EOG Resources Inc (EOG) 2016 Q1 法說會逐字稿

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 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 first quarter 2016 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the press release and EOG's SEC filings and we incorporate those by reference for this call. This conference call also contain certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to US investors that appears at the bottom of our press release in 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 included guidance for the second quarter and full-year 2016 in yesterday's press release. This morning we will discuss topics in the following order: Bill Thomas will review our 2016 plans and first quarter highlights, Billy Helms and David Trice will review 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 than it was just a year ago by [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 cost. I will briefly highlight those and Billy and David will provide details in a moment. Finally, our review our shift to premium drilling and how this shift has -- is a game changing events with significant long-term implications for EOG shareholders.

First, I want to highlight EOG's development of the first successful enhanced oil recovery technology in US horizontal shale. We initiated our EOR efforts in the Eagle Ford three years ago. Here is what we have learned since that time. Number one, geology matters. The Eagle Ford is unique. The same geologic characteristics that made the Eagle Ford prolific in primary delivered also make it unique for enhanced oil recovery. The EOR process we're 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 lease 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 cost over time.

The second item I will highlight is our discovery in the South Texas Austin Chalk. The turn 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 concepts in an existing play. Our team at EOG has cracked the code on how to make our particular footprint in the Austin Chalk at top tier horizontal play, earning returns on par with the Eagle Ford, Permian and Bakken.

A 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 is a few more clarifying points regarding this inventory.

First, 30% return is not an average, it's the 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, this is the most important points, our shift to premium is permanent and not simply a temporary high grading process and a low commodity price environment.

So 2016 will mark the point in time when 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 as 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 drilling 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 will help us reach our long-term goal of being one of the lowest-cost producers in the global oil market.

Now I will 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. 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 solve the problem, they demonstrated returns that are competitive with our premium drilling program. The 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 confident barriers that incase the Eagle Ford and provide vertical containment for completion. This unique feature allows plays -- also plays a significant role in keeping the injection in contact with the targeted reservoir. The injected gas is thus able to become [missable] 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 is also important for the EOR process. Acreage that is too far down dip or up dip in the play may not benefit as greatly. The EOR economics are significantly enhanced by the scale of EOG's footprint in 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 processes success and are why EOG -- why 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 take aways regarding the economics and recovery potential.

One, this EOR technique is not capital intensive. There is no incremental drilling required for capital cost to average approximately $1 million per well. Two, the operating cost 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 long-term -- on our long-term Eagle Ford base production profile. Unlike typical secondary recovery projects, the production response occurs quickly within the first two or 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 pay backs. Our EOR pilots have a much different profile, characterized by a 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. Delivering at -- delivered at potential [finding] cost of $6 per barrel of oil 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 protection and earnings affect of EOR. It is 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 developed 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's style completions. Our high density completions create complex fracture systems close to the wellbore and 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 at best 20 to 30 feet of rock. Precision targeting combined with EOG style completions is not generating prolific premium level well performance.

It is too early in our exploration efforts to know how much of the Austin Chalk is perspective 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, especially on the Second Bone Spring Sand. During the first quarter we completed 12 wells with pro 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 wellbore design. As a result, our wells are industry-leading, as illustrated on slide 8 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 the operational practices that maximize efficiencies and lower costs.

Our next step for Wolfcamp optimization is to extend the lateral. Breakthroughs we made and wellbore 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 efficiency and cost in the Wolfcamp. During the first quarter, drilling days decreased 14% from our 2015 average to 16.1 days. Also well cost decreased 8% to $6.9 million, more than offsetting costs associated with continued completion enhancements. In addition, in the second quarter we will 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 test to determine the optimal production rate. Our full-year guidance has been adjusted until we complete more testing.

Here is 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. 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, or 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 will 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 US 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 US 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 a low cost US 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 and -- 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 reduced net debt with property sales. We are 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 take aways 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. EOR 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 US and we believe we have achieved that goal. Our sites 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 towards that target rapidly.

Thanks for listening and now we will go to Q&A.

(Operator instructions)

Our first question comes from Evan Calio, Morgan Stanley.

Good morning, guys, and thanks for all the comments. The new EOR results are very encouraging. The next step is that 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?

Yes, Evan. This is Billy Helms. So as you mentioned there the next step obviously is implementing the 32 well pilot. We are 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 rollout certainly our 2017 guidance on that probably in February. But we were very encouraged with our initial results. It is 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? Does it make 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 do not think it changes it dramatically. We are focused on premium drilling at all of our place. And at 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 will 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 will move along both of them at a nice steady pace. And we will just continue to learn as we go forward. And I think the EOR process will be much like the drilling program. We will get more efficient as we move forward and we will be able to lower cost and it will just become kind of a normal part of our investment in the Eagle Ford.

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

We will move forward to our next caller, Arun Jayaram, JPMorgan.

Good morning. Bill, on the EOR process, you have done for pilots and tested that on 15 producing wells. Were the tests successful on all the wells? Or can you just talk a little bit about the effectiveness that you have seen thus far?

Yes, Arun, this is Billy Helms. Certainly to each one of our tests we've learned a lot. I would say that 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 full 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 a 32 well pilot. And we will certainly continue to learn from that. But yes, each one was very successful.

Thanks for that. And then just my follow-up -- Bill, in your prepared remarks when you're talking about the premium locations, you expressed confidence that you could either replace these premium locations from an inventory perspective on an ongoing basis. Can you just give us a little bit more color around what is driving that confidence?

Yes, Arun. As you know, we believe we have very sustainable cost reduction and technology gains. We have done it every year we have 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 better rock 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 reduction. 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. And so we are quite confident that efficiency and technology will continue to drive those costs down. 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 will add continued premium in the Bakken and other plays too. So we are very confident that our premium inventory but grow much faster than our drilling pace.

Thanks.

We will move forward to our next question from Scott Hanold with Royal Bank of Canada Capital Market.

Yes, thanks. Another question on the EOR process. And I know a lot of the stuff you all did was proprietary but when do think it is 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?

Yes, Scott, this is Billy Helms. We've -- typically the governing part will mainly be -- and 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 as we -- I think we have a slide in the deck on I think slide 4 that shows that timeframe will be somewhere in the first two to five years. So I think that will probably be our initial guide. There's no detriment that we see as to if you wait too long to implement it, it's going to be detrimental. We think it is 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 to answers your question but I would say that it will be somewhere in that first couple of years -- two to three years of developing.

Yes. Absolutely. That does help. And I was just trying to gage how this compares to say a re-frac 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 that -- what you learned in the Eagle Ford could actually be transferred up into the Wolfcamp?

The Eagle Ford is -- as we mentioned in the call, the primary -- one of the primary factors in the Eagle Ford success is the vertical containment. The Eagle Ford is very well incased 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 to be more challenged in that area. That's probably the key primary difference that I would say lends the success more readily to the Eagle Ford than maybe other plays.

Thank you.

We will move forward to our next question from Subash Chandra from Guggenheim.

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

We have no desire or intention to consistently out spend. 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 -- prices continue to firm. We have a lot of confidence that we are on the road to accomplishing that. We do believe that because we are seeing significant cost savings in the current drilling, we think that is 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 to be disciplined. We are certainly watching the market to make sure that we are 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 will be -- we will have the capital to do that.

Okay. And my follow up is any update our guidance on, for lack of a better word, rank exploration as we have sort of last couple of quarters talked about refinement of the existing portfolio, how your progress on a new portfolio of opportunities?

Yes, we have a very robust exploration effort on new plays. So we have various plays -- actually we will be testing this year. We will see -- update you that when we have some meaningful results. And then we're also picking up acreage. It has been a great time to pick up low-cost acreage in places that we couldn't get acreage in the previous years. So we have an active program going on. Of course, we are very selective. We only want premium plays to fit into our capital program. So we are trying -- we're identifying rock that would meet that category and deliver those kinds of returns. So we're not short changing that effort at all.

Thank you.

Doug Leggate, 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 you will be able to give some updates? And I'm just thinking about the development, again realizing it's early days, but will you develop this concurrently and are you seeing any pods off of the Eagle Ford? Or how are you thinking about that in terms of relative economics?

Doug, this is David. On the chalk, we drilled these two wells. We have taken a couple cores here and we've got quite a bit of log dated to go with that. So we have really kind of mapped out the play and we are 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 a mentioned in my remarks, we will test another seven wells this year to kind of delineate the play. And then, like I said, we will go ahead and move that into the premium [in-store] account. And so it will be developed along with the Eagle Ford.

Okay. We will watch for more details. My follow up is I've got to say, as an old reservoir [hack], you guys never ceased to amaze us with the things you have been able to. And this EOR is 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 idea on 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?

Yes, Doug, this is Billy. The second part of your question 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. We -- but we are still early on in that process and 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 and maybe what we will look at in the future. Will be subsets of -- 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've kind of given you some guidelines of what we think the capital cost is. And we tried to boil that down to a single well just so you can kind of think about it and knowing that each lease will have different counts of wells -- maybe 12 to 20 wells on any given lease.

And then the production profile we have kind of given a [cueme] curve out there that maybe give you some insights on what the cueme curves might look like. The production response from this is pretty unique in the sense of secondary recovery projects in that it is 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. And so that maybe -- and so that is probably about as much detail on the -- on how we see the -- how it would be rolled out. Again, the pace of development -- I know this is tough to model economically. The pace of development is purely just going to be on the things we learned from this next pilot. And then our development of existing units, we've used our high density completions. So we de expect to increase the -- I would say we expect to increase the number of wells each year as we rollout the new budgets. And it will become an ever-increasing part of San Antonio's capital allocation.

Appreciate the answer, Billy. Thank you.

We will move forward to Charles Meade with Johnson Rice.

Good morning, Bill. To the rest of your team there, I really appreciate the -- what you've been offered -- are 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 EOR. 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 that you're working with.

Yes, 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 start 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 to be, we're trying to model that with some simulation techniques. I would say that our challenge technically -- so we're working on some enhance models to better understand what the long-term production will actually be.

So I think we just need further clarification and tests from existing pilots that were -- and future pilots to really nail that down. And then you're right. I think the vintage of the completions so -- 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 completion in large part. So we expect improvements to continue to improve. I think there is upside there.

That's helpful color. But if I could ask my follow-up on the Austin Chalk. I know that the -- historically the way the play has worked is a lot of the successful wells have been a function of intersecting national fracture. But I'm wondering if perhaps for you're new concept it's maybe the inverse of that. And if you're not avoiding natural fractures in the wellbore, perhaps if you're trying to avoid them in the stimulation of the zone and if that is part of what you're trying to figure out here.

Yes, Charles. This is David. I think you are on the right path there. What we've learned is here where we're playing the chalk is the oil is stored a bit different than has been in kind of the previous history of the play. And what that does is 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 is just going to give is a little more certainty on drilling repeatable high-quality wells.

Charles, I would like to add to that too to kind of expand on what David said. I think that same kind of techniques that we're finding very successful in these other plays, by identifying their very sweet spots, the very best rock quality with our proprietary techniques and then being able to keep that bit at a very small zone in conjunction with the high density frac, that's really the key to all of these plays. And it's no different from the chalk. So we're just finding that we can identify a quality pay in the chalk and we are very encouraged about that.

That's helpful, Bill. Thanks a lot.

We will move forward to our next question from Bob Brackett with Bernstein Research.

Hi. Good morning. More questions on the EOR side. Is this a sort of producer injector concept or is it a huff and puff?

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

You guys were issued a patent for a thermal process for shale a couple of 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, were not going to give a lot of details on how much gas we are 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 in the facilities and infrastructure that we been able to put in place for our field really enhances our ability to move the 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 a final one. Should we trust sort of 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'll it will be -- 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 gleam from that data. We'll see. Honestly, I haven't checked a lot of that dated to see what it looks 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.

Thank you very much.

Pearce Hammond, 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 depths above the Eagle Ford? And then are you leasing any additional acreage?

Yes, Pearce. We would -- we hold Austin Chalk with our Eagle Ford production. So, yes. It's right above the Eagle Ford. And the second part of your question was?

Was are you leasing any additional acreage?

As you know, there in the Eagle Ford, 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 basic line? Seems like it would cause your Eagle Ford base declines to moderate significantly over time once you apply this technology in full force.

Yes, Pearce. I think that's right. I think the overall benefit in the long-term is, yes, 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 the field in general.

Thank you, Billy.

We will move forward to our next question from David Tameron, Wells Fargo.

Good morning. A couple questions. One on the Austin Chalk, how perspective 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 are 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 will be testing some of these concepts. And so once we get those done and we get some results that confirm the production like we have seen, then we will 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 kind of 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 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 has 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 [cuemed] 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 are very repeatable.

Okay.

David, the technical advantages from a competitive standpoint are our -- I think our ability to recognize these pay zones. And then target those pay zones. That is -- it's 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've covered this, I apologize. I don't think I heard anybody talk about it. But as far as the DUC balance and going into 2017 and I know some of the rigs are coming off on contract. How should we think about the way you want to manage that going forward?

Yes. This is Gary Thomas, David. And what we've shared before is we're just going to be completing roughly 270 wells this year -- drilling about 200. So we will be completing roughly 70 of our DUCs. And we're just -- as Bill said, we've got these in inventory. When we see prices improved, when we have additional capital, this will be just a source of assets that we can develop rapidly to bring on production when it is justified.

Okay. Appreciated. Thanks for the time this morning.

We will move forward to our next question from Irene Haas with Wunderlich.

Yes, 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 get shoot up 4 or 5 per Mcf -- how would the process work then?

Yes, 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 are currently modeling and also incrementally up to $5 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 be -- continue to be -- it will continue to be economic, even at what we see could be a foreseeable gas price in the future.

Great. Thank you.

We will move forward to our next question with Brian Singer, Goldman Sachs.

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 our 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 declined to 9 at the end of the year. So we will really average about 9 because we started with 15 rigs there in January. And then next year I will start with 8 and that will declined to 4 so we will average about 5.5 rigs in 2017. So, yes, we will have some DUCs but we will have quite a number of wells that we will be able to drill. And we've got quite a few of these patterns we would like to further develop. So we will 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?

The first -- that's a long question there. As far as the premium DUCs, roughly 100 of the DUCs are in the Eagle Ford. Most all of those are going to be premium. We've got some there in the Permian Basin, they will 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 -- barrel oil equivalent. And when you look at the DUCs and having already spent the dollars to drill, it's probably in the $7 range. So those all look pretty darn good.

And as far as on our Eagle Ford and what 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 is what Bill and Billy are talking about now and just mentioning, yes, we want to go ahead and further develop these. Because we're still working on our spacing and we need to 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.

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.

Yes, in closing, the first thing I would like to say is that we are extremely proud of all of the EOG employees. They're doing an incredible job this year of resetting EOG to be successful in lower price environment. The second thought I will leave you with is that EOG continues to focus on long-term value creation by making sure that every dollar we invested 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 the $40 oil environment. And this uniquely positioned EOG to continue its leadership in high return US oil growth as prices improve. Thanks for listening at thanks for your support.

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