EOG Resources Inc (EOG) 2018 Q1 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources First Quarter 2018 Earnings Conference Call.

As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Thank you, and good morning. Thanks for joining us. 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 reconciliations for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

Some of the reserve estimates on this conference call may include estimated potential reserves not necessarily calculated in accordance with the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our earnings press release issued yesterday.

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; and David Streit, VP Investors and Public Relations.

This morning, we'll discuss the following topics in the following order. Bill Thomas will review our corporate strategy and cash flow and priorities. I'll cover our capital structure and dividend outlook. Billy Helms will cover first quarter operating and financial highlights. And Ezra Yacob, Lance Terveen and David Trice will review asset-level results and marketing developments across our most active plays. Then Bill will provide concluding remarks.

Here's Bill Thomas.

Thanks, Tim. Good morning, everyone. EOG is a disciplined, high-return, organic growth company. Delivering high returns and strong growth is a rare combination not often found in any industry. With our low-cost organic exploration expertise, the company is currently developing 9 premium geologic plays across 6 basins in North America. The power of our premium-only drilling strategy is reflected in our first quarter performance. We earned a company record direct after-tax rate of return of 150% on $1.5 billion of total invested capital. The ability of EOG to generate 150% direct after-tax rate of return on that much capital in 1 quarter is remarkable compared to any standard.

Strong execution delivered volumes on the high end of our forecast and most of our operating costs came in below targeted ranges. We're well on our way to executing our 2018 plan that will deliver 18% oil growth and generate over $1.5 billion of free cash flow at $60 oil. We believe disciplined reinvestment of cash flow in high rate-of-return drilling is fundamental to creating significant long-term value. We've been very consistent and clear about this priority for our cash flow. We believe it is by far the most shareholder-friendly decision we can make. Disciplined investment in premium oils, defined as having strong returns at $40 oil, allows EOG to deliver strong oil growth with free cash flow at $50 oil and substantial free cash flow at $60 oil.

Along with reinvesting in high-return wells, we've outlined the following priorities for utilization of free cash flow. First, an impeccable balance sheet is fundamental to a commodity-exposed business. Having low debt strengthens the sustainability of our dividend and maintains our investment flexibility through the volatility of the commodity price cycle. Concerning flexibility, let me be clear on one point: We have no interest in extensive corporate M&A in any commodity price environment. EOG is an organic exploration company with the ability to continually add premium drilling through low-cost organic leasing and low-cost tactical property additions. And it's important to emphasize here that our premium hurdle rate applies across the board to everything we do. We have set a target to reduce total debt outstanding by $3 billion over the next several years. Tim Driggers will provide more detail on our debt reduction plans in a moment.

Second, we'll target dividend growth above our historical 19% compounded annual rate. We have a long history of delivering a dividend that we can maintain throughout the volatility of the commodity price life cycle. The result has been 17 increases in 19 years without a single dividend cut. We believe our prospects for cash flow growth will support strong dividend growth that is sustainable through price cycles.

In summary, EOG is a high-return organic growth company. Our ability to grow production and cash flow, produce double-digit ROCE and deliver cash returns to shareholders through strong dividend growth simultaneously is rare. That's a truly unique combination not just in the E&P industry, but in any industry. It is perfectly aligned with our ultimate goal, to create significant shareholder value.

I'll now turn it over to Tim Driggers for more on our capital structure and dividend.

Thanks, Bill. Over the last 3 years, we have reset the company to thrive at much lower oil and gas prices. As a result, we are uniquely positioned to generate a meaningful amount of free cash flow. EOG now has the opportunity to take the next steps to further strengthen the balance sheet and increase the rate of dividend growth. Currently, our balance sheet is strong at 28% leverage and $6.4 billion of total debt. Our target is to further reduce our total debt by $3 billion. The $3 billion of debt reduction is a prudent target in a cyclical capital-intensive business. We expect to achieve that target over the next several years by repaying bonds as they mature using cash generated from operations. This measured pace of debt reduction provides room to fund strong dividend growth. We were pleased to make it through the last downturn without cutting the dividend and without a dilutive equity offering to shore up the balance sheet. Whatever future commitments EOG makes must be sustainable for the long term. This means we must consider the strength of our balance sheet and sustainability of the dividend through low commodity price scenarios, not just against the rising level of oil prices that exists today.

The dividend is an important element of EOG's financial strategy. We've increased the dividend at a compounded annual rate of 19% since 1999. With a lower breakeven cost structure and a strong balance sheet, we are now targeting a dividend growth rate that exceeds the 19% historical rate. Our dividend growth strategy signals our confidence in the future profitability of the company, provides shareholders with a tangible form of return on their investment, and imparts a measure of discipline on the organization.

EOG creates shareholder value through operations and not financial engineering. A strong financial position is a competitive advantage as we seek to sustain our performance through the volatility of the commodity price cycle. The company can do this with a straightforward financial structure and an impeccable balance sheet. This will leave EOG positioned to keep its financial commitments in future downturns, including sustaining a more ambitious dividend.

Up next to provide details on our operational performance is Billy Helms.

Thanks, Tim. 2018 is all about maintaining our disciplined capital growth program. In the first quarter, we delivered at or above our production targets and have laid the groundwork to deliver our forecasted well cost targets. We are maintaining our full year capital guidance of $5.4 billion to $5.8 billion, growing oil production 18%, growing total production 16%, reducing well cost 5%, reducing debt, reducing free cash flow and most importantly, delivering double-digit return on capital employed.

There are a number of operational accomplishments from the first quarter I'd like to highlight. We increased activity early in the year and are now operating about 40 rigs across 6 basins. We still expect to average about 39 rigs for the year. Our operating teams in each area are quickly moving the new rigs in our fleet up the learning curve to deliver sustainable efficiency improvements that will yield benefits the rest of the year. In our larger development programs, we moved to larger packages of wells with longer laterals, completing more than 150 net wells with over 30 of those brought to sales in the last week of the quarter. About 2/3 of the wells in the Delaware Basin were in packages of 6 wells or more. In Eagle Ford, over half the wells were in packages of 5 wells or more. In the coming quarters, we will be completing several 6- to 10-well packages in both plays, which will improve our operational efficiency and maximize the net present value of our acreage. Initiating this development from larger multi-well packages results in a production profile that is more weighted to the second half of the year, as can be seen in our full year production guidance. As a result, we anticipate that our growth will be more heavily weighted to the third quarter than any other quarter this year.

We improved our completions efficiency, increased the number of wells completed per month by each completion crew. This allows us the option to consider reducing the pressure pumping equipment utilized this year.

And finally, we continue to meaningfully lower sand, water, flowback and facility cost. As a result of the progress we made during the first quarter, we remain confident that we will be able to deliver the targeted 5% well cost reductions we discussed at our last earnings call. Controlling cost is key to the successful commodity business. Year after year, we have been able to consistently control cost, and that is true whether we are at the top or bottom of the cycle.

There are a few good reasons for that. First, we have a unique benefit of having worked in multiple basins through their life cycles for almost 20 years. That experience provides valuable foresight. We take our very forward-looking growth plan and analyze the market to anticipate when and where we might see tightness from the services industry, takeaway, relative demand for oil, gas and NGLs and many other factors. These hard-earned lessons over the past 2 decades have given us the experience to quickly adjust our plans to the ever-changing conditions in the industry.

Second, the scale of our operations provides several pricing benefits as well as efficiency opportunities. The more wells we drill in any given area, the better we get at drilling those wells. Drilling and completing hundreds of wells over and over is how our talented engineers generate ideas for innovation. Scale also allows us to invest time and money into unbundling services and, if advantageous, bringing those efforts in-house. That includes anything from building our own water sourcing and gathering infrastructure to self-sourcing or procuring raw materials directly from the manufacturer. Our sales sourcing capabilities started with sand and have now grown to include tubulars, chemicals and drilling mud.

Third, we run a conservative business, both operationally and financially. Operationally, we avoid going so fast that we start to degrade our return profile by paying too much for services or allowing ourselves to get inefficient. Financially, we're committed to a strong balance sheet. Low debt combined with scale allows us to commit to services when others in the industry may be hesitant to do so. This is exactly what occurred last year when we were able to lock in completion spreads at a low cost as one of the few E&Ps willing to commit capital.

Looking ahead to 2019. We'll continue to be -- to opportunistically lock-in services by proactive engagement with our suppliers. We'll also continue to optimize well package size and increase the use of multi-well pads and zipper fracs, which will speed operations and well transitions. Finally, we see more opportunity to optimize our sand program and accelerate water reuse to further reduce cost. We have line of sight into these and many more areas to reduce cost and improve efficiencies well into 2019.

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

Thanks, Billy. The Eagle Ford continues to prove itself quarter-after-quarter as a world-class oil play and EOG's premier asset. In the first quarter, we brought 72 wells online with average spacing of about 300 feet and average payout of 7 months. We believe this operational and financial performance in the Eagle Ford is unmatched in the industry. We increased our rig count to 11 in the first quarter and realized a 5% increase in footage drilled per day accompanied by a 5% decrease in cost per foot. Not to be outdone, our completions team also increased operational efficiencies and is forecasting further cost savings with the addition of local sand sources.

Wells on the Eastern Eagle Ford acreage position averaged 1,810 barrels of oil equivalent per day for the first 30 days online, and wells on our Western acreage averaged 1,375 barrels of oil equivalent per day for the first 30 days. While the wells on our Western acreage position have lower initial rates, the combination of less faulting and our contiguous acreage position allows for consistently longer laterals than in the East, which drives operational efficiencies. Therefore, the wells across our entire 520,000 net acres in the oil window are all equally competitive on a rate-of-return basis.

The Eagle Ford is a key contributor to the flexibility of our diverse portfolio of assets, providing the company many options. We modeled several growth forecasts assuming no productivity improvements or cost reductions. If we chose to pursue more growth in the Eagle Ford, our current inventory of well locations and large acreage position would support more than 10 years of development. No North American basin compares with the Eagle Ford for low transportation cost and access to Gulf Coast pricing. Currently, 85% of our oil production in this basin flows through EOG-owned gathering systems, and all of our oil from the Eagle Ford receives LLS prices, which averaged about a $4 premium to WTI during the first quarter. This basin continues to deliver consistently outstanding results. Furthermore, we are still reducing costs through internally designed innovative technology advances. Therefore, we are convinced that Eagle Ford still has significant upside even as it enters its ninth year of development.

In our Austin Chalk play, we continue to drill some of the most prolific and highest-return wells in the company. The first quarter development program earned over 150% direct after-tax rate of return. The average 30-day production from the 8 net wells brought online during the first quarter was 2,750 barrels of oil equivalents per day. The Austin Chalk target lies just above the Eagle Ford in our South Texas acreage, and as such, benefits from our operational efficiencies and knowledge of the area. Production from Austin Chalk wells also benefits from lower operating costs and Gulf Coast pricing due to our existing infrastructure. We're on track to complete 25 net wells in 2018.

In the Delaware Basin, our results have been just as strong. In the Wolfcamp, the 58 wells brought to sales in the first quarter averaged 1,925 barrels of oil equivalents per day for the first 30 days and delivered less than a $9 per barrel of oil equivalent direct finding and development cost. The 9 wells brought online in the Bone Springs delivered solid results, producing an average of 1,645 barrels of oil equivalents per day in their first 30 days. And in the Leonard, we brought on 3 wells to sales. The average 30-day rates were well over 2,400 barrels of oil equivalents per day on 4,300-foot laterals. That production per foot rivals well performance typically seen from our Austin Chalk wells in South Texas.

One of our constant studies across all basins is determining the most efficient number of wells to drill and complete together as a package. This work is essential to maximize the recovery and NPV of the whole asset and is particularly important for a complex basin of stacked pay, such as the Delaware Basin. Each play has an optimum number of wells that both captures operational efficiencies and minimizes parent-child productivity effects without sacrificing net present value to either long cycle times or large production facilities needed to handle high initial volumes.

During the first quarter, we averaged 4 wells per package versus 2 last year. We expect to further increase the average to 5 by year-end. Larger well packages necessitate a larger inventory of wells needed to stay ahead of our completion crews, so much of January was spent ramping up drilling activity and increasing inventory to prepare for our completions scheduled this year. We increased our rig fleet 20%, exiting the quarter operating 20 rigs in the basin. And we are realizing the increased efficiencies of larger well packages on both the drilling and completion side.

Our Delaware Basin team has been diligently optimizing our completions operations and has achieved a 24% increase in stages per month per completion crew, and we are beginning to realize cost savings associated with increased use of both local sand and recycled produced water in our completions. The State Magellan 7 22H-28H wells, located in the over-pressured Wolfcamp oil window of Loving County, Texas, illustrate our achievements drilling well packages. This 500-foot spaced, 7-well package took approximately 65 days from initial spud to first sales. The average 30-day rates for these 4,700-foot stimulated laterals were 2,200 barrels of oil equivalents per day. We completed 157 total stages on this group of wells and pumped more than 80 million pounds of sand over the course of 14 days. Furthermore, 100% of the water used during the stimulations was sourced from reused produced water. The outstanding operations performance and well productivity delivered an average well payout of 5.5 months.

Next up is Lance Terveen to discuss our takeaway positioning.

Thank you, Ezra. I'd like to bring everyone up to speed since our last call on EOG's pricing mix for our crude oil and natural gas sales in the Permian, infrastructure build-out and takeaway positioning.

Our 2018 Delaware Basin oil and natural gas production will have minimal exposure to in-basin pricing. Only 25% of our in-basin crude production is exposed to Midland pricing. This translates to less than 10% exposure for EOG's total U.S. oil production. Furthermore, we supplemented physical capacity with additional price protection with Mid-Cush Basis Swaps. On the natural gas side, less than 20% of in-basin production is exposed to Waha Hub pricing, which translates to about 5% exposure when viewed on a total U.S. production basis.

We are in similar shape for our Delaware Basin production next year. Only 20% of crude production is exposed to Midland pricing and about 20% of natural gas production is exposed to Waha, which is manageable risk when viewed on a total U.S. production basis. So we are in great shape, and historically, we've always been able to consistently anticipate the infrastructure needed to support growth. Similar to our past experiences in the Barnett, Bakken and Eagle Ford, an early-mover strategy in the Delaware Basin is paying off. We've successfully diversified our marketing options with physical firm takeaway to protect flow assurance and benefit from higher price realizations for both crude and natural gas sales. Please see slide 18 of our investor presentation for a history of our industry-leading oil price realizations.

On our last earnings call, we referenced a new Conan oil gathering system and terminal. This system has been at work since 2016 and was placed into service on schedule during the first quarter of this year. Between the gathering system and short-haul dedicated truck offloads, we anticipate $50 million-plus in savings per year. Our goal by year-end is to have up to 80% of our production on the gathering system in our core areas, which will have the added benefit of freeing up trucking availability. In 2018, the oil terminal will have 4 market connections. Our fifth connection to a newly announced long-haul pipeline that will service the Houston, Corpus Christi and export markets is planned to be in service in late 2019.

On gas takeaway, our early-mover strategy allowed us to lock up transportation capacity at well below today's market rates. Also, in lockstep with our residue gas transportation capacity, we secured sufficient plant processing with each plant location strategically fitting with the footprint of our gas gathering system throughout our acreage position. At each of the centralized hubs along our gathering system, we have the option to deliver our gas top to up to 4 different processing plants. This gives EOG the ability to source our gas to multiple plants but also feed our takeaway capacity away from the Permian Basin. We're confident our early-mover strategy will allow us to move forward with our development and growth plan in the Delaware Basin and realize attractive netbacks, bridging us to 2020, when adequate infrastructure will be in place to service the broader basin.

Here's David Trice to review the progress we've made in the Rockies and Midcontinent.

Thanks, Lance. Well costs continue to drop for our Rockies plays. The efficiency gains we are making in both the Powder River Basin and DJ Basin are astounding, particularly considering they are in addition to the incredible progress made last year. In just 1 quarter, we have reached and beat well cost targets in some of our Rockies plays. Tremendous progress has been made in both drilling and completions to reduce days on location that translate directly to cost savings.

Overall, drilling days are down 70% since the beginning of the downturn in 2014 for the DJ, Powder River Basin and Williston Basin. This is a powerful testament to the great sustainable efficiency gains our teams have made during the last several years. Recently, normalized spud-to-TD drilling days in the Powder River Basin are down from 9 days on average in 2017 to about 7.5 for the first quarter of 2018. During that time, completion efficiencies have more than kept pace with drilling. Stages per day and footage per day are up a whopping 50% in the first quarter versus the 2017 average. This includes a record day in the DJ Basin of 26 stages pumped on a 4-well pad in a single 24-hour period. That record-breaking pad averaged 21 stages a day for the entire job. Our cost performance in the DJ Basin Codell has set the bar for the rest of the company.

Some notable wells that we highlighted in last night's press release are the 3-well Flatbow package that IP-ed at over 1,300 barrels of oil equivalent per day from 3,900-foot laterals and averaged just $2.9 million per well. We also turned on a 4-well 9,500-foot big sandy package that averaged over 1,300 barrels a day equivalent per well with a well cost of $3.5 million per well. These 7 low-cost Rockies wells are earning an average direct rate of return of over 250%. Our cost structure in the Rockies and Bakken gives us a competitive advantage and creates significant upside potential to add to our premium inventory in the future.

The Anadarko Basin and Woodford Oil Window is the latest addition to our diverse portfolio of premium oil assets. We are increasing activity and building working inventory to support our 25 net well program this year. Our latest well to come online is the Terri 1621 #1H, which is a 2-mile lateral that delivered over 1,100 barrels of oil per day in its first 30 days.

We currently have 4 rigs running in the Woodford, and as we move into development mode in the basin, we expect to have a number of new well results to share in the future. We will also be testing multiple spacing patterns in order to determine the optimal spacing to maximize NPV per development unit. We are optimistic the Woodford play has upside potential for inventory additions and certainly returns as we increase efficiencies and reduce cost. Plays like the Woodford enhance the diversity of our portfolio and provide us flexibility to consistently deliver high-return production growth.

Now I'll turn it back over to Bill.

Thanks, David. I have a few closing thoughts. Number one, our first quarter results have positioned EOG to have record-breaking direct rates of return on capital investments in 2018. We are going to remain disciplined and stay focused on improving returns going forward. Number two, we're on track to continue reducing both operating cost and well costs. Number three, with our diversified assets, forward-looking marketing arrangements and advanced infrastructure planning, we are in excellent position to avoid any significant takeaway issues or negative product price differentials in the Permian or in any of our other active plays. Number four, with 2 decades of horizontal experience and technology advancements behind us, we are developing sweet-spot acreage positions with our latest precision targeting techniques and determining optimal spacing patterns to produce industry-leading well results and per-acre net present value. And finally, EOG has never been in a better position to deliver long-term shareholder value. We have the largest and highest-quality drilling inventory in the U.S. and it continues to grow much faster than we drill it. We are a low-cost leader today, and we will continue to lower cost as we go forward.

We are delivering record-setting returns on capital invested, improving corporate ROCE along with strong production growth and substantial free cash flow. EOG is a high-return organic growth company, delivering sustainable long-term shareholder value.

Thanks for listening. And now we'll go to Q&A.

(Operator Instructions) And our first question, we'll hear from Arun Jayaram with JPMorgan.

Bill, no one's going to fault you for wanting to reduce your debt or increase your dividends over time, but I did want to ask you one question. As you execute your premium drilling strategy, your returns on capital employed are now moving into the double digits. And I was wondering if you could talk about weighing buyback above your cost of capital versus reducing debt, what looks to be in the 6% to 7% range.

Arun, we're committed to doing what's right for the shareholders. Our senior management team and our board are significant EOG shareholders and we're aligned with investors, and we're constantly evaluating what's best to create long-term shareholder value. Currently, with the improving commodity prices, we believe investing in high returns and reducing our debt and strong sustainable dividend growth are the best ways to create long-term shareholder value. So at the moment, we're very confident in that plan, and we believe that, that will be the best avenue to create shareholder value.

Great, great. And just the reduction in debt. Does that suggest maybe keeping some dry powder for -- as you execute your exploration drilling program or to look at potentially other opportunities like you did with the Yates package?

Arun, we don't plan any corporate M&As. That's just not one of our game plans. We -- as you know, we're a very organic company. We've got a lot of confidence in our organic exploration effort, and corporate M&As are just something that would be really not in our game plan at this time.

And next we'll move to Bob Morris with Citi.

A bit of a follow-up here. Billy, you've always said that you would spend 100% of your cash flow unless you saw some sharp degradation in efficiencies, and obviously, $1.5 billion of excess cash flow is quite a significant amount. But you're starting out the year at what you plan to average for the full year on the rig count. So what precludes you from stepping up activity or adding some rigs in some of these key areas given the sort of returns you're seeing here as we move through the year?

Yes, Bob, this is Billy Helms. First of all, we remain committed to stay within our capital guidance. We're very much on track with our plan as we laid it out. It's -- actually our rate of capital spend is directly in line with what we laid out at the start of the year. And we've already talked about the benefits of moving to these larger packages of wells. And as a result, the front end of the year is more loaded towards capital spend with the production more weighted towards the back half of the year. So at this moment, yes, we're very pleased with where we are headed, and we don't really anticipate increasing activity above where we currently are. We're still guiding towards that average rig count of 39 and staying within our capital guidance.

And we'll hear from Irene Haas with Imperial Capital.

So I have a question for the Eagle Ford trend, which you guys definitely was the first mover, and has been going on 9 years. I was wondering, what is the organic growth rate for this trend in 2018? And also regarding the Austin Chalk, I want to understand what are the key gating factors that would lead you to fully develop this concept. And when would the Chalk be a meaningful contributor to your Eagle Ford trend growth?

Yes, Irene, this is Ezra Yacob. And I don't think we're going to spend any time today guiding to the direct growth on that asset right now. But what I will say about the Eagle Ford is, the upside we see there is -- just involves our continued progression of integrating the data that we've collected over the development cycle that we've had there. We continue to integrate both high-graded geologic mapping, completions data into the -- back into our geologic model, and it helps kind of drive our precision targeting as we develop even finer scale and high-graded targets. And then also, with respect to the Austin Chalk, we've gone a little bit slow making announcements on that because geologically, it is a bit more complex than the Eagle Ford. I would say that it already is contributing in a pretty good way to not only our returns, but also, in 2017, both the Eagle Ford and Austin Chalk actually showed just a little bit of growth year-over-year. And so we're happy with our pace of development there in Austin Chalk. And when we have more information on that, we're a little more comfortable with it, we'll provide greater detail.

Okay. May I ask one more question? So are you generating organic growth out of the Eagle Ford and Austin Chalk trend in 2018?

Yes, Irene. Without getting into specific details, we do plan to grow that asset this year. And we'll be doing that a pace...

Okay, thank you. sorry?

I was just going to finish up and say, we'll be doing that at a pace commensurate with where we can go ahead and continue to integrate our learnings and do that really with a focus on returns first.

And next, we'll move on to Brian Singer with Goldman Sachs.

Wanted to start on the well cost front. How can we define the more secular versus timing impact of your ability to use your scale to gain preferred services pricing exposure? Specifically, if you're not seeing the inflation in cost in 2018 because you locked in services cost early, what level of inflation would we see in 2019 when you need to recontract? Or is there is some -- is there a quantifiable secular advantage?

Yes, Brian, this is Billy Helms. What we can give you is -- it's a little bit early to talk about guiding for 2019. So let me give you a little bit of color on where we are for 2018. First of all, we -- as you're aware, we locked in about 60% of our well cost with the services we have locked in so far with drilling -- really preferred providers on drilling -- on the drilling side and the completion side. And we self-source quite a bit of that too, about 25% of well cost is self-sourced. So what -- the progress we're making and, I guess, the confidence we would have in lowering our well cost in 2018, we talked a little bit about how we're lowering cost in each one of the plays. I think the Permian, we added quite a few rigs, and so we're starting to see the operational performance on those rigs get to the metrics that we like to see in our rig fleet. Completions are already down about 2.3% for the first part of the year. On the Eagle Ford, our drilling cost is already down about 5% and the completions are expected to follow. And then we've made tremendous progress in the Rockies, both on the drilling and completion side, and lowering our well cost anywhere between 4% and 5%. So I think overall, we're very pleased with where we're headed, and we have a long history -- and just speaking of 2019 again, we have a long history each year. As we go into the year, we anticipate what the trends are going to be, and we get ahead of them and try to work with our preferred providers to lock up some services for the ongoing -- the upcoming year. And I expect 2019 will be done the same way. It's a little bit early to really guide on where we'll be, but we're very confident that we'll be able to maintain our cost advantages as we go into the next year.

Great. And my follow-up goes back to the earlier discussion on the Eagle Ford, and maybe trying to tie Bob and Irene's questions together. What would you need to see either in capital availability, rate of return or confidence in that precision targeting to allocate more capital to the Eagle Ford? And do you need to exhaust your financial goals of reducing debt by $3 billion and delivering on that above 19% dividend growth before you would do that?

Brian, yes, this is Ezra again. Well, kind of like I reiterated, I think we're happy with our plan and we're happy with where we're at kind of executing on it, and we're on track with it. As far as adding additional capital or redirecting capital to the Eagle Ford, I think without guiding into the future years, we have definitely run through a number of different forecast growth models, like I talked about in the opening statements, where, if we choose to actually grow more aggressively there, we can certainly do that. And we have the inventory and acreage position to do that for over 10 years at high returns. But as far as doing it within the year, I think it's safe to say that we're pretty happy with where we're at with our balanced approach across multiple basins to achieve our CapEx and volume growth goals for this year.

And we'll move on to Doug Leggate with Bank of America.

Bill, the -- I wonder if you'll go back to the dividend policy and capital discipline, share buyback discussion -- or not so much the last part, but I'm just -- looking at the dividend policy going forward, what do you see as the competitive metrics? So what's kind of the endgame you're trying to get to there? And I just want to be clear on the $60 -- $50 to $60 range you gave, I guess, a year-or-so ago. Is the $60 as a budget a kind of hard stop, so you should think about anything beyond that as going towards the balance sheet? And if that is the case, what happens longer term as it relates to incremental, let's call it, windfall cash flows?

Doug, I don't think we have some hurdle rate on the oil price. We've really reset the company to be very successful even in moderate prices going forward. And so the company is in a fantastic position now to make, I think, a strong statement to say that we're in a position to more aggressively grow our dividend than we ever have in the past. And we believe that our dividend is sustainable through the commodity cycles. And so the company is in a fantastic position to both systematically reduce our debt and to grow our dividend very aggressively and sustainably in most commodity price situations.

No question on the reset. I appreciate you tolerating another question on that issue. My follow-up is really on inventory. And this is a -- I'm not challenging the discipline of the $40 hurdle for premium locations. But obviously, some in the market might have different view as to what the sustainable oil price is. And the question is really about inventory relative to your growing pace. If we had to run that $45 or $50 number as the threshold for premium inventory, how would it change over the disclosure you've given so far? Does it go up 10% or does it double?

I think first of all, we don't have any plans on changing our criteria. We're going to stick with $40 oil and $2.50 flat. That needs to be really clear going forward, that's a fundamental thing with EOG. If you looked at our entire inventory, which is quite substantial, I would say pretty much all of it would be 30% or better rate of return at $50. So it's a very high-quality total inventory. It would be -- the inventory that we have in the company that's nonpremium at $40 would be, I would say, equal to or better than the average inventory of the whole industry. So it's a very high-quality inventory set. And we have a lot of confidence that we'll continue to make improvements on the non-premium inventory and bring it to a level to where it will classify as premium at $40 oil. So we got, again, a very sustainable cost reduction. It's not just a 1-year thing. It's a very consistent cultural attribute of the company, and then we have a tremendous ability to continue to improve well productivity at the same time. So our goal is to convert a lot of that premium inventory as we go forward -- nonpremium inventory into premium inventory as we go forward.

And we'll move on to Scott Hanold with RBC Capital Markets.

Could I ask another question on your increasing that long-term -- the dividend rate versus the long-term rate? Is there a particular yield that, when you guys step back, you would like to be at? It looks like you guys are running somewhere sub-1% right now and some of your larger -- the large peers are in that 1.5% kind of range. Is there a target rate you'd like to see EOG at?

No, Scott. We don't have a specific target other than just to say that on a percent increase, on a yearly basis, we want to be above our historical average of 19% CAGR. So that's where we want to guide as we go forward. And we certainly, as I said before, we've got the ability to do that at relatively moderate oil prices and sustain that going forward.

Okay, appreciate that. And a little bit more on -- it seems like you're definitely more front-end CapEx weighted, as you said, and in the back half see some of that production. Can you talk about the cycle times that some of these larger premium pads have? It looks like you average about 4 in the first quarter, moving to 5. But can you discuss maybe what those cycle times look like as you move from 2 to 4 to 5?

Yes, Scott, this is Billy Helms. The cycle times, of course, vary by play. So in the Eagle Ford, there is a much shorter cycle time than say the Delaware Basin, just strictly because the drilling times are much longer. And it also depends on the size of the pads. So certainly, a 10-well pad might be a lot longer to cycle time than a 6-well package. And then it also depends on how many rigs and frac fleets we put on each package. So it's hard to give you directionally a certain number other than to say, it takes several months to start drilling a pad or a package of wells and bring that whole package to production. And as a result, it results in some lumpy nature of both capital spend and production. And that's why you see the production growth vary by quarter. And that's also why as we entered the year, we obviously had to build some inventory to be able to execute this plan, so the capital guidance is more weighted towards the front of the year than the second part of the year. And that's just the nature of the -- the lumpy nature of this development.

Does that smooth out in 2019 as you sort of catch-up with that inventory?

Yes. I think you'll still see a lumpiness to the overall production growth. But you won't see the -- I'd say, the delay we exhibited in the first quarter on a go-forward basis. You'll see it more just growth quarter-over-quarter as we move through the future.

And next we'll move to Leo Mariani with NatAlliance Securities.

I was hoping you could address the Austin Chalk a little bit more. I know that you said you're not prepared to make extensive comments. But I'm just trying to get a sense of the inventory there. I mean, it sounds like this is one of the best-returning plays you guys have. Just curious, I mean, is this kind of a couple of years of inventory? Or is there a similar 10 years like the Eagle Ford?

Yes, Leo, this is Ezra Yacob again. It's just really still pretty early in the Austin Chalk. We are still doing a lot of testing on our well spacing, trying to determine kind of the optimal spacing, how many precision targets we have in there. We've talked about in the past that it is different than the historical Austin Chalk play. It is a matrix -- contributing kind of a matrix [drive] play. And so it's not quite as straightforward to use a lot of those historical learnings. What we're -- the way we're developing it is different and it's unique. I'd say the initial production looked good. I know it seems like we put a lot of wells on, but we'd like to be confident before we really come out with any detailed numbers on that. And like I said, when we have a little more detail on that, we'll certainly talk about it.

Okay, that's helpful. And I guess, I just wanted to follow up on the Eagle Ford. You guys talked about some of the differing production rates you saw in the first quarter on the Eastern wells versus the Western wells, but then cited that returns are pretty similar. Just curious, does that kind of imply that maybe your well cost in the West are lower than the East? What can you sort of say about that?

Yes, Leo, it's Ezra again. I think you hit the nail on the head there. The cost per foot -- as I tried to highlight in those opening remarks, the contiguous nature of the Western Eagle Ford acreage and a little bit less faulting out there allows us the opportunity to drill larger -- longer wells and larger packages. It's a little bit less pressure and less shallow too, so in general, the costs are a little bit cheaper there. In the Eastern Eagle Ford side of our acreage position though, we usually have wells with a little bit more robust rates, a little bit bigger wells, but it is a little bit more challenging drilling over there. It's a little bit deeper, a little bit extra pressure. And then in general, the well lengths tend to be just a little bit shorter due to both the layout of specific leases over there, but then also, there's an increase in the faulting off to that Eastern side.

Okay, that's helpful. And I guess just a quick question on your dividend here. You talked about increases in the future. Should we expect to see an increase here in 2018? Or are you more talking about evaluate that for 2019 and beyond?

We don't have any specifics on timing. Our board evaluates the business environment every quarter, and -- concerning the dividend. And I think what we're saying is we believe EOG is in the best shape we've ever been for a sustainable, more aggressive dividend growth. So our board is eager to return cash to shareholders with a strong dividend growth.

And next we'll move to Charles Meade with Johnson Rice.

You covered this a little bit already in your comments in the Q&A, but I just want to go back to the comments you made in your opening when you said you had no interest in corporate M&A. And that's certainly been the pattern for you guys, with the one prominent exception of the Yates deal. And [Billy and Ron], that was really a brilliant deal for you guys, but I'm trying to understand a little bit more, are you -- is the Yates deal the exception that's not likely to come along again? Or should we be interpreting that you see the market or the opportunities differently from the way you did at that time?

I think, Charles, what we are saying is that we've got extreme confidence in our ability to organically add new, high potential at very low cost through our exploration efforts. In general, I think this year, we have a very robust exploration effort ongoing. And we've acquired a significant amount of low-cost acreage in multiple plays, and we're testing numerous new plays with exploration or step-out drilling this year. And so our organic machine is really in high gear, and we have a lot of confidence in it. And we believe we can acquire significant, hopefully even better drilling potential than we currently have through that process at very low costs.

And we'll move on to David Heikkinen with Heikkinen Energy Advisors.

We appreciated the details that you put on Slide 29 around your diversified marketing options. Can you talk more specifically about firm sales, firm transportations, financial hedges and then the balance of avoiding those long-term contracts that I know EOG doesn't want?

Yes. Sure, David, this is Lance Terveen. Let me start and answer your last question there. When we talk about commitments, I'll tell you all of us in this room, we've seen the Barnett, the Haynesville, the Uinta. And so when we think about long-term commitments, it's really twofold. It's -- we want to have near-term flow assurance. And two, we just want to be very disciplined about any kind of long-term commitments. And what we think that does, when we can kind of have that first mover and we can identify where we need to identify transportation and access to get to markets, at that point, we really make good business decisions because a lot of folks are going to be waiting for new pipelines that are going to be starting up in late '19 and probably into 2020. But what happens when there is a lot of hype in especially a very active area like the Permian with 453 rigs running, it's just -- it's not a panic that comes in, but people are looking for capacity. So we want to get out in front of that like we've done and like what we've shown. So for us on the commitments, it's really just being very disciplined, have a balanced approach, get in front of it. And the second thing with that is, it allows you to have more discretionary volumes and it allows you to look at other projects and other things that can come available at even lower rates. So getting in front of that and having some of that near-term assurances really sets us up in the future to lock in other markets or also look at lower transportation costs.

Any specifics of splits as far as you think about that flow assurance of marketing agreements, either firm sales, firm transportation? Because you might have done these contracts or terms 2 years ago, 3 years ago. I'm just trying to get an idea of how you think about splitting marketing agreements, pipeline agreements, hedges, just in that kind of forward-looking process that go [into supplying '21].

Sure, sure. Again, it goes back to our experiences and what we've seen in other basins and as we've looked at making commitments and transportation commitments. So again, when we look at that, we look at kind of the forward forecast and where we think each of the basins might be growing, especially like a new emerging basin. So typically, we want to lock up anywhere from maybe 70% to 80% of that near term and leave kind of more available on the outer years. So really, with the crystal ball when we're looking at making the commitments, we try to protect more of kind of, call it, the first 3 years. And then if we need to make medium-term commitments, then those commitment volumes are a little smaller in the outer years. So that's kind of strategically how we think about the commitments, David.

And we'll move on to Jeffrey Campbell with Tuohy Brothers.

I just wanted to ask for a little bit color on the Woodford Oil. I noticed that you've added a rig and you drilled quite a long lateral there, which is usually a sign that you are more into development than into delineation. It just seems like this play has really accelerated in a reasonably short amount of time. So just kind of wanted check in on that.

Yes, Jeff, this is David Trice. On the Woodford, yes, we have picked up additional rigs there. We are running 4 rigs currently there. And what we're doing this year is, one, we're securing operatorship on a lot of these units. And then also we're doing several spacing tests there. So what we want to really focus on in the Woodford this year is we want to, like in our other plays, we want to really confirm the correct spacing so that we can be sure to maximize the NPV per section there.

And if I could just follow up on what you just said. What's your -- if you look at your position as a whole, what percentage of it can you operate now and what you are trying to get to?

Really, most of the 50,000 acres net that we show, we will be able to operate that. We have quite a few trades going on where we may not have the majority interest. And so we think at the end of the day, we'll be able to operate the entire position.

And next, we'll move to Bob Brackett with Bernstein Research.

I will follow up a bit on the Austin Chalk. If I divide the Austin Chalk into the Karnes Trough, into Louisiana and into everything else, where is your sense of how mature your understanding of those plays are right now? And where is the upside on each of those?

Yes, Bob, this is Ezra Yacob. And let me start with the Karnes Trough area down in the South Texas trend. Like I said, we brought to -- we brought to sale over the last year a number of wells. We're very happy with the initial rates on there. And again, it's a new concept on the play that we've been working over the last couple of years where we're basically applying our precision targeting, our petrophysical model in combination with our seismic attributes to upscale and model these precision targets that actually have matrix contribution. And then we're applying some of our high-density frac design, things that we've developed in these different basins or different unconventional plays basically to the Austin Chalk. And so we're really happy with it. I would say, where the upside resides down in South Texas is continuing to delineate targets, high grading those targets, and again, kind of the continued evolution of our frac designs. It is the chalk, so it does -- each of these plays that we're in, whether it's carbonate, siltstones, mud rocks, as you know, little tweaks on your completion design can make a big difference. And so the biggest upside I see with Austin Chalk is just that advances -- continue to evolution advances on our completions, delineating additional targets. And then in Louisiana, it's very early on that prospect. I think everyone knows that we've drilled a very successful Eagles Ranch well out there. We're very pleased with the initial results on there, and we'll provide further details on that on future calls.

And elsewhere, is the Austin Chalk trend, should we think of it working along the entire trend? Or do you need sort of local structures to help you out?

This is Ezra again, Bob. Yes, the way I'd follow-up with that is I'd say, there are definitely are going to be sweet spots. It's obviously a widespread play from Mexico all the way up around the Gulf Coast there. Just like any big regional unconventional play, there are going to be sweet spots in different parts of that area. There are different attributes geologically and geophysically, including structure as one of them that we're looking at to high-grade those areas. But any additional color than that, I'm not sure if we want to provide today.

And that will conclude today's question-and-answer session. At this time, I would like to turn the call back over to Mr. Bill Thomas for any additional or closing remarks.

In closing, I want to say thank you to every EOG employee for all of your great work. Our execution in the first quarter was outstanding. We are well on the way to the delivering the best investment returns in company history. EOG has never been in a better shape to deliver sustainable, long-term shareholder value. Thanks for listening, and thank you for your support.

And that will conclude today's call. We thank you for your participation.