Timothy K. Driggers - EOG Resources, Inc. William R. Thomas - EOG Resources, Inc. Lloyd W. Helms, Jr. - EOG Resources, Inc. Ezra Y. Yacob - EOG Resources, Inc. David W. Trice - EOG Resources, Inc. D. Lance Terveen - EOG Resources, Inc..

Leo P. Mariani - NatAlliance Securities Scott Hanold - RBC Capital Markets LLC Ryan Todd - Deutsche Bank Securities, Inc. Subash Chandra - Guggenheim Securities LLC Robert Scott Morris - Citigroup Global Markets, Inc. Brian Singer - Goldman Sachs & Co. LLC Phillips Johnston - Capital One Securities, Inc.

David Martin Heikkinen - Heikkinen Energy Advisors LLC Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc..

Good day, everyone, and welcome to the EOG Resources Fourth Quarter and Full Year 2017 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir..

Thank you, and good morning. Thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 2017 earnings and operational results. This conference call includes forward-looking statements.

The risk associated with forward-looking statements have been outlined in 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 schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves, as well as possible reserves.

Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves, not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S.

investors that appears at the bottom of our press release and Investor Relations page of our website.

Participating on the call this morning are Bill Thomas, Chairman and CEO; Gary Thomas, President; Billy Helms, Chief Operating Officer; David Trice, EVP-Exploration & Production; Ezra Yacob, EVP-Exploration & Production; Lance Terveen, Senior VP-Marketing; David Streit, VP-Investor & Public Relations.

An updated IR presentation was posted to our website yesterday evening and we included guidance for the first quarter and full year 2018 in yesterday's press release. This morning we'll discuss topics in the following order.

Bill Thomas will review 2017 highlights; Billy Helms, Ezra Yacob, and David Trice will preview our 2018 capital plan, review operational results, and year-end reserve replacement data. Then I will discuss the new tax law, EOG's financials and capital structure; and Bill will provide concluding remarks. Here's Bill Thomas..

Thanks, Tim. EOG is driven by returns. Our goal is to earn return on capital employed that is not only the best among our peers in the E&P industry, but also competitive with the best companies outside our industry. Premium returns and capital discipline are how we reach that goal.

Furthermore, by executing our premium capital allocation standard and practicing capital discipline, we believe we can sustain competitive ROCE throughout the commodity price cycle. Earning sustainable ROCE is how we deliver long-term shareholder value. First, I'd like to discuss our premium capital allocation standard.

As a reminder, for a well to be classified as premium requires a 30% direct after-tax rate of return and a flat $40 oil price. Premium wells have low finding and development cost per Boe and the premium reserves we've been adding are beginning to make a significant difference in our bottom line results.

In addition, the full benefit of our current inventory of premium location has not been fully realized. As we continue to drill premium wells and add low costs reserves, our DD&A rate will continue to fall. We also believe we will continue to reduce completed well costs and operating costs in 2018, which Billy Helms will update you on shortly.

As a result, we are in a position to generate healthy financial returns even in a moderate oil price environment. When you couple this with increasing oil prices, like those we are seeing today, the potential for generating higher ROCE accelerates. Second, EOG's capital discipline governs our growth.

Disciplined growth means not adding overpriced or poor performing services and equipment in order to grow. Disciplined growth means not growing so fast that we outrun the technical learning curve and leave significant reserve value in the ground.

Disciplined growth means operating at a pace that allows EOG to sustainably lower costs and improve well productivity, instead of growing so fast that costs go up and well productivity goes down. EOG's disciplined growth is driven and incentivized by returns and not growth for growth's sake.

Our strong growth is an expression of generating strong returns first. And finally, EOG's disciplined growth maintains a strong balance sheet. We will not issue new equity or debt to fund capital expenditures or the dividend. In 2017, we grew high return U.S.

oil production 20%, paid the dividend, reduced our debt, and generated over $200 million in free cash flow. Remarkably, we delivered those results, while oil prices averaged a modest $50. Throughout the downturn, our goal was to reset the company to be successful in a lower oil price environment.

We shifted to premium drilling in 2016 and the power of our premium drilling is now evident in our 2017 bottom line results. We believe this sets EOG apart as one of the most capital efficient and disciplined growth companies in the U.S. Here are more highlights from 2017. Our premium well level returns are reflected in our bottom line results.

We significantly improved net income, cash flow, and ROCE. Our commitment to exploration-driven organic growth drove increases to premium net resource potential of 2.2 billion barrels of oil equivalent from an additional 2,000 net premium drilling locations, which is nearly 4 times the number of wells completed in 2017.

We increased proved reserves 18%, replacing more than 200% of last year's production at low finding and development cost, which lowered our company DD&A rate by 12%. Due to sustainable cost initiatives, we continued to lower total well costs and operating costs.

And additionally, as a result of the board's confidence in EOG's future performance and exploration prospects, we approved a 10% dividend increase. 2017 was just the start of realizing the full benefit of premium drilling. In 2018, we'll improve in every category we use to measure performance internally. Capital efficiency is up.

All-in rate of return and PVI are better, and all-in finding costs are lower this year than last year. In 2018, we expect to earn double-digit ROCE, deliver strong disciplined organic production growth, and substantial free cash flow. EOG is a high return organic growth company.

We have expanded our industry lead in both returns and growth, and we are excited about the future. Up next to provide details on our operational performance in 2017 and preview the 2018 game plan is Billy Helms..

Thanks, Bill. The progress we've made on our capital cost structure, operational cost structure, and overall capital efficiency these last three years during the downturn has been phenomenal. EOG has never been more efficient in its history. Surviving a downturn is always challenging, but it also creates many opportunities for improvement.

Like many in the industry, we realize the benefits of lower service cost. But the bigger opportunity was to lower our cost structure through operational efficiencies. It never fails when EOG enters a downturn, we resurface on the other side as a more efficient, leaner and better company. It's the one reason to get excited about a down cycle.

We slow down and take a critical look at how we can improve every aspect of our business. In 2018, we expect to deliver 18% oil growth, 16% total equivalent growth, with a $5.6 billion capital program. Our 2018 capital plan includes tests of several new plays and an expansion of our more recently announced emerging plays.

We've increased activity in each area at a deliberate pace designed to maintain our capital efficiency achieved in recent years. We will not increase activity if it means eroding our operational performance or increasing our well cost. In 2017, we set our sights on drilling longer laterals and larger well packages.

Determining the most efficient number of wells to drill and complete together is essential to maximizing the recovery and net present value of the whole asset. Those efforts will expand in 2018. Our average lateral will be 8% longer this year, and we expect the average size of our well packages to more than double.

Larger well packages and increased use of multi-well pads increase the inventory of wells needed to stay ahead of our completion crews. Therefore, activity and inventory will build, particularly in the first quarter, and there will be fewer wells brought online in the first half of the year compared to the second half.

More specifically, only 27 net wells were brought online in January, so first quarter volumes were down sequentially. However, the pace of volume growth will be fairly balanced for the remaining three quarters.

During 2017, we opportunistically contracted with the most efficient service providers and secured a large portion of our 2018 services during favorable market conditions. This was a rate of return decision to lock in low cost as we move into a year where we expect to see increased industry activity and potential price inflation.

We secured 85% of our drilling rigs at very favorable rates compared to the current market, and under these agreements, we maintain flexibility with our favored vendors to adjust, should market conditions dictate. We've locked in 80% of our casing needs with prices 15% to 20% below the current market.

We also locked in 60% of our frac fleets below current market prices, and we have more diverse and local sources of frac sand, and sand unit costs are expected to decrease by 15% year-over-year. Beyond contracted service costs, we're confident we can further improve operational efficiencies in a number of areas.

During the downturn, we took the opportunity to upgrade our rig fleet to one of the most modern and efficient in the industry. On the completion side, we expect to complete 5% to 10% more wells per frac fleet this year, despite longer laterals.

We also continue to expand our water infrastructure and reuse program, which is expected to reduce well cost in some areas by another $100,000 per well. Through these and other efforts, we are building on our momentum from last year when we reduced well costs 7% across active areas.

This year, we expect to reduce completed well costs an additional 5% across the board. This is unique in the industry, as I expect that we are one of the few companies that will have decreased well cost in both 2017 and 2018.

We also expect to see downward pressure on our unit operating cost, reducing LOE, transportation, and DD&A driven by infrastructure, information technology, and a relentless focus on operating efficiency.

2018 will be another great year for improvements to EOG's capital efficiency, maintaining our position as the low-cost, high-return leader in the E&P industry. I'll now turn the call over to Ezra, who will update you on the Eagle Ford and Delaware Basin plays..

Thanks, Billy. The Eagle Ford continues to be the workhorse and centerpiece of EOG's oil production portfolio of assets. Consistent well performance combined with sustained low well costs and operational costs contributed to the Eagle Ford achieving the best overall returns in the company in 2017.

Well costs in the Eagle Ford continue to decrease, averaging just $4.5 million per 5,300-foot lateral. Lower cost wells, longer laterals, and precision targeting are driving increased well productivity and led to the addition of 500 net premium locations, more than two times the number completed in 2017.

We expect to make additional operational improvements in 2018 and plan to complete 260 net wells, targeting record well costs of $4.3 million per well. We continue to increase the size of our well packages and extend lateral lengths while being careful to maintain per-foot recovery.

The goal of these measured improvements is to maximize the NPV per section of this consistently prolific asset. Our 582,000 net acre position is now 99% held by production.

Exploration work will continue in 2018 to delineate areas that can support multiple targets in the Lower Eagle Ford and delineate where the Upper Eagle Ford can produce premium rates of return. The Eagle Ford continues to be a growth asset for the company that we expect will contribute premium return production and reserve additions.

On our Eagle Ford acreage, we also drilled some of the most prolific and high-return wells in our history in the Austin Chalk. The average 30-day production from the 28 net wells completed in 2017 was well over 3,200 barrels of oil equivalents per day. Furthermore, well costs averaged $4.9 million for laterals ranging from 4,000 to 6,000 feet.

We expect to complete another 25 net wells in 2018. Last year, we identified a sweet spot in Karnes County through an integrated exploration effort. Precision targets within the Austin Chalk respond extremely well to EOG's high density completions.

We continue to combine our geologic database created through our Eagle Ford development with recent core data from the Austin Chalk to delineate additional sweet spots across our Eagle Ford acreage. The Austin Chalk is geologically and stratigraphically complex, so our continued exploration effort will take time.

The Delaware Basin is setting up to be our fastest growing asset for a second year in a row after almost doubling crude oil production last year. We made tremendous progress during 2017. We continued mapping the geologic complexities of this mile-thick column of pay.

We tested multiple spacing patterns to determine how best to develop stacked pay that maximizes recovery and NPV per section, and we delivered record-breaking well results and phenomenal returns for the company.

Furthermore, we added 700 net premium locations within our existing targets, the Wolfcamp, Second Bone Spring and Leonard, through well productivity gains and cost reductions.

We introduced a fourth premium target, the First Bone Spring, adding 540 net premium locations for a combined total of more than 1,200 net locations, a 35% increase year over year. We lowered completed well costs in the Wolfcamp 9%. We increased lateral lengths about 20%, lowering cost per foot and, more importantly, without losing per foot reserves.

In 2017, we drilled and completed 24 net wells associated with our merger and acquisition with Yates Petroleum at the end of 2016.

As previously highlighted, much of this acreage was hand in glove fit with EOG's legacy acreage position, and this resulted in the opportunity to drill extended laterals and the ability to utilize much of our existing infrastructure in our core area.

The wells tested multiple targets, and approximately 50% of the wells were drilled outside of our core acreage position. The results exceeded our initial expectations. Overall, this 24-well program delivered a 97% direct after-tax rate of return.

Most of our drilling in the Delaware Basin targeted the Upper Wolfcamp, which will continue to be the case in 2018. The Wolfcamp earns some of the best rates of return in the company and has the added benefit of giving us a look at shallower Bone Spring and Leonard targets.

We also expect to lower Wolfcamp costs, and we'll continue to increase operational efficiency through longer laterals and larger packages of wells. In 2018, we plan to complete 205 net wells in the Wolfcamp, 10 in the First and Second Bone Spring and 15 in the Leonard. Our drilling program in the Delaware Basin totals 230 net wells.

While we brought online an average of two wells per package last year, we expect to average about five wells per package in 2018. We'll also continue to test both well spacing and well timing to maximize recovery and NPV.

Lastly, our team has done an exceptional job positioning our Delaware Basin asset for key takeaway capacity away from the Permian Basin at low cost. Our existing gas and water gathering systems controlled by EOG drive low LOE and transportation costs. Also, a new oil gathering system and terminal will begin service for EOG this quarter.

From the new terminal, EOG will ultimately have up to four market connections to downstream markets, where we secured firm capacity to Cushing and Corpus. Furthermore, our team has been very active on the residue gas front. We've secured significant transportation away from the Permian Basin and Waha Hub.

We started this process in 2015 and have tactically layered in firm capacity over time to match up with our drilling program. This capacity provides diversified marketing options and potential pricing advantages over those waiting on new built pipelines.

This asset is one of, if not the best, tight oil play in North America, and we are excited about its tremendous growth potential. Here's David Trice to review the progress we've made in the Mid-Continent and our Rockies, Bakken, and international activity..

Thanks, Ezra. Last quarter we introduced a new premium oil play in the Eastern Anadarko Basin, the Woodford oil window. This play is a concentrated sweet spot of moderately over-pressured high quality rock located primarily in McClain County, Oklahoma.

The well we highlighted when introducing the Woodford, the Curry 21, is a fascinating well that continues to demonstrate a very low decline rate, particularly considering that it is a shale reservoir.

The average 150-day rate for the Curry is over 1,100 barrels of oil per day, which is a low decline compared to its initial 30-day rate of about 1,500 barrels of oil per day. The Curry well is solidly in the oil window as opposed to many SCOOP/STACK wells that are in the gas condensate window.

It produces a 43 degree API oil with a gas/oil ratio of approximately 1,000. This premium well is earning over 100% direct after-tax rate of return at today's strip. Currently we have one rig working in the Woodford oil window and plan to add another rig later this quarter.

We expect to complete 25 net wells in 2018 and have planned a number of spacing tests. Our current inventory of 260 net locations assumes an average of 660 feet between wells. We expect to test spacing down to 330 feet. The addition of the Woodford play demonstrates EOG's ability to consistently add premium quality rock and inventory.

Plays like the Woodford enhance the diversity of our portfolio and provide the flexibility to consistently grow production, while maintaining capital efficiency for years to come. The Powder River Basin has become a core asset for EOG.

We amassed 400,000 net acres following the merger with Yates in late 2016, and we are consistently drilling low-cost, moderate-decline wells that compete with the best in the company. Last year we stepped up activity, completing 39 net wells, 9 more than our initial plan.

Completed well costs for an 8,000-foot lateral dropped 10%, helping drive returns in the Powder River Basin that are highly competitive with returns from our largest premium asset, the Eagle Ford and the Delaware Basin. In 2018, we expect to complete 45 net wells, targeting well costs of $4.5 million.

Our focus will be blocking up acreage, testing spacing, and mapping the Powder River Basin's mile-deep column of pay to delineate acreage that is prospective for various targets. We continue to see significant premium inventory potential in the Powder River Basin.

We're also stepping up activity in the Wyoming DJ Basin, doubling our activity to 35 net wells in 2018. DJ Basin well results are less flashy than our other basins; however, they produce consistent low-decline results and are the fastest to drill and the lower cost wells in the company.

We routinely drill 18,000-foot wells in three to four days, while remaining in a tight target window. We averaged $4.5 million for 9,000-foot laterals in 2017, and this year we expect to average just $4 million. Additionally, robust water and gas gathering infrastructure is driving down operating cost.

In the Bakken, last year's activity was focused on drawing down our inventory of legacy drilled but uncompleted wells, which didn't have the benefit of our latest precision targeting techniques. Once we completed our inventory of DUCs, we completed a few fantastic wells in both the Bakken and the Three Forks targets.

In 2017, the top well of a package of four new wells of the Antelope Extension produced almost 3,200 barrels of oil equivalent per day in the first 30 days. After 120 days, production was holding up averaging over 2,500 barrels of oil equivalent per day.

Now that our pre-2016 DUC inventory is depleted, we are excited to get a fresh start for our 2018 drilling program and take advantage of the significant progress made on our Bakken cost structure. In the past two years, we've cut completed well cost by more than a third to $4.6 million for a long 8,400-foot lateral.

Furthermore, we expect to continue lowering costs through a recently implemented seasonal drilling and completion program. Wells are drilled year-round, then completed mostly during the summer.

This program will eliminate the additional expense incurred by handling water during the freezing winter months and dealing with road restrictions during breakup. This is a great example of how EOG can continue to increase capital efficiency.

Our deep premium inventory in multiple basins provides flexibility to adjust to changing operational conditions in any given basin. In 2018, we'll focus our 20 net well program in the Bakken Core and Antelope Extension.

We'll also drill a number of step-out wells in the Bakken Lite and other areas to continue testing and refining our latest precision targeting and advanced completions outside our core operating areas.

Our lower cost structure in the Bakken generates highly competitive premium returns and we are optimistic it will drive additional sources of premium inventory over time. We had an eventful year in Trinidad division during 2017. We brought on seven net natural gas wells across our Sercan, Banyan, and Osprey areas.

The outperformance of these new wells allowed our Trinidad division to produce 15 million cubic feet of gas per day, more than initially forecasted in 2017. We also finalized a new gas contract with the National Gas Company of Trinidad and Tobago beginning in 2019, that supports and extends our 25-year partnership.

Looking ahead, 2018 is going to be an exploration year in Trinidad. Our exploration efforts are focused on leveraging new seismic data to identify prospects to drill in 2019 and beyond in order to maintain natural gas production and supply the domestic Trinidad gas market for many years to come.

Here's Billy to review our year-end reserve replacement and finding costs..

Thanks, David. We replaced more than 200% of our 2017 production at a very low finding cost of $8.71 per Boe, which excludes positive revisions due to commodity price improvements. The proved developed finding cost, excluding leasehold capital and revisions due to price, was $10.73 per Boe.

Improving well productivity and sustainable cost reductions drove positive reserve revisions. As a result, our proved reserves increased 380 million barrels of oil equivalent, or 18% year-over-year.

Our ability to consistently add reserves at low cost demonstrates the tremendous capital efficiency gains we made through the downturn from our permanent shift to premium drilling and laser focus on cost reductions. I'll now turn it over to Tim Driggers to discuss the new tax law, financials, and capital structure..

Thanks, Billy. The tax law enacted near the end of 2017 had a number of effects on EOG's results of operations, cash flows, and consolidated financial statements. I will discuss a few of the more significant items.

You can find details on these and other items related to the new tax law in Note 6 of EOG's annual report on Form 10-K, which we filed yesterday with the SEC.

EOG recorded a noncash reduction in the fourth quarter and full year 2017 income tax provision of $2.2 billion related to the re-measurement of its net deferred tax liability for the lower statutory tax rate under new law. The reduction in income tax expense caused an increase in net income and shareholders' equity by a like amount.

In addition, the tax law repeals the corporate alternative minimum tax and allows AMT credit carryovers to be refunded over four years beginning in 2018. EOG estimates that its AMT credits being carried over to 2018 will total $798 million.

The tax law provides for a tax on deemed repatriation of accumulated foreign earnings for the year ended December 31, 2017. EOG estimates it has a deemed repatriation tax liability of $179 million which can be paid over eight years.

The tax law also makes fundamental changes to the taxation of multinational companies, including a shift to a so-called territorial system. Under this new regime, EOG does not expect to pay any significant amount of U.S. federal income taxes on its foreign operating earnings beginning in 2018.

Finally, the tax law preserves the immediate deductibility of intangible drilling costs as well as expands and extends bonus depreciation. All of these amounts are estimates which EOG believes to be reasonable, but could change based on further analysis, new IRS guidance, and other factors.

A strong balance sheet is an important part of EOG's strategy. This is appropriate in a capital-intensive cyclical industry.

This financial strength enables us to maintain a low-cost structure and strategic relationship with our service providers by funding a steady CapEx program; make commitments for low-cost services and supplies at opportunistic times, often when oil and gas prices are depressed; and similarly, make opportunistic acquisitions of acreage or other assets.

We are very pleased that EOG weathered the industry downturn without an equity offering or cutting the dividend. Financial leverage as measured by net debt-to-total-capitalization has declined from 34% at its peak in June 2016 to 25% at year-end 2017.

We estimate that with $60 oil in 2018, EOG can generate over $1.5 billion of free cash flow after paying the dividend. We intend to repay with cash on hand $350 million bond that matures in October of this year. In addition, the board increased the dividend by 10% this week, affirming our commitment to the dividend.

Beyond that, we intend to further strengthen the balance sheet this year. Now I'll turn it back over to Bill..

Thanks, Tim. In closing, I will leave you with a few important takeaways. First, the size and quality of our horizontal assets are unmatched in the industry. In 2018, we have active drilling programs across nine high-quality premium plays.

EOG has the unique flexibility to allocate capital to maximize returns by adjusting to changing market conditions and managing each asset's development pace with technical and cost reduction discipline. Second, in 2018, we have a robust exploration program underway in multiple basins, with more capital allocated to this process than in recent years.

Our long history of horizontal drilling and vast proprietary database combined with an innovative EOG culture are working together to make EOG the leader in organic generation of new and better premium drilling inventory. Third, EOG is a leader in capital discipline with a relentless focus on returns.

We are committed to delivering industry-leading high-return organic oil growth, committed to our dividend, and committed to reducing debt, while generating significant free cash flow in 2018. And finally, the power of premium has placed us among the low-cost producers in the global oil market.

Our potential for financial returns, operational performance, and overall capital efficiency is much better today than before the downturn. In 2018, we are poised for strong, disciplined growth.

More importantly, we are positioned to reach our goal of returning to double-digit ROCE performance, which is competitive not only with our peers in the E&P industry, but also with the broader market. Thanks for listening, and now we'll go to Q&A..

Thank you. The question-and-answer session will be conducted electronically. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. We'll pause for just a moment to give everyone an opportunity to signal for questions. And we'll take our first question from Leo Mariani with NatAlliance..

Hey, guys. Just a quick question here on the Eagle Ford. So just noticing that your oil volumes in the Eagle Ford didn't really grow in 2017; I think they were down a little bit versus the prior year. You guys kind of signaled this was a growth asset in your prepared comments. I think you're drilling more wells this year.

Is there anything else that's sort of changing there maybe technically other than just kind of drilling more wells this year? And is this expected to kind of be a growth asset for many years to come? Can you just comment on that?.

Yeah, Leo, this is Billy Helms. Yeah, the San Antonio division, our Eagle Ford division really operates both the Eagle Ford and the Austin Chalk. And if you look at the two combined, well volumes were up slightly for both Eagle Ford and Austin Chalk.

The Eagle Ford position, as you mentioned, it is a growth asset for the company and we expect that to grow into 2018. But last year the mix of the wells was balanced between the Eagle Ford and the Austin Chalk, and together they did grow..

Okay. And just following-up on your comments around free cash flow here. So clearly, you guys plan on putting out some pretty significant free cash flow if oil holds $60 here. You talked about the $350 million debt pay-down as well as the 10% dividend hike. But clearly, there's going to be proceeds beyond that.

What else is EOG potentially planning on doing with the money? Could there be a ramp-up in even more exploration activity than you've already talked about, or more acreage purchases? Just any color around that please..

Leo, this is Bill Thomas. Yeah, certainly our priorities haven't changed. Our first priority is to use free cash flow and reinvest in the high-return drilling. And we think this is the best way to continue to improve the company, to increase ROCE, and the shareholder value.

The one caveat on that is we're not going to ramp-up spending at the cost of returns. We want to maintain the efficiencies and the cost that we built into the system, and in fact, we want to continue to improve. So we want to go at a pace that our well productivity continues to improve.

It's improved this year over last year and our rates of return in our 2018 plan are improved this year over last year, and that's because we continue to reduce costs and increase productivity. And so we want to continue to do that and continue to reinvest. That's our first priority.

The second is, as Tim mentioned, we want to continue to firm up our balance sheet. Really, our goal is to have an impeccable balance sheet and we're going to pay off the bond this year and as we go forward, we want to incrementally continue to reduce debt and firm up the balance sheet. This gives us so much flexibility.

It's served us so well during the last downturn. We didn't have to issue equity or we didn't cut the dividend. We want to be a consistent deliverer of shareholder value throughout the commodity cycles. And it does position us to take advantage of opportunities for maybe an acquisition.

We continue to look at those, but also, as you mentioned, we are very organic, prolific, generating company and we have a lot of exploration and step-out testing going on this year. We collect a lot of core data, and our goal with all that is to find better and better inventory than we currently have.

We think that is investments into the future of the company and those are very, very important to us getting better. So we want to be able to take advantage of that. And then our third priority is our commitment to the dividend. We have a strong commitment to the dividend. We've increased it 17 times over the last year.

As we've said, we increased it this quarter and our board is committed to continuing to increase our shareholder value certainly through better ROCEs in the future, and through our commitment to the dividend. So those are all the priorities we have and we're going to stay focused on that and stay focused on getting better as we go forward..

Thanks, guys..

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

Yeah, thanks. Could you guys give a little bit of color on some of the increased pad sizes you're expecting? And is it primarily mostly in the Permian? What was the pad size you did last year versus what you're looking at this year? And a little bit of color on that in the Eagle Ford as well..

Yeah, Scott, this is Ezra. Yeah, we're increasing the package size of these wells in both the Eagle Ford and Permian. And we're increasing this – the focus really is on maximizing the NPV of the sections and returns.

And so when we plan these packages, we want to plan them large enough that they take advantage of the increased operational efficiency and cost savings that come with that. But at the same time, we don't want to increase them to the size and scale where they take so long that we cannot incorporate learnings from one set of wells to the next.

As you know, we like to collect an awful lot of real-time data and incorporate that into the next wells that we drill. And so really it's kind of a balancing act between those two things. As we highlighted, in the Permian, we'll be more than doubling the size of our average package size of wells from two to five..

Okay. Okay.

And just specifically with that, and when you look at sort of that, I guess what you said, the slower start in January, that was a big part of it is just those increased pad sizes specifically in the Permian?.

Yeah, Scott. This is Billy Helms. Yeah, basically as we ramp up activity there in the first half of the year and start drilling longer laterals in these bigger packages of wells, it requires that we build inventory for our completion crews more so than we've seen in the past. So that delay is really what's affected our first quarter's production..

Okay. Understood. And as my follow-up then, you did talk about uses of cash flow priorities and not wanting to push it where it impairs returns.

What is the trigger point that you start seeing things degraded? Is it more service cost rising? Is it just lack of infrastructure? What is the bottleneck on using some more capital to invest currently?.

Scott, it's really a couple of things. One is, certainly, the service costs, we are not interested in paying high prices for services.

And so we work really hard, like we've done this year, to mitigate increases, and actually going to decrease them this year – total well costs, we're going to decrease total well costs by locking in really strong services at below-market rates. And the other thing is going too fast and outpacing our technical learning curve.

And so in every one of these plays – and we've been doing this for two decades now – we've learned to take a systematic approach and not really switch in to what some people would call a manufacturing mode, because we want to continue to learn and we want to continue to get better.

And if you just lock yourself into a manufacturing mode, you could be locking yourself into drilling a large amount of wells in the wrong way. And so we continue to learn to place the wells at different spacing vertically and laterally, and our goal is to maximize NPV on those. So that can only go at a certain pace too. So we're very careful.

Everything we do in the company is driven by increasing returns, and that is the focus of, as you all know, EOG and that's what we're doing..

Understood. Appreciate that. Thanks..

And we'll take our next question from Ryan Todd with Deutsche Bank..

Good. Thanks. Maybe as a follow-up to what you were just talking about there on learnings, we've seen a few companies over the course of this quarter walk back spacing expectations a little bit in the Permian Basin.

How have your views evolved as you've continued to get more data out of the basin? And maybe thoughts on how you're thinking about your evolving base case in terms of spacing your wells per unit..

Yeah, Ryan, this is Ezra again. In the Permian Basin, it's still relatively early in the play development. We're still testing a lot of concepts on spacing and staggering of our targets. It's definitely area-dependent, and then target-dependent as well.

But, as we've said in the past, in the Wolfcamp oil window, we're seeing good results with spacings from 500 to 660-foot spacing. It's a little bit different down like in our combo, Wolfcamp combo area, where spacing ranges from more like a 800-foot to 1,000-foot spacing.

But again, before we really come out with any greater detail on that, the slowdown in activity kind of slowed down our data collection on that, but we continue to push forward with it..

Okay. Thanks. And maybe a follow-up to that. Can you talk about the trends in lateral length in the Permian in 2018? I think you're still – you're targeting a little over 6,000 feet, but a relatively wide range across some of your wells.

What's the limiting factor in you guys going higher?.

Yeah, Ryan, again, this is Ezra. So our lateral length actually, so we were able to extend it 20% year-over-year and we're anticipating about another 10% increase here in 2018. Really, as we just continue to make acreage trades and block up our acreage across the basin, you'll continue to see those lateral lengths getting longer and longer.

At this point, that's kind of the limiting factor..

Okay. Thanks. I'll leave it there..

And we'll go next to Subash Chandra with Guggenheim..

Thank you.

As you've doubled the package size in the Permian, I think, two to five as you said, do you think at some point you have to get to a cubed style development, for lack of a better term? And the benefits and costs of doing that, do you think that's necessary or can you more moderately increase the package sizes over time and accomplish your objectives?.

Yeah, this is Ezra again. No, I think the last part that you said is right. I think we can more moderately expand the package size. Like I said, it's a real balance there trying to get the package sizes large enough, so that you're maximizing the operational efficiencies that exist with multi-well operations.

But we definitely don't want to get them so large that we have to sacrifice being able to – the flexibility to integrate real-time data collection and learnings into our subsequent well packages. And then also we don't want to get into situations where we end up overbuilding facilities to try and solve temporary issues or anything like that.

We're much more focused on integrating our learnings from well-to-well. And then the last thing to think about too is, as Bill mentioned previously and being cautious not to get into manufacturing mode, is the size of these packages are going to be very area dependent.

It's really complex geologically, and as we've discussed before, we focus a lot on precision targeting and working out the stratigraphy and the complexities of the geology to make sure we're putting these wells in the best targets..

Okay. Thanks. And my follow-up is in the Wolfcamp or in the Delaware, you've sidestepped all the issues it seems like that have hobbled some of your competitors from sand to takeaway, to inflation, et cetera. And I think what you've messaged on this call is that your real hurdles are internal in managing IRRs and learnings and the like.

Did I hear that correctly, or are there some speed bumps that you're concerned about that are external, whether it's water or some other things that maybe we haven't considered?.

I think, Subash, you're correct. We're really in great shape in the Permian, sand, water, takeaway, all those things.

And the real thing we're focused on and really what makes a difference in our well productivity versus the industry is our ability to execute in a complex geologic setting, and continue to stay flexible and to learn and to continue to focus on cost reduction.

And so those are the things that, I think, we've been fortunate to learn over our two decades in drilling horizontal wells and we're putting those to good use in the Permian..

Okay. Thank you..

We'll take our next question from Bob Morris with Citi..

Thank you. Bill, looking at slide 13 on the Wolfcamp six-month production from the wells, you extended the data out through July versus November before and I notice the average rate dropped a little bit here. And I know some of that's in moving more of your wells to Reeves County.

But how much of that is just the child/parent relationship, particularly as you go from two- to five-well packages? How much of that are you seeing? And how much is the degradation on going from unbounded or parent wells to child wells in that situation?.

Yeah, Bob, this is Ezra again. I think you hit the nail on the head. That's kind of more a reflection of increasing here recently the percentage of wells drilled down on our combo play in Reeves County. I think the issue of parent/child well performance isn't really anything new.

It's a challenge that operators have been faced with since horizontal resource plays have been developing, and we've been collecting data on this topic for almost 20 years now throughout our multiple basins and multiple plays. I think there's not really a single variable to eliminate the issue.

I think the way we approach it is it begins with the well planning, that's to say the spacing and targeting, making sure that you get that right for the geology that you're in. Different targets obviously respond differently to how much they affect that parent/child relationship.

And then also there are things you can do on the completions and production side, certain techniques and designs, again, to alleviate some of those issues..

And we'll go next to Brian Singer with Goldman Sachs..

Thank you. Good morning..

Morning..

I wanted to start in the Eagle Ford. I think in your comments, you mentioned the Eagle Ford is where you saw some of the best rates of return in the company during 2017, and I wondered why not shift more activity there relative to the Permian Basin.

I think the increase in rig count's about one in the Eagle Ford, but more substantially in the Delaware.

Can you just talk a little bit more about that capital allocation decision, and then how the rates of return, inflationary pressures, and ability to execute compare in the Eagle Ford relative to the Delaware?.

Yeah, Brian, this is Billy Helms. Yeah, in the Eagle Ford, we're very pleased with the rate of return and the program. And this last year was a really good year for them where they continue to learn and develop our learnings there quite a bit over the last year.

The growth there in the Eagle Ford – the Eagle Ford is really a pretty stable platform for us to continue to slightly grow over the time as we develop that, but we've got some of these other areas that we're also very interested in growing and applying our learnings to to continue to benefit from the learnings that really kind of started in the Eagle Ford.

We're also, as a result of the activity in the Eagle Ford, we are improving our well cost, and the well count is actually going up more so than rigs in the Eagle Ford versus that.

The other thing that's important to note on the Eagle Ford too, remember, is that 99% of our acreage there is HBP, so we have a lot of flexibility in how we manage our activity levels in the Eagle Ford..

Great. Thank you. And then my follow-up question is with regards to well cost and efficiencies. You've highlighted your expectations for well costs to fall in a couple of these key basins, and some of the reasons for that I think you mentioned was because of below-market contracts.

How much of this is timing, i.e., would go away all else equal in 2019 and your costs would rise versus a sustainable example of EOG's skill that could continue beyond 2018?.

Yeah, Brian, this is Billy Helms, again. Yeah, I think the thing that's unique about EOG in some aspects, we did lock in services certainly at the low cost.

A lot of people are able to take advantage of the service cost declines, but I think the thing that's a little bit unique in EOG is our culture of continuous improvement that we really focus relentlessly on improving every aspect of our business, our drilling times, lowering our completed well costs by completing more of the lateral every day with each stage.

We also self-source 25% to 30% of our well costs, so we do a lot of things that enable us to continue to make steady improvements in our well costs. And we can't be more proud of our operational teams as they continue to strive to do that..

Yeah, I'd just like to add to what Billy said. I think, historically – I've been with the company 39 years now, I don't really remember many years when well costs were going up in EOG. And so I think we've got a lot of confidence in our ability to continue to hold and even reduce costs as we go forward..

Great. Thank you..

And we'll go next to Phillips Johnston with Capital One..

Hey, guys. Thanks. Just to follow-up on the topic of parent/child wells, a few operators have recently highlighted a decline in per-well productivity and EURs as infill drilling has occurred.

I think you guys have previously talked about seeing similar trends in the Bakken just as infill drilling has occurred, but I wanted to get a sense of what you're seeing in the Eagle Ford.

I realize that per-well productivity as a whole in the play has continued to improve throughout 2017, but what are you seeing in areas where the number of wells per section is approaching your 16-well target?.

I would say, Phillips, we have continually learned to have variable targets as we develop the Eagle Ford. We have the Lower Eagle Ford and the Upper Eagle Ford and the multiple targets, and we continue to learn to place those better.

And we also are learning to manage the parent/child relationship even down to wells that are as close as 200 feet apart. So it's managing the pattern sizes, the timing of the completions, the targeting, and the way that you spatially locate the targets in these W patterns. We're really proud of our folks in San Antonio.

They continue to make really strong technical learning in the Eagle Ford and our costs are going down too. So our Eagle Ford returns just consistently every year are going up, and that's the way we want to develop all of our assets, that we're constantly improving and making them better..

Okay. Great. That's helpful. And then just on the return on capital employed target, nice to see the projected uptick to 10% or higher this year.

I'm wondering what that number would look like if you ran the same price deck of $48 by $2.70 that you show for the last three years on page 4 of the slide deck?.

We're not going to give a number out on ROCE, but I'll tell you, we feel very good about that double-digit ROCE. The company is in great position this year and we're really confident that we're going to be able to deliver that number..

Okay. Thank you very much..

We'll go next to David Heikkinen with Heikkinen Energy Advisors..

Good morning, guys. Thanks for taking my question.

Thinking about your cash margins and your differential guidance, early in the year you benefited by LLS, but your full year guide, is that incorporating a wider differential for things like the Delaware as that grows? Or can you talk some about how you think about your long-dated differentials as other regions beyond the Eagle Ford really start really dominating growth?.

Hi, David. This is Lance. Yeah, as we look at our guidance, we take all those considerations. So like we talked about, 100% of our Eagle Ford is all priced on LLS. And you can look at that forward curve, we've priced that into our guidance.

And then as you think about the Delaware Basin, with our transportation capacity that we have, we talk a little bit – you see on slide 24, 20% of that we're able to get into the Corpus market, which is what we see as a Brent or an LLS type marker. So we've factored all that into our guidance for what you're seeing today for the full year for 2018..

And so do you think that a range at the end of the year should carry forward in that more similar to the full year 2018 as opposed to where we are just early – more thinking 2019 and 2020 free cash flow generation is what becomes important?.

The crystal ball so far there, David, in terms of when we look at the forward curves and where that's trading, we look at 2019 too, same thing for gas like the crude. So we've got the guidance out there for 2018 and we bake that all the way through in terms of for crude and also for gas.

So everywhere from the Rockies to the Delaware Basin, even into the Eagle Ford, each one of those markets, that's all factored into our guidance. And what we've been very positive about is, as you've seen, the Rockies has definitely strengthened.

So I think across the board when you look at all of our divisions and our domestic oil production, we've seen strength in all the divisions..

All right. Thanks..

And we'll take our last question from Sameer Panjwani with Tudor, Pickering, Holt..

Hey, guys. Good morning. I wanted to get a bit granular here at the end on the CapEx budget. So I'm just kind of looking through it, it looks like the exploration and development budget $4.5 billion to $4.8 billion. Just kind of taking an average of that over 690 wells kind of implies $6.7 million.

Go back to 2017, I think the average kind of works out to $5.9 million. And I know there's lot of moving parts in terms of longer laterals and at the same time you guys are lowering normalized laterals well costs. Just trying to figure out what exactly is kind of causing this shift.

I think a big piece of it is that you guys are shifting more activity to the Delaware, which is a higher per well cost and that might be bringing up the average, but I wanted to get your thoughts there..

Yeah, this is Billy Helms. I think what you're seeing is a result of the increased activity there in the Delaware Basin relative to the overall program. We're increasing our activity mostly to grow the potential we see in the Delaware. So the mix of wells within the capital budget is different.

Then the other thing that's in our capital budget, and Bill alluded to this earlier, we are testing some new plays. And so early on in new plays, we do collect some science data, cores and microseismic in places, 3D seismic, those kind of things that add into our capital program that would not be typical in just a normal development program..

Okay. That's helpful. And then on slide 19, outlook through 2020 it looks like you can achieve this at roughly $5 a barrel lower based on the 2018 capital efficiency that's being implied.

Is this the right way to think about it? And do you have any plans to update this outlook going forward?.

You're looking at it correctly. We're getting better every year. The 2017 metrics versus the 2018 metrics, the 2018 metrics are better in every way. So we're able to deliver a very, very strong growth at lower oil prices going forward. So you're looking at that correctly.

We have a very strong, I think incredible, high return inventory in place, and we really believe our quality of inventory is going to increase over time and our costs are going to continue to go down.

So I think what you can look for us to do is just keep updating this 2020 outlook that we have, and I think we're very hopeful that we will keep outperforming the outlook guidance going forward..

Okay, great. If I can squeeze in one last one. I know you guys talked about 27 wells online in January.

But any additional color you can provide on the expected total for the first quarter?.

We haven't really looked at how many wells per quarter. I just know that the well count in the first quarter is low relative to the rest of the quarters, and it's really due to the ramp-up and activity that we see at the start of the year.

And drilling these larger packages with longer laterals and getting the inventory back in where we need it for this level of activity, you just have less wells coming online in the first quarter relative to the rest of the year. So we're very confident in our plan and the volumes that we played out and the guidance we've given.

And we expect to be able to deliver that within our program we've laid out..

And that concludes our question-and-answer session. I'd like to turn the conference back to our speakers for any additional or closing remarks..

Yes. In closing, just like to conclude by saying, 2017 results were outstanding and we believe 2018 will be even better. The company is driven by strong returns and is poised to deliver in 2018 and beyond. We have a sustainable business model and we're excited about EOG's ability to create long-term shareholder value.

So thank you for listening, and thank you for your support..

Thank you. Everyone, that does conclude today's conference. We thank you for your participation. You may now disconnect..