Good day everyone, 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, 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 in EOG's SEC filings, 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, Investor and Public Relations. This morning, we'll discuss topics in the following order. Bill Thomas will review our corporate strategy and cash flow priorities. I'll cover our capital structure and dividend outlook. Billy Helms will cover first quarter operating and financial highlights. Ezra Yacob, Lance Terveen, and David Trice will review asset-level results and marketing developments across our most active plays. 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 nine premium geologic plays across six 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 one 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 are 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 and 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 wells, 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. 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. Timothy K. Driggers will provide more detail on our debt reduction plans in a moment. Second, we will 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 Timothy K. Driggers for more on our capital structure and dividend.
Thanks, Bill. Over the last three 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 the sustainability of the dividend through low commodity price scenarios, not just against the rising level oil prices that exist today. The dividend is an important element of EOG's financial strategy. We've increased the dividend, a compounded annual rate of 19% since 1999. With a lower break-even 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-$5.8 billion, growing oil production 18%, growing total production 16%, reducing well cost 5%, reducing debt, generating 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 six 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 two-thirds of the wells in the Delaware Basin were in packages of six wells or more. In the Eagle Ford, over half the wells were in packages of five 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. Finally, we continue to meaningfully lower sand, water, flow-back, 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 a successful commodity business.
Year after year, we have been able to consistently control cost, 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 two 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 everything from building our own water sourcing and gathering infrastructure to self-sourcing or procuring raw materials directly from the manufacturer. Our self-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 are 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 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 costs. We have line of sight into these and many more areas to reduce costs 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 seven 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 equivalents per day for the first 30 days online, and wells on our western acreage averaged 1,375 barrels of oil equivalents per day for the first 30 days. While the wells in 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 eight 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 low 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 nine wells brought online in the Bone Spring delivered solid results, producing an average of 1,645 barrels of oil equivalents per day in their first 30 days. In the Leonard, we brought on three 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 four wells per package versus two last year. We expect to further increase the average to five by year-end. Larger well packages necessitate a larger inventory of wells needed to stay ahead of our completion crews. Much of January was spent ramping up drilling activity and increasing inventory to prepare for our completion schedule this year. We increased our rig fleet 20%, exiting the quarter operating 20 rigs in the basin. 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. 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 through 28H wells, located in the overpressured Wolfcamp Oil Window of Loving County, Texas, illustrate our achievements drilling well packages. This 500-foot space, seven-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 simulations was sourced from reused produced water.
The outstanding operations performance and well productivity delivered an average well payout of five and a half 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. We're in great shape, and historically, we have 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 in works 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+ 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 four market connections. A 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.
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 to up to four 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 are 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 the Cotton Valley.
Thanks, Lance. Well cost continued 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 one 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 nine days on average in 2017 to about seven and a half 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 four-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 three-well Flatbow package that IP'd 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 four-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 seven low-cost Rockies wells are earning an average direct rate 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 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 Terry 1621 #1H, which is a two-mile lateral that delivered over 1,100 barrels of oil per day in its first 30 days. We currently have four rigs running in the Woodford, 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 costs. 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 costs 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 two 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.
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 costs 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. Now we'll go to Q&A.
Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit 1 on your touch-tone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Operators, questions are limited to 1 question and 1 follow-up question. We will take as many questions as time permits. Once again, please press star 1 on your touch-tone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star 2. We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question, we'll hear from Arun Jayaram with J.P. Morgan.
Good morning. 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 1 question. As you execute your premium drilling strategy, your returns on capital employed are now moving into the double digits. I was wondering if you could talk about weighing a buyback above your cost of capital versus reducing debt, what looks to be in the 6%-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
Strong, sustainable dividend growth are the best ways to create long-term shareholder value. At the moment, we're very confident in that plan, and we believe that will be the best avenue to create shareholder value.
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. As you know, we're a very organic company. We've got a lot of confidence in our organic exploration effort, corporate M&As are just something that would be really not in our game plan at this time.
Great. Thanks a lot.
Next, I'll move to Bob Morris with Citi.
Thank you. 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. Obviously, $1.5 billion of excess cash flow is quite a significant amount. You're starting out the year, what you plan to average for the full year on the rig count. 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?
Yeah. 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. Actually, our rate of capital spend is directly in line with what we laid out for the start of the year. We've already talked about the benefits of moving to these larger packages of wells. 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. At this moment, yeah, 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.
Okay, great. Thank you.
We'll hear from Irene Haas with Imperial Capital.
Yes, good morning. I have a question for the Eagle Ford trend, which you guys definitely was the first mover, and it's been going on nine years. I was wondering, what is the organic growth rate for this trend in 2018? 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?
Yeah, 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. What I will say about the Eagle Ford is the upside we see there 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 back into our geologic model, and it helps drive our precision targeting as we develop even finer scale and high-graded targets. 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. We're happy with our pace of development there in the Austin Chalk. When we have more information on that and we're a little more comfortable with it, we'll provide greater detail.
Okay. May I ask one more question? Are you generating organic growth out of the Eagle Ford and Austin Chalk trend in 2018?
Yeah, Irene, without getting into specific details, we do plan to grow that asset this year. We'll be doing that at a pace.
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.
Understood. Thank you so much.
Next, I'll move on to Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning.
I 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 a quantifiable secular advantage?
Yeah, Brian, this is Billy Helms. What we can give you is it's a little bit early to talk about guiding for 2019. Let me give you a little bit of color on where we are for 2018. First of all, 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 the drilling side and the completion side. We self-source quite a bit of that too. About 25% of our well cost is self-sourced. 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 costs in each one of the plays.
I think the Permian, we added quite a few rigs. 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%. The completions are expected to follow. We've made tremendous progress in the Rockies, both on the drilling and completion side, and lowering our well cost anywhere between 4%-5%. I think overall, we're very pleased with where we're headed. We have a long history, 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 that and try to work with our preferred providers to lock up some services for the upcoming year. 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. Thank you. My follow-up goes back to the earlier discussion on the Eagle Ford, and for me, 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? 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?
Yeah. Brian, this is Ezra again. Well, like I reiterated, I think we're happy with our plan, and we're happy with where we're at, kind of executing 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. 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.
Thank you.
We'll move on to Doug Leggate with Bank of America.
Thanks. Good morning, everybody.
Morning.
Bill, I wonder if I could go back to the dividend policy capital discipline share buyback discussion, or not so much the last part. I'm just looking at the dividend policy going forward. What do you see as the competitive metrics? What's kind of the end game you're trying to get to there? I just want to be clear on the $50-$60 range you gave, I guess, a year or so ago. Is $60 as a budget a kind of hard stop, so you shouldn't think of anything beyond that as going towards the balance sheet? If that's 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. The company's 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. We believe that our dividend is sustainable through the commodity cycles. The company is just 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 I'm not challenging the discipline of the $40 hurdle for premium locations. Obviously, some in the market might have a different view as to what the sustainable oil price is. The question is really about inventory relative to your growth pace. If we had to run a $45 or a $50 number as the threshold for premium inventory, how would it change over the disclosure you've given so far? Is it about 10%, or is it double? I'll leave it there. Thanks.
I think, first of all, we don't have any plans on changing our criteria. We're going to stick with $40 oil and 250 flat. That needs to be really clear going forward. That is 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. It's a very high quality total inventory. The inventory that we have in the company that's non-premium at $40 would be, I would say, equal to or better than the average inventory of the whole industry. It's a very high-quality inventory set, 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. We got, again, a very sustainable cost reduction. It's not just a one-year thing. It's a very consistent cultural attribute of the company, we have a tremendous ability to continue to improve well productivity at the same time.
Our goal is to convert a lot of that non-premium inventory into premium inventory as we go forward.
Thank you, Bill. Very clear.
We'll move on to Scott Hanold with RBC Capital Markets.
Thanks. Good morning. Could I ask another question on your increasing the dividend rate versus the long-term rate? Is there a particular yield that when you guys step back, would like to be at? It looks like you guys are running some more sub 1% right now and some of the large peers are in that 1.5% 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. That's what 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. It seems like you're definitely more front-end CapEx weighted, as you said, and the back half sees some of that production. Can you talk about the cycle times that some of these larger Permian pads have? It looks like you average about four in the first quarter moving to five, but can you discuss maybe what those cycle times look like as you move from two to four to five?
Yeah, Scott, this is Billy Helms. Cycle times, of course, vary by play. In the Eagle Ford, it's a much shorter cycle time than, say, the Delaware Basin, just strictly because the drilling times are much longer. It also depends on the size of the pad. Certainly, a 10-well pad might be a lot longer to cycle time than a six-well package. It also depends on how many rigs and frac fleets we put on each package. 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. As a result, it results in some lumpy nature of both capital spend and production. That's why you see the production growth vary by quarter.
It's also why as we entered the year, we obviously had to build some inventory to be able to execute this plan. The capital guidance is more weighted towards the front of the year than the second part of the year. That's just 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.
Appreciate that. Thanks.
Next, we'll move to Leo Mariani with NatAlliance Securities.
Hey, guys. I was hoping you could address the Austin Chalk a little bit more. I know that you said you're not going to make extensive comments, but I was just trying to get a sense of the inventory there. It sounds like this is one of the best returning plays you guys have. Just curious, is this a couple of years of inventory, or is there a similar 10 years like the Eagle Ford?
Yeah, 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 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, a matrix drive play. So it's not quite as straightforward to use a lot of those historical learnings. The way we're developing it is different and it's unique. I'd say, the initial productions look 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. Like I said, when we have a little more detail on that, we'll certainly talk about it.
Okay, that's helpful. 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 costs in the west are lower than the east? What can you sort of say about that?
Yeah, 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 pressured and less shallow, too. 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.
In general, the well lengths tend to be just a little bit shorter due to both the layout of specific leases over there, also there's an increase in the faulting off to that eastern side.
Okay, that's helpful. 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 evaluating that for 2019 and beyond?
Leo, we don't have any specifics on timing. Our board evaluates the business environment every quarter. Concerning the dividend, I think what we're saying is we believe EOG is in the best shape we've ever been for sustainable, more aggressive dividend growth. Our board is eager to return cash to shareholders with a strong dividend growth.
Thank you very much.
Next we'll move on to Charles Meade with Johnson Rice.
Yes. Good morning, Bill, to you and your whole team there. You've covered this a little bit already in your comments in the Q&A, 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, that's certainly been the pattern for you guys with the one prominent exception of the Yates deal. Don't get me wrong, that was really a brilliant deal for you guys. I'm trying to understand a little bit more. Is the Yates deal the exception that's not likely to come along again? 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, we've acquired a significant amount of low-cost acreage in multiple plays. We're testing numerous new plays with exploration or step-out drilling this year. Our organic machine is really in high gear, we have a lot of confidence in it, we believe we can acquire significant, hopefully even better drilling potential than we currently have through that process at very low cost.
Got it. That's helpful, Bill. That's all for me. Thanks a lot.
We'll move on to David Heikkinen with Heikkinen Energy Advisors.
Good morning, guys, and thanks for taking my question. We appreciated the details that you put on slide 21 around your diversified marketing options. Can you talk more specifically about firm sales, firm transportation, financial hedges, and then the balance of avoiding those long-term contracts that I know EOG doesn't want?
Yeah, sure, David. This is Lance Terveen, and thanks for your question. 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. So when we think about long-term commitments, it's really twofold. We want to have near-term flow assurance, and two, we just want to be very disciplined about any kind of long-term commitments. What we think that does, when we can kind of have that first mover and we can identify it, 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 2019 and probably into 2020.
What happens when there's a lot of hype and especially a very active area like the Permian with 453 rigs running, it's not a panic that comes in, but people are looking for capacity. We want to get out in front of that like we've done and like what we've shown. For us on the commitments, it's just being very disciplined, have a balanced approach, get in front of it. 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. 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.
Go ahead, David.
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 two years ago, three years ago. I'm just trying to get an idea of how you think about splitting marketing agreements, pipeline agreements, hedges, just in that forward-looking process that goes into slide 21.
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. Again, when we look at that, we look at a forward forecast and where we think each of the basins might be growing, especially like a new emerging basin. Typically, we want to lock up anywhere from maybe 70%-80% of that near term and leave more available in the outer years. Really, with the crystal ball, when we're looking at making the commitments, we try to protect more of, call it the first three years. Then if we need to make medium-term commitments, then those commitment volumes are a little smaller in the outer years. That's strategically how we think about the commitment, David.
Yeah. It's got a three-year run. Okay, that's helpful. Thanks, guys.
We'll move on to Jeffrey Campbell with Tuohy Brothers.
Good morning. I just wanted to ask for a little bit of 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're more into development than into delineation. It just seems like this play has really accelerated in a reasonably short amount of time. Just wanted to check in on that.
Yeah, Jeffrey, this is David Trice. On the Woodford, yes, we have picked up additional rigs there. We are running four rigs currently there. What we're doing this year is, one, we're securing operatorship in a lot of these units. Also, we're doing several spacing tests there. 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.
If I could just follow up on what you just said. If you look at your position as a whole, what % of it can you operate now, and what are you trying to get to?
Really, most of the 50,000 acres net that we show, we'll be able to operate that. We have quite a few trades going on where we may not have a majority interest. We think at the end of the day, we'll be able to operate the entire position.
Okay, great. Thanks for the color.
Next, I'll move to Bob Brackett with Bernstein Research.
Thanks for taking my question. I'll 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's your sense of how mature your understanding of those plays are right now? Where's the upside on each of those?
Yeah, Bob, this is Ezra Yacob, let me start with the Karnes Trough area down in the South Texas trend. Like I said, we brought to sale last year a number of wells that we're very happy with the initial rates on there. 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. 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. 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.
Again, the continued evolution of our frac designs. It is a chalk, so each of these plays that we're in, whether it's a carbonate, siltstones , mud rocks, as you know, little tweaks on your completion design can make a big difference. The biggest upside I see with Austin Chalk is just that advances continue to evolution and advances on our completions, delineating additional targets. Then in Louisiana, it's very early on that prospect. I think everyone knows 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.
Elsewhere, is the Austin Chalk trend, should we think of it working along the entire trend, or do you need local structures to help you out?
This is Ezra again, Bob. Yeah, the way I'd follow up with that is I'd say there are definitely 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 is one of them, that we're looking at to high-grade those areas. Any additional color than that, I'm not sure if we want to provide today.
Great. Appreciate it.
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 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.
That will conclude today's call. We thank you for your participation.