EOG Resources Inc_ (EOG) Q4 2017 Earnings Conference Call Transcript

EOG Resources, Inc. (EOG 0.59%)
Q4 2017 Earnings Conference Call
January 28, 2018, 9:00 a.m. ET

Contents:

Prepared Remarks

Questions and Answers

Call Participants

Prepared Remarks:

Operator

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.

Timothy K. Driggers -- Chief Financial Office

Thank you. 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 the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation 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 on the 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 and Production; Ezra Yacob, EVP, Exploration and Production; Lance Terveen, Senior VP, Marketing; David Streit, 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 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 review our 2018 capital plan, review operation results, and year-end reserve replacement data; I will discuss the new tax law, EOG's financials and capital structure; Bill will provide concluding remarks.

Here's Bill Thomas.

William R. Thomas -- Chairman, Chief Executive Officer

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 standards 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 rated return at a flat $40.00 oil price. Premium wells have low finding and development costs, or 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 locations has not been fully realized. As we continue to drill premium wells and add low cost 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 at 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.

EGO'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. 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 $50.00. Throughout the downturn, out 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 expiration 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 four 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 costs, which lowered our company DD&A rate by 12%. Due to sustainable cost initiatives, we continue to lower total well costs and operating costs. Additionally, as a result in the board's confidence in EOG's future performance and expiration 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 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.

Lloyd W. "Billy" Helms -- Chief Operating Officer

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 costs, 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 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 costs.

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 maintained flexibility with our favored vendors to adjust should market conditions dictate.

We locked in 80% of our casing needs with prices 15-20% below the current market. We also locked in 60% of our frack fleets below current market prices. We have more diverse and local sources of fracks end, and sand unit costs are expected to decrease by 15% year-over-year.

Beyond contracted service costs, we are 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 5-10% more wells per frack fleet this year, despite longer laterals.

We also continue to expand our water infrastructure and reuse program, which is expected to reduce well costs 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 decrease well costs in both 2017 and 2018.

We also expect to see downward pressure on our unit operating costs, 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.

Ezra Yacob -- EVP, Exploration and Production

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 continued to decrease, averaging just $4.5 million for a 5,300-foot lateral. Lower cost wells, longer laterals, and precision targeting are driving increased well productivity, and let do the addition of 500 net premium locations, more than two times the number completed in 2017 (sic).

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 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 average $4.9 million for laterals ranging from 4,000-6,000 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 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 stick column of pay. We tested multiple spacing patterns to determine how best to develop stacked pay that maximizes recovery and NPV perception. We delivered recording 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 earned 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 longer packages of wells.

In 2018, we plan to complete 205 net wells in the Wolfcamp, ten 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 build 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 Midcontinent and our Rockies, Bakken, and international activity.

David W. Trice -- EVP, Exploration and Production

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 of 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 have massed 400,000 net acres following the merger with Yates in late 2016, and we are consistently drilling low cost, moderately declining wells that compete with the best in the company. Last year, we stepped up activity, completing 39 net wells, nine more than our initial plan. Completed well costs for an 8,000-foot lateral dropped 10%, helping driving returns in the Powder River Basin that are highly competitive with returns from our largest premium assets, the Eagle Ford and 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 basins; however, they produce consistent low decline results and are the fastest to drill and the lowest 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 average $4.5 million for 9,000-foot laterals in 2017. This year, we expect to average just $4 million. Additionally, robust water and gas gathering infrastructure is driving down operating costs.

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 or ducts, we completed a few fantastic wells in both the Bakken and Three Forks targets.

In 2017, the top well of a package of four new wells in 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 duct 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 costs 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 around, 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 line and other areas to continue testing and refining our latest precision targeting and advance completions outside our core operating areas. Our lower cost structure in the Bakken generates highly competitive premium returns and we're 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 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.

Lloyd W. "Billy" Helms -- Chief Operating Officer

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 costs, 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 300 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.

Timothy K. Driggers -- Chief Financial Officer

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 Six of EOG's annual report on Form 10-K, which we filed yesterday with the SEC.

EOG recorded a non-cash reduction in the fourth quarter in full year 2017 income tax provision of $2.2 billion, related to the remeasurement of its net deferred tax liability for the lower statutory tax rate, or the 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 out 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 acquisition 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 is measured by net debt to total capitalization, that has declined from 34% at its peak in June 2016 to 25% at year end 2017.

We estimate that, with $60.00 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 a $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 continue to further strengthen the balance sheet this year.

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

William R. Thomas -- Chairman, Chief Executive Officer

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 under way 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 the innovative EOG culture are working together to make EOG the leader in organic generation of new and better premium 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.

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.

Questions and Answers:

Operator

Thank you. The question and answer session will be conducted electronically. [Operator instructions] We'll take our first question from Leo Mariani with Nat Alliance.

Leo Mariani -- National Alliance Securities -- Analyst

Hey, guys. On the Eagle Ford, I was noticing that your oil volumes didn't really grow in 2017. I think they were down a little bit versus the prior year. You guys signaled this was a growth asset in your prepared comments. I know you're drilling more wells this year. Is there anything else that's changing there technically, other than just drilling more wells this year? Is this expected to be a growth asset for many years to come?

Lloyd W. "Billy" Helms -- Chief Operating Officer

Yeah, Leo. This is Billy Helms. The San Antonio Division, our Eagle Ford Division, operates both Eagle Ford and Austin Chalk. If you look at the two combined, oil volumes were up slightly for both Eagle Ford and Austin Chalk. The Eagle Ford position 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. Together, they did grow.

Leo Mariani -- National Alliance Securities -- Analyst

Following up on your comments around free cash flow. Clearly, you guys plan on putting out some pretty significant free cash flow if oil holds at $60.00. You talked about the $350 million debt paydown, as well as the 10% dividend hike. Clearly, there are going to be proceeds beyond that. What else is EOG potentially planning to do with the money? Could there be a ramp up in more exploration activity than you've already talked about, or more acreage purposes? Just any color around that, please.

William R. Thomas -- Chairman, Chief Executive Officer

Leo, this is Bill Thomas. Yeah, our priorities haven't changed. Our first priority is to use free cash flow and reinvest in the high return drilling. 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 in the costs that we built into the system. In fact, we want to continue to improve. We want to go at a place 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. That's because we continue to reduce costs and increase productivity. So, we want to continue to do that and continue to reinvest. That's our first priority.

The second is, we want to continue to firm up our balance sheet. Our goal is to have an impeccable balance sheet, and we're going to pay off the bond this year. 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 served us so well during the last downturn. We didn't have to issue equity or 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, we're a 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. Our goal with all of 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. We want to be able to take advantage of that.

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 said, we increased it this quarter, and our board is committed to continuing to increase our shareholder value through better ROCEs and our commitment to the dividend. Those are all of the priorities we have and we're going to stay focused on that and on getting better a we go forward.

Leo Mariani -- National Alliance Securities -- Analyst

Thanks, guys.

Operator

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

Scott Hanold -- RBC Capital Markets LLC -- Analyst

Thanks. Can you guys give a little bit of color on some of the increased pad sizes you're expecting. Is it primarily mostly in the Permian? What was the pad size you did last year versus what you're looking at this year? A little bit of color on that and the Eagle For as well.

Ezra Yacob -- EVP, Exploration and Production

Yeah, Scott. This is Ezra. We're increasing the package size of these wells in both the Eagle Ford and Permian. We're increasing this -- the focus really is on maximizing NPV of the sections and returns. When we planned these packages, we wanted 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. It's 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.

Scott Hanold -- RBC Capital Markets LLC -- Analyst

Okay. Specifically with that, when you look at the slower start in January, that was a big part of it? Those increased pad sizes, specifically in the Permian?

Lloyd W. "Billy" Helms -- Chief Operating Officer

Yeah, Scott. This is Billy Helms. 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 what's effected our first quarter's production.

Scott Hanold -- RBC Capital Markets LLC -- Analyst

Understood. As my follow-up, 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 lack of infrastructure? What is the bottleneck on using some more capital to invest currently?

Lloyd W. "Billy" Helms -- Chief Operating Officer

Scott, it's a couple of things. One is service cost. We're not interested in paying high prices for services, so we work really hard, live we've done this year, to mitigate increases. Actually, we're going to decrease them this year. We're going to decrease total well costs by locking in strong services at below market rates. The other thing is going too fast and outpacing our technical learning curve. 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. We want to continue to learn and to get better.

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. So, we continue to learn to place the wells at different spacing vertically and laterally. Our goal is to maximize the NPV on those. So, that can only go at a certain pace, too. We're very careful. Everything we do in the company is driven by increasing returns. That is the focus of EOG and what's we're doing.

Scott Hanold -- RBC Capital Markets LLC -- Analyst

That's good. Appreciate that. Thanks.

Operator

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

Ryan Todd -- Deutsche Bank Securities, Inc. -- Analyst

Thanks. As a follow-up to what you were just talking about 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 or wells per unit?

Ezra Yacob -- EVP, Exploration and Production

Yeah, Ryan. This is Ezra. In the Permian Basin, we continue to -- it's still relatively early in the play development. We're testing a lot of concepts on spacing and staggering of our targets. It's area dependent and target dependent. But, as we've said in the past, in the Wolfcamp Oil Window, we're seeing good results of spacing from 500- to 660-foot spacings. It's a little bit different down in our Wolfcamp combo area, where spacing ranges from more like 800- to 1,000-foot spacing. Before we really come out with any greater detail on that, the slowdown in activity slowed down our data collection on that. But, we continue to push forward with it.

Ryan Todd -- Deutsche Bank Securities, Inc. -- Analyst

Thanks. Can you talk about the trends in lateral length in the Permian in 2018? You're targeting a little over 6,000 feet, which are a relatively wide range across some of your wells. What's the limiting factor in you guys going higher?

Ezra Yacob -- EVP, Exploration and Production

Again, this is Ezra. We're able to extend our lateral length 20% year-over-year, and we're anticipating another 10% increase here in 2018. As we 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 the limiting factor.

Ryan Todd -- Deutsche Bank Securities, Inc. -- Analyst

Okay. Thanks. I'll leave it there.

Operator

We'll go next to Subash Chandra with Guggenheim.

Subash Chandra -- Guggenheim Securities -- Analyst

Thank you. As you double the package size in the Permian, two to five as you said, do you think at some point you have to get to a cube 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?

Ezra Yacob -- EVP, Exploration and Production

Yeah. No, I think the last part that you said is right. We can more moderately expand the package size. It's a real balance there of trying to get the package sizes large enough so that your maximizing the operational efficiencies that exist with multi well operations. We definitely don't want to get them so large that we have to sacrifice the flexibility to integrate real time data collection and learnings and/or our subsequent well packages. And then, we also don't want to get into situations where you 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.

The last thing to think about, as Bill mentioned previously, and being cautious not to get in a manufacturing mode, the size of these packages are going to be very area dependent. It's complex geologically and we focus a lot of precision targeting and working out the stratigraphy and complexities of the geology, to make sure we're putting these wells in the best targets.

Subash Chandra -- Guggenheim Securities -- Analyst

Thanks. In the Wolfcamp or Delaware, you've sidestepped all the issues that have hobbled some of your competitors -- sand, takeaway, inflation, etc. I think what you've messaged on this call is that your real hurdles are internal in managing IRRs, learnings, and the like? Did I hear that correctly? Are there some speedbumps that you're concerned about that are external, whether it's water or some other things that we haven't considered?

Ezra Yacob -- EVP, Exploration and Production

I think you're correct, Subash. We're in great shape in the Permian -- sand, water, takeaway, and all of those things. The real thing we're focused on, and 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, learn, and continue to focus on cost reduction. Those are things that we've been fortunate to learn over our two decades in drilling horizontal wells. We're putting those to good use in the Permian.

Subash Chandra -- Guggenheim Securities -- Analyst

Thank you.

Operator

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

Robert Scott Morris -- Citigroup Global Markets, Inc. -- Analyst

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. I noticed the average rate dropped a little bit here. I know some of that's in moving more of your wells to Reeves County. 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 ungrounded, or parent, wells to child wells in that situation?

Ezra Yacob -- EVP, Exploration and Production

Bob, this is Ezra again. I think you hit the nail on the head. That's more of a reflection of increasing the percentage of wells drilled down in our combo play in Reeves County. I think the issue of parent/child well performance isn't anything new. It's a challenge that operators have been faced with since horizontal resource plays have been developing. We've been collecting data on the topic for almost 20 years now throughout our multiple basins and multiple plays. There is not really a single variable to eliminate the issue. The way we approach it is it begins with the well planning -- that's to say the spacing, the targeting, and making sure you get that right for the geology that you're in. Different targets respond differently to how much they effect that parent/child relationship. Also, there are things you can do on the completions and production side. Certain techniques and designs to alleviate some of those issues.

Operator

We'll go next to Brian Singer with Goldman Sachs.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good 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. I wondered why not shift more activity there relative to the Permian Basin? I think the increase in the rig counts about one in the Eagle Ford a little bit more substantially in the Delaware. Can you talk a little bit more about that capital allocation decision and how the rates of return inflationary pressures and ability to execute compare in the Eagle Ford relative to the Delaware?

Lloyd W. "Billy" Helms -- Chief Operating Officer

Brian, this is Billy Helms. In the Eagle Ford, we're very pleased with the rate of return and the program. This last year was a 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, look at the Eagle Ford as a pretty stable platform for us to continue to slightly grow over the time, as we develop that. But, we have 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 started in the Eagle Ford.

We're also, as a result of the activity in Eagle Ford, improving our well costs. The well count is actually going up more so than rigs in Eagle Ford versus that. The other thing that's important to note on Eagle Ford, remember that 99% of our acreage there is HBP. We have a lot of flexibility in how we manage our activity levels in Eagle Ford.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you. My follow-up question is in regard to well costs and efficiencies. You've highlighted your expectations for well costs to fall in a couple of these key basins. Some of the reasons for that you mentioned are 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?

Lloyd W. "Billy" Helms -- Chief Operating Officer

Brian, this is Billy Helms again. The thing that's unique about EOG in some aspects is that we did lock in services at low costs. A lot of people are able to take advantage of the service cost declines. But the thing that's a little bit unique in EOG is our culture of continuous improvement, that we focus relentlessly on improving every aspect of our business -- our drilling times, lowing our completed well costs by completing more of the lateral with each stage. We also self-sourced 25-30% of our well costs. So, we do a lot of things that enable us to continue to make steady improvements in our well costs. We can't be more proud of our operational teams as they continue to strive to do that.

Ezra Yacob -- EVP, Exploration and Production

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 remember many years when oil costs were going up in the EOG. I think we have a lot of confidence in our ability to continue to hold and even reduce costs as we go forward.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you.

Operator

We'll go next to Phillips Johnston with Capital One.

Phillips Johnston -- Capital One -- Analyst

Hey, guys. Just a follow-up on the topic of parent/child wells. A few operators have recently highlighted a decline in per well productivity in the URs as infill drilling has occurred. I think you guys have previously talked about seeing similar trends in the Bakken as infill drilling has occurred. I want to get a sense of what you're seeing in the Eagle Ford. I realize that per well productivity as a whole play has continued to improve throughout '17. What are you seeing in areas where the number of wells per section is approaching your 16-well target?

William R. Thomas -- Chairman, Chief Executive Officer

I would say, Phillips, we have continually learned to have variable targets as we develop the Eagle Ford. We have the Lower Eagle Ford, the Upper Eagle Ford, and multiple targets. We continue to learn to place those better. We also are learning to manage the parent/child relationship, even down to wells as close as 200 feet apart. It's managing the pattern sizes, the timing of the completions, the targeting, and the way that you spatially locate the targets and w-patters. 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 consistently, every year, are going up. That's the way we want to develop all of our assets, to where we're constantly improving and making them better.

Phillips Johnston -- Capital One -- Analyst

Great. That's helpful. On the return on capital employed target, nice to see the projected uptick to 10% or higher this year. What does that number look like if you ran the same price deck of 48x270 that you showed for the last three years on Page 4 of the slide there?

William R. Thomas -- Chairman, Chief Executive Officer

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

Phillips Johnston -- Capital One -- Analyst

Okay. Thank you very much.

Operator

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

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Good morning, guys. Thanks for taking my question. Thinking about your cash margins and your differential guidance, early in the year, you're benefited by LOS, but your full year guide -- is that incorporating a wider differential for things like the Delaware as that grows? Can you talk some about how you think about your long-dated differentials as other regions beyond the Eagle Ford start dominating growth?

D Lance Terveen -- VP, Marketing Operations

David, this is Lance. As we look at our guidance, we take all of those considerations. 100% of our Eagle Ford is all priced on LOS. You look at that for 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'll see on Slide 24, 20% of that we're able to get into the Corpus market. We see it as a brand or LOS type marker. We factored all of that into our guidance, what you're seeing today, for the full year '18.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

So, do you think a range at the end of the year should carry forward in that more similar to the full year '18 as opposed to where we are this early in '19 and '20 free cash flow generation? Is that what becomes important?

D Lance Terveen -- VP, Marketing Operations

The crystal ball, so far, in terms of -- when you look at the Ford curves and where that's trading. We look at '19 and the same thing for gas, like the crude. We've got the guidance out there for '18 and we bake that all the way through in terms of for crude and for gas. Everywhere from the Rockies to the Delaware Basin, and even into the Eagle Ford -- that's all factored into our guidance. We've been very positive about -- as you've seen, the Rockies has definitely strengthened. Across the board, when you look at all of our divisions and our domestic oil production, we're seeing strength in all of the divisions.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Alright. Thanks.

Operator

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

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

Good morning. I wanted to get a bit granular on the CapEx budget. I was looking through it. It looks like the exploration development budget of $4.5-4.8 billion, just taking an average out over the 690 wells implies $6.7 million. When you go back to 2017, the average works out to $5.9 million. I know there are a lot of moving parts in terms of longer laterals and you guys are lowering normalized lateral well costs.

I'm just trying to figure out what exactly is causing this shift. I think a big piece of it is 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.

Lloyd W. "Billy" Helms -- Chief Operating Officer

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. The other thing in our capital budget is, we are testing some new plays. Early on in new plays, we do collect some science data cores -- micro seismic in places, 3D seismic -- those kinds of things add into our capital program that would not be typical in just a normal development program.

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

Okay. That's helpful. On Slide 19, outlook through 2020 looks like you can achieve this at roughly $5.00 per barrel lower based on the 2018 capital efficiency that's being implied. Is this the right way to think about it? Do you have any plans to update this outlook going forward?

Lloyd W. "Billy" Helms -- Chief Operating Officer

You're looking at it correctly. We're getting better every year. 2017 metrics versus the 2018 metrics. The 2018 metrics are better in every way. So, we're able to deliver very strong growth at lower oil prices going forward. You're looking at that correctly. We have a very strong, incredible, high return inventory in place and we believe our quality of our inventory is going to increase over time and our costs are going to continue to go down. I think you can look for us to keep updating this 2020 outlook that we have, and we're very hopeful that we'll keep outperforming the outlook guidance going forward.

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

Great. If I can squeeze in one last one, you guys talked about 27 wells online in January. Any additional color you can provide on the expected total for the first quarter?

Lloyd W. "Billy" Helms -- Chief Operating Officer

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. It's due to the ramp up in activity that we see at the start of the year. Drilling these larger packages and 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. We're very confident in our plan and the volumes that we've laid out and the guidance we've given. We expect to be able to deliver that without our program we've laid out.

Operator

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.

William R. Thomas -- Chairman, Chief Executive Officer

In closing, 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. Thank you for listening and for your support.

...

Operator

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

Duration: 63 minutes

Call participants:

Timothy K. Driggers -- Chief Financial Officer

William R. Thomas -- Chairman, Chief Executive Officer

Gary L. Thomas -- President

Lloyd W. "Billy" Helms -- Chief Operating Officer

Ezra Yacob -- EVP, Exploration and Production

David W. Trice -- EVP, Exploration and Production

D Lance Terveen -- SVP, Marketing

David Streit -- VP, Investor and Public Relations

Robert Scott Morris -- Citigroup Global Markets, Inc. -- Analyst

Leo Mariani -- National Alliance Securities -- Analyst

Scott Hanold -- RBC Capital Markets LLC -- Analyst

Ryan Todd -- Deutsche Bank Securities, Inc. -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Subash Chandra -- Guggenheim Securities -- Analyst

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

Phillips Johnston -- Capital One -- Analyst

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