Timothy K. Driggers - Chief Financial Officer & Vice President William R. Thomas - Chairman & Chief Executive Officer Lloyd W. Helms - Executive Vice President-Exploration & Production David W. Trice - Executive Vice President-Exploration & Production Gary L. Thomas - Chief Operating Officer.

Evan Calio - Morgan Stanley & Co. LLC Arun Jayaram - JPMorgan Securities LLC Scott Hanold - RBC Capital Markets LLC Subash Chandra - Guggenheim Securities LLC Doug Leggate - Bank of America Merrill Lynch Charles A. Meade - Johnson Rice & Co. LLC Bob Alan Brackett - Sanford C. Bernstein & Co. LLC Pearce Hammond - Piper Jaffray & Co. (Broker) David R.

Tameron - Wells Fargo Securities LLC Irene Oiyin Haas - Wunderlich Securities, Inc. Brian Singer - Goldman Sachs & Co..

Good day, everyone, and welcome to the EOG Resources 2016 first quarter results conference call. At this time for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir..

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 second quarter and full-year 2016 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review our 2016 plan and first quarter highlights.

Billy Helms and David Trice will review the operational results. I will then discuss EOG's financials, capital structure, and hedge position. And Bill will provide concluding remarks. Here's Bill Thomas..

Thanks, Tim, and good morning, everyone. EOG is becoming an even better company that was just a year ago about lowering development and production costs and increasing returns. In yesterday's press release, we announced two exciting developments that have the potential to be significant additional drivers of higher returns and lower costs.

I'll briefly highlight those, and Billy and David will provide details in a moment. Finally, I'll review our shift to premium drilling and how this shift is a game-changing event with significant long-term implications for EOG shareholders.

First, I want to highlight EOG's development of the first successful enhanced oil recovery [EOR] technology in U.S. horizontal shale. We initiated our EOR efforts in the Eagle Ford three years ago. Here's what we've learned since that time. Number one, geology matters. The Eagle Ford is unique.

The same geologic characteristics that make the Eagle Ford prolific in primary development also make it unique for enhanced oil recovery. The EOR process we are using to produce incremental oil out of the Eagle Ford is not necessarily applicable to other horizontal basins. Number two, how you initially drill the field matters.

Secondary recovery works best on leased units that were developed using the best completions with optimal spacing. Finally, returns matter. We figured out how to execute EOR economically. The process can be implemented at rates of return that rival our premium drilling and significantly lower finding costs over time.

The second item I'll highlight is our discovery in the South Texas Austin Chalk. The term "discovery" is loaded, as many operators have been drilling the Chalk for years with varying degrees of success. Perhaps a more accurate characterization is that we discovered a new geologic concept in an existing play.

Our team at EOG has cracked the code on how to make our particular footprint in the Austin Chalk a top-tier horizontal play, earning returns on par with the Eagle Ford, Permian, and Bakken. The third item I would like to review is EOG's shift to premium drilling this year. The shift is a game-changer with significant long-term implications.

I will cover those implications in a moment. But first, let's review what we mean by premium. Premium inventory is defined as drilling locations that generate at least 30% direct after-tax rate of return at $40 oil. Here are a few more clarifying points regarding this inventory. First, 30% return is not an average; it's a minimum.

Second, 30% was established as the minimum direct return to ensure that when indirect costs are included, the drilling program earns healthy full-cycle returns. Third, we fully expect to more than replace our drilling inventory with new premium locations every year. Therefore, and this is the most important point.

Our shift to premium is permanent and not simply a temporary high-grading process in a low commodity price environment. So early 2016 will mark the point in time that EOG made a significant permanent shift in its drilling program. There are many long-term implications for that shift. The first is superior capital discipline.

Premium drilling sets a new higher standard for capital allocation within the company. The second is a large capital efficiency gain. We do not need 50 rigs drilling thousands of wells per year. It will take far less capital to grow production at strong double-digit rates.

The third implication is we can return to triple-digit direct rates of return with oil as low as $60 per barrel. And if history is any indication, we will continue to push the oil price needed for triple-digit returns even lower. And finally, premium drill extends our lead as the low-cost horizontal oil producer.

As I outlined, our permanent shift to premium drilling this year is a game-changing event for EOG.

Yesterday's announcement regarding our enhanced oil recovery success in the Eagle Ford and our Austin Chalk drilling success are two more technical and operational achievements that help us reach our long-term goal of being one of the lowest-cost producers in the global oil market.

Now I'll turn it over to Billy Helms to discuss our exciting results from enhanced oil recovery in the Eagle Ford..

Thanks, Bill. Three years ago we initiated an effort to test EOR using gas injection in horizontal shale. The results from lab experiments indicated that the process was technically feasible, but the economics and operational execution were going to be challenged without some creative problem solving.

Our EOR team has not only solved the problem, but demonstrated returns that are competitive with our premium drilling program. That EOR process we developed is highly proprietary, and this limits the amount of detail we are able to disclose. However, I will share several reasons why EOG is uniquely positioned to achieve a successful outcome.

As Bill mentioned earlier, the geological setting is important. We have long discussed the competent barriers that encase the Eagle Ford and provide vertical containment for completions. This unique feature also plays a significant role in keeping the injection in contact with the targeted reservoir.

The injected gas is thus able to become miscible with the oil in the reservoir and subsequently drive incremental oil recovery. EOG's acreage position is situated in the optimal thermal maturity of the play to maximize oil recovery.

Being in the oil window has provided many benefits during the primary development, but it's also important for the EOR process. Acreage that is too far downdip or updip in the play may not benefit as greatly. The EOR economics are significantly enhanced by the scale of EOG's footprint in the play.

The infrastructure and facilities that are utilized during primary development across the field are key to being able to operationally execute the EOR process, thus providing a significant economic benefit.

These reasons are the keys to the process's success and are why that we believe EOR will not be a blanket application across the Eagle Ford or necessarily applicable to other horizontal shale plays. We have not yet determined how much of EOG's acreage will benefit from EOR or what the overall resource potential may be.

The four pilot projects have tested different geographic and geologic settings, each proving the concept successful. But further definition and time will be needed to assess the applicability and overall benefit across EOG's acreage position. Here are some of the key takeaways regarding the economics and recovery potential.

One, this EOR technique is not capital intensive. There is no incremental drilling required, so capital costs average approximately $1 million per well. Two, the operating costs are low. The process makes use of produced gas readily available to the field, and there are few other incremental operating costs.

Three, EOR may have significant effect on our long-term Eagle Ford base production profile. Unlike typical secondary recovery projects, the production response occurs quickly, within the first two to three months, and holds steady for longer.

Four, the combination of lower operating costs and steady production delivers a return profile that complements our primary drilling program. Primary drilling delivers high returns and short paybacks.

Our EOR pilots have a much different profile, characterized by modest upfront capital investment that delivers a long annuity of incremental oil production and strong cash flow. The rate of return is still on par with primary drilling. But for each dollar invested, EOR delivers at least twice the net present value created as primary drilling.

Finally, our models indicate that this process will increase recovery by 30% to 70%. I want to emphasize. These are incremental potential reserves, not accelerated production, delivered at potential finding costs of $6.00 per barrel or below or less. We will conduct a fifth pilot in 2016, and we will evaluate the results and review our acreage.

We will determine the long-term capital production and earnings effect of EOR. It's important to note that while this is a significant technical and economic breakthrough, rolling out this effort will take time and is dependent on the pace of primary development drilling and field development. Now here's David Trice..

Thanks, Billy. Another exciting development on our South Texas acreage position concerns the Austin Chalk. In our press release yesterday, we published the results of two tremendous Austin Chalk wells. The Leonard AC Unit 101H produced an average of 2,715 barrels of oil equivalent per day for 30 days.

The Denali Unit 101H was completed in April, and its average production for the first 20 days was 3,130 barrels of oil equivalent per day. While the Austin Chalk is not a new play, historically industry production has been inconsistent from well to well.

While good wells are possible, the performance and resulting returns are highly variable across the play. However, using proprietary petrophysical analysis, we discovered how to apply new geologic concepts to the Austin Chalk and drill prolific wells consistently. Much like the Eagle Ford, the Chalk responds very well to EOG-style completions.

Our high-density completions create complex fracture systems close to the well bore, significantly improving well performance. Also like the Eagle Ford, the Austin Chalk benefits from the detailed work we conduct to determine the best target.

The chalk can be as thick as 140 feet in some areas, but our targeting efforts keep the drill bit confined to the best 20 to 30 feet of rock. Precision targeting combined with EOG-style completions is now generating prolific premium level well performance.

It's too early in our exploration efforts to know how much of the Austin Chalk is prospective over our acreage, but subsurface data and detailed mapping throughout the field are encouraging. We plan to drill seven additional Austin Chalk wells in 2016 and look forward to updating you with future drilling results as we learn more.

In the Permian Delaware Basin, our recent activity has focused on the Wolfcamp oil window. Drilling the Wolfcamp generates excellent returns while allowing us to collect data on the shallower targets, such as the Second Bone Spring sand.

During the first quarter, we completed a dozen wells, with per well average 30-day rates over 2,100 barrels of oil equivalent per day, with approximately 70% oil cut. The average lateral of these Wolfcamp wells is approximately 4,500 feet.

Over the last year we've focused on increasing our understanding of the geology and maximizing well performance through better technology, such as precision targeting, high-density completions, and better well bore design. As a result, our wells are industry-leading, as illustrated on slide eight in our investor presentation.

Since January of last year, our wells have been twice as good as the industry average in the Midland or Delaware Basin when normalized for lateral length. This is the approach EOG takes across all of our plays.

We seek to first, understand the geology; second, optimize the completions; and finally, enhance operational practices that maximize efficiencies and lower cost. Our next step for Wolfcamp optimization is to extend the lateral.

The breakthroughs we made in well bore design will allow us to apply EOG-style high-density completions to long Wolfcamp laterals. Longer laterals will enhance the economics of our highly successful Wolfcamp program and reduce our surface footprint across the play. In April we drilled two 7,000-foot laterals, the Rattlesnake 21 Fed Com 701H and 702H.

These wells are too new to report a 30-day rate. However, the first 20 days of production are averaging more than 3,800 barrels of oil equivalent per day per well with maximum 24-hour rates of 4,200 barrels of oil equivalent per day per well. Meanwhile, we continue to further improve operational efficiencies and costs in the Wolfcamp.

During the first quarter, drilling days decreased 14% from our 2015 average to 16.1 days. Also, total well costs decreased 8% to $6.9 million, more than offsetting costs associated with continued completion enhancements.

In addition, in the second quarter we'll begin using our brackish water supply for our New Mexico completions, with an anticipated saving of $150,000 per well. This new water supply along with many other operational improvements will allow EOG to continue to lower cost and increase returns.

On the international front, we are very happy to report that our East Irish Sea Conwy project achieved first production in late March. We are currently addressing normal startup items, and running tests to determine the optimal production rate. Our full-year guidance has been adjusted until we complete more testing. Here's Tim Driggers..

Thanks, David. Capitalized interest for the first quarter 2016 was $9 million. Total exploration and development expenditures were $568 million, excluding property acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $25 million.

As compared to the first quarter 2015, total exploration expenditures decreased by 62%, while our total production volumes decreased by just 7%. We have maintained our full-year capital expenditure guidance of $2.4 million to $2.6 million (sic) [$2.4 billion to $2.6 billion].

At the end of March 2016, total debt outstanding was $7 billion, and the debt to total capitalization ratio was 36%. At March 31, we had $700 million of cash on hand, giving us non-GAAP net debt of $6.3 billion, for a net debt to total cap ratio of 34%. The effective tax rate for the first quarter was 34%, and the deferred tax ratio was 82%.

For the period May 1 through June 30, 2016, EOG has crude oil financial price swap contracts in place for 128,000 barrels of oil per day at a weighted average price of $42.56 per barrel.

For the period June 1 through August 31, 2016, EOG has natural gas financial price swap contracts in place for 60,000 MMBtu per day at a weighted average price of $2.49 per MMBtu. Now I'll turn it back over to Bill..

Thanks, Tim. First, a brief word on our macro views and how they relate to EOG's plans. The substantial reduction in capital investment by the industry in 2015 and 2016 is causing oil supply to decline in many producing regions around the world. Led by steady declines in the U.S.

and supported by strong gasoline demand, the market continues to rebalance. We agree with consensus that this process will accelerate in the second half of this year and into 2017. We believe that in the U.S., it will take a sustained $60 to $65 oil price and 12 months of lead time for the industry to deliver a modest level of growth.

However, what is true for the industry in general does not hold for EOG. EOG is the low-cost U.S. horizontal oil producer. With our premium drilling inventory, we believe our reinvestment advantage is $15 to $20 per barrel lower than the average industry operator.

When the market balances and prices recover to moderate levels, our leading asset quality, best-in-class technology, and low cost structure will become apparent with how quickly we can resume high-return oil growth.

And that may be the number one question we received the last two months, or more accurately, at what price will you accelerate and return to growth? Our first priority this year is to completely fund our capital program with cash flow and reduce net debt with property sales.

We're in the late stages of negotiating on a number of deals and are confident we will be successful on many this year. We expect their collective impact will be meaningful. Our second priority will be to complete DUCs.

We have managed our operations such that we have the capacity to add 40% more completions without adding any additional equipment from the service industry. We can respond quickly as supply and demand balance and oil prices firm. In summary, I would like to leave you with the following important takeaways from this call.

Number one, our shift to premium drilling this year is a game-changer. We expect well productivity to improve more than 50% in 2016, which is the largest one-year improvement in the history of the company. More importantly, this shift is permanent.

Premium drilling will allow us to maintain a balanced capital program and resume high-return oil growth in a moderate oil price environment. Number two, our enhanced oil recovery success is another example of EOG's ability to make significant technology gains.

EUR has the potential to add meaningful long-term value to our Eagle Ford asset by adding low-decline, low-cost, high-return reserves. Number three, the new Austin Chalk results are encouraging for our South Texas acreage position.

Time will tell, but we believe the chalk geology we discovered is substantially better and more repeatable than previous chalk drilling. Number four, last year we said 2015 was a record year for improving the company. As we start this year, we are beginning to realize that improvements in 2016 may be even stronger than 2015.

Our sustainable gains in technology and efficiencies are running at record-setting pace. And we are excited about what we can achieve in cost reduction and productivity improvements in 2016. Number five, our goal has always been to be the highest return E&P company in the U.S., and we believe we have achieved that goal.

Our sights are now set on becoming one of the lowest cost producers in the global oil market. We believe it's possible, and we are moving toward that target rapidly. Thanks for listening, and now we'll go to Q&A..

Thank you. Our first question comes from Evan Calio with Morgan Stanley..

Hi, good morning, guys, and thanks for all the comments. The new EOR results are very encouraging. I know the next step is the 32-well pilot.

But once that's complete, what are the remaining gating items to full-scale development, or when do you expect to better understand the extent of the opportunity across the play?.

Evan, this is Billy Helms. So as you mentioned there, the next step obviously is implementing the 32-well pilot. We're still learning a great deal about the process and what its overall impact will be.

And primarily the pace of development in the future will depend on our pace of development primarily for the developing out the remaining leases and then how we roll that out. I would say that our pace of rollout, we expect to continue to announce new wells or bring new wells into that process in the coming years.

And it will become a part of our overall capital allocation to the Eagle Ford that we do primarily each year, and we'll roll out certainly our 2017 guidance on that probably in February. But we are very encouraged with our initial results. So it's probably a little bit too early to talk about how we're going to roll that out.

We still have a lot to learn from our 32-well pilot. And then we still have a lot of leases to develop too..

Does the existence of the EOR potential later in life opportunity, does it change the way you allocate capital on primary drilling, meaning does it make the Eagle Ford either relatively more attractive or the black window versus the condensate window more attractive given this new secondary recovery option?.

Evan, this is Bill. I don't think it changes it dramatically. We're focused on premium drilling in all of our plays. And the Eagle Ford, that's what we want to develop first in our leases and that's what we're going to focus on really permanently from now on. So we'll develop those at a normal pace.

As Billy mentioned, the key is really to get those developed with the drilling and the completions in the most optimal spacing and to connect as much rock through the primary process and that really enhances the EOR effectiveness as we go forward.

So we'll move along both of them at a nice steady pace, and we'll just continue to learn as we go forward. And I think the EOR process will be much like the drilling program. We'll get more efficient as we move forward and we'll be able to lower costs, and it will just become a normal part of our investment in the Eagle Ford..

Great, guys. I'll leave it there. Thank you..

And we'll move forward to our next caller, Arun Jayaram with JPMorgan..

Good morning. Bill, on the EOR process, you've done four pilots and tested it on 15 producing wells.

Were the tests successful on all the wells, or could you just talk a little bit about the effectiveness that you've seen thus far?.

Arun, this is Billy Helms. Certainly, in each one of our tests we've learned a lot. I would say without hesitation that all of our pilot tests were successful. Certainly we continue to learn from each one.

We started the project really with some laboratory experiments on just trying to understand what the fluid behaviors would be, and that certainly was very encouraging. Then we rolled it out to a single-well pilot and had positive results from that. And then we started applying it to more multi-well pilots.

We had two four-well pilots and a six-well pilot, and each one of those was successful. So the next step, as we discussed, is to roll it out on more of a field-scale model, which is this 32-well pilot, and we'll certainly continue to learn from that. But yes, each one was very successful..

Thanks for that. Then just my follow-up, Bill, in your prepared remarks when you're talking about the premium locations, you express confidence that you could replace these premium locations from an inventory perspective on an ongoing basis.

Can you just give us a little bit more color around what's driving that confidence?.

Yes, Arun. As you know, we believe we have very sustainable cost reduction and technology gains. We've done it every year we've been in the business, and we have a lot of confidence and we see a lot of upside going forward to continue that process.

So as we increase productivity through being able to identify bedrock and precision targeting and get even better with our high-density frac techniques, we believe that the well productivity will continue to increase. That would be one way to convert. And then we also believe that we have sustainable cost reductions.

So two-thirds of our cost reductions during the downturn have been through technology and efficiency gains, and we do not see any end in that. So we're quite confident that efficiency and technology will continue to drive those costs down.

And so we believe a large percentage of the inventory that we have in the Eagle Ford will be converted to premium. We also believe that in the Permian, and we believe we'll add continued premium in the Bakken and other plays too. So we're very confident that our premium inventory will grow much faster than our drilling pace..

Thanks..

We'll move forward to our next question from Scott Hanold with Royal Bank of Canada Capital Markets..

Yeah. Thanks, another question on the EOR process. And I know a lot of the stuff that you all did was proprietary. But when do you think it's the right time to actually put this application to work? So what I'm getting at is obviously these wells have a pretty steep decline rate in the first few years.

But generally speaking, is it something that happens more typically earlier in the life compared to say, what occurs in conventional reservoirs when you apply a similar application?.

Yeah. Scott, this is Billy Helms. Typically, the governing part will mainly be – in actual field applications will be on how we develop each pattern. So as Bill mentioned earlier, the primary goal will be to go through and do a full-scale development on each and every lease with the latest high-density completions. That's the number one goal.

And the pace of development from that will dictate as to when we roll out the secondary or the EOR process. But typically – I think we have a slide in the deck on I think slide four that shows that timeframe will be somewhere in the first two to five years. So I think that would probably be our initial guide.

There's really no detriment that we see as to if you wait too long to implement it, it's going to be detrimental. We think it's a great tool for just continuing to contact the remaining oil left in the reservoir. Certainly, economically there might be an advantage to doing it earlier than later.

But more importantly, the advanced completions are driving probably incrementally more success to start with. So I don't know if that helps answer your question, but I would say that it will be somewhere in that first couple years, two to three years of development..

Yes, absolutely, that does help. And I was just trying to gauge how this compares to say a refrac or something else through the life of the well, but great. And as my follow-up question, and obviously, you all had I believe tried this up in the Williston Basin, some enhanced opportunities.

Several years ago, that may not have been as successful, and I know it may not be applicable everywhere.

But can you compare and contrast what occurred then versus now, and if what you learned in the Eagle Ford could actually be transferred up into the Williston?.

Yeah. The Eagle Ford, as we mentioned in the call, one of the primary factors in the Eagle Ford's success is the vertical containment. The Eagle Ford is very well encased and has good strong barriers for both upward and downward growth, which is key for the process. The Bakken and many other plays are going be more challenged in that area.

That's probably the key primary difference that I would say lends to the success more readily to the Eagle Ford than maybe other plays..

Thank you..

And we'll move forward to our next question from Subash Chandra from Guggenheim..

Yeah. Thanks.

First question is as you talk about these 50% efficiencies in 2016 and the continued focus on ROI over growth, how does this influence your desire to outspend in a normalized oil price environment?.

We have no desire or intention to consistently outspend. So the number one goal this year is to balance our discretionary cash flow with CapEx, and then of course we are working on property sales to help us reduce net debt. And if prices continue to firm, we have a lot of confidence that we're on the road to accomplishing that.

We do believe that because we're seeing significant cost savings in the current drilling, we think that's going to continue, and any extra capital that we would have from cost savings, we will apply to completing new wells. And that will be – we're going be disciplined.

We're certainly watching the market to make sure that we're not in a temporary uptick on prices, that the prices are more sustainable. But when we feel good about that, we will apply those cost savings to completing additional DUCs later in the year, most likely in the fourth quarter.

We want to enter 2017 on a growth mode, in an uptick, so we believe that we'll have the capital to do that..

Okay.

My follow-up is any update or guidance on, for lack of a better word, rank exploration, as we've the last couple of quarters talked about the refinement of your existing portfolio, how your progress on a new portfolio of opportunities?.

Yes, we have a very robust exploration effort on new plays, and so we have various plays actually we'll be testing this year. We'll update you that when we have some meaningful results. And then we're also picking up acreage. It's been a great time to pick up low-cost acreage in places that we couldn't get acreage in, in previous years.

So we have an active program going on. Of course, we're very selective. We only want premium plays to fit into our capital program. So we're identifying rock that would meet that category and deliver those kinds of returns. So we're not shortchanging that effort at all..

Thank you..

We'll move forward to our next question from Doug Leggate with Bank of America Merrill Lynch..

Thank you, good morning, Bill. Good morning, everybody. Bill, the Austin Chalk inventory, I realize it's early days, but you haven't added to your inventory, at least not in the slide deck so far. What do you need to see there? When do you expect that you'll be able to give us some updates? I'm just thinking about the development.

Again, realizing it's early days, but will you develop this concurrently with same pipes (38:05) off the Eagle Ford, or how are you thinking about that in terms of relative economics?.

Yeah, Doug. This is David. On the Chalk, we drilled these two wells. We've taken a couple of cores here, and we've got quite a bit of log data to go with that. So we really mapped out the play. And we're feeling pretty confident that we can move this play into the premium category and have a meaningful impact to EOG.

So we're going to go ahead and test – like I mentioned in my remarks, we'll test another seven wells this year to delineate the play. And then like I said, we'll go ahead and move that into the premium inventory account. So it will be developed along with the Eagle Ford..

Okay, we'll watch for more details. My follow-up is I've got to say, as an old reservoir hack, you guys never cease to amaze us with the things you've been able to do. And those EORs are another example of that, but it also provides us with a bit of a modeling challenge.

So I'm wondering if you could, to the extent you can, help us with some ideas how you would think about fitting that into the portfolio.

What I'm really getting at is, is this an individual well situation? Is it a cluster of wells? Is there a minimum area that we think about? Anything you can help us in terms of framing what the relative scale of this would look like once you get going.

And maybe as an add-on, what proportion of your Eagle Ford today is ready to go in terms of being able to move this thing forward?.

Doug, this is Billy. The second part of your question there, to the extent of the acreage that might be applicable to this, honestly we just don't know at this point.

We do know that there are some areas that probably will be challenged to work economically, but we are still early on in that process in trying to determine how much of the acreage is applicable. We just don't know yet. Now the 32-well pattern is probably a good indication of maybe what we'll look at in the future.

It will be subsets or leases that will dictate the size of how we develop it going forward. So maybe you guys think about it instead of a single well, it will be groups of wells that will be implemented at one time and not single wells.

So we're trying to give you some guidelines on what we think the capital cost is, and we tried to boil that down to a single well, just so you think about it and knowing that each lease will have different counts of wells, maybe 12 to 20 wells on a given lease.

And then the production profile, we've given a cume curve out there that maybe gives you some insights on what the cume curves might look like. The production response from this is pretty unique in the sense of secondary recovery projects in that it's probably the only process that gives you such a rapid production response.

You get a response in the first three months essentially, which is pretty fast. And then it holds pretty steady for a number of years. So that may be – and so that's probably about as much detail on how we see how it would be rolled out. Again the pace it's on – I know it's tough to model economically.

The pace of development is purely just going to be on the things we learn from this next pilot and then our development of existing units we've used in our high-density completions. So we do expect this to increase.

I would say we expect to increase the number of wells each year as we roll out the new budgets, and it will become an ever increasing part of San Antonio's capital allocation..

I appreciate the answer, Billy. Thank you..

And we'll move forward to Charles Meade with Johnson Rice..

Good morning, Bill, and to the rest of your team there. I really appreciate what you've been able to offer as disclosures here on this EOR. It's really a thought-provoking development.

And I wanted to ask if you could maybe add a little bit on what's driving that range on the 30% to 70% uplift versus the original EUR because it strikes me as a wide range. And I'm wondering if perhaps part of the explanation is a function of the vintage or density of the original completions this year you're working with..

Charles, this is Billy again. You're exactly right. I think that's a part of it. First of all, we're early in the process. So you have to remember that our forecast started out with trying to model – trying to use simulation models to match our history from the pilot projects and then forecast what the future production might be from these.

So we haven't actually seen long-term production from a pilot over the number of years it would take to demonstrate what the ultimate recovery is going be. We're trying to model that with some simulation techniques, I would say, that are challenged technically.

So we're working on some enhanced models to better understand what the long-term production will actually be. So I think we just need further clarifications and tests from existing pilots that we're in and future pilots to really nail that down. And then you're right. I think vintage of the completions will make a big difference.

The new high-density completions we expect will respond better than some of the completions done several years ago. Our pilot projects to date have been older-style completions in large part, so we expect improvements to continue to improve. I think there's upside there..

That's helpful color, Billy. And then if I could ask my follow-up on the Austin Chalk, I know that historically the way that play has worked is a lot of the successful wells have been a function of intersecting natural fractures. But I'm wondering if perhaps for your new concept, it's maybe the inverse of that.

And if you're not avoiding natural fractures in the wellbore, perhaps you're trying to avoid them in the stimulation of the zone, and if that's part of what you're trying to figure out here..

Charles, this is David. Yes, I think you're on the right path there. What we've learned is here where we're playing in the Chalk is the oil is stored a bit different than it has been in the previous history of the play. And what that does, it allows it to be a bit more predictable and also allows us to employ our completion techniques.

And so I think going forward, it's just going give us a little more certainty on drilling repeatable high-quality wells..

Thanks for that..

Charles, I'd like to add to that to expound on what David said.

I think the same techniques that we're finding very successful in these other plays, by identifying the very sweet spots, the very best rock quality with our proprietary techniques, and then being able to keep that bit in a very small zone in conjunction with the high-density frac, that's really the key to all these plays, and it's no different from the Chalk.

So we're just finding that we can identify quality pay in the Chalk, and we're very encouraged about that..

That's helpful, Bill. Thanks a lot..

We'll move to our next question from Bob Brackett with Bernstein Research..

Hey, good morning, more questions on the EOR side.

Is this a producer injector concept, or is a huff-and-puff?.

Bob, right now at this point we're not going to give you a lot of details around the process itself or how we're implementing it. But we will say that it is a miscible process.

And so you can read into that what you might, but we're not really giving a lot of specific details about how we're doing that or the interaction between wells or those kind of things..

You guys were issued a patent for a thermal process for shale a couple years ago.

This isn't that process?.

No, it's definitely not that process..

And could you give an idea of barrels per scuff in terms of how much gas injected versus how much incremental oil you get out?.

Again, we're not going to give a lot of details on how much gas we're injecting. But the important thing there is that – two things I guess. One is that we have gas readily available in the field.

And then two, with our large footprint there and the facilities and infrastructure that we've been able to put in place for our field really enhances our ability to move gas around and get it to these leases to take advantage of this EOR process. It really helps position EOG uniquely to be able to take advantage of something like this..

And then a final one, should we trust Railroad Commission lease level production? Will that be able to help us figure out incremental volumes, or is it just all wrapped up at the pad level so we can't – or lease level so we won't be able to see it?.

We're reporting production on a lease basis as we're required to do under the Railroad Commission rules. And certainly, over time there may be some things you can glean from that data. We'll see. Honestly, I have not checked a lot of that data to see what does it look like versus what we see internally.

But I think over time, you'll be able to discern what the actual results are, and I would expect that data will become apparent in the future..

Okay, thank you very much..

We'll move forward to our next question from Pearce Hammond with Simmons Piper Jaffray..

Good morning.

On the Austin Chalk, is your acreage already held by virtue of your completions in the Eagle Ford since you would hold all depth above the Eagle Ford? And then are you leasing any additional acreage?.

Yes, Pearce. Yes, we would. We hold the Austin Chalk with our Eagle Ford production. So yes, it sits right above the Eagle Ford.

And the second part of your question was?.

Are you leasing any additional acreage?.

As you know, there in the Eagle Ford the acreage is held pretty tight. So at this point, we're not leasing anything new on the Austin..

And then my follow-up, with the EOR technology, what do you think this does to your base decline? It seems like it would cause your Eagle Ford base declines to moderate significantly over time once you apply this technology in full force..

Pearce, I think that's right. I think overall benefit in the long term is it will help flatten the decline. The long-life decline from the field, we still haven't been able to quantify that yet. But we're certainly very optimistic that it will certainly be very meaningful to not only the individual leases but over the field in general..

Thank you, Billy..

And we'll move forward to our next question from David Tameron with Wells Fargo..

Good morning, a couple questions.

One, on the Austin Chalk, I guess one, how prospective do you think this is? Like how big is that sweet spot as a subset of your total Eagle Ford position? And then as I just start thinking about what – and I don't know if you guys will talk about it, but what are you doing differently? What can you give us as far as – or give the Street as far as confidence that this isn't the same Austin Chalk that's in everybody's head?.

David, this is Bill Thomas. As far as the potential on our acreage, we're encouraged because we see data, rock data and test data, on various parts of our acreage that are encouraging. And so we have seven wells, additional wells, additional to the two we've already drilled that we have planned this year that we'll be testing some of these concepts.

And so once we get those done and we get some results that confirm the production like we've seen, then we'll be able to I think give people an update that will be more meaningful on what the scope could be. And then on the technical side of it, let me let David update you on that part of the question..

Okay, thank you..

Like I mentioned before, we have collected a substantial amount of data. Pretty much all of the Eagle Ford wells that we've drilled have drilled down through the chalk. So we have a very good set of log data, seismic data, and like I mentioned before, core data to delineate this. So that's what gives us confidence.

And as well, there have been other industry wells drilled. Some of the larger operators have not necessarily drilled very good wells, but some of the smaller operators have drilled some really good wells along this trend. Some of them have cum-ed 300,000 to 400,000 barrels of oil in the first year. So these are substantial wells.

And like I mentioned before, based on the data we have, we think they're very repeatable..

Okay..

David, the technical advantages from a competitive standpoint are, I think, our ability to recognize these pay zones and then target those pay zones. That is before what we've learned on the other plays is applying to the Austin Chalk.

So we're just taking this targeting, precision targeting a step further to the chalk, and we think that's very proprietary knowledge at this point..

Okay, I appreciate that color, just one more follow-up. If I think about – and if you covered this, I apologize. I don't think I heard anybody talk about it. But as far as the DUC balance going into 2017, I know some of the rigs are coming off contract.

How should we think about the way you want to manage that going forward?.

This is Gary Thomas, David. What we've shared before is we're just going be completing roughly 270 wells this year, drilling about 200 wells. So we'll be completing roughly 70 of our DUCs. And we're just, as Bill said, we've got these in inventory.

When we see prices improve and we have additional capital, this will be just a source of assets that we can develop rapidly to bring on production when it's justified..

Okay. Appreciate it. Thanks for the time this morning..

And we'll move forward to our next question from Irene Haas with Wunderlich..

Yeah. Very quickly, this enhanced oil recovery process, how sensitive it is to gas prices? Right now we're at an all-time low.

But what if one of these days gas shoots up to $4.00 or $5.00 per Mcf, how would the process work then?.

Yeah. Irene, we've certainly taken a look at a lot of different pricing scenarios. But we've looked at it in the sense of what we're currently modeling and also incrementally up to $5.00 gas prices, and we still see incremental benefit and good economics even up to those levels.

So our economic sensitivity is not really a factor of what we think gas prices could be anywhere in the near future. So I think it's going to continue to be economic even at what we see could be a foreseeable gas price in the future..

Great, thank you..

And we'll move forward to our next question with Brian Singer..

Thank you, good morning..

Good morning, Brian..

I wanted to see if you can give us an update on your rig contracts.

How many are rolling off at the end of the year? And more importantly, what is your minimum or what are your commitments for 2017, and to tie that in a little with the discussion here on EOR and DUCs, whether you can get to a point or whether it can be meaningful enough from your investment in EOR and reducing DUCs where you can essentially have rigless growth in 2017?.

This is Gary. We have 11 rigs under contract currently, and that will decline to nine rigs at the end of the year. So we'll really average about nine rigs because we started with 15 rigs there in January. And then next year, we'll start with eight rigs and that will decline to four rigs, so we'll average about 5.5 rigs in 2017.

So yes, we will have some DUCs, but we'll have quite a number of wells that we'll be able to drill. And we've got quite a few of these patterns we'd like to further develop, so we'll maintain certainly more than 5.5 rigs in 2017..

Got it, thanks.

And then to follow up on both the DUCs and the EOR locations, on the DUCs, could you characterize how many of your DUCs would be locations you would regard as premium locations if you were drilling these wells now? And then on the EOR locations, can you characterize how many locations in the Eagle Ford over the last two to five years have been drilled in the area with the completion techniques where you could apply EOR right away if you wanted to?.

Yes, first you had a long question here. As far as the premium DUCs, roughly 100 of the DUCs are in the Eagle Ford. Most all those are going be premium. We've got some there in the Permian Basin; they'll also be premium. The neat thing here is when you look at it on a finding cost basis, our new drilling is roughly $10 a barrel of oil equivalent.

And when you look at the DUCs, having already spent the dollars to drill, it's probably in the $7 range. So those all look pretty darn good. Now as far as on our Eagle Ford and plugged wells have the modern completion to fit with EOR.

By the time we get these patterns developed, a large portion, the majority of our wells will have the more modern completion. So that's what Bill and Billy are talking about now. And just mentioning that, we want to go ahead and further develop these because we're still working on our spacing and we need get our spacing down there in the Eagle Ford.

So with that, the vast majority of the wells will have modern completion, very fitting for EOR..

Great, thank you..

And, ladies and gentlemen, that concludes our question-and-answer session. I'd like to turn the conference back over to our speakers for any additional or closing remarks..

In closing, the first thing I would like to say is that we're extremely proud of all the EOG employees. They're doing an incredible job this year of resetting EOG to be successful in a lower price environment.

The second thought I'd leave you with is that EOG continues to focus on long-term value creation by making sure that every dollar we invest today is making a strong return, and growth should be a product of making great returns.

So because of the tremendous technology and efficiency gains, the company has the ability to make strong returns in a $40 oil environment. And this uniquely positions EOG to continue its leadership in high-return U.S. oil growth as prices improve. So thanks for listening and thanks for your support..

And, ladies and gentlemen, that concludes today's conference call. We thank you for your participation. You may now disconnect..