Good day, everyone, and welcome to the EOG Resources 2015 fourth quarter and full year 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. 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 fourth quarter and full-year 2015 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release 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 schedule 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 first and full-year 2016 in yesterday's…

Thank you. And we'll take our first question from Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley & Co. LLC: Hey. Good morning, guys. My first question is your premium locations appear higher than most peers' core or comparable locations. Can you discuss what you think differentiates EOG's premium locations and what's proprietary and represents a barrier for peers to achieve similar results? And also, if I could, you mentioned upside at locations. Any color on what percentage of the average locations have already been reviewed? William R. Thomas - Chairman & Chief Executive Officer: Evan, certainly we believe moving into premium drilling mode is a step change in the future of the company. It's a substantial increase, as we said. Over the last two years, it's about a 95% increase in the quality of the wells we're going to drill and a 50% uplift for this year. So we're moving more rapidly than what maybe we might have even thought a few years ago. What's driving that is the quality of the rock. The quality of the rock is the most important factor in the productivity of the well. So we made extremely strong technical advancements in identifying the best rock in the best plays over the years, and certainly we believe we've captured the premier acreage in the premier plays in the U.S. And then also, in each one of those plays we've developed petrophysical techniques, seismic techniques. We've used a lot of core data and our combined over 10 years' experience in these horizontal plays to identify the best target zones in each one of the plays. And so that is the main driver. It's the rock quality, capturing it first and then being able to take all the technical knowledge and tools that we've…

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

Thanks. Good morning, everybody. William R. Thomas - Chairman & Chief Executive Officer: Good morning, Doug.

Bill, the production range for the year is obviously pretty wide. I guess what I'm trying understand is, there's a fairly large proportion of DUCs, I'm guessing. I would have thought that would have given greater certainty to the outcome, so I'm just wondering if you can help us reconcile the – are you being relatively conservative with the range that you're giving us, or is it something else? And I've got a follow-up, please. William R. Thomas - Chairman & Chief Executive Officer: Doug, I'm going to ask Gary Thomas to give you some color on that.

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

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

Okay. On the DUCs, yes, as Bill mentioned, we're going to be completing quite a number, about 70 of our DUCs. We're going to be completing additional DUCs than that. We're going to be completing at least 100 first quarter wells that we drill as DUCs. And those DUCs are all premium. They generate a 30% rate of return at $40 oil. And our guidance is very similar to what we've had in previous years. We're saying anywhere from 260,000 to 280,000 barrels of oil per day for 2016. That pretty well duplicates what we had in 2015. Does that answer your question?

Yes, well I guess I was talking about BOE guidance, which is still quite wide, but I'll take it offline with Cedric [Burgher]. My follow-up is really more balance sheet related. So I think in the past, though in a more robust oil price environment, you talked about a 30% ceiling on your net debt-to-cap. You're slightly above that right now. I'm just wondering how you're thinking about that. And this is not in any way disparaging to the industry, but a lot of very strong companies with very strong balance sheets have taken advantage of their relative outperformance by, obviously, issuing equity. I'm just curious as to how you feel about the uncertainty of the outlook and how you might balance the priorities to reinforce the strength of your balance sheet, given how well your stock has done relative to the market? William R. Thomas - Chairman & Chief Executive Officer: Doug, first of all, EOG has no current plans to issue equity at this time. Certainly we entered the year, we came into the downturn with a strong balance sheet, and we've been disciplined throughout the process. And so, when we look, as we go forward for this year, we have tremendous flexibility to make further adjustments to capital throughout the year. We do anticipate selling non-core properties, as we consistently do every year. We're pretty far along in that process. We have what we believe are very high-quality, strong buyers for properties. And this could be – this is not a small amount of money; it's very significant. So we're quite confident in that process. And so our goal going forward is to maintain a strong balance sheet. And fortunately, our balance sheet right now is one of the strongest in the peer group. So, that's certainly a focus for us. It's certainly been a hallmark. A strong balance sheet has been a hallmark for EOG for years, and we've not taken our sight off that. And we're going to be committed to maintaining a good strong balance sheet going forward.

The next question is from Arun Jayaram with JPMorgan.

Bill, I was wondering if you could elaborate a little bit more on the premium drilling inventory. You guys cited, I believe, 3,200 premium locations and 2 billion barrels, I believe, of gross recovery. That would equate to an EUR of 625 MBoe, if you just average that out. About half of that premium inventory is in the Eagle Ford. So I guess my question is, your overall Eagle Ford guidance is for 450 MBoe recovery, and that's after royalties. So I was wondering if you could just maybe comment on the differences in the premium inventory in the Eagle Ford relative to that 450 MBoe average? William R. Thomas - Chairman & Chief Executive Officer: The first thing, the 2 billion barrels is net.

That's net? Okay. William R. Thomas - Chairman & Chief Executive Officer: Yes, that's net. So the gross EUR per well would be quite bigger than what you stated. And let me let David Trice comment a little bit more on the details on the Eagle Ford and what we expect there going forward. David W. Trice - Executive Vice President-Exploration & Production: Arun, in the Eagle Ford, like we stated in our remarks, we've done a lot of work there. Obviously, over the years, we've collected a tremendous amount of data. Even this last year in 2015, we drilled quite a few pilot holes where we actually drilled down through the Eagle Ford and collected a lot of data. And so what that allowed us to see was that we have a lot of additional upside there as far as working on the targeting. Like I had mentioned, we're drilling 20-foot target intervals and doing multiple targets within the lower Eagle Ford. We're seeing very good results with that, and we're quite encouraged. So I think really going forward, we see a real opportunity to continue to add premium locations. We stated in our slides that we've got approximately 1,500 premium locations in the Eagle Ford, but we certainly see that as a starting point as far as being able to continue to add premium locations. William R. Thomas - Chairman & Chief Executive Officer: Let me just add, to answer your question specifically on the 450 net MBoe per well in the Eagle Ford. That is for an average Eagle Ford well, and that is not a premium well. Premium wells would be quite a bit better than that. And then that number is stale. So we haven't updated that 450 net MBoe per well for several years, and we've made quite a bit of advancements since then in the high-density frac technology, and now we're making advancements in targeting also. So those numbers, it takes a little bit of time to get confirmation on what the new EUR number is. So when you make these advancements, you want to make sure you get at least a year of production, and then you can adjust them up accordingly.

Thank you, Bill. And my follow-up, Bill, in some cases you now stratified the inventory a little bit between premium and other locations. You mentioned in your prepared remarks about EOG potentially being open to upgrading or trading inventory, and I was wondering if you could maybe elaborate on that for the non-premium inventory. William R. Thomas - Chairman & Chief Executive Officer: The non-premium inventory will have two avenues. The first avenue will be that we believe the majority of it will be converted to premium over time as we continue to learn how to target the rock more correctly and we continue to be able to be better at picking out the high-quality rock in the target zone. So it's an ongoing process in every one of these plays, and we expect continued improvement. If it doesn't make it to the premium inventory level and it never gets in our CapEx, then certainly it has a lot of value. All this non-premium inventory that we have, if you compared it to the rest of the industry, it would be Tier 1 inventory. It's very high quality. So that gives us a chance to market this as we go forward down the road through property sales, as we normally do in our asset upgrading process. Hello?

And we'll go next to Brian Singer. Brian Singer - Goldman Sachs & Co.: Thank you, good morning. William R. Thomas - Chairman & Chief Executive Officer: Good morning. Brian Singer - Goldman Sachs & Co.: Bill, in your opening comments, you mentioned a focus, more specific focus of EOG being a competitive low-cost producer in the global market, not just U.S. shale. Before we run with this too far, do you still expect to do this predominantly through U.S. shale, or is this any signal you're willing to pursue international shale or global non-shale investment opportunities to a greater degree? And is it still your view that you can do this from the premium focus areas that you talked to and then that you have in the Delaware Basin, Eagle Ford, and Bakken? William R. Thomas - Chairman & Chief Executive Officer: Brian, we have no intention of expanding international efforts, so we are going to be very much U.S. driven. We see tremendous opportunity in the U.S. And so this whole direction towards being not only the low-cost producer in the U.S. horizontal, we think we're clearly there. And our sight now is really set on being one of the lowest-cost producers in the world market. And we believe that we can accomplish this with our very high-quality assets that we currently have and continuing to improve them and continuing to come up with new technology as we go forward. And we also believe very strongly that we can continue to grow that quality asset much faster than we're drilling it. And that would be through converting existing inventory in the premium and also through new plays. So we see tremendous opportunity the U.S., and we're going to stay focused there. And we're quite confident that we can…

And your next question is from Pearce Hammond with Simmons & Company. Pearce Wheless Hammond - Simmons & Company International: Good morning. Thanks for taking my questions. My first question is what commodity price assumptions are embedded in your 2016 capital plan? William R. Thomas - Chairman & Chief Executive Officer: Pearce, we use the strip, and we used the strip that was in the first part of January. And so we haven't got any – we don't really put in a lot of upside to the current prices. I think it was based on prices around $40 was the current strip we used. Pearce Wheless Hammond - Simmons & Company International: Okay, perfect. Thank you. And then my follow-up, this is a hard question to ask, so just bear with me, but it follows up on Brian Singer's question. On the exploration front, for the past number of years you guys have worked on various plays. And obviously you've had tremendous success, with the Eagle Ford as an example. But now those plays weren't really – some of those plays weren't economic or couldn't compete with your really core plays back when oil was $80 to $100. And now obviously oil is a lot lower. And I know service costs have come down. But when you look at those plays and you also look at what you mentioned in the press release about this premium inventory and how much success you're having at improving your existing inventory, would it make sense instead of spending the money on exploration on trying to discover new plays to actually use that money to buy existing acreage around the core around plays, whether it be the Eagle Ford, the Permian, the Bakken, SCOOP/STACK, or whatnot, and then take your core competency and expertise,…

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

Hi. Good morning, everyone. William R. Thomas - Chairman & Chief Executive Officer: Hi, Paul.

I was wondering if your drilling contracts are committing you to more drilling than you would otherwise do, all things being equal. It just feels as if you're somewhat dependent now on the oil price recovering. But more importantly, I was wondering whether if you didn't have those locked-in drilling contracts, you would actually be completing more wells and drilling less. Thanks. William R. Thomas - Chairman & Chief Executive Officer: Paul, we did enter the year with 13 rigs under contract. I think the average this year will be 11 rigs. We looked very hard at trying to buy out those contracts to reduce that, since we do have so many DUCs in place. But when we ran the numbers, it just didn't make economic sense. Those rigs are the best quality rigs in the business. The efficiency is tremendous, and it just didn't make economic sense to buy those out. And so we're really focused on going forward. We didn't want to grow oil, obviously, this year in the low part of the cycle, and so we didn't want to accelerate the DUCs. And so I'm going to let Gary Thomas give you a little bit more detail on the rig situation and our DUC situation.

Yes, Paul, this is Gary. And if we didn't have these rigs under contract, we would certainly be completing more of our DUCs, with them all being premium wells, but we're just honoring those contracts. And as Bill said, yes, we're going to average – we were at 27 rigs under contract in 2015. It's 11 rigs this year, and we average 5.5 rigs next year. So yes, in 2017 we'll be able to certainly accelerate the completion of our DUCs, which will be very beneficial to us.

And the follow-up would just be I assume at these prices CapEx would be lower but for the contracts.

That's right, yes.

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

That's correct. Yes, sir.

Thank you, that clarifies it.

That's more flexibility.

Got it, understood. Thank you.

Next is Biju Perincheril with Susquehanna Brokers.

Hi, thanks. Good morning. Bill, I had a question about the high-density completions. It almost sounds like when I look at it, you're taking the unconventional rust warren (52:33) and transforming it into something close to a conventional rust warren (52:36) near the wellbore. And I don't expect it's a fair way to characterize it, but I guess my question is do you think there are any implications for the longer-term shape of the decline curve of these new completions? I'm thinking several years out. I would like to hear your take on it. Thanks. William R. Thomas - Chairman & Chief Executive Officer: The high-density completions, what they do, you described it fairly accurately, is that they contact enormous amounts of surface area of the rock, and they hit it very, very, very close to the well bore. So obviously, the better the rock and the more that you connect to the well bore, especially close to the well bore, has the tremendous effect on the uplift of wells. And I'm going to let Billy Helms comment on the long-term effect of this uplift. Lloyd W. Helms - Executive Vice President-Exploration & Production: Biju, you did characterize it fairly accurately. I think the one way to think about is, certainly the more rocky contact in the reservoir, basically yes, you're going to increase the initial potential of that well. But by contacting more of that rock, you're also increasing the ultimate recovery from every well. So you will see good initial production rates. But your decline, we're seeing the benefit of declines flattening, with more production from these high-density completions. So the overall effect has been quite uplifting.

So when we compare the shape of the decline curve in the longer term, do you think it will remain fairly similar? So, when we look at the terminal rates, would you expect a higher decline for the higher-density completions, or no? Lloyd W. Helms - Executive Vice President-Exploration & Production: No, no. Actually, we're not seeing that at all. We're seeing, longer term, the wells will produce longer, and the initial decline is little bit less steep than the older completions are, just simply because you're connecting a lot more rock to the well bore.

Perfect, thanks. Appreciate it.

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

Hi, good morning. Bill, how do you think about a ramp as you go into – assuming we get some upward pressure on prices a year from now, how quickly can you ramp? I know you talked about prior – the availability of people, maybe the services industry can't respond as fast. Can you just walk us through how you would see a scenario, if oil goes back to $55 tomorrow, like how does that play out for EOG? William R. Thomas - Chairman & Chief Executive Officer: David, we're set up tremendously well. Of course, we're going to have a very large, very high-quality DUC inventory. We have rigs in place, and we have a substantial amount of frac spreads running. We delayed the work schedule on some of the frac spreads to maybe five days a week instead of seven days a week type scenarios, so that we could keep a number of frac spreads in place that would be easy to accelerate. When the oil prices begin to recover, we're going to be disciplined going forward. We don't – obviously don't want to be fooled again, like the industry was fooled last year by a little bit of an uptick in oil price and it is not sustainable. So, we're going to be disciplined and cautious going forward on ramping up capital until we're very much convinced that this is not a short-term uptick in the price, and that the market is more in balance, and that the price is more sustainable. But we think, obviously, EOG is in a fantastic shape to generate extremely strong – we're talking about triple-digit rates of return – as oil prices improve, and we have ability to grow oil when the time comes.

Okay. And then, if I think about it, I've asked a couple others the same question. But if I think about – if you make the decision tomorrow to add rigs, and obviously, with the DUCs, you can cover some of this gap. But how long – you say tomorrow, you say, let's add a rig. How long does it take before we see that production, given the laterals and pads and everything else? Is that a six month before you start to see that production in the numbers? William R. Thomas - Chairman & Chief Executive Officer: David, I'm going to ask Gary Thomas to give some color on that.

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

Yes.

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

Okay. No, that's helpful. Thanks for all the color.

Our next question is from Mike Scialla with Stifel. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Maybe a follow-up to David's question, it sounded like you're not inclined to want to go back to growth mode unless you see a significant price increase. But looking at that inventory of 3,200 premium locations that generate a 30%-plus IRR with $40 oil, if it looks like that's all that we're going to get out of a recovery, would you go back to a growth mode, if that were the case? William R. Thomas - Chairman & Chief Executive Officer: I think, Mike, that would give – $40 oil would give us obviously a bit more cash flow, but we would be certainly wanting to stay balanced, discretionary cash flow to CapEx. So that's really going to control the amount of growth that we have, and along with making sure that the oil price is really sustainable. So we can generate the returns, but the growth of the company will be regulated by, obviously, the number of wells we complete and the continued improvement we have, but it would be regulated by the cash flow of the company. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Okay. And then can you talk about in terms of that premium count, you said, Bill, that you could grow that over time. You alluded to how you would do that with better targeting. But I wanted to see where you anticipate if you can say where most of that will come from. Is it downspacing in the Eagle Ford? Is it primarily from the Permian or somewhere else? William R. Thomas - Chairman & Chief Executive Officer: Mike, it will be from really multiple sources. We're learning in every one of the plays that we're in, and it's really just being able to identify those target windows within those good plays and then executing on those. So we were still working on downspacing in every one of the plays. So it will come from multiple plays, improving the inventory there to premium, and then it will come from new plays too. We have quite a bit of confidence that through our learning process on existing plays that we can identify very high-quality rock in emerging plays, and so we're actively engaged in buying acreage and testing wells in those too. So it will come from a multiple source. Historically, even though the uptick when we had $90 – $95 oil and we were growing very quickly and drilling a lot of wells, we were able to add twice as many wells each year than what we actually drilled. And so we're very confident that we can continue that kind of multiple on the premium going forward. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Great, thank you.

And the next question is from Subash Chandra with Guggenheim.

Good morning. Are we looking at a permanent shift to better wells but fewer wells, and how exacting your premium process is and how reliant it is on massive data analysis? And then I have a follow-up. Thanks. William R. Thomas - Chairman & Chief Executive Officer: Certainly, when you're drilling twice as good a well, you don't have to drill nearly as many of them. And so that certainly helps keep your CapEx down and you're able to have a lot more efficiency there. So as we go forward, the learning process will be incremental in each one of these plays, and it's just an ongoing theme. We learn this and then we try it. And as we get good positive results, we're able to apply that to additional wells. And then the sustainable technology gains that we have in the company have been very, very continuous and very steady over the whole life of our involvement in horizontal drilling. It's over 10 years of experience, combined knowledge, and we have quite an innovative culture in the company. And we expect that to continue to improve the wells as we go forward.

And the follow-up is, and no question, you're light years ahead in many ways. When we think about the additional inventory in that it's dependent on data that where you have more wells is likely where we'll see more inventory over time? And so the other side of that is how applicable is this to new exploration concepts? William R. Thomas - Chairman & Chief Executive Officer: Correctly, when we have an ongoing drilling program and we're collecting data all the time in an existing play, that's certainly how you make advances. But we also are able to take that learning experience and apply it to new plays. So the high-density frac techniques, the kinds of rocks that would respond to high-density techniques, and then the petrophysical properties of rocks in emerging plays and then the core work where we do an extensive amount of very detailed core work, and we integrate all this data along with 3-D seismic. And so all that goes into bear on defining new plays with high-quality rock. And so it's a learning process that spills over, and it really helps us keep the momentum and to keep adding premium inventory as we go forward.

That concludes today's question-and-answer session. Mr. Thomas, at this time I will turn the conference back to you for any additional or closing remarks. William R. Thomas - Chairman & Chief Executive Officer: EOG has got a strong track record of game-changing events that have made the company successful over time. Our shift to premium drilling mode this year with an estimated 50% year-over-year increase in well productivity is another step-change to the company's performance. Premium drilling allows EOG to generate solid capital returns at $40 oil, and quite frankly spectacular returns if oil prices recover. With our focus on improving returns instead of production growth during this down cycle, EOG is now positioned for tremendous performance as prices improve. We believe the best times for the company are ahead of us. So thank you for listening and thank you for your support.

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