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. Timothy K. Driggers - Chief Financial Officer & Vice President: 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 contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. Participating on the call this morning are: Bill Thomas, Chairman and CEO; Gary Thomas, 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…

Thank you. Our first question comes from Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley & Co. LLC: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Evan Calio - Morgan Stanley & Co. LLC: 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…

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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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? William R. Thomas - Chairman & Chief Executive Officer: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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? William R. Thomas - Chairman & Chief Executive Officer: 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? William R. Thomas - Chairman & Chief Executive Officer: 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? David W. Trice - Executive Vice President-Exploration & Production: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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.…

I appreciate the answer, Billy. Thank you.

And we'll move forward to Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Co. LLC: 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. Lloyd W. Helms - Executive Vice President-Exploration & Production: 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.…

We'll move to our next question from Bob Brackett with Bernstein Research. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: Hey, good morning, more questions on the EOR side. Is this a producer injector concept, or is a huff-and-puff? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: You guys were issued a patent for a thermal process for shale a couple years ago. This isn't that process? Lloyd W. Helms - Executive Vice President-Exploration & Production: No, it's definitely not that process. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay, thank you very much.

We'll move forward to our next question from Pearce Hammond with Simmons Piper Jaffray. Pearce Hammond - Piper Jaffray & Co. (Broker): 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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? Pearce Hammond - Piper Jaffray & Co. (Broker): Are you leasing any additional acreage? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Pearce Hammond - Piper Jaffray & Co. (Broker): 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. Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Pearce Hammond - Piper Jaffray & Co. (Broker): 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? William R. Thomas - Chairman & Chief Executive Officer: 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. David W. Trice - Executive Vice President-Exploration & Production: 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. William R. Thomas - Chairman & Chief Executive Officer: 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? Lloyd W. Helms - Executive Vice President-Exploration & Production: 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. Brian Singer - Goldman Sachs & Co.: Thank you, good morning. William R. Thomas - Chairman & Chief Executive Officer: Good morning, Brian. Brian Singer - Goldman Sachs & Co.: 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. Brian Singer - Goldman Sachs & Co.: 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. Brian Singer - Goldman Sachs & Co.: 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. William R. Thomas - Chairman & Chief Executive Officer: 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.