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Edited Transcript of EOG earnings conference call or presentation 28-Feb-17 3:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 EOG Resources Inc Earnings Call

HOUSTON Feb 28, 2017 (Thomson StreetEvents) -- Edited Transcript of EOG Resources Inc earnings conference call or presentation Tuesday, February 28, 2017 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Tim Driggers

EOG Resources Inc - EVP & CFO

* Bill Thomas

EOG Resources Inc - Chairman & CEO

* Gary Thomas

EOG Resources Inc - President & COO

* Billy Helms

EOG Resources Inc - EVP of Exploration and Production

* David Trice

EOG Resources Inc - EVP of Exploration and Production

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Conference Call Participants

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* Brian Singer

Goldman Sachs - Analyst

* Evan Calio

Morgan Stanley - Analyst

* Arun Jayaram

JPMorgan - Analyst

* Scott Hanold

RBC Capital Markets - Analyst

* Paul Sankey

Wolfe Research - Analyst

* John Abbott

BofA Merrill Lynch - Analyst

* Mike Scialla

Stifel Nicolaus - Analyst

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Presentation

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Operator [1]

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

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Tim Driggers, EOG Resources Inc - EVP & CFO [2]

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Good morning, and thanks for joining us. We hope everyone has seen the press release announcing fourth-quarter and full-year 2016 earnings and operation results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call.

This conference call also contains certain non-GAAP financial measures. The reconciliation 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 theirs 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 US investors that appears at the bottom of our press release and investor relations page of our website.

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

An updated IR presentation was posted to our website yesterday evening, and we included guidance for the first-quarter and full-year 2017 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review 2016 highlights and our 2017 capital plan. Gary Thomas, Billy Helms and David Trice will review operational results and year-end reserve replacement data. And I will discuss EOG's financials and capital structure, and Bill will provide concluding remarks. Here's Bill Thomas.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [3]

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Thanks, Tim. As we look back, 2016 will be remembered as truly historic for EOG, because it's the year we permanently shifted to premium drilling and reset the Company to be successful in a lower-commodity price environment. To remind everyone, a premium well is one that earns a minimum of 30% after-tax rate of return, with flat $40 oil and $2.50 gas prices on a direct basis. We set the minimum at 30% to ensure that fully loaded well returns are accretive to corporate returns.

I want to emphasize that this shift to premium is permanent, which means that the return hurdle and the inventory of premium wells did not change with improving oil prices. Going forward, EOG's capital will be focused on wells that are profitable at $40. Meaning, with modest increases to oil price, our returns have the potential to soar. You can see this on slide 24 of our investor presentation.

Our list of accomplishments in 2016 include a few Company records and first-time achievements. In 2016, we achieved one of the highest returns on capital expenditures in Company history, and we did it at the low point of the commodity price cycle. Our shift to premium drilling and improvements in operating costs resulted in record-low finding costs of $5.22 per Boe, when you exclude revisions due to commodity price.

Over the course of the year, we increased our premium drilling inventory nearly 9% to 6,000 locations and over 5 billion barrels of oil equivalent. The Company added 3.7 billion barrels oil equivalent of new drilling potential in the Delaware Basin.

Since the downturn began in late 2014, we slashed unit operating costs by 22%. As a result of drilling low-cost premium wells, the Company grew oil production within cash flow during the second half of 2016. We announced the world's first technically successful enhanced oil recovery in shale that delivers strong project economics. EOG completed the largest transaction in the Company's history, with the Yates Petroleum acquisition. Finally, we accomplished all of this while maintaining a healthy balance sheet and posting the best safety record in the Company's history.

To sum up 2016, record-setting capital efficiency gains and a significantly larger and improved drilling inventory have reset the Company to achieve outstanding results in the years to come. This is why we are confident that we'll be one of the lowest-cost producers, and competitive in the global oil market.

Now looking ahead to 2017, we're more excited than ever to resume our leadership and high-return oil growth. Transforming EOG into a premium-only driller means we expect to deliver 18% oil growth within cash flow during 2017. Remarkably, EOG can deliver strong 18% oil growth plus the dividend within cash flow if prices were to average $50 oil and $3 gas. We believe this is unique in the industry, and sets EOG apart as the most capital-efficient operator in the US.

Furthermore, each of EOG's major basins will be contributing to that growth in 2017 -- the Eagle Ford, the Delaware Basin, the Bakken, the Powder River Basin and the DJ Basin. That's a testament to our diverse portfolio of high-return assets.

Our plan was finalized last month when strip prices were closer to $55 oil and $3.50 natural gas. If current prices hold, we will reach our goal of generating free cash flow. Our number one priority for that cash is to reinvest into high-return premium drilling. We also want to continue firming up the balance sheet with non-core asset sales. And if the business environment continues to improve, we will want to refocus on our commitment to the dividend.

Looking beyond 2017, I want to talk about EOG's return prospects, specifically return on capital employed. If a Company is earning the well level returns we and many of our peers assert, you should eventually see those results reflected in ROCE. For EOG specifically, we expect returns and finding costs to continue to improve in the years ahead as premium wells become a higher percentage of total well completions. As new premium wells are drilled, the DD&A rate will converge towards premium finding costs. The lower DD&A rate, along with lower cash operating costs, such as LOE and transportation, should significantly improve EOG's ROCE over time.

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

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

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Gary Thomas, EOG Resources Inc - President & COO [4]

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Thanks, Bill. The 2016 accomplishments I'm most proud of are the capital efficiency gains from cost control and operational efficiencies. At the start of 2016, our plan was to drill 200 and complete 270 net wells within cash flow for $2.5 billion. By year end, due to our astonishing progress on cost control and efficiency gains, we drilled 280 and completed 445 net wells for $2.7 billion, all within cash flow. That's a 40% and 65% increase in drilling and completing activity, with only an 8% increase in capital, compared to our initial guidance.

Almost 60% of these competed wells were drilled but uncompleted wells. So we're beginning 2017 with a normal inventory of 137 DUCs. Furthermore, our fourth-quarter average oil rate of 312,000 barrels of oil per day set an all-time high from our previous record set in the fourth quarter of 2014.

Here are a few highlights from our 2016 operational accomplishments. We expanded electrical power and gas lift infrastructure in South Texas and the Delaware Basin. We also expanded our water-handling infrastructure in the Delaware Basin and Rockies, to better reuse and more efficiently transport drilling, completion and production water, which will reduce transportation and disposal costs.

We extended our in-house chemical program and other cost-cutting practices to the Yates properties. And we continue to see significant cost-reduction opportunities. For 2017, we have line of sight into sources of savings to further improve on cost control initiatives in 2016, in spite of potential service cost increases.

Four significant sources of service cost savings in 2017 are: our average daily rig rates are down 25% compared to last year. 14 of our drilling rigs, or 60% of the total, are under long-term contracts, and nine of these rigs are at bottom-of-market rates. We've locked in three-quarters of our casing needs at prices 30% below our 2016 costs. To further control costs, we've also locked in 50% of our frac fleets. And we have diverse sources of frac sand, and our aggregate sand costs are expected to decrease by 18% year over year.

Furthermore, I'm confident we'll be able to further improve operational efficiencies in 2017. During the downturn, we took the opportunity to upgrade our rig fleet to one of the most modern and highly efficient fleets in the industry. We're drilling 20% longer laterals, and increasing the use of multi-well pads. Our expanded water infrastructure systems are expected to reduce our well costs by another $100,000 per well. And because of the combination of operational efficiencies, we expect to complete 15% more wells per frac fleet this year.

We expect 2017 to 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 turn the call over to Billy Helms, who will update you on our Eagle Ford and Delaware Basin plays.

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Billy Helms, EOG Resources Inc - EVP of Exploration and Production [5]

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

The wells completed in 2016, as a group, are outperforming wells from previous years, largely as a result of the precision-targeting and advanced completion designs. During 2016, 210-day cumulative production improved 13% for wells drilled in our western acreage, while wells drilled in the east improved 10%. We also reduced completed well costs by $1 million to $4.7 million, and believe further reductions are possible in 2017.

I'll leave you with one final important note about this play. There is still a tremendous amount of upward potential in the Eagle Ford. To date, we have drilled less than one-third of the total identified locations in this world-class play. Efforts to update the total resource potential are underway, and can only be assessed with longer-term performance from each of the various targets and spacing tests. Our technical team continues to integrate the latest results into our future plans, to assess the full potential of this asset. Suffice it to say, it continues to grow.

Eagle Ford oil production is expected to grow during 2017 while drilling less than half the number of wells we did during the peak of activity in 2014. Using our 2017 rate of approximately 195 net completed wells, we have over 20 years of inventory. The Eagle Ford has been and will continue to be a growth asset for the Company.

Last year, we announced early success in the first enhanced oil recovery project in horizontal shale. In 2015, we tested four pilots comprised of 15 wells across a geologically diverse area, and the results were consistently positive and highly economic. In 2016, we initiated a larger 32-well pilot to test how well EOR technology can be implemented on a larger manufacturing-type scale. The pilot has been a success and confirms our initial results for field scale implementation. As with the 2015 pilots, the 32-well project delivered premium economics with a finding cost of less than $6 per barrel.

This 32-well project provided insights into EOR's impact across a wide variety of completion styles and spacing patterns. The results were favorable for wells completed from 2011 through 2016 with well spacing ranging from 200 feet to 500 feet. This gives us further confidence in the applicability of EOR across major areas of the field.

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

In 2017, we are eager to expand our EOR project by testing approximately 100 additional wells in six different areas. The results of this program will provide additional data on EOR's uplift to Eagle Ford's resource potential and EOR's effect on field production decline. This data will help determine how we will incorporate EOR into our long-term Eagle Ford capital program.

2016 was a breakout year for the Delaware Basin, setting up this play to be our fastest growing asset in 2017. First, EOG completed some of the industry's best wells in the Permian Basin through the application of our leading-edge technology, including precision-targeting and high-density completions. This technology is proving to deliver step change in well performance.

And with an improved well bore design, we began testing longer laterals in the second half of the year, with promising recovery results on a per-foot basis. Our goal is to achieve the same recovery measured by EUR per foot of lateral as we increase lateral length. In 2017, we expect to use longer laterals on a larger percentage of our program, so we're excited to watch the well performance continue to improve.

Second, the Yates transaction was truly transformative. The acreage obtained in the Delaware Basin is not only adjacent to our existing program, but is also generating highly economic results. Our technical capabilities, combined with this transformative transaction, resulted in adding a record-setting 3.7 billion barrels of oil equivalent of estimated resource potential last year alone. In addition, we've already identified almost 3,500 premium well locations across three targets in the Delaware -- the Wolfcamp, the Second Bone Springs and the Leonard. This is almost a mile of stacked pay in this world-class basin, and our exploration efforts are just getting started.

And third, we are well-positioned on infrastructure. Over the last few years we've made strategic investments in oil and gas gathering and take-away, gas processing, water sourcing and handling, and sand railcar unloading facilities.

As an example, the water sourcing and handling infrastructure is helping to reduce both our initial well costs, as well as reducing our long-term cash operating costs. Some of the assets obtained in the Yates transaction included water gathering systems that support our existing systems. In our major areas of activity, we will deliver a significant percentage of our produced water into these systems. We're also increasing the volume of recycled water for use in our operations.

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

The Delaware Basin Wolfcamp is arguably the most prolific [titeable] play in North America, and EOG consistently delivers the best Wolfcamp results in the industry. Please see slide 9 of our investor presentation for a plot of our 2016 well performance versus the industry. In 2017, the Wolfcamp will again be the primary focus of our drilling program, as we plan to complete 110 net wells. Here's David Trice to review the progress we made in the Austin Chalk and our Rockies, Bakken and international activity.

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David Trice, EOG Resources Inc - EVP of Exploration and Production [6]

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Thanks, Billy. Last year, our Eagle Ford team took a fresh look at the Austin Chalk and discovered that, within our current Eagle Ford footprint, there are areas where the Austin Chalk is prospective. Using proprietary petrophysical analysis, we can identify and map the best properties, using our existing well control. We are then able to target the best rock with horizontal laterals, and apply EOG-style high-density completions.

The result is consistent premium Austin Chalk wells. These wells can be very prolific, and in fact, some of the best wells drilled by the Company last year were in the Austin Chalk. In 2016, we completed 14 Austin Chalk wells with an average 30-day rate of 1,700 barrels of oil per day, and total equivalent rate of 2,200 barrels of oil equivalent per day, from an average lateral of 4,400 feet.

We continue to drill delineation and spacing tests, analyze subsurface data and create detailed mapping throughout the field, to understand the prospectivity of the Austin Chalk across our South Texas position. During 2017, we will drill approximately 25 net wells in the Austin Chalk. Those well results, along with the work we did last year, should get us closer to providing a resource estimate for this emerging play.

In the Rockies, we had great success in the Powder River Basin and Wyoming DJ Basin during 2016. In the Powder River Basin, we focused predominately on the Turner interval in 2016. Turner wells compete with the best inventory in the Company. Our 2016 drilling program in this play averaged over 1,600 barrels of oil equivalent per day, rate-restricted for the first 30 days, and cost about $5 million to drill and complete.

During the fourth quarter, we returned to the [Partman] interval, and applied our latest techniques with excellent premium-level results. Three Partman wells had a 30-day rate that averaged 2,200 barrels of oil equivalent per day. With the addition of the Yates acreage, our core position on the Powder River Basin has grown to 400,000 acres. We are expanding this program in 2017 to complete 30 net wells, and we look forward to blocking up the acreage, applying longer laterals, adding to our premium inventory and exploring the 4,800 feet of stacked pay.

In the DJ Basin, we added 200 premium Codell wells through sustainable cost reductions and precision-targeting during 2016. We also completed installation of water and gas infrastructure that should further reduce costs and enhance returns as we increase our development in 2017. We plan to complete approximately 15 net wells in the DJ Basin Codell this year.

The Bakken is another area we've been investing in water take-away infrastructure, that should further reduce costs to support and enhance returns of our ongoing drilling program. In the fourth quarter of 2016, we completed the majority of the remaining pre-2016 DUCs. As a result, our 2017 drilling program will be focused on drilling premium Bakken Core and Antelope Extension inventory. We expect to complete 35 net wells during 2017.

In Trinidad, we continue to get great results from existing wells, which led to out-performance versus forecasts in 2016. Production in Trinidad was virtually flat, despite drilling just one additional well that came online in December of 2016. In 2017, we expect to drill an additional five net wells throughout the year. Here's Billy to review our year-end reserve replacement and finding costs.

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Billy Helms, EOG Resources Inc - EVP of Exploration and Production [7]

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Thanks, David. We replaced 163% of our 2016 production at a very low finding cost of $5.22 per Boe, excluding revisions due to commodity price changes. That's less than half of our 2015 finding cost. The proved developed finding cost, excluding leasehold capital, was $6.50 per Boe. Notably, sustainable LOE reductions drove positive reserve revisions that more than offset negative revisions due to lower commodity prices. As a result, our proved reserves increased by 1.4% year over year, driven by a 7.7% increase to crude oil and natural gas liquids reserves.

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

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Tim Driggers, EOG Resources Inc - EVP & CFO [8]

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Thanks, Billy. I'll begin with a few comments about our capital spending last year and in the fourth quarter. These amounts exclude the Yates transaction, which I'll cover separately.

Capitalized interest for the fourth-quarter 2016 was $6 million. Total exploration and development expenditures were $748 million, including facilities of $122 million, and excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment, were $31 million.

For the full-year 2016, capitalized interest was $31 million. 2016 capital expenditures, excluding acquisition and asset retirement obligations, were $2.7 million, in line with the updated guidance provided on last quarter's call. This amount includes facilities of $375 million and expenditures for gathering systems, processing plants and other property, plant and equipment of $92 million. Total discretionary cash flow was $2.75 billion.

We are pleased to have reached our goal of balancing CapEx and discretionary cash flow in 2016. In addition, proceeds from asset sales were $1.1 billion, which included natural gas assets in the Barnett Shale and Haynesville plays, and marginal liquids plays in the Permian Basin and Rockies. We also completed the sale of Argentina assets during the year. Total property acquisition costs other than Yates were $14 million for the year.

Capital additions related to the Yates transaction are $3.1 billion of lease-hold acquisitions, $735 million of proved property acquisitions, and $17 million of other property, plant and equipment. We also recorded $1.1 billion of deferred taxes related to the transaction. To fund the Yates transaction, EOG issued 25 million shares of common stock, and paid cash of $16 million, for a total consideration of $2.4 billion. At year end, total debt outstanding was $7 billion, for a debt-to-total capitalization ratio of 32%. Considering $1.6 billion of cash on hand at year end, net debt to total cap was 28%.

In the fourth-quarter 2016, total impairments were $298 million. For the full-year 2016, total impairments were $620 million. Impairments to proved properties of $116 million were primarily the result of a write-down to fair value of legacy natural gas assets, which have since been divested. Impairments for both the fourth-quarter and full-year 2016 included charges of firm commitment contracts related to divested Haynesville natural gas assets, and obsolete inventory. The effective tax rate for the fourth quarter was 27%, and deferred tax ratio was 44%.

Yesterday we included a guidance table with our earnings press release for the first-quarter and full-year 2017. Our 2017 CapEx estimate is $3.7 billion to $4.1 billion, excluding acquisitions. The exploration and development portion, excluding facilities, will account for about 81% of total CapEx budget. The budget for exploration and development facilities, and gatherings, processing and other accounts, were approximately 19% of the total CapEx budget for 2017.

We plan to concentrate our infrastructure spending in the Eagle Ford, Delaware Basin and Rockies, to support our drilling program in those areas and enhance operating efficiencies. Now I'll turn it back over to Bill.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [9]

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Thanks, Tim. In closing, I will leave you with a few important points. First, our improvement of well performance has been accomplished through the use of proprietary technology to identify high-quality rock, drill precisely targeted laterals, and execute leading-edge completions. We're now beginning to drill longer laterals, and we believe our industry-leading well performance, combined with longer laterals, will drive significant productivity gains in the future. Slide 10 in the IR deck illustrates this conclusion.

Second, EOG is not and has never been a one-trick pony. We have top-tier positions in the big three producing North American oil basins, and strong positions in what we believe are the best emerging plays. Our diverse portfolio of assets and decentralized operating structure provides incredible flexibility to invest in the basins with the highest returns, particularly as technology, infrastructure and netbacks change.

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

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

Fourth, EOG's exploration focus is still in high gear. We have never been more excited about the leading-edge technology that we are developing in-house, and the new exploration concepts we continue to discover. Everything we learned from our existing plays is being applied to generate new exploration concepts and leasing efforts. With new knowledge, we continue to see significant opportunities to add to and improve our inventory through exploration. Better rock makes better wells, and that's our exploration focus. Do not count us out. We're not through.

And finally, in my 38 years with EOG, I've seen many downturns. Every time, we emerge from a downturn in better shape than we entered it. This downturn, however, is unique in every respect, except direction. We're not simply in better shape, we vaulted ahead with record-setting achievements in cost reduction, productivity gain, inventory growth and capital efficiency improvements.

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

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Questions and Answers

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Operator [1]

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Thank you.

(Operator Instructions)

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

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Brian Singer, Goldman Sachs - Analyst [2]

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Thank you, good morning.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [3]

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Good morning, Brian.

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Brian Singer, Goldman Sachs - Analyst [4]

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First question is on the Eagle Ford from a primary drilling perspective. You talked about the increase in oil rates. Slide 40 shows some of this in terms of your wells in 2016 versus 2015 versus 2014. What are the implications for EURs and spacing from the improved well performance that you're seeing over multiple days? And if not yet certain there, can you just talk to the milestones that you're looking for to have more confidence?

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Billy Helms, EOG Resources Inc - EVP of Exploration and Production [5]

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

We're still testing some spacing patterns and in different areas of the field, and applying this new technology to understand longer-term performance. And as we've stated in the past, as we make these changes, we want to further understand the longer-term performance before we do a resource estimate increase. We are encouraged that the Eagle Ford is going to continue to improve with time, but we're still watching that data.

The Eagle Ford has been essentially a very large laboratory for us to continue to experiment with. So as we continue to gather this data, we'll have a better idea of what that implication means to the long-term performance. I can't really give you a timeframe yet, but I'd say that we're encouraged with what we see.

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Brian Singer, Goldman Sachs - Analyst [6]

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Thanks. And then my follow-up is with regards to well costs. On slide 14, you talk about some targets for further cost reductions, which seems in the face of an inflationary environment, we may be going into or are already in. Can you just talk about the achievability, and whether these are more, one-off we'll get there, or whether these are ultimate averages? What happens if prices aren't $50, they're a little bit higher, and the inflation environment assumptions that you've baked in?

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Gary Thomas, EOG Resources Inc - President & COO [7]

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Brian, this is Gary. And yes, we look at each of the wells in the area, and what we see is about 40% of our well cost is subject to inflation. Because we've got contracts in place, we've got sales sourced, all that sort of thing. When we do that and we look at what kind of opportunities we see for just other efficiency improvements, we believe that we'll be able to meet these targets that we've set here for each of these plays that's listed on this exhibit 14.

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Brian Singer, Goldman Sachs - Analyst [8]

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Got it. And is there any upside -- if oil prices are $55, then I guess one would just apply the inflation to that 40%, and get to something modestly higher?

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Gary Thomas, EOG Resources Inc - President & COO [9]

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Well, as far as the -- irregardless of oil prices, it's where we think we'll be able to get here on this 2017 target.

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Brian Singer, Goldman Sachs - Analyst [10]

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Great. Thank you very much.

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Operator [11]

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

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Evan Calio, Morgan Stanley - Analyst [12]

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Good morning, guys.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [13]

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Good morning.

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Evan Calio, Morgan Stanley - Analyst [14]

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You guys highlight more prominently exploration in the presentation and in your 10-K and in your comments this morning. Let me ask, how de-risked does a new play need to be before you'll disclose it? And outside of securing acreage, what are the key parameters necessary before you'll show it to investors? And I raise it from the context of peers, both US and globally, that unveiled unconventional plays at much earlier stages, raising the risks as data is released.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [15]

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Well, the first thing, Evan, is, the play has to be premium-quality, so it has to meet the investment hurdles that we've set for premium drilling. And then second of all, we like to have multiple tests, and we like to be really convinced that the play is going to work up to our expectations and we have some consistency about it. We don't want to drill a one- or two-well wonder, and then come back and some of the other wells are not going to get it. So we do take a little bit more time. I think it's because we're just more thorough, and we want to be more sure about it.

And then there's always, in every one of these plays you mentioned, acreage. Acreage is a critical thing, and we want to -- as we test them, we learn more about where the sweet spots could be in the plays. And so we're only focused on tying up the sweet spots of that acreage.

We have a large number of plays in the Company that we're working on. As you know, we're very decentralized, and each one of our operating divisions has a full set of exploration folks, and we're spread out all over the US. So we're working multiple plays at the same time. And we're quite optimistic about new plays providing additional premium inventory in the future.

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Evan Calio, Morgan Stanley - Analyst [16]

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Great. I'll look forward to hearing results as we move through the year. My second question on the Permian. You guys are running 11 rigs and targeting 140 wells in 2017. Implied spud-to-spuds are up year over year. Any color there on how many well completions in the 2017 program are being carried into 2018? Or does the lower number of wells reflect a larger appraisal program? Just some color around that, just sequentially would be helpful.

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Billy Helms, EOG Resources Inc - EVP of Exploration and Production [17]

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

On the number of well completions, I believe we're going to complete about 140 total wells in the Delaware Basin this year, most of those in the Wolfcamp. And we're down to the normal level of inventory in all of our major plays, including the Delaware Basin. So we're not really carrying over into 2017 an abnormally high amount of DUCs, you might say. So I think we're just -- the rig count there has increased relative to last year. We will be going to longer laterals. But we'll add about 140 net wells completed this year.

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Evan Calio, Morgan Stanley - Analyst [18]

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Is there a carryover into 2018, was my question? It seems as though there would be on those numbers.

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Billy Helms, EOG Resources Inc - EVP of Exploration and Production [19]

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

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Evan Calio, Morgan Stanley - Analyst [20]

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Got it. Thanks, guys.

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Operator [21]

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

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Arun Jayaram, JPMorgan - Analyst [22]

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Good morning. My first question is just on the overall guidance. Bill, you guys issued essentially in-line oil production guidance, but you're using quite a bit of lower oil price perhaps relative to strip and consensus, around $50. I was wondering if you could comment on how you plan to address the CapEx budget and guidance for the year? Do you plan to look at it on a quarterly basis, or reassess things around the middle of the year? Because on our numbers, your cash flow would be closer to just under $5 billion using the strip.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [23]

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

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

I can say this. We have extreme amount of flexibility. So with our decentralized structure and multiple high-return plays, it's very easy for EOG to redeploy capital. And we can do it relatively quickly. As one area, say, heats up, and maybe it's difficult to get a frac spread or something in one area, we've got other areas that it's easier, and they have high return. So we can ramp up relatively quickly.

The priority for the free cash flow is to reinvest. That's the number one priority, is obviously reinvest in the high-return premium drilling. We also want to continue to firm up our balance sheet. We're going to do that primarily with non-core property sales. So we need to watch how that process proceeds.

And then EOG's got a great track record of increasing the dividend 16 times in the last 17 years. So consistent with that commitment to the dividend, as the year unfolds, we'll continue to evaluate the business environment as it relates to the dividend. So again, I think we've got a lot of flexibility, and we'll give you more details on a quarterly basis.

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Arun Jayaram, JPMorgan - Analyst [24]

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That's helpful. My follow-up is just a follow-up to Brian's question. In terms of the Eagle Ford, you did show a positive rate of change in both the east and the west. My question is regarding the Q4 activity. If you look at some of the 30-day rates on the 75 wells, they're a touch below our expectations or type curve. Can you comment on what you saw in terms of productivity between the 45 wells which were drilled prior to 2016 versus the 30 that you drilled last year, in terms of the impact of precision-targeting, in terms of well results?

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Billy Helms, EOG Resources Inc - EVP of Exploration and Production [25]

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Yes, Arun, this is Billy Helms. Certainly you're picking up on it there. In the fourth quarter, about 60% of our well completions were DUCs carried over from prior years. And those wells didn't benefit from the precision-targeting that we have done more recently. And so you're seeing some of the 30-day initial IP rates from those wells being below those of previous quarters.

But I think overall, after time, you can see on that productivity chart that after about 120 to 150 of days, they start to -- because of the advanced completions, long-term performance is still improving. So we're continuing to be pleased with our technology and what it's yielding there, both in longer-term performance, as well as initial upfront productivity.

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Arun Jayaram, JPMorgan - Analyst [26]

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Okay, thanks a lot.

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Operator [27]

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

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Scott Hanold, RBC Capital Markets - Analyst [28]

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Thanks, good morning.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [29]

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Hello, Scott.

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Scott Hanold, RBC Capital Markets - Analyst [30]

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

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Bill Thomas, EOG Resources Inc - Chairman & CEO [31]

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Scott, I think we're watching the oil market, particularly inventory levels, and I think just in the last week or so, we're starting to see some very encouraging signs on inventory drawdown. And I think we're getting close. It won't be in the next month or two. I think we're going to know a lot about how the OPEC cuts have affected supply/demand dynamics, and the drawdown of that inventory. So we're about there, but we just need a little bit more time on that.

I think the other thing is, with the rapid ramp-up of drilling rigs in the US, we don't want to ramp up too rapidly, to decrease the capital efficiency. We're very committed to keeping the capital efficiency of the Company extremely high, and we really only want to increase the capital efficiency. So part of our ramp-up strategy will be to have -- certainly to stay very disciplined, to allocate the capital to obviously the highest-return investments that we have. And to do it in a systematic manner, where we are bringing in really good equipment, really good people, and we don't lose performance there.

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Scott Hanold, RBC Capital Markets - Analyst [32]

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

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Gary Thomas, EOG Resources Inc - President & COO [33]

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Scott, this is Gary. We've ramped up pretty rapidly here in 2017. Because we ended 2016 with 17 drilling rigs, and we've now, just this week, reached 23. So we're a little bit heavier in the Delaware. We run about 11 rigs there. And we're running in the seven to eight rigs in the Eagle Ford, and a couple in the Rockies. So we're close. And like we mentioned earlier, yes, we've really been working hard just to get the very best available rigs in the industry. So we're pretty well there.

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Scott Hanold, RBC Capital Markets - Analyst [34]

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Appreciate that. Thanks.

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Operator [35]

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We'll go to Paul Sankey with Wolfe Research.

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Paul Sankey, Wolfe Research - Analyst [36]

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

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Bill Thomas, EOG Resources Inc - Chairman & CEO [37]

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

And generally, when you look across all these plays -- and there's been quite a bit of studies, not just our studies, but this is basically HIS data that anybody can duplicate -- it shows that as lateral lengths increase, obviously the well productivity is increasing. But EOG is in the red there, and if you look at that chart, you can see that our productivity is increasing much faster than, generally, the industry. And our wells are much more productive, even at a short lateral, versus some of the laterals that are almost twice as long.

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Paul Sankey, Wolfe Research - Analyst [38]

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Would you put that down to technology or acreage? Is there any way of -- I know it's a very simplistic question for a very complicated --

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Bill Thomas, EOG Resources Inc - Chairman & CEO [39]

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

And then the second part of it is identifying the specific targets in those sweet spots, and then executing the lateral in a large percentage of that really great rock, and then using our very advanced, very proprietary completion techniques. So it's a combination of all that technology.

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

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Paul Sankey, Wolfe Research - Analyst [40]

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Yes, understood. Could I just ask a follow-up as well? I think you're also somewhat unique in the way that you pay your staff. How does it -- in a sense, like the Company could think if you were returns-focused. Why would you -- I'm trying to get around to the idea that you're still incentivized to grow. But if you could just remind us how the staff payment through returns works, and you how that affects your strategy? And I'll leave it there, thanks.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [41]

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

Number two is how you meet your volume target. So volume growth is second, and returns are first. And then number three is how well you're setting yourself up for the future. So of course, we have a very strong culture of generating new inventory and better inventory all the time, and it all ties together. If you invest your money and you get a very high rate of return, you're going to grow your volumes exactly at the same time. So it all fits, and it's very focused.

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Paul Sankey, Wolfe Research - Analyst [42]

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

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Bill Thomas, EOG Resources Inc - Chairman & CEO [43]

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Well, I would agree. I think it's just a culture that's been in the Company for decades, and it just keeps getting better every year.

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Paul Sankey, Wolfe Research - Analyst [44]

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Thank you then.

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Operator [45]

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

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John Abbott, BofA Merrill Lynch - Analyst [46]

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Good morning, this is John Abbott speaking on behalf of Doug Leggate. We appreciate you taking our questions. Our first question relates to 2017 activity levels. How do you see the pace of completions throughout the course of the year? And then our follow-up would be -- it looks like you exit 2017 with significant momentum. Could you provide an early look at the exit rate for the year, and a preliminary view for 2018? Thank you.

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Bill Thomas, EOG Resources Inc - Chairman & CEO [47]

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

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

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Gary Thomas, EOG Resources Inc - President & COO [48]

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John, we've got our completion schedule pretty well-balanced each quarter through the year. And as I mentioned earlier, we had maybe a little slow start, as far as just to ramp up the rigs. And we also mentioned that once we take our rigs up, it's two to three months before you really start to see production from each of those rigs. So we do have a ramp from first quarter through 2017.

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John Abbott, BofA Merrill Lynch - Analyst [49]

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We appreciate it. Thank you.

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Operator [50]

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We'll go to Mike Scialla with Stifel Financial.

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Mike Scialla, Stifel Nicolaus - Analyst [51]

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Good morning, guys. Looking at your 2017 CapEx increase over 2016, doesn't look proportional to the number of wells. I think the CapEx is up over 40%, number of wells is about 7%. I know you had the benefit of completing some DUCs in 2016, and you alluded to this earlier, but I think a lot of that is due to longer laterals in 2017. So one, is that fair? And then two, if it is, do you have an average lateral length for the 2017 wells versus 2016?

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Bill Thomas, EOG Resources Inc - Chairman & CEO [52]

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Mike, the reason that the CapEx is going up -- several reasons. Number one is, the DUCs, as you mentioned, we had a benefit there. The well is already drilled. We drill more wells this year than last year. The wells are much better this year, due to the technology and the higher shift of premium.

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

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Mike Scialla, Stifel Nicolaus - Analyst [53]

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Okay. Any sense of the lateral length 2017 versus 2016?

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Gary Thomas, EOG Resources Inc - President & COO [54]

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It's up about 20%. And as you say there, Mike, that's a part of our increase. But the big part is just the increased drilling, since we had so many DUCs in 2016. We had a little bit more --

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Mike Scialla, Stifel Nicolaus - Analyst [55]

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Okay. I wanted to follow up on the Austin Chalk. Tim made some comments on that. Those wells do look really strong. Can you say where the 14 wells are located that you've drilled so far? Are they all in the Karnes Trough, or is it spread across your Eagle Ford acreage?

I know you want to see the results from this year's drilling program before you start talking about resource potential, but just wanted to get any sort of sense on how much of that Eagle Ford acreage could be prospective? Are we talking maybe up to half, or is that way too optimistic?

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David Trice, EOG Resources Inc - EVP of Exploration and Production [56]

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This is David. On the Austin Chalk, that's really what we're focused on right now, is delineating the play. So the 14 wells that you mentioned, those are really across the play. And so we continue to evaluate that. For encouragement we saw from 2016, we're going to up that this next year in 2017 to 25 wells, and we'll do the same. We'll be testing some spacing patterns and then stepping out, and seeing what the prospectivity is across the entire position. But we just want a little more time with the data.

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Mike Scialla, Stifel Nicolaus - Analyst [57]

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

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David Trice, EOG Resources Inc - EVP of Exploration and Production [58]

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

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Mike Scialla, Stifel Nicolaus - Analyst [59]

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Okay. Thanks, David.

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Operator [60]

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

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Bill Thomas, EOG Resources Inc - Chairman & CEO [61]

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

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Operator [62]

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