Timothy K. Driggers - EOG Resources, Inc. William R. Thomas - EOG Resources, Inc. Gary L. Thomas - EOG Resources, Inc. Lloyd W. Helms, Jr. - EOG Resources, Inc. David W. Trice - EOG Resources, Inc..

Brian Singer - Goldman Sachs & Co. Evan Calio - Morgan Stanley & Co. LLC Arun Jayaram - JPMorgan Securities LLC Scott Hanold - RBC Capital Markets LLC Paul Sankey - Wolfe Research LLC John H. Abbott - Merrill Lynch, Pierce, Fenner & Smith, Inc. Michael Scialla - Stifel, Nicolaus & Co., Inc..

Good day and welcome to the EOG Resources 2016 fourth quarter full year results conference call. At this time, I'd like to turn the conference over to Mr. Tim Driggers. Please go ahead..

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, Senior 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 quarter and full year 2017 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review 2016 highlights and our 2017 capital plan.

Gary Thomas, Billy Helms, and David Trice will review operational results and year-end reserve replacement data. Then, I will discuss EOG's financials and capital structure, and Bill will provide concluding remarks. Here's Bill Thomas..

Thanks, Tim. As we look back, 2016 will be remembered as truly historic for EOG because it's the year we permanently shifted to premium drilling and reset the company to be successful in a lower commodity price environment.

To remind everyone, our premium well is one that earns a minimum of 30% after-tax rate of return with flat $40 oil and $2.50 gas prices on a direct basis. We set the minimum at 30% to ensure that fully loaded well returns are accretive to corporate returns.

I want to emphasize that this shift to premium is permanent, which means that the return hurdle and the inventory of premium wells did not change with improving oil prices. Going forward, EOG's capital will be focused on wells that are profitable at $40, meaning with modest increases to oil price, our returns have the potential to soar.

You can see this on slide 24 of our investor presentation. Our list of accomplishments in 2016 include a few company records and first-time achievements. In 2016, we achieved one of the highest returns on capital expenditures in company history, and we did it at the low point of the commodity price cycle.

Our shift to premium drilling and improvements in operating costs resulted in record low finding cost of $5.22 per BOE when you exclude revisions due to commodity price. Over the course of the year, we increased our premium drilling inventory nearly 9% to 6,000 locations and over 5 billion barrels of oil equivalent.

The company added 3.7 billion barrels of oil equivalent of new drilling potential in the Delaware Basin. Since the downturn began in late 2014, we slashed unit operating costs by 22%. As a result of drilling low-cost premium wells, the company grew oil production within cash flow during the second half of 2016.

We announced the world's first technically successful enhanced oil recovery in shale that delivers strong project economics. EOG completed the largest transaction in the company's history with the Yates Petroleum acquisition.

Finally, we accomplished all this while maintaining a healthy balance sheet and posting the best safety record in the company's history. To sum up 2016, record setting capital efficiency gains and a significantly larger and improved drilling inventory have reset the company to achieve outstanding results in the years to come.

This is why we are confident that we'll be one of the lowest cost producers and competitive in the global oil market. Now looking ahead to 2017, we're more excited than ever to resume our leadership in high-return oil growth. Transforming EOG into a premium-only driller means we expect to deliver 18% oil growth within cash flow during 2017.

Remarkably, EOG can deliver strong 18% oil growth plus the dividend within cash flow if prices were to average $50 oil and $3 gas. We believe this is unique in the industry and sets EOG apart as the most capital efficient operator in the U.S.

Furthermore, each of EOG's major basins will be contributing to that growth in 2017, the Eagle Ford, the Delaware Basin, the Bakken, the Powder River Basin, and the DJ Basin. That's a testament to our diverse portfolio of high-return assets. Our plan was finalized last month when strip prices were closer to $55 oil and $3.50 natural gas.

If current prices hold, we will reach our goal of generating free cash flow. Our number one priority for that cash is to reinvest into high-return premium drilling. We also want to continue firming up the balance sheet with non-core asset sales.

And if the business environment continues to improve, we will want to refocus on our commitment to the dividend. Looking beyond 2017, I want to talk about EOG's return prospects, specifically return on capital employed [ROCE].

If a company is earning the well-level returns we and many of our peers assert, we should eventually see those results reflected in ROCE. For EOG specifically, we expect returns and finding costs to continue to improve in the years ahead as premium wells become a higher percentage of total well completions.

As new premium wells are drilled, their DD&A rate will converge towards premium finding costs. The lower DD&A rate along with lower cash operating costs such as LOE [Lease Operating Expense] and transportation should significantly improve EOG's ROCE over time.

With our shift to premium drilling, our goal is to generate ROCE that exceeds our historical average of 13%. We believe this performance will make us competitive not only among our peers, but with other industries outside the energy sector. ROCE has been a very important performance metric at EOG and remains a top priority in our long-term vision.

EOG is rate-of-return driven. Returns are the number one criteria for incentive compensation, and it drives capital allocation within the company. We believe EOG's best days for ROCE still lie ahead of us. Up next to provide details on our operational performance in 2016 and review the 2017 game plan is Gary Thomas..

our average daily rig rates are down 25% compared to last year. Fourteen of our drilling rigs or 60% of the total are under long-term contracts, and nine of these rigs are at bottom-of-market rates. We've locked in three-quarters of our casing needs at prices 30% below our 2016 costs.

To further control cost, we've also locked in 50% of our frac fleets. And we have diverse sources of frac sand, and our aggregate sand costs are expected to decrease by 18% year over year. Furthermore, I'm confident we'll be able to further improve operational efficiencies in 2017.

During the downturn, we took the opportunity to upgrade our rig fleet to one of the most modern and highly efficient fleets in the industry. We are drilling 20% longer laterals and increasing the use of multi-well pads. Our expanded water infrastructure systems are expected to reduce our well cost by another $100,000 per well.

And because of the combination of operational efficiencies, we expect to complete 15% more wells per frac fleet this year. We expect 2017 can be another great year for improvements for EOG's capital efficiency, maintaining our position as the low-cost, high-return leader in the E&P industry.

I'll turn the call over to Billy Helms, who will update you on our Eagle Ford and Delaware Basin plays..

Thanks, Gary. The Eagle Ford has seen consistent year-over-year improvements in both production performance and operational efficiencies that have been the hallmark of EOG's advancements in horizontal technology. We continue to test multiple targets and spacing patterns to determine the optimal development pattern for each area of the field.

The wells completed in 2016 as a group are outperforming wells from previous years, largely as a result of the precision targeting and advanced completion designs. During 2016, 210-day cumulative production improved 13% for wells drilled in our western acreage, while wells drilled in the east improved 10%.

We also reduced completed well cost by $1 million to $4.7 million, and believe further reductions are possible in 2017. I'll leave you with one final important note about this play. There's still a tremendous amount of upward potential in the Eagle Ford.

To date, we have drilled less than one-third of the total identified locations in this world-class play. The efforts to update the total resource potential are underway and can only be assessed with longer-term performance from each of the various targets and spacing tests.

Our technical team continues to integrate the latest results into our future plans to assess the full potential of this asset. Suffice it to say it continues to grow. Eagle Ford oil production is expected to grow during 2017 while drilling less than half the number of wells we did during the peak of activity in 2014.

Using our 2017 rate of approximately 195 net completed wells, we have over 20 years of inventory. The Eagle Ford has been and will continue to be a growth asset for the company. Last year we announced early success in the first enhanced oil recovery project in horizontal shale.

In 2015, we tested four pilots, comprised of 15 wells across a geologically diverse area, and the results were consistently positive and highly economic. In 2016, we initiated a larger 32-well pilot to test how well EOR technology can be implemented on a larger manufacturing type scale.

The pilot has been a success and confirms our initial results for field-scale implementation. As with the 2015 pilots, the 32-well project delivered premium economics with a finding cost of less than $6 per barrel. This 32-well project provided insights into EOR's impact across a wide variety of completion styles and spacing patterns.

The results were favorable for wells completed from 2011 through 2016, with well spacing ranging from 200 feet to 500 feet. This gives us further confidence of the applicability of EOR across major areas of the field. And in addition, our technical understanding of this first in the world EOR process is increasing.

The 300,000 barrels of net oil production from EOR in 2016 was within 5% of our forecast, further validating the consistency of the results observed in the four pilots prior to 2016. This data supports our previous estimates that the incremental recovery due to EOR is adding 30% to 70% more oil to our primary recovery estimates.

In 2017, we are eager to expand our EOR project by testing approximately 100 additional wells in six different areas. The result of this program will provide additional data on EOR's uplift to the Eagle Ford's resource potential and EOR's effect on field production decline.

This data will help determine how we will incorporate EOR into our long-term Eagle Ford capital program. 2016 was a breakout year for the Delaware Basin, setting up this play to be our fastest growing asset in 2017.

First, EOG completed some of the industry's best wells in the Permian Basin through the application of our leading-edge technology, including precision targeting and high-density completions. This technology has proven to deliver step change in well performance.

And with an improved wellbore design, we began testing longer laterals in the second half of the year, with promising recovery results on a per foot basis. Our goal is to achieve the same recovery measured by EUR per foot of lateral as we increased lateral length.

In 2017, we expect to use longer laterals on a larger percentage of our program, so we're excited to watch the well performance continue to improve. Second, the Yates transaction was truly transformative. The acreage obtained in the Delaware Basin is not only adjacent to our existing program, but it's also generating highly economic results.

Our technical capabilities combined with this transformative transaction resulted in adding a record-setting 3.7 billion barrels of oil equivalent of estimated resource potential last year alone.

In addition, we've already identified almost 3,500 premium oil locations across three targets in the Delaware, the Wolfcamp, the Second Bone Springs, and the Leonard. This is almost a mile of stacked pay in this world-class basin, and our exploration efforts are just getting started. And third, we are well positioned on infrastructure.

Over the last few years we've made strategic investments in oil and gas gathering and takeaway, gas processing, water sourcing and handling, and sand rail car unloading facilities. As an example, the water sourcing and handling infrastructure is helping to reduce both our initial well cost as well as reducing our long-term cash operating cost.

Some of the assets obtained in the Yates transaction included water gathering systems that support our existing systems. In our major areas of activity, we will deliver a significant percentage of our produced water into these systems. We're also increasing the volume of recycled water for use in our operations.

These examples along with other cost initiatives have rendered the lease operating expense in the Delaware Basin to be among the lowest in the company. We believe these investments will provide us a competitive advantage now and in the future as we grow in the Delaware Basin.

The Delaware Basin Wolfcamp is arguably the most prolific tight oil play in North America, and EOG consistently delivers the best Wolfcamp results in the industry. Please see slide 9 of our investor presentation for a plot of our 2016 well performance versus the industry.

In 2017, the Wolfcamp will again be the primary focus of our drilling program, as we plan to complete 110 net wells. Here's David Trice to review the progress we've made in the Austin Chalk and our Rockies, Bakken, and international activity..

Thanks, Billy. Last year, our Eagle Ford team took a fresh look at the Austin Chalk and discovered that within our current Eagle Ford footprint, there are areas where the Austin Chalk is prospective. Using proprietary petrophysical analysis, we can identify and map the best reservoir properties using our existing well controls.

We are then able to target the best rock with horizontal laterals and apply EOG-style high-density completions. The result is consistent premium Austin Chalk wells. These wells can be very prolific. And in fact, some of the best wells drilled by the company last year were in the Austin Chalk. In 2016.

we completed 14 Austin Chalk wells with an average 30-day rate of 1,700 barrels of oil per day and total equivalent rate of 2,200 barrels of oil equivalent per day from an average lateral of 4,400 feet.

We continue to drill delineation and spacing tests, analyze subsurface data, and create detailed mapping throughout the field to understand the prospectivity of the Austin Chalk across our South Texas position. During 2017, we'll drill approximately 25 net wells in the Austin Chalk.

Those well results along with the work we did last year should get us closer to providing a resource estimate for this emerging play. In the Rockies, we had great success in the Powder River Basin and Wyoming DJ Basin during 2016. In the Powder River Basin, we focused predominantly on the Turner interval in 2016.

Turner wells compete with the best inventory in the company. Our 2016 drilling program in this play averaged over 1,600 barrels of oil equivalent per day rate-restricted for the first 30 days and cost about $5 million to drill and complete.

During the fourth quarter, we returned to the Parkman interval and applied our latest techniques with excellent premium-level results. Three Parkman wells had a 30-day rate that averaged 2,200 barrels of oil equivalent per day. With the addition of the Yates acreage, our core position in the Powder River Basin has grown to 400,000 acres.

We are expanding this program in 2017 to complete 30 net wells. And we look forward to blocking up acreage, applying longer laterals, adding to our premium inventory, and exploring the 4,800 feet of stacked pay. In the DJ Basin, we added 200 premium Codell wells through sustainable cost reductions and precision targeting during 2016.

We also completed installation of water and gas infrastructure that should further reduce cost and enhance returns as we increase our development in 2017. We plan to complete approximately 15 net wells in the DJ Basin Codell this year.

The Bakken is another area we've been investing in water takeaway infrastructure that should further reduce costs to support and enhance returns of our ongoing drilling program. In the fourth quarter of 2016, we completed a majority of the remaining pre-2016 DUCs.

As a result, our 2017 drilling program will be focused on drilling premium Bakken core and Antelope Extension inventory. We expect to complete 35 net wells during 2017. In Trinidad, we continue to get great results from existing wells, which led to outperformance versus forecast in 2016.

Production in Trinidad was virtually flat despite drilling just one additional well that came online in December of 2016. In 2017, we expect to drill an additional five net wells throughout the year. Here's Billy to review our year-end reserve replacement and finding costs..

Thanks, David. We replaced 163% of our 2016 production at a very low finding cost of $5.22 per BOE, excluding revisions due to commodity price changes. That's less than half of our 2015 finding cost. The proved developed finding cost excluding leasehold capital was $6.50 per BOE.

Notably, sustainable LOE reductions drove positive reserve revisions that more than offset negative revisions due to lower commodity prices. As a result, our proved reserves increased by 1.4% year over year, driven by a 7.7% increase to crude oil and natural gas liquids reserves.

These are record low finding costs and demonstrate the tremendous capital efficiency gains we made this year resulting from our permanent shift to premium drilling and laser focus on cost reductions. I'll now turn it over to Tim Driggers to discuss financials and capital structure..

$3.1 billion of leasehold acquisitions; $735 million of proved property acquisitions; and $17 million of other property, plant, and equipment. We also recorded $1.1 billion of deferred taxes related to the transaction.

To fund the Yates transaction, EOG issued 25 million shares of common stock and paid cash of $16 million for a total consideration of $2.4 billion. At year end, total debt outstanding was $7 billion, for a debt to total capitalization ratio of 32%. Considering $1.6 billion of cash on hand at year end, net debt to total cap was 28%.

In the fourth quarter 2016, total impairments were $298 million. For the full year 2016, total impairments were $620 million. Impairments to proved properties of $116 million were primarily the result of a write-down to fair value of legacy natural gas assets, which have since been divested.

Impairments for both the fourth quarter and full year 2016 included charges for firm commitment contracts related to the divested Haynesville natural gas assets and obsolete inventory. The effective tax rate for the fourth quarter was 27% and deferred tax ratio was 44%.

Yesterday we included a guidance table with our earnings press release for the first quarter and full year 2017. Our 2017 CapEx estimate is $3.7 billion to $4.1 billion excluding acquisitions. The exploration and development portion excluding facilities will account for about 81% of the total CapEx budget.

The budget for exploration and development facilities and gathering, processing, and other accounts for approximately 19% of the total CapEx budget for 2017. We plan to concentrate our infrastructure spending in the Eagle Ford, Delaware Basin, and Rockies to support our drilling program in those areas and enhance operating efficiencies.

Now I'll turn it back over to Bill..

Thanks, Tim. In closing, I will leave you with a few important points. First, our improvement to well performance has been accomplished through the use of proprietary technology to identify high-quality rock, drill precisely targeted laterals, and execute leading-edge completions. We're now beginning to drill longer laterals.

And we believe our industry-leading well performance combined with longer laterals will drive significant productivity gains in the future. Slide 10 in the IR deck illustrates this conclusion. Second, EOG has not and has never been a one-trick pony.

We have top tier positions in the big three producing North American oil basins and strong positions in what we believe are the best emerging plays.

Our diverse portfolio of assets and decentralized operating structure provides incredible flexibility to invest in the basins with the highest returns, particularly as technology, infrastructure, and netbacks change. Third, the recent downturn has highlighted one of EOG's core values, and that's capital discipline.

There are two guiding principles to our capital discipline, a strong balance sheet and return-based capital allocation. EOG generated near record capital returns at the low point of the commodity price cycle last year. In addition, we not only maintained but improved our balance sheet without issuing equity to pay down debt or cutting the dividend.

EOG is a leader in capital discipline, with a relentless focus on returns and a commitment to spend within our means. We are committed to delivering industry-leading oil growth and returns and delivering this within cash flow, including dividends, even in a flat $50 oil environment. Fourth, EOG's exploration focus is still in high gear.

We have never been more excited about the leading-edge technology that we are developing in-house and the new exploration concepts we continue to discover. Everything we learn from our existing plays is being applied to generate new exploration concepts and leasing efforts.

With new knowledge, we continue to see significant opportunities to add to and improve our inventory through exploration. Better rock makes better wells, and that's our exploration focus. Do not count us out. We're not through. And finally, in my 38 years with EOG, I've seen many downturns.

Every time we emerged from the downturn in better shape than we entered it. This downturn, however, is unique in every respect except direction. We're not simply in better shape. We've vaulted ahead with record-setting achievements in cost reduction, productivity gains, inventory growth, and capital efficiency improvements.

We have the deepest inventory of premium inventory in the industry, and it's growing rapidly. We are poised for amazing growth. And more importantly, our goal of returning to the historic levels of company ROCE performance are in sight. Thanks for listening, and now we'll go to Q&A..

Thank you. We'll take our first question from Brian Singer with Goldman Sachs..

Thank you, good morning..

Good morning, Brian..

My first question is on the Eagle Ford from a primary drilling perspective. You talked about the increase in oil rates. Slide 40 shows some of this in terms of your wells in 2016 versus 2015 versus 2014.

What are the implications for EURs and spacing from the improved well performance that you're seeing over multiple days? And if not yet certain there, can you just talk to the milestones that you're looking for to have more confidence?.

Brian, this is Billy Helms. So yes, you're seeing on that slide that we see continued improvement in production performance year over year in the play. And that's really accomplishing lots of things, but it's really driven by our technology that we're bringing, mainly the targeting and the enhanced completions that we're doing now.

Those two things have made a step change. So we're still testing some spacing patterns in different areas of the field and applying this new technology to understand longer-term performance. And as we've stated in the past, as we make these changes, we want to further understand the longer-term performance before we do our resource estimate increase.

We are encouraged that the Eagle Ford is going to continue to improve with time, but we still are watching that data. The Eagle Ford has been essentially a very large laboratory for us to continue to experiment with. So as we continue to gather this data, we'll have a better idea of what that implication means to the long-term performance.

So I can't really give you a timeframe yet, but I'd say that we're encouraged with what we see..

Thanks. Then my follow-up is with regards to well costs. On slide 14, you talked about some targets for further cost reductions, which seems in the face of an inflationary environment we may be going into or are already in.

Can you just talk about the achievability and whether these are more one-off we'll get there, or whether these are ultimate averages? What happens if prices aren't $50, they're a little bit higher in the inflation environment and assumptions that you've baked in?.

Brian, this is Gary. Yes, we look at each of the wells in the area. And what we see is about 40% of our well cost is subject to inflation because we've got contracts in place, we've got sole-source, all that sort of thing.

When we do that and we look at what kind of opportunities we see for just other efficiency improvements, we believe that we'll be able to meet these targets that we've set here for each of these plays that's listed on this Exhibit 14..

Got it. Is there any upside? If oil prices are $55, then I guess one, we just apply the inflation to that 40% to get to something modestly higher..

As far as – irregardless of oil price, this is where we think that we'll be able to get here on this 2017 target..

Great, thank you very much..

We'll go next to Evan Calio with Morgan Stanley..

Good morning, guys..

Good morning..

You guys highlight more prominently exploration in the presentation and in your 10-K and in your comments this morning. Let me start.

How derisked does a new play need to be before you'll disclose it? And outside of securing acreage, what are the key parameters necessary before you'll show it to investors? And I raise it from the context of peers, both U.S. and global, that have unveiled unconventional plays at much earlier stages, raising the risks as data is released..

The first thing, Evan, is the play has to be premium quality, so it has to meet the investment hurdles that we've set for premium drilling. And then second of all, we like to have multiple tests, and we like to be really convinced that the play is going to work up to our expectations and we have some consistency about it.

We don't want to drill a one or two-well wonder, then come back and some of the other wells are not so good. So we do take a little bit more time. I think it's because we're just more thorough and we want to be more sure about it. And then there's always, in every one of these plays, you mention acreage. Acreage is the critical thing.

And we want to – as we test them, we learn more about where the sweet spots could be in the plays. And so we're only focused on tying up the sweet spots of that acreage. So we have a large number of plays in the company that we're working on.

As you know, we're very decentralized, and each one of our operating divisions has a full set of exploration folks, and we're spread out all over the U.S. And so we're working multiple plays at the same time, and we're quite optimistic about new plays providing additional premium inventory in the future..

Great, I look forward to hearing results as we move through the year. My second question on the Permian, you guys are running 11 rigs and targeting 140 wells in 2017. Implied spud to spuds are up year over year.

Any color there on maybe how many well completions in the 2017 program are being carried into 2018, or does the lower number of wells reflect a larger appraisal program? Or just some color around that sequentially would be helpful..

Evan, this is Billy Helms. So what we're seeing there in the Delaware Basin is we've had a steady rig count, and we're typically going be drilling longer laterals in 2017 than we did in 2016. So the drilling times are going increase slightly just as a result of that.

On the number of well completions, I believe we're going to complete about 140 total wells in the Delaware Basin this year, most of those in the Wolfcamp. And we're down to a normal level of inventory in all of our major plays, including the Delaware Basin. So we're not really carrying over into 2017 an abnormally high amount of DUCs, you might say.

So I think we'll just – the rig count there has increased relative to last year. We will be going to longer laterals, but we'll have about 140 net wells completed this year..

Is there a carryover into 2018 I guess was my question because it seems as there would be on those numbers..

No, no, there's no carryover into 2018 that we see..

Got it. Thanks, guys..

And we'll now go to Arun Jayaram with JPMorgan..

Good morning. My first question is just on the overall guidance. Bill, you guys issued essentially in line oil production guidance, but you're using quite a bit of a lower oil price perhaps relative to strip and consensus, around $50. I was wondering if you could comment on how you plan to address the CapEx budget and guidance for the year.

Do you plan to look at it on a quarterly basis or reassess things around the middle of the year? Because on our numbers, your cash flow would be closer to just under $5 billion using the strip..

Arun, we set the $50 marker just to give a reference point there. That's where we would be able to have a balanced cash flow to our CapEx and our dividend. So if prices are higher than that, we're going to have free cash flow, and that's certainly one of our goals every year is to generate free cash flow.

As far as how we're going to deploy that, it's a bit early to give you specifics. The overall guidance would be that we're going to stay disciplined, obviously watch commodity prices, watch our drilling results and our cost and watch property sales. And we'll just update you every quarter on where we are on all that. I can say this.

We have an extreme amount of flexibility. So with our decentralized structure and multiple high-return plays, it's very easy for EOG to redeploy capital, and we can do it relatively quickly.

If one area, say, heats up and maybe it's difficult to get a frac spread or something in one area, we've got other areas that it's easier and they have high return. So we can ramp up relatively quickly. The priority for the free cash flow is to reinvest. That's the number one priority is obviously reinvest into high-return premium drilling.

We also want to continue to firm up our balance sheet. We're going to do that primarily with non-core property sales. So we need to watch how that process proceeds. And then EOG's got a great track record of increasing the dividend, 16 times in the last 17 years.

So consistent with that commitment to the dividend, as the year unfolds we'll continue to evaluate the business environment as it relates to the dividend. So again, I think we've got a lot of flexibility, and we'll give you more details on a quarterly basis..

That's helpful. My follow-up is perhaps a follow-up to Brian's question. In terms of the Eagle Ford, you did show a positive rate of change in both the east and the west. My question is regarding the Q4 activity. If you look at some of the 30-day rates on the 75 wells, they're a touch below our expectations or type curve.

Can you comment perhaps on what you saw in terms of productivity between the 45 wells which were drilled prior to 2016 versus the 30 that you drilled last year in terms of the impact perhaps of precision targeting in terms of well results?.

Arun, this is Billy Helms. Certainly you're picking up on it there. In the fourth quarter, about 60% of our well completions were DUCs carried over from prior years. And those wells didn't benefit from the precision targeting that we have done more recently.

And so you're seeing some of the 30-day initial IP rates from those wells being below those of previous quarters. But I think overall, after time you can see on that productivity chart that after about 120 to 150 days, they start to – because of the advanced completions, long-term performance is still improving.

So we're continuing to be pleased with our technology and what it's yielding there both in longer-term performance as well as initial upfront productivity..

Okay, thanks a lot..

We'll go now to Scott Hanold with RBC Capital Markets..

Thanks; good morning..

Hello, Scott..

Hey.

Just as a follow-up to the question on looking at a higher commodity price and your ability to deploy that to more drilling, can you specifically discuss when you look at the market as it sits right now, strip probably closer to the mid-$50s, how do you internally look at that to make that decision whether to increase activity or not? So what I'm trying get to is what are the key indicators that provide you the confidence that oil's going be $55 or $60 rather than say $50?.

Scott, I think we're watching the oil market, particularly inventory levels. And I think just in the last week or so, we're starting to see very encouraging signs on inventory drawdown, and I think we're getting close. It won't be in the next month or two.

I think we're going to know a lot about how the OPEC cuts have affected supply/demand dynamics and the drawdown of that inventory. So we're about there, but we just need a little bit more time on that.

I think the other thing is, with the rapid ramp-up of drilling rigs in the U.S., we don't want to ramp up too rapidly to decrease the capital efficiency. So we're very committed to keeping the capital efficiency of the company extremely high, and we really only want to increase the capital efficiency.

So part of our ramp-up strategy will be certainly to stay very disciplined, to allocate the capital to obviously the highest return investments that we have, and then do it in a systematic manner where we're bringing in really good equipment, really good people, and we don't lose performance there..

Okay; appreciate that.

And as my follow-up, just in terms of the progression of activity right now, where are we at in terms of your current activity, your rig count relative to what the budget contemplates? Are we there yet, or is there still a little bit of ramp to go in some areas?.

Scott, this is Gary. We've ramped up pretty rapidly here in 2017 because we ended 2016 with 17 drilling rigs, and we've now just this week reached 23. So we're a little bit heavier in the Delaware. We run about 11 rigs there. And then we're running in the seven to eight rigs in the Eagle Ford and a couple in the Rockies. So we're close.

And like we mentioned earlier, yes, we've really been working hard just to get the very best available rigs in the industry. So we're pretty well there..

I appreciate that; thanks..

We'll go to Paul Sankey with Wolfe Research..

Good morning, everyone. I think a lot of people when they hear you talk get very bearish on oil prices, and I don't think that's the way you look at the world. Bill, can you remind us why what you're doing isn't replicable across the industry, which is I guess the reason why people would be very bearish? Thanks..

Sure, Paul. The productivity that EOG has, the capital efficiency, which goes really back to our ability to contain costs and renew costs on a sustainable basis, and particularly as we've shifted to premium drilling over the last several years and we've applied the new technology. There's a chart on page 10 that we referred to in the opening remarks.

And it shows well productivity for the industry as lateral lengths increase. And generally, when you look across all these plays, there's been quite a bit of studies, not just our studies, but this is basically IHS data that anybody can duplicate. It shows that as lateral lengths increase, obviously the well productivity is increasing.

But EOG is in the red there. And if you look at that chart, you can see that our productivity is increasing much, much faster than generally the industry. Even our wells are much more productive even at a short lateral versus some of the laterals that are almost twice as long. So --.

Bill, would you put that down to technology or acreage? Is there any way to – I know it's a very simplistic question for a very complicated....

Well, it's two parts. It's better rock and you have to capture that better rock. So with our exploration focus over the years, we've really honed in on capturing the sweet spots of the best play. So that is the beginning of it.

And then the second part of it is identifying the specific targets in those sweet spots, and then executing the lateral and a large percentage of that really great rock, and then using our very advanced, very proprietary completion techniques. So it's a combination of all that technology, and that is not very duplicable.

It has taken us really a decade to get to this point. We have very proprietary petrophysical models that we do, obviously take a lot of cores, and we've tied that back into productivity data. And so it's a cumulative effect of a large amount of years in time and a lot of data, and it's not easily duplicated..

Yes, understood. Can I ask a follow-up as well? I think you're also somewhat unique in the way that you pay your staff. How does it in a sense like the company to think if you're returns focused? Why would you – I guess I'm trying to get around to the idea that you're still incentivized to grow.

If you could, just remind us how the staff payment through returns works and how that affects your strategy. And I'll leave it there, thanks..

Sure. The bonus system has three metrics for each division, certainly for the folks here in Houston, and then it goes down to each employee. So the number one criterion on the bonus pool on the compensation is returns. So the capital returns that your division is responsible for and that you helped execute is the number one.

Number two is how you meet your volume targets. So volume is second. Volume growth is second and returns are first. And then number three is how well you're setting yourself up for the future. So of course, we have a very strong culture of generating new inventory and better inventory all the time. And it all ties together.

If you invest your money and you get a very, very high rate of return, you're going to grow your volumes spectacularly at the same time. So it all fits and it's very focused..

Why don't you think other people do it? Why do you think it's unique to you guys to use that methodology? I would have thought everyone should do that..

I would say the same. I would agree. I think it's just a culture that's been in the company for decades and it just keeps getting better every year..

Thank you, sir..

We'll go to Doug Leggate with Bank of America Merrill Lynch..

Good morning. This is John Abbott speaking on behalf of Doug Leggate. We appreciate you taking our questions. Our first question relates to 2017 activity levels. How do you see the pace of completions throughout the course of the year? And then our follow-up would be, it looks like you exit 2017 with significant momentum.

Could you provide an early look at the exit rate for the year and a preliminary view for 2018? Thank you..

Let me just answer the second part first. We have given a long-term outlook. That's provided on one of our slides. I'll give you the number here in a minute, but we've given an outlook at $50 to $60 oil. We can grow at a compounded annual growth rate of 15% to 25%. So you can look at that.

That means that in the year 2020, EOG would be producing 500,000 to 700,000 barrels of oil per day. And so you can use that as a guide. As far as the specifics on 2017 about how we're going to schedule our completions, I'm going to let Gary Thomas comment on that..

John, we've got our completion schedule pretty well balanced each quarter through the year. And as I mentioned earlier, we had maybe a little slow start as far as just the ramp up of the rigs. And we also mentioned that once we take our rigs up that it's two to three months before you really start to see production from each of those rigs.

So we do have a ramp from first quarter through 2017..

We appreciate it, thank you..

We'll go to Mike Scialla of Stifel Financial..

Hey, good morning, guys. Looking at your 2017 CapEx increase over 2016, it doesn't look proportional to the number of wells. I think the CapEx up over 40%, the number of wells is about 7%. I know you had the benefit of completing some DUCs in 2016, and you alluded to this earlier, but I think a lot of that is due to longer laterals in 2017.

So one, is that fair? And then two, if it is, do you have an average lateral length for the 2017 wells versus 2016?.

Mike, the reason that the CapEx is going up – it's several reasons. Number one is the DUCs. As you mentioned. we had a little bit of a benefit there. The wells were already drilled. So we haven't drilled more wells this year than last year. But the wells are much better this year due to the technology and the higher shift to premium.

The more capital per well on the completion side is due primarily to the Permian. We've increased the Permian well count substantially more than the other plays. And the wells are a bit more expensive in the Permian than they are in the Eagle Ford or the Bakken, and also because the wells are getting longer too..

Okay.

Any sense of the lateral length 2017 versus 2016?.

It's up about 20%. As you say there, Mike, that's a part of our increase. The big part is just the increased drilling since we had so many DUCs in 2016..

Okay. I wanted to follow up on the Austin Chalk. Tim made some comments on that; that those wells do look really strong.

Can you say where the 14 wells are located that you drilled so far? Are they all in the Austin Chalk, or is it spread across your Eagle Ford acreage? I know you want to see the results from this year's drilling program before you start talking about resource potential.

But I just wanted to get any sort of sense on how much of that Eagle Ford acreage could be prospective.

Are we talking maybe up to half, or is that way too optimistic?.

This is David. On the Austin Chalk, that's really what we're focused on right now is delineating the play. So the 14 wells that you mentioned, those are really across the play. And so we continue to evaluate that. And so we're going to – the encouragement we saw from 2016, we're going to up that this next year in 2017 to 25 wells.

And we'll do the same, we'll be testing some spacing patterns and then stepping out and seeing what the prospectivity is across the entire position. But we just want a little bit more time with the data..

Just to follow up on that, did it look like it could be a resource-type play, or is it going be more one-off areas where you've got little isolated pockets that work?.

One thing in the Austin, it's a little bit more geological than the Eagle Ford. And so we have multiple zones there that we're looking at, so we'll be testing each of those zones. So that's really why we want the opportunity to see the data and look at the spacing tests..

Okay. Thanks, David..

Ladies and gentlemen, that does conclude our question-and-answer session. At this time, I'd like to turn the conference over to Mr. Thomas for any additional or closing remarks..

In closing, I want to say thank you to the outstanding employees of EOG. Their performance during the downturn has been incredible. The company is set up to deliver, and we look forward to creating long-term shareholder value in 2017 and beyond. Thank you for listening and thank you for your support..

Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation..