Ford and collected a lot of data, and so what that allowed us to see was that we have a lot of additional upside there as far as working on the targeting, like I had mentioned, I mean, we're drilling 20 ft target intervals and doing multiple targets within the lower Eagle Ford. And we're seeing very good results with that, and we're quite encouraged.

So I think really going forward, we see a real opportunity to continue to add premium locations, you know, we stated in our slides that we've got approximately 1,500 premium locations in the Eagle Ford, but we certainly see that as a starting point as far as being able to continue to add premium locations.

Let me just add, to answer your question specifically on the 450 net MBOE per well, in the Eagle Ford, that is for an average Eagle Ford well, and that is not a premium well. Premium wells would be quite a bit better than that and then that number is stale.

We haven't updated that 450 net MBOE per well for several years, and we have made quite a bit of advancements since then in the high density frac technology, and now we're making advancements in targeting also, so those numbers, it takes a little bit of time to get confirmation on what the new EUR number is, so when you make these advancements, you want to make sure you get at least a years of production, and then you can adjust them up accordingly.

Thank you, Bill, and my follow up, Bill, in some cases you've now stratified the inventory a little but between premium and other locations. You mentioned in your prepared remarks about EOG potentially being open to upgrading or trading inventory, and I was wondering if you could maybe elaborate on that for the nonpremium inventory?

The nonpremium inventory will have two avenues. The first avenue will be that we believe the majority of it will be converted to premium over time as we continue to learn how to target the rock more correctly and we continue to be able to be better at picking out the high quality rock in the target zone, so it's an ongoing process in every one of these plays, and we expect to continue in improvement.

If it doesn't make it to the premium inventory level, and it never gets in our CapEx, then certainly it has a lot of value, all this nonpremium inventory that we have, if you compared it to the rest of the industry, it would be tier 1 inventory. It's very high quality, so that gives us a chance to market this as we go forward down the road, and through property sales as we normally do in our asset upgrading process.

Hello?

And we'll go next to Brian Singer.

Thank you, good morning.

Good morning.

Bill, in your opening comments, you mentioned a focus -- more specific focus of EOG being a competitive low-cost producer in the global market, not just US shale. Before we run with this too far, do you still expect to do this predominantly through US shale or is this any signal you're willing to pursue international shale or global nonshale investment opportunities to a greater degree? And is it still your view that you can do this from the premium focused areas that you have talked to and that you have in the Delaware Basin, Eagle Ford, and Bakken?

Brian, we have no intention of expanding international efforts, so we are going to be very much US driven. We see tremendous opportunity in the US, and so this whole direction towards being not only a low cost producer in the US horizontal group, we are, you know; we think we're clearly there.

And our sight now is really set on being one of the lowest cost producers in the world market, and we believe that we can accomplish this with our very high quality assets that we currently have and continuing to improve them, and continuing to come up with new technology as we go forward, and we also believe very strongly that we can continue to grow that quality asset much faster than we're drilling it. And that would be through converting existing inventory into premium, and also through new plays.

So we see tremendous opportunity in the US, and we're going to stay focused there, and we're quite confident that we can continue to lower our operating costs, lower our well cost, and improve well productivity to become more than competitive in the world.

Got it. Thanks, and then on the follow up side, just two little questions. One, you highlighted exploration here, and I wondered if you could give an update on whether you expect to bring any meaningful products to the finish line, and ultimately announce that in 2016 or whether the reduced budget is prohibitive in that regard. And then on the asset sale front, have you worked any of, any production impact from potential asset sales into the guidance that you've provided?

Yes, for the latter part of your question, we have not put any asset sales volumes into the production guidance. And so the first part of it, what was the first part of the question? Oh, yes, exploration.

We did not want to take any short-term cuts that might affect the long-term benefit of the company this year, so we left in a considerable amount of money in the current budget for exploration, both in acreage, buying acreage on emerging plays and we'll also have several tests of new plays, continuing this year. So we'll see how all those go. We're quite hopeful, quite optimistic that we have maybe some plays that will be premium plays. We won't move them forward unless there would be premium, of course, but we're quite optimistic on the exploration front.

And the next question is from Pearce Hammond with Simmons & Company.

Good morning. Thanks for taking my questions. My first question is what commodity price assumptions are embedded in your 2016 capital plan?

Pearce, we use the strip, and we use a strip that was in the first part of January, and so we haven't got any -- we don't really put in a lot of upside to the current prices. I think it was based on prices around $40 was the current strip we used.

Perfect, thank you, and my follow up, this is kind of a hard question to ask, so just bear with me., but it follow up on Brian Singer's question. On the exploration front, for the past number of years you guys have worked on various plays and obviously you've had tremendous success with the Eagle Ford as an example, but now you know, those plays -- some of those plays weren't economic or couldn't compete with your really core plays, back when oil was $80 to $100, and now obviously oil is a lot lower, and I know service costs have come down.

But when you look at those plays and you also look at what you mentioned in the press release about these premium inventory and how much success you're having at improving your existing inventory, would it make sense, instead of spending the money on exploration, on trying to discover new plays, to actually use that money to buy existing acreage around the core, around plays, whether it be the Eagle Ford, the Permian, the Bakken, Scoot Stack or whatnot, and then take your core competency and expertise which is clearly in making something better. Would it be a better use of the capital and generate a higher return for shareholders?

Pierce, let me let Billy Helms comment on that. We're very focused both on tactical acquisitions. Let me let him give you some color on that.

Good morning, Pierce. What we were able to accomplish last year was a good example of that. We focused in first, the first effort is understanding where the premium acreage is that Bill described earlier. It gets down to basically understanding the rock, and we have to understand where that rock exists and then those pieces that are added to our portfolio, they compete for capital in our existing portfolio, certainly we'll add to that, as we exhibited last year in our Delaware Basin acquisitions.

And we'll continue that effort as we go into the next year. That's just part of our ongoing philosophy of how we continue to grow the company. And we balance that off with, as you know, we also manage to sell off properties every year, and so we balance those two with the overall capital discipline we have in the company, so that's always been part of our strategy, and will continue to be.

And the next call is from Paul Sankey with Wolfe Research.

Hi, good morning, everyone. I was wondering if your drilling contracts are committing you to more drilling than you would otherwise do all things being equal. It just feels as if you're somewhat dependent now on the oil price recovering. But more importantly I was wondering whether, if you didn't have those locked in drilling contracts, you would actually be completing more wells and drilling less? Thanks.

Paul, we did enter the year with 13 rigs under contract. I think the average this year will be 11 rigs. We looked very hard at trying to buy up those contracts to reduce that since we do have so many DUCs in place. But when we ran the numbers, it just didn't make economic sense. Those rigs are the best quality rigs in the business. The efficiency is tremendous, and it just didn't make economic sense to buy those out.

And so we're really focused on -- going forward, we didn't want to grow oil. Obviously this year, in the low part of the cycle and so we didn't want to accelerate the DUCs, and so I'm going to let Gary Thomas give you a little bit more detail on the rig situation and our DUC situation.

Yes, Paul, this is Gary, and if we didn't have these rigs under contract, we would certainly be completing more of our DUCs, with them all being premium wells. But we're just honoring those contracts and as Bill said, yes, we're going to average -- we were 27 rigs under contract in 2015, it's 11 this year, and it's the average 5 1/2 next year. So yes, in 2017, we'll be able to certainly accelerate the completion of our DUCs, which will be very beneficial to us.

Yes, and the follow up would just be, I assume that at these prices, CapEx would be lower but for the contracts?

That's right. Yes.

And you would simply -- neither completing nor drilling as much if it wasn't for the fact you're committed and it would be too expensive to buy the contracts out?

That's correct. Yes, sir.

That clarifies it.

Much more flexibility.

Got it, understood. Thank you.

Next is Biju Perincheril with Susquehanna Brokers.

Hello, thanks, good morning. Bill, I had a question about the high-density completions. It almost sounds like when I look at it, you're sort of taking the unconventional [rust] bore and transforming it into something close to a conventional rust bore or the well bore, and I don't expect a fair way to characterize it. But I guess my question is, do you think there is any implications for the longer term shape of the decline curve of this new completion? From, you know, thinking several years out. I'd like to hear your take on it. Thanks.

The high-density completions, what they do, you described it fairly accurately, is that they contact enormous amounts of surface area of the rock, and they get it very, very, very close to the well bore, so obviously the better the rock, and the more that you connect to the well bore, especially close to the well bore has the tremendous effect on the uplift of wells, and let me let Billy Helms comment on kind of the long-term effect of this uplift.

Yes, Biju, you did characterize it fairly accurately. I think that one way to think about it is certainly the more rock you contact in the reservoir, basically, yes, you're going to increase the initial potential of that well. But by contacting more of that rock, you're also increasing the ultimate recovery from every well, so you will see good initial production rates, but your decline, we're seeing the benefit of declines flattening with more production from these high-density completions. So the overall effect has been quite uplifting.

So when we compare the shape of the decline curve in the longer term do you think it will remain fairly similar? So, you know, when we look at sort of the terminal rates, would you expect a higher decline for the higher density completions? Or no?

No, actually, we're not seeing that at all. We're seeing, you know, longer term, the well to produce longer and initial decline is a little bit less than the older completions are. Just simply because you're connecting a lot more rock to the well bore.

Perfect. Thanks. Appreciate it.

Our next question is from David Tameron with Wells Fargo Securities.

Hi, good morning. Bill, how do you think about a ramp as you go into, assuming we get some upper pressure on prices a year from now, like how quickly can you ramp? I know you talked about prior, you know, the availability of people and maybe the services industry can't respond as fast, can you just walk us through how you'd see a scenario of, you know, oil goes back to $55 tomorrow, like how does that play out for EOG?

David, we're set up tremendously well, of course we're going to have a very large, very high quality DUC inventory. We have rigs in place, and we have a substantial amount of frac spreads running. We delayed the work schedule on some of the frac spreads to maybe five days a week instead of seven days a week type scenario, so that we could keep a number of frac spreads in place that would be easy to accelerate.

When oil prices begin to recover, you know, we're going to be disciplined, going forward. We don't, obviously don't want to be fooled, again, like the industry was fooled last year, by a little bit of an uptick in oil price, and it is not sustainable, so we're going to be disciplined in costs just going forward on ramping up capital until we're very much convinced that this is not a short-term uptick in the price and that the market is more in balance, and that the price is more sustainable, but we think, I mean, obviously EOG is in a fantastic shape to generate extremely strong, we're talking about triple digit rates of return as oil prices improve, and we have the ability to grow oil when the time comes.

Okay. And then if I think about -- I've asked a couple others the same question, but if I think about, you know, if you make the decision tomorrow to add rigs and obviously with the DUCs, you can cover some of this gap, but how long -- you say tomorrow, you say -- let's add a rig. How long does it take before we see that production given the laterals and pads and everything else? Is that a six month before we start to see that production, the numbers?

David, I'm going to ask Gary Thomas to give some color on that.

David, the benefit to EOG is having these -- by end of year, we'll have 230 of these DUCs to complete.

Yep.

And with having those, and then having the number of flat frac fleets that we have currently that we could ramp up as Bill's saying, besides being able to add, when you just start with the completion and then bringing on, you can see a pretty substantial increase in volumes within three to four months. Now, when you were just starting grass roots with drilling rigs, it would be almost twice that long. Like you're mentioning the six month. It will be about half that time.

Okay. That's helpful. Thanks for all the color.

Our next question is from Mike Scialla with Stifel.

Maybe I'll follow up to David's question, sounded like you're not inclined to want to go back to growth mode unless you see a significant price increase, but looking at that inventory of 3,200 premium locations that generate 30% plus IRR with $40 oil, if it looks like that's all that we're going to get out of a recovery, would you go back to a growth mode if that were the case?

I think, Mike, that would give -- a $40 oil would give us obviously, a bit more cash flow, but we would be, you know, certainly wanting to stay balanced, discretionary cash flow to CapEx, so that's really going to control the amount of growth that we have. And along with making sure that the oil price is really sustainable, so we can generate the returns, but the growth of the company will be regulated by obviously the number of wells we complete and the continued improvement we have, but it would be regulated by the cash flow of the company.

Okay. And then can you talk about in terms of that premium count, you said, Bill, that you could grow that over time. You alluded to how you would do that with better targeting and -- but I wanted to see where you anticipate if you can say where most of that will come from. Is it down spacing in the Eagle Ford? Is it primarily from the Permian or somewhere else?

Mike, it will be from really multiple sources. We're learning in every one of the plays that we're in. And it's really just being able to identify those target windows within those good plays and executing on those. So we were still working on down spacing in every one of the plays, so it will come from multiple plays, improving the inventory there to premium, and then it will come from a new plays, too.

We have quite a bit of confidence that through our learning process on the existing plays that we can identify very high quality rock in emerging plays, and so we're actively engaged in buying acreage and testing wells in those cities, and so it will come from multiple source. Historically, even through the uptick, when we had $95 oil, and we were growing very quickly, and drilling a lot of wells, we were able to add twice as many wells each year than what we actually drilled, and so we're very confident that we can continue that kind of multiple on the premium going forward.

Great. Thank you.

And the next question is Subash Chandra with Guggenheim.

Yes. Good morning, are we looking at a permanent shift to better wells but fewer wells in how exacting your premium process is and how reliant it is on, you know, massive data analysis? And then I have a follow up. Thanks.

Well certainly, when you're drilling twice as good of wells, you don't have to drill nearly as many of them. And so that certainly helps keep your CapEx down and you're able to have a lot more efficiency there. so as we go forward, the learning process will be incremental at each one of these plays, and it's an ongoing thing.

We learn this, and then we try it. And as we get good positive results we're able to apply that to additional wells. The sustainable technology gains that we have in the company have been very, very continuous, and very steady over the whole life of involvement in horizontal drilling. It's over ten years of experience, combined knowledge, and we have quite an innovative culture in the company, and we expect that to continue to improve the wells as we go forward.

And the follow up is, and no question, you're light years ahead in many ways. When we think about the additional inventory, in that it's dependent on data, that where you have more wells is likely where we'll see more inventory over time? And so the other side of that is how applicable is this to new exploration concepts?

Yes, correctly when we have an ongoing drilling program, and we're collecting data all the time in existing play, that's certainly how you make advances. But we also are able to take that learning experience and apply it to new plays.

So the high density frac techniques, the kind of rocks that would respond to high density techniques and then the petrophysical properties of rocks in emerging plays and then the core work, we do an extensive amount of very detailed core work and we integrate all this data along with 3D seismic, and so all that goes into bear on defining new plays with high quality rock. It's a learning process that spills over, and it really helps us keep the momentum and to keep adding premium inventory to go forward.

That concludes today's question-and-answer session. Mr. Thomas, at this time I will turn the conference back to you for any additional or closing remarks.

EOG's got a strong track record of game changing events that have made the Company successful over time. Our shift to premium drilling mode this year with an estimated 50% year-over-year increase in well productivity is another step change to the Company's performance.

Premium drilling allows EOG to generate solid capital returns at $40 oil, and quite frankly, spectacular returns as oil prices recover. With our focus on improving returns instead of production growth during this down cycle, EOG is now positioned for tremendous performance as prices improve. We believe the best times for the Company are ahead of us, so thank you for listening, and thank you for your support.

This concludes today's call. Thank you for your participation.