Good day everyone and welcome to EOG Resources Third Quarter 2019 Earnings Results Conference Call. As a reminder this call is being recorded. At this time for opening remarks and introductions I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead sir..

Bill Thomas, Chairman and CEO; Billy Helms, Chief Operating Officer; Ken Boedeker, EVP Exploration and Production; Ezra Yacob, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; David Streit, VP Investor and Public Relations. Here's Bill Thomas..

number one, our priorities have not changed. We firmly believe that investing in high-return production growth, generating substantial free cash flow and delivering strong dividend growth delivers the highest long-term business value. Number two, our plan is based on a conservative outlook for commodity prices.

At $55 WTI we can deliver mid-teens production growth, grow our dividend and generate significant free cash flow. Number three, we believe well cost and per unit operational costs will continue to decline. Number four, we believe capital efficiency and F&D costs will continue to improve.

Number five, we have high confidence in the ability of our organic exploration efforts to add and improve our premium drilling inventory faster than we are drilling. And number six, we have no plans for large expensive M&A. Any potential bolt-on acquisition must compete with our premium drilling returns.

As we look to the future we know that the business environment will continue to change. But our competitive advantage is rooted in our culture, ensure that we can meet these challenges head on.

EOG is a resilient company that will continue to differentiate itself as a leader among any company in any sector of the S&P 500 by creating significant long-term value for our shareholders. Next up is Billy to review our third quarter operational performance and outlook for the remainder of 2019..

leasing acreage and new exploration plays and high-return infrastructure projects that are lowering lease operating expense. Across the board, 2019 is shaping up to be the best year we've had operationally and is particularly notable across our company-wide per unit operating expenses.

At the start of 2019, lease operating expense on a unit basis was initially forecasted to be flat year-over-year. However, we now expect full year 2019 LOE to be 4% lower than 2018. At the midpoint of our 2019 DD&A guidance range of $12.65, we were on track to deliver the lowest rate since EOG's transition from a natural gas company to oil.

Our permanent switch to premium drilling continues to transform the company, driving down finding and development costs, reducing D&A and enabling EOG to deliver double-digit returns throughout commodity price cycles. Also of note during the third quarter, we entered into long-term gas supply arrangements with Cheniere Energy.

Consistent with our strategy of having flexibility and diversity in marketing our products, these arrangements provide additional markets for off-take and pricing diversity for up to 440 million BTU per day starting in 2020 with the ultimate goal of maximizing the realized price for our growing production of low-cost natural gas.

Now I would like to provide some color on the Bakken and other Rockies plays. In the Bakken this quarter we completed 15 wells with an average IP-30 of 2150 barrels of oil per day, 300 barrels of NGLs and 2 million cubic feet a day of natural gas. Our strong well results reflect the impact of EOG precision targeting and our new completion techniques.

The highlight for the quarter was the Clarks Creek 18 well that was completed in the Three Forks with an IP-30 of 3800 barrels of oil per day. This well is our best well to date in the Bakken, which along with strong performance from other wells completed this quarter are a testament to the continued improvements we see across our entire inventory.

In the Powder River Basin, we completed a total of eight wells including four wells in the Parkman, three wells in the Turner and one well in the Niobrara. It is worth noting that our premium inventory in the Powder River Basin now includes the Parkman which we have combined with the Turner play.

The Niobrara completion, the Arbalest 473 had an IP-30 of 1250 barrels of oil per day with 250 barrels of NGLs and 4 million cubic feet a day of natural gas. We continue to be encouraged by the results of our program in the Powder River and look forward to its growth in the near future. Next up is Ken to discuss the Eagle Ford..

Thanks, Billy. Year-after-year, quarter-after-quarter EOG's Eagle Ford asset delivers strong consistent results and the third quarter of 2019 was no different. The Eagle Ford delivered high-return oil volume growth with a continued decline in well costs.

We have exceeded our full year cost reduction goal of 5% in the third quarter by continued improvement in operational efficiencies. Specifically, our drilling time has been reduced by 10% to 20% depending on the lateral length in the third quarter of 2019 compared to 2018.

We also drilled our fastest well to date in Eagle Ford, the Meadowlark B2H, which was drilled to a measured depth of 17,288 feet with a 7,500-foot lateral section in a remarkable 2.4 days.

Even after nearly a decade of development our premium well inventory in the Eagle Ford remains strong at 1900 net locations representing over six years of drilling at current activity levels. We continue to have high confidence in our ability to grow our premium inventory in this play.

Our best well to date has a cost that is 20% below our average 2019 well cost. This difference in cost between our best well and the average well this year is evidence of the opportunity ahead to convert our approximately 2200 remaining non-premium locations to premium over time.

EOG is in the best position it has ever been in to maximize the value of this flagship asset. Now here's Ezra for an upgrade -- or an update on the Delaware Basin..

Thanks, Ken. In the Delaware Basin we announced the addition of just under 1700 net premium locations including two new plays, the Third Bone Spring, which accounts for 615 net premium locations and the Wolfcamp Middle or M for short, which contributes 855 net premium locations.

The Third Bone Spring and the Wolfcamp M combined -- added approximately 1.6 billion barrels of equivalents of incremental resource potential net to EOG. Additionally, we added over 200 net premium locations from previously identified plays in the Delaware Basin.

These locations not only benefit from this year's reduced well costs and increased well performance but also reflect further delineation and greater confidence in areas outside of our core acreage position. The Third Bone Spring is an example of making an old play new again.

EOG began drilling the Third Bone Spring sand in our core Red Hills area in Southeast New Mexico over 25 years ago through vertical and horizontal development to exploit these high-quality reservoir sands.

Fast forward to today, where modern drilling and completion technology along with the benefit of a large data set of core samples and logs has allowed EOG to exploit the tighter sands shales and carbonate rocks in the Third Bone Spring.

While over 1000 horizontal wells have been drilled in the traditional Third Bone Spring sand target across the basin, less than 50 wells have exploited these tighter reservoir targets.

With the advantage of a rich trove of technical data, EOG has identified the sweet spots of these new targets and the result is an $8 per barrel of equivalent finding and development cost with a production decline profile somewhat shallower than other plays in the Delaware Basin.

We anticipate developing the Third Bone Spring at approximately 880-foot spacing between wells with per well gross reserve potential of approximately 1.2 million barrels of equivalents for a targeted completed well cost of $7.6 million.

We also announced the Wolfcamp M with 855 new net premium locations identified across a wide expanse of EOG's acreage position in Lea, Eddy, Loving and Reeves Counties. This combo play with 63% liquids sits below the Upper Wolfcamp plays and is planned to be developed on 1050-foot spacing.

A typical Wolfcamp M well is expected to produce approximately 1.5 million barrels of equivalents over its life for a $7.7 million targeted completed well cost. EOG began data collection analysis and delineation of this interval in 2014 and refined our precision targets to the highest quality portion of the reservoir.

Utilizing proprietary steering software, we have reduced our specific drilling target by over 20% while simultaneously decreasing our drilling days by 50% compared to the 2014 delineation tests.

The combination of increased well productivity, operational efficiency lowering well costs and utilization of water, gas and oil infrastructure has delivered another premium play to EOG's portfolio.

Altogether in the Delaware Basin, EOG now has an inventory of approximately 6500 future net premium drilling locations or 24 years of inventory at the current drilling pace.

This inventory is based on actual locations customized to the local geology across our over 400,000 acre position and includes multiple targets within the 5000-foot thick column of pay. We use proprietary core log and completions data to determine our targets and spacing and integrate real-time data from every well we drill to improve future wells.

In contrast, to one-size-fits-all manufacturing mode, our continual process of data collection, analysis and application allows us to continue improving our wells, lower finding and development costs and optimize returns and net present value for each development unit.

We're also confident in our ability to add future premium locations to our current inventory through lower well costs, increased well productivity and additional delineation of targets outside of our core area.

For example, in the Wolfcamp oil play, the well count averages a single target being developed at 660-foot spacing across the 226,000 acre play. During 2019 EOG has regularly drilled patterns of wells on tighter spacing including the State Atlantis seven Unit number 1H through 5H, a 5-well Wolfcamp oil development at 440-foot spacing.

These two-mile laterals averaged less than a $7 per barrel of equivalent finding and development cost generate over $50 million NPV and average payouts in approximately three months. The bottom line is EOG is very confident that a lot of upside remains to the currently identified drilling potential in this world-class basin.

In addition to the updated inventory, EOG's outstanding operational performance during the first half of 2019 has continued through the third quarter in the Delaware Basin.

Total well cost for the Wolfcamp oil play has already reached the full year goal of $7.2 million, while operating expenses in the Delaware Basin are also moving down notching a 7% improvement year-to-date compared to 2018. Well productivity in the Delaware Basin also continues to improve across our various plays.

Average cumulative oil production for the first 90 days compared to 2018 was up 15% in the Wolfcamp oil play and up 20% in the Second Bone Spring. The standout for the quarter is the McGregor D unit number 5H, which came online an initial 24-hour rate of 11,500 barrels of oil per day and nearly 20 million cubic feet per day of rich natural gas.

For its first 30 days, the well averaged 6,400 barrels of oil per day. The McGregor was drilled as part of a three-well package on 700-foot spacing in the Wolfcamp upper target. The entire package produced a staggering 445,000 barrels of oil and 1.2 Bcf of natural gas in the first 30 days of production.

These wells benefited from EOG's highly integrated multidisciplinary technical approach to development.

Data collection and applying real-time analysis to improve well performance is a hallmark of EOG's approach to unlock upside potential across all of our assets and as highlighted with our announcement of additional premium plays in the Delaware Basin. I'll now turn it over to Tim Driggers to discuss our financials and capital structure..

Thanks, Ezra. The benefits of EOG's balanced high-return growth strategy continued to shine through in the financial results in the third quarter.

During the quarter, the company generated discretionary cash flow of $2 billion, invested $1.5 billion in capital expenditures before acquisitions toward the low-end of our guidance and paid $166 million in dividends. This brought $337 million in free cash flow.

Cash on the balance sheet at September 30 was $1.6 billion and total debt was $5.2 billion for a net debt to total capitalization ratio of 15%. A strong balance sheet is a strategic imperative for EOG. As Bill mentioned, our first priorities for capital allocation in 2020 will be investing in high-return drilling and supporting dividend growth.

Two bonds totaling $1 billion are scheduled to mature in 2020. As those dates get closer, we will decide whether to use cash on hand to redeem the bonds or to refinance one or both of them. I'll now turn it back over to Bill for closing remarks..

Thanks, Tim. In conclusion, there are several important takeaways from this call. First, EOG's 2019 operating performance is the best in company history. Our high-return disciplined growth strategy is producing strong returns, strong growth and substantial free cash flow. At the same time, we continue to get better in every area of the company.

Second, our premium inventory continues to grow in both size and quality much faster than we drill it. Third, the company continues to reduce costs and with our pleased-but-not-satisfied mindset, we see endless opportunities to continue to lower cost in the future.

Fourth, our GHG reduction and water reuse efforts demonstrate our leading, innovative and returns-focused approach to environmental stewardship and sustainability. And fifth, EOG is a resilient company. Our culture produces sustainable success.

As we look ahead, we're confident and excited about the company's ability to continue to create significant long-term shareholder value with performance that competes with the best companies in the S&P 500. Thanks for listening. Now we'll go to Q&A..

Thank you, sir. [Operator Instructions] And the first question we have will come from Brian Singer with Goldman Sachs. Please go ahead..

Thank you. Good morning..

Good morning, Brian..

Can we start on the two new zones in the Permian Basin? First, how are these being integrated into the drilling program? And given the greater wet gas mix, what are the implications for gas NGLs growth and infrastructure needs? And second, in your prepared comments, you mentioned the Bone Spring three helps mitigate the decline profile of the company.

Can you add more color on the reasons? And is this the type of decline rate improvement you've been referring to in the past? Or would that be driven by other exploratory projects under evaluation?.

Brian, I'm going to ask for Ezra to comment on the two new zones..

Yes, Brian. This is Ezra. Thanks for the question. There's kind of a lot there. So let me tear it apart piece by piece and maybe I'll start with the Wolfcamp Middle first, the Wolfcamp M. With regards to how it will be integrated into the -- into our development, that's a deeper zone across much of our core acreage position.

So one great thing about being able to turn this new bench premium is that it has the benefit of having pre-existing well control seismic infrastructure for both oil, gas and water gathering. And one way to look about that the greater wet gas mix is I think it's on slide 47 in our slide deck where we have the Delaware Basin play matrix.

It's very similar to the Wolfcamp combo in per well reserves in the gas, oil and NGL make up kind of a combo percentage there. And it's also very similar in cost. And so that gives us great confidence in having a premium play there and the fact that it's going to be a high-return play for a long time.

In the Wolfcamp combo, we've turned about 50 wells to sales in the past two years and they're generating over 100% rate of return and approximately $8 million of NPV per well. So we're very excited about that play. On the Third Bone Spring sand shifting gears to that. As we talked about that's kind of a tale of two plays.

We've got the more traditional sand target, which definitely because of the better porosity and the better permeability the decline rates are very similar to those in the First Bone Spring and the Second Bone Spring. And yes, I would say on a side bar that that is the type of reservoir quality that we're looking for in our exploration program.

And then the second part of that Third Bone Spring probably a little bit slower to integrate it, because it's really as you step outside of our core area and we're delineating some of the new acreage positions on it are these emerging targets that I talked about the Third Bone Spring, the shale and carbonate targets in there.

Industry has drilled about 50 wells in those targets and we're very excited about the potential there again as we move into those new areas..

Great. Thank you. And then my follow-up is if you could talk a little bit about the operational momentum into 2020. It is a daunting task to grow 15% from your large base of oil production.

So how are you setting up in terms of late 2019 and early 2020 activity? And do you expect ratable growth through the year or a bit more back-end loaded?.

Yes, as we said early in the remarks, Brian that our -- we're really having a fantastic operation this year in the operational momentum that we've got going and the company is going to carry over into 2020. So I'm going to ask Billy to comment a little bit more on the specifics about that..

Yes, thanks Bill. Yes, Brian, as we go into 2020 first of all, it's a little bit early to kind of give you too much detailed guidance on where we are. We don't expect to be able to reduce our rig count any further in 2019.

As we go into 2020 depending on what oil prices look like, we'll set what our activity is going to look like, but we certainly have the capability of increasing rig activity if the prices so warrant. The bottom line is we fully expect to deliver quarter-over-quarter production growth as we enter into 2020.

So the growth of -- the amount of which would be dependent on what the oil prices look like..

Next we have Subash Chandra of Guggenheim Partners..

Yeah. Good morning. First question is on, I guess, deflation. Understanding that you're budget for next year and your capital efficiencies aren't dependent on it. I'm curious, if you're seeing any evidence as some of the other operators are slowing down, or at least say they are slowing down..

Subhash, yes, I think, just in general, the U.S. shale industry, I think, year-over-year production growth is slowing. That's certainly not the case for EOG. I think, we continue to differentiate ourselves by continuing to improve and our well productivity remains very, very strong and robust.

We continue to -- as Ezra pointed out, we continue to drill record wells. And we continue to have record drilling times and we're setting new records really literally almost every play on well costs.

So the key to success in any business is getting better all the time and lowering your cost and getting your production up and maintaining a very, very strong performance. And I think the EOG culture is quite unique in the business and it really sets EOG apart..

Yes.

I guess, the question was, do you see cost deflation actually occurring?.

Well, I'll ask Billy to comment specifically on that..

Yes. This is Billy Helms. What we see on the service side, I guess, is the service industry is pretty much at a low. I wouldn't expect to see much further cost reductions on the service side. I think services are at a pretty low price point at this present time.

And for them to stay healthy, to be able to service our industry, I think there's not much room to go any lower. So I think the important thing for -- to differentiate, as Bill said, on EOG is that, we're not dependent on service cost to really continue to reduce our well cost. I think that's an important point to make.

Our operating teams continue to find ways to drill the wells faster, figure out more efficient completion techniques drive our lease operating costs down to improve our overall economics. And that's really what's driving EOG's continued efficiency gains..

Right. Okay. Got you. And then, my follow-up is, I guess, a philosophical question. And acquisitions, you've ruled out corporate. And maybe it's a moot point, because you have so much inventory that you can find organically. But it just seems that the A&D market is at sort of, at least in recent history, historical lows.

And the cost of your growth, I think, your slide suggests $30,000, $35,000 for flowing BOE per day. And there's acquisitions there equal to or less than that number.

Do you see an opportunity to exploit what hopefully is a temporary divergence in the market?.

So, I think, we want to be really clear on that. We do not envision doing any large M&A, expensive M&A, especially expenses. M&A is -- large M&As are just really not in our game plan. We have tremendous confidence in our organic ability to generate very strong, even better quality inventory than we currently have.

And we can do that organically at a much, much lower cost, even compared to what you might think M&A could produce. So our game plan will be continuing to focus on organic growth, low-cost growth, adding inventory that would be additive to the quality that we have and adding that at really low cost.

And we believe we can add very much a large amount of inventory that way if we -- I think, we commented that we're looking -- we're operating in six different basins and we have active prospects in 10 different basins ongoing right now. So it's the most robust exploration effort, I've been with the company 40 years, that I've seen in the company.

So we've got a lot of confidence in our ability to more than replace and to improve our inventory going forward at very, very low cost..

Next we have Charles Meade with Johnson Rice..

Yes. Good morning, Bill, to you and the whole team there. I want to just pick up, maybe, on the points you were just commenting on and try them a little bit differently.

Going back to your prepared comments, I think, it was point three on your points to differentiate, you said, you -- for mid-50s oil, you expect to grow -- or, excuse me, mid-50 WTI you grow oil comparable to the rate in -- that you grew in 2019, grow the dividend and then I believe it was also grow free cash flow.

And it makes sense that you guys would have better capital efficiency in 2020 than you have in 2019.

But can you give me an idea what is that increment that we should be looking for? And did I kind of get that whole setup correct?.

Now, then you're exactly right, Charles. What we said, is -- what we say is that, we can -- we believe, we can deliver mid-teens growth. We can grow the dividend and generate substantial free cash flow with oil at about $55. So we want to continue to operate.

Obviously, if you look at the company right now, we're operating in a continual -- a very high level, an optimum level. And we're generating a lot of free cash flow. We're producing really, really strong growth. And if you look over the last two years, we've grown the dividend over 70%. So that's what we want to continue to do in the future.

We want to continue to make sure that, first of all, that we're maximizing our returns. Our company's focus has always been on returns and returns come first. And volume growth is just an expression of reinvesting at high returns. So we want to operate at a point, at a level, at a growth level where we continue to get better every year.

And so next year, because of the operational momentum, we have this year and the ongoing cost reductions, we see that continuing going into next year. And so, our focus is to get better and to make better returns next year. And that will help us to grow at a very healthy rate and it also help us to generate very substantial free cash flow.

And so, we're also focused on the dividend. We want to have -- as we've talked in the past, I think, we've kind of -- a very good indication over the latter of the last two years, with dividend increases of 30% or better per year. And we want to do that going forward.

We're not going to commit to the level we're going to increase the dividend specifically, but we want to continue to have strong dividend growth in the future. And so, of course, that all depends on the macro environment what the oil price is and we evaluate that every quarter, our Board does. And we'll make those decisions on a quarterly basis.

But our goal is to get our dividend yield up to the 2% yield level as quick as possible..

That's a helpful elaboration. Thank you. And then, if I could ask the follow-up on the Middle Wolfcamp perhaps of Ezra. Ezra, you talked a little bit about -- when you're talking about the Third Bone Spring's in response to an earlier question, how many other wells in the industry had targeted the carbonate and the shale.

But do you have a similar sense for how many other industry wells have targeted this section in the Wolfcamp M?.

Yes, Charles. This is Ezra. I'm glad you asked that question. I was just sitting here trying to figure out if I had actually mentioned that or not. The Wolfcamp Middle, or M, as we call it, it roughly correlates to the Wolfcamp B and part of the C as known by some other operators.

And so, really across the Delaware Basin, there have been a few hundred wells drilled in a similar target there. And so we've got -- that's one of the reasons we've looked at all that data, they're landing zones, we've incorporated that with our own data to go ahead and announce this premium play..

Got it. That's what I was after. Thanks Ezra..

Next we have Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead..

Good morning and congratulations on the quarter. I thought the supply agreement with Cheniere was both interesting and innovative and it brought up two questions.

So the first one is, what sort of long-term price uplift versus Henry Hub do you expect from that portion of your supply that's indexed to the JKM Marker? And second, is this kind of a deal that you're looking at repeating again in the future, maybe with Cheniere or maybe another LNG exporter?.

I'm going to ask Lance to comment on that one..

Yes Jeff. Hey, good morning. Thanks for the question. First, to start off, I mean, it kind of follows up with what Billy talked about. I mean, this new transaction and the gas sales agreements that we've done with Cheniere, it's really consistent with our marketing strategy in how we're trying to diversify our sales points and having multiple options.

And really when we undertook this process when you really look at Cheniere, I mean they are the industry leader. I mean if you look at the 7.5 Bcf a day that's being exported today on LNG, they represent 5.5. So expanding our business with them, we're very excited about.

And just a reminder that starts at the 140,000 MMBtus a day starting in January of next year and that ramps up to the 440,000. But on your question just on the price realizations as that contract starts up next year, we'll be incorporating that into our guidance. So I'm not going to give any specific color on that.

But what I can tell you that's why it got us excited about it is just when you look at the amount of LNG demand growth that's going to be coming on especially over like the next 10 years, it's definitely all in the Asia Pacific region.

And so tying it to that and to see especially with significant weather events in those areas it's -- it can provide as you look historically for significant upside. So that's what got us excited about that. And then your last question there just about new structures and new deals.

I mean, we're very excited about this first and we're going to stay poised. I think, we're going to continue to watch the market. We're always looking for new opportunities in diversifying our portfolio. So we'll definitely be staying active in the future as we look at new structures that may come in front of us..

Thanks for that color, Lance. I appreciate it. My other question was earlier in the call there was some discussion of the corporate decline. And slide 49 notes that longer laterals exhibit shallower declines than shorter laterals, and I assume that's a comparison within a given play.

I wondered if some of the portfolio plays as a whole exhibit shallower declines than others.

And does this help influence attracting capital?.

Yeah, Jeffrey. That decline rate is something that we're very much focused on in the company. And so as we continue to focus our capital and high grade our capital, we do consider that as part of the process. And so we're looking at low decline, lower decline plays particularly in our exploration efforts.

Some of the newer plays we've announced in the last several years have lower decline than some of our historical plays. And then we're also looking and focused on lower finding costs. So low finding costs, low decline plays are certainly preferred for us and that's a focus of our exploration effort.

And it really is a function of the quality of the rock in combination with the completion technology and they work together to help in that regard. So we're focused on that and that helps the company get better. That's part of the process. We've been going on the last several years.

It's helped us get better in the last couple of years; certainly this year and we think that will continue to help us in the future..

And next we have Neal Dingmann of SunTrust..

Just want to get through all the details. And you talked a little bit -- I see as you always done on your slide 5 you break out the premium sort of parameters.

I guess my question is more around slide 36 and just what caused the changes in both what you were able to add but also to the Eagle Ford Bakken and Woodford, I think that was down a little bit on those.

I'm just wondering what contributed to that?.

Billy would you comment on that?.

Yeah, I think an important point to take away, Neal is that this represents our best estimate going forward on each play. The Eagle Ford as we've talked about it's an update relative -- taking into account the number of wells we drilled and then what we have remaining.

The important point on the Eagle Ford is to recognize as Ken discussed, we have 2,200 remaining locations that we can continue to work on to convert to premium over time as we continue to move into areas that are less developed. So I think that's the upside on the Eagle Ford.

The rest of the plays it just represents kind of what we see as the remaining inventory at this point in time for each one of these plays that are mentioned here. And overall it's in keeping with replacing -- more than replacing what we drill every year..

Very good. And then Bill maybe just one broad question.

I'm just wondering when you look at what's been mentioned today about the growth versus the free cash versus shareholder return, I'm just wondering when you sort of put out there the 15% growth to $55 is your primary delta, kind of, what free cash flow you want to achieve? Or what shareholder return? I'm just wondering how you all go about thinking about that..

Yeah. Certainly the free cash flow is an important component of it. So it's a balance of allocating capital at the right that we can get better and can increase our returns every year. It is certainly focused on generating substantial free cash flow and continuing to increase the dividend in a very strong manner too.

So we want to work on all three of those. And then as you know we have been reducing our debt. And Tim talked about that in the opening remarks. And so we want to continue to pay off those bonds as they mature.

So we look at all that but, primarily it's really focusing the capital on generating really strong returns and certainly working on the dividend..

Very helpful. Thanks guys..

Next we have Leo Mariani of KeyBanc..

Hey guys, I fully appreciate that you guys don't have 2020 guidance out there. You certainly talked about the mid-teens oil growth rate at $55 WTI, which sounds great.

I guess just from a high level philosophical perspective, in order to kind of achieve that, do you guys think you'd have to increase activity and CapEx at all? Or maybe a little bit to do that? Or do you think the efficiencies are such that you could do that with a similar type of activity?.

I'll ask Billy to comment on that..

Yeah Leo. This is Billy Helms. I think the takeaway would be we're going to be targeting as Bill said how do we continue to improve, what we do. We're not going to give you any specific guidance on how much capital that's going to deploy. We have the capability of increasing activity if the commodity outlook supports that.

But we're going to stay extremely flexible at this point in time to make sure that as we go into the next year, we're doing so with the discipline that we want to maintain in each one of our programs. So I guess we certainly have the capability of doing whatever the market shows us that is prudent to do. And our programs will support it.

And we have the teams to execute any of those programs. So we'll just, kind of, leave it there for right now..

Okay. I guess just wanted to see if we can get maybe a little bit more kind of a high-level update on some of the new plays. I certainly realize you guys aren't ready to announce any of the exploration plays but I know you've drilled a number of wells in 2019.

Really just wanted to get a sense of whether or not on some of the wells you've drilled you think that you're getting competitive economics even in these early stages here to the point where you can foresee some new premium drilling inventory? Any comments on that?.

I'm going to ask Ezra to comment on that..

Yeah, Leo. Thank you for the question. This is Ezra. As we've discussed previously, we're very excited about our exploration program. And Bill had mentioned that we're currently leasing and testing in over 10 different basins across all of our divisions, our focus primarily on oilier plays with higher rock quality that we've applied.

We're searching for these plays. We're prospecting for plays that we've applied core and log data in our reservoir models developed from our multi-basin approach.

So really leveraging off of our efforts in the Delaware Basin, the Powder River Basin, the Eagle Ford and Woodford oil window to really identify rock quality that will perform very well in combination with our horizontal drilling and completions technology and hopefully deliver slightly shallower declines.

And hopefully we'll be very competitive with our current inventory. Again we want to increase the quality of our inventory not just add to the back end. As far as that, we're confident in our reservoir models. And hopefully we'll be able to update you on a future call..

And next we have Scott Hanold of RBC Capital Markets..

Yeah, thanks. You all talked about hitting some of your -- the cost reduction targets this year and it sounds like you've got some new efficiencies you're seeing in place.

Is there anything specific you can point out to outside of, hey we're drilling faster but like specifically what's happening on the ground and maybe even from a technological side that's causing that improved uplift?.

Yes, Billy will comment on that..

Yes, Scott. It's not any one specific thing that helps us achieve these improved efficiencies. It goes back to what Bill talked about in his opening comments. It's the culture of the company. It's the drive of every one of our operating teams to continue to get better. And I couldn't be prouder of the execution those guys have made.

One example on the drilling side to help us get the wells drilled faster as I mentioned in the prepared remarks the innovations we've made on designing drilling motors that enable us to increase the speed at which we do and the reliability of those tools to keep them in the ground is just one example.

There's several examples on the completion side that go along with that to allow us to complete more of the lateral feet per day than we used to a year ago at a much lower cost and still deliver the same productivity improvements that we're seeing as we deliver the production from our wells. So it's just a number of different things.

And it's hard for us to capture them all in one call like this, but just to say, that everybody in each division is working hard to try to continue to improve every day..

Okay, understood. And then if I could try a question on next year's activity just at a high level. I mean it seems like this year if I'm not mistaken you've got around $400 million of that $6.3 billion budget allocated to kind of research development and technological improvements.

As you look into 2020 should we expect a very similar amount? Or -- and if I'm not mistaken I thought 2019 was going to be heavier.

What does 2020 look like?.

Scott, we're not I think ready at this point to give you a specific number on that. But we do certainly have an ongoing exploration and leasing program and so we'll continue to keep that up. But we won't give you a specific number on that. We're still working through all those details..

And next we have Joseph Allman of Baird..

Thank you. Good morning. My question is on political risk. Bill, EOG has been very good at reducing political risk, for example, not operating in Colorado.

What steps might you take to reduce the political risk that you addressed in your slides related to federal acreage?.

Well, I think, as we've talked about I think in the opening remarks we do have a very active permitting process going on. So we're well ahead of that. We have two to four years of permits in hand. And we have the ability to modify our operations and we have a lot of flexibility with the different operating areas and shifting rigs here and there.

And so we will -- we have been and we will continue to actively develop our federal acreage position very strongly. So we'll -- we've not really ever I think had a problem working with any of the regulatory changes. We have a great relationship with BLM and a great relationship with the state governments that we are active in. So it all works together.

We try to be a good citizen, a good operator. And it really has worked out well for us in the past..

Thanks, Bill. And then my second question is on the Austin Chalk. What is preventing the Austin Chalk from making it to the list of premier plays? You clearly have many great wells. Do you just not have enough to call it a premier play? Or is it really on the cost side? And you're drilling a couple dozen wells a year.

So it would seem to be -- it's at least a great play if not a premier play..

Yes. Well I think the first thing is when you think about the Austin Chalk, it's a really big play. It goes a long ways. And it's got all different kinds of aspects to it. And we've been very successful in our -- under our Eagle Ford acreage we have great results in the Austin Chalk. And it's certainly an exploration target for us.

And we have multiple places in the play that we're looking and testing. And so they keep our competitive advantage on making sure we get the acreage in the right spot. We haven't talked about anything specific. But we will at some point and we'll give you some updates on our progress in the Chalk..

Next we have Arun Jayaram of JPMorgan..

Hey, Bill, I wanted to talk to you or ask you about the potential sensitivity to your 2020 program to lower oil prices. I think you outlined a mid-teens oil growth at $55.

If oil prices average closer to $50 per barrel would you adjust activity accordingly? And could you discuss broadly the sensitivity to your oil growth rate at a $50 number?.

Well, we can't give you any specifics there Arun. But certainly we would adjust our capital. Again, we want to have great returns. That's numbers one. We want to have strong oil growth. We want to have substantial free cash flow. So we continue to work on the dividend. So we really balance all those.

And we would set it appropriately based on our macro view of oil in 2020. And at this point, we don't want to speculate, whether it's going to be higher or lower. We're just trying to give you some guidelines of kind of where we see our efforts next year..

Great, great and just a follow-up, I know the reduction in your rig count in the second half has garnered a lot of attention. But it sounds like this decline was driven by rig efficiencies. I guess my question is, in 2019 Bill, you're delivering call it 740 net wells for $6.3 billion, in capital.

If we were going to bake in the rig efficiencies, you're seeing today OFS deflation do you have any thoughts on what your CapEx dollar could do incremental to 2019? Could we see another call it 5% to 10% improvement in well cost next year?.

Again Arun, we're not going to give you any specific numbers. So -- but we do certainly believe that, our capital efficiency will improve next year over this year. We definitely believe that our well costs will continue to decrease next year too. So and we're certainly hopeful operating costs will continue to go down.

So the company just incrementally is getting better every quarter. And our culture, and our people, and our divisions are just doing a tremendous job in doing that. And so, along with oil prices, we bake all that in and that will really determine what our plan will be..

Next we have Michael Scialla of Stifel..

Yeah. Good morning, everybody. If you are successful with these new exploration plays, they turn out to generate better returns than even your premium inventory. I just want to see how quickly they could move to the top of the drilling inventory.

And if they're not just additive, would that allow you to actually replace some inventory to where you could look at monetizing some of the inventory that's maybe at the end of the spectrum?.

Yeah. And Michael thank you for your question, yeah the plays, the ones we're looking at these 10 different basins, most of them are in areas, where we could increase activity reasonably fast not jump in with 10 rigs in one year. But we could incrementally I think add rigs to each one of these plays and develop the infrastructure.

They're not in -- most of them are not in places where you couldn't do that fairly quickly. So, if they were incremental to our returns, we would certainly move that way on each one of them as quickly as possible. And we have a lot of inventory obviously in the company.

And we have sold, I think about $6 billion -- over $6 billion of properties over the last 10 years. And we'll continue to look to get value through possibly monetizing, any of that. But we don't think they'll ever get to a premium category. So, certainly that would be another avenue to add value to the company..

Okay. Thanks. And then, Bill you mentioned last quarter you were pleased with those first three Niobrara wells in the Powder. And then it looks like you added another one this quarter. One of your nearby competitors had some favorable things to say about the Niobrara this quarter.

I just want to see, how you're viewing that zone relative to the other targets in the Powder River Basin..

I'm going to ask Billy to comment on that..

Yeah. I think we're very pleased with the early results we're seeing from the Niobrara play. It's -- it looks to be something that we had hoped for. It's going to be more of an oily play in that Powder River Basin that we can grow oil volumes. And be competitive with the rest of our inventory.

And we're going at a pace now, that's really dictated by the learning's that we're taking into account, but also the infrastructure we have there now. And as we've mentioned in earlier calls, the pace of activity will be really married up with our level of spending on infrastructure to grow that play.

But it looks to be a play that we can see us growing another leg of growth that we'll have in the future..

Ladies and gentlemen, this will conclude our question-and-answer session. I would now like to turn the conference call back over to, Mr.

Thomas for his closing remarks, Sir?.

Yeah. So I'd just like to say that again, we're just so pleased with another outstanding performance by EOG in the third quarter. And we want to say many thanks to everyone in the company for making it happen. They're doing a fantastic job. The company continues to improve in every area. Our costs continue to fall. Oil well results are very strong.

Capital efficiency continues to improve. And our premium inventory continues to grow. So our high-return organic growth machine is running at the most optimum level in the company's history. And most importantly, we're very excited about performing at an even higher level in 2020. So again, thank you for listening. And thank you for your support..

And we thank you sir and to the rest of the management team for your time also today. Again, the conference call is now concluded. Again, we thank you all for attending today's presentation. At this time, you may disconnect your lines. Thank you. Just take care. And have a great day, everyone..