Good day, welcome to the EOG Resources fourth quarter and full year 2014 earnings results conference call. At this time, for opening remarks and introductions, I would like to turn the call over to Chief Financial Officer of EOG Resources, Tim Driggers. Please go ahead, sir.
Good morning, thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 2014 earnings and operational results. 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 reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, also probable reserves, as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines.
We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and investor relations page of our website. Participating on the call this morning are Bill Thomas, Chairman and CEO, Gary Thomas, Chief Operating Officer, Billy Helms, EVP, Exploration and Production, David Trice, EVP, Exploration and Production, Lance Terveen, VP, Marketing, and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, we included guidance for the first quarter and full year 2015 in yesterday's press release. This morning, we'll discuss topics in the following order. Bill Thomas will review 2014 highlights and our 2015 capital plan. David Trice and Billy Helms will review operational results and year-end reserve replacement data. I will discuss EOG's financials, capital structure, and hedge position, Bill will provide concluding remarks. Now, here's Bill Thomas.
Thank you, Tim. 2014 was another record year for EOG. Our results continue to demonstrate our return-focused capital discipline and EOG's superior ability to apply technology to the exploration and development of tight plays. Here are the highlights. Number one, EOG demonstrated its capital efficiency by earning peer-leading returns. ROE for 2014 was 16%, ROCE was 14%. For the year, we increased crude oil production by 31%, driven by our top three oil plays, the Eagle Ford, Bakken, and Delaware Basin. NGL production increased 23% while natural gas production held flat, yielding total company production growth of 17%. We announced five new plays, four in the Rockies, DJ and Powder River Basins, and a second Bone Spring sand play on the Delaware Basin side of the Permian. These plays add flexibility to our portfolio of options to grow production in coming years.
In the Delaware Basin, we identified an oil window in our existing Wolfcamp acreage. Early in 2014, we increased the reserve potential in the Eagle Ford 1 billion barrels of oil equivalent to 3.2 billion barrels of oil equivalent net to EOG. Between that Eagle Ford reserve increase and the new Rockies play alone, we added 1.4 billion barrels of potential reserves to our portfolio and 2,300 high-return net drilling locations. In recent years, we have consistently added twice as many locations as we drilled. Finally, EOG remained laser-focused on cost by driving down per well expenses in all of our major plays while simultaneously driving up well productivity. Before I move on to 2015, I'd like to expand on that last highlight. We have demonstrated a unique ability to get the most out of tight oil plays from both a cost and well productivity standpoint.
Over the last 10 years, we have developed expertise across all the disciplines required to drill in shale and other tight rock and make that drilling highly economic. This proven ability is why we posted strong returns in 2014 and why we are so well positioned to not only weather the current low price environment but to take advantage of it. Now let's talk about EOG's goals for 2015. First, our overarching goal this year is to prepare for oil price recovery. It is clear that current prices are too low to meet the world's supply needs, and the market will rebalance. We will be ready to respond swiftly when oil prices improve and resume our leadership in high-return oil growth. Second, we do not believe that growing oil in what could turn out to be a short-cycle, low-price environment is the right thing to do.
Let me repeat, we do not believe that growing oil in what could turn out to be a short-cycle, low-price environment is the right thing to do. We remain committed to maintaining a strong balance sheet at today's strip prices. 2015 cash flow should fund our CapEx budget of approximately $5 billion. Third, returns are what matter. Therefore, we will focus capital on the Eagle Ford, Bakken, and Delaware Basin plays. At $55 oil, these premier assets deliver a direct after-tax rate of return greater than 35% without factoring in the potential for additional service cost reductions. I'll now explain in further detail how we plan to prepare for the oil price recovery. First, we will reduce average rigs 50%, down to 27 for 2015, and intentionally delay any of our completions, building a significant inventory of approximately 285 uncompleted wells.
This allows EOG to use rigs under existing commitments. When prices improve, we will be poised to ramp up completions. Oil price improvement of even a few dollars generates incremental NPV. Delaying completions to wait for improved prices, as evidenced by the forward curve, will add significant value. Please see slide eight of our investor presentation for a play-specific example. Second, we remain focused on driving down finding costs and improving per-well production rates. This is our best hedge against low oil prices. For example, as a result of cost and well productivity improvements in the Eagle Ford Western acres, we can now generate better returns with $65 oil than we did with $95 oil just two or three years ago. We illustrate this on slide 11 of the investor presentation.
Due to low oil prices, we have already seen service cost reductions in many areas and see the potential for 10%-30% vendor savings during this downturn. Additionally, every one of our plays has room to reduce costs further through ongoing efficiency gains. We believe our integrated approach to completion technology is industry-leading. Quarter after quarter, we make improvements to well productivity, and that will continue to be a high priority this year for EOG. Third, low oil prices mean unique opportunities to add low-cost, high-quality acreage. We will continue to grow our acreage portfolio through leasehold, farm-in, or tactical acquisitions. We view our strong balance sheet and excess liquidity as a strategic asset for opportunities in times like these. We are already benefiting from the oil downcycle, adding new leases at lower cost than last year, and we're optimistic that additional opportunities will become available.
Finally, in my 36 years with the company, I've seen many downturns, and each time, EOG stays disciplined, performs well, and emerges on the other side in better shape than we entered it. In 2015, EOG plans to build a stronger position and be ready to resume long-term, high-return production growth when prices improve. I will now address the Eagle Ford. David Trice will discuss the Permian Basin, and Billy Helms will provide an update on the Bakken and Rockies plays, along with a repeat of our year-end reserves. 2014 was another remarkable year in the Eagle Ford. Oil production from the play increased 45%, and EOG achieved several key milestones. Number one, down-spacing and improved completion techniques enabled us to increase our total potential reserve estimate in 2014 by 1 billion barrels of oil equivalent, to 3.2 billion barrels equivalent net to EOG.
We continue to advance our technical expertise, as evidenced by ongoing improvements in productivity across the field. Slide 17 in our updated investor presentation shows an 8% increase in productivity for wells completed in 2014 versus 2013. We continue our progress with high-density completions across the entire play. A high-density completion is simply various techniques used to maximize the amount of rock connected to the wellbore. Due to geologies, those techniques will change from one county to the next, and we're making progress determining how to tweak those techniques across our acreage. Number four, after five years in the Eagle Ford, we're still making drilling time and cost improvements. Please see slide 18 in the investor presentation. Number five, at the end of 2014, our acreage in the Eagle Ford was over 80% held by production.
We had a number of lease retention commitments in our western acres that we successfully fulfilled in 2014, freeing up drilling flexibility going forward. Eagle Ford activity in 2015 will continue to be balanced between the west and east sides of the field. As I mentioned, we are intentionally delaying completions while we wait on improved product prices. Thus, our inventory of uncompleted wells is expected to increase. This strategy allows us to maximize the value of our existing contractual commitments while waiting on improved pricing before we bring on newly completed wells with high oil production rates. Delaying completions will also provide an opportunity to take advantage of lower service costs that will likely materialize in the coming months. The Eagle Ford remains EOG's premier play. We have about 5,500 net wells to drill on our acreage, over 10 years of inventory.
The Eagle Ford represents a huge call option on oil that EOG can exercise at any time to take advantage of a favorable oil price environment. We often refer to the Eagle Ford as our technology laboratory. Our understanding of this field and how to increase its recovery rate has led to improvements in plays across the entire company. The first to benefit from this technology transfer was the Bakken, beginning in late 2012. Now the Permian Basin is experiencing the latest step change in our application of technology. I will now turn it over to David Trice to discuss activities in the Permian.
Thanks, Bill. In 2015, EOG's capital budget in the Permian will expand to take advantage of new Delaware Basin targets, advancements in well performance, and cost reductions achieved in 2014. If you'll recall, last year, we shifted capital from the Midland Basin to the Delaware Basin, which allowed us to advance our technical understanding of the Delaware. In 2015, we will have fewer drilling commitments to hold acreage in the Midland Basin, which frees up capital and provides more flexibility. Let's quickly review the 2014 achievements that set this play up to be a major contributor to EOG's returns and long-term growth. First, we made significant advancements in our most mature oil play in the Delaware Basin, the Leonard Shale, by increasing well productivity 17%. In 2015, we will continue to push wells closer together, developing and further testing down to 300 feet.
We are encouraged with the initial results and expect to see further advancements throughout the year. Second, in our Delaware Basin Wolfcamp play, we made great progress in 2014 as the play moved into development mode. We greatly increased well productivity, as evidenced by the three wells we highlighted in our press release. At a $7 million completed well cost, the Wolfcamp play delivers very strong returns. Also in the Wolfcamp during 2014, we identified and delineated 90,000 net acres in the oil window. Third, we tested and proved the Second Bone Spring sand to be another high-return oil target in our Delaware Basin acreage. Initial results were promising, and we did extensive G&G work to delineate this play. The Second Bone Spring sand produces 70% oil in our Red Hills acreage in New Mexico and promises returns on par with our premier oil plays.
We will move the Second Bone Spring sand into development mode this year, it will receive the largest relative increase in capital. In summary, the Leonard Shale is in full development mode and continues to deliver impressive results. The Delaware Basin Wolfcamp finished its first year of development drilling. The wells are outstanding, and the costs are dropping. We are excited to add the Second Bone Spring sand to the drilling program and bring it forth into full development mode. We are confident that we will see the same progress in the Second Bone Spring sand that we have seen from the Leonard Shale over the last two years. While the Delaware Basin is still in the early innings of its exploration and development, the returns we are already generating from multiple targets make it very competitive with the Eagle Ford and the Bakken.
Billy Helms will now discuss the Bakken, the Rockies, and year-end reserves.
Thanks, David. 2014 was a successful year for the Bakken program. We began downspacing, testing various spacing patterns, and continued experimenting with completion techniques to improve the performance of the field. Here are some of the highlights for 2014's activity. First, we made significant advancements in improving drilling times and reducing well cost. A typical 10,000-foot lateral is now drilled in just over 10 days with a completed well cost of $9.3 million. This represents a cost reduction of 11% from 2013, and we expect more efficiency gains and service cost reductions in the current environment. Second, we now have production data from each of the various spacing patterns and can begin to determine the optimal development plan. We have tested wells at 1,300 foot, 700 foot, and 500 foot spacing patterns and have just started producing wells in a 300-foot spacing pattern.
Similar to the Eagle Ford, we expect that the spacing will vary depending on the specific rock characteristics in each area of the field. One of our latest tests is a six-well pattern with wells spaced 700 feet apart in the Bakken core. The initial production rates of these wells range from 1,000 barrels of oil per day to 1,900 barrels of oil per day and represent a customized completion design tailored for the rock properties in this particular area of the field. Third, we are confident that there is a significant amount of remaining potential in the Bakken and that downspacing will be highly economic. As I mentioned earlier, evaluating the production from each spacing pattern will lead us to the appropriate spacing and the ultimate reserve potential. While the Bakken will receive less capital in 2015, it remains a core high-return asset in our drilling program.
A typical 10,000-foot lateral in the Bakken core generates greater than 35% after-tax rate of return with a $55 flat oil price. In addition, maintaining activity allows us to retain momentum on operational efficiencies. For example, we recently drilled an 18,600-foot well to total depth in just over seven days. We continue to believe that EOG has the premier acreage position in the play with many years of development drilling remaining and the potential for long-term production growth. In the DJ Basin, EOG made significant progress in both the Codell and Niobrara. We have been experimenting with well bore targeting, interwell spacing, and modifications to the completion design for both intervals. For the Codell, we have identified a specific stratigraphic interval within the pay section that, when targeted, greatly enhances the performance of the well.
The improved completion techniques we use are even more effective when we focus on this target. Please see our press release for some notable well results. Like the Codell, we have tested several targets within the Niobrara. With this additional testing, we have determined a correlation between the amount of lateral focus within a specific target interval and the production performance of the well. In 2014, we made progress in several areas that contributed to reaching our well and operating cost goals in the DJ Basin. These include drilling and completion efficiencies in oil and gas gathering system, the water gathering and distribution system, and the infrastructure needed to obtain EOG self-source sand. Our activity in 2015 in the DJ Basin will be limited to drilling wells needed to maintain leasehold and finishing completion operations on a few remaining wells drilled last year.
The Powder River Basin is a stack pay system where we have drilled primarily in the Parkman and Turner Oil reservoirs. Similar to other areas within EOG's portfolio, in 2014, we focused on well targeting, improved completion designs, and interwell spacing to determine the optimal development plan. We made significant improvements in all aspects during 2014. Please see our press release for some excellent fourth quarter well results in both the Parkman and Turner plays. We plan to have limited activity in the Powder River Basin in 2015 while we wait for commodity prices to improve. I'll now address reserve replacement and finding costs. Excluding revisions due to commodity price changes, we replaced 249% of our 2014 production at a low finding cost of $13.25 per BOE. Proved reserves increased 18%, and more than half of our reserve growth was driven by crude oil.
In addition, net proved developed reserves increased 20%. For the 27th consecutive year, DeGolyer and MacNaughton did an independent engineering analysis of our reserves, and their estimate was within 5% of our internal estimate. Their analysis covered about 76% of our proved reserves this year. Please see the schedules accompanying the earnings press release for the calculation of reserve replacement and finding costs. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, Billy. Let me start by addressing an unusual item affecting the fourth quarter. In early December, we announced the sale of most of our producing assets in Canada for proceeds of approximately $400 million. As a result, volumes were lower than our previous guidance for the fourth quarter by approximately 2,300 barrels of oil per day and 15 million cubic feet per day of natural gas. Also, G&A for the quarter was higher due to $21.5 million of exit costs related to the sale. I'd like to make a few comments about our capital spending last year and in the fourth quarter. Capitalized interest for the quarter was $14.5 million. For the fourth quarter 2014, total exploration and development expenditures were $1.8 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $140 million.
There were $66 million of acquisitions during the quarter. For the full year 2014, capitalized interest was $57.2 million. Total exploration and development expenditures were $7.6 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $727 million. For the full year, capital expenditures, excluding acquisitions and asset retirement obligations, were $8.3 billion. Total cash flow from operations was $8.6 billion, exceeding total cash expenditures. In addition, proceeds from asset sales were $569 million. Total acquisitions for the year were $139 million. At year-end, total debt outstanding was $5.9 billion for debt to total capitalization ratio of 25%. Taking into account $2.1 billion of cash on hand at year-end, net debt to total cap was 18%, down from 23% at year-end 2013. In the fourth quarter of 2014, total impairments were $536 million.
$445 million of these impairments were the result of significant declines in commodity prices during the fourth quarter. For the full year of 2014, total impairments were $744 million. $501 million of these impairments were a result of declines in commodity prices and negotiated sales prices for property sales. The remaining impairments for both the fourth quarter and full year 2014 were ongoing lease and producing property impairments. The effective tax rate for the fourth quarter was 61%, and the deferred tax ratio was 104%. Yesterday, we included a guidance table with the earnings press release for the first quarter and full year 2015. Our 2015 CapEx estimate is $4.9 billion-$5.1 billion, excluding acquisitions. The exploration and development portion, excluding facilities, will account for approximately 80% of the total CapEx budget. 2015 CapEx represents a 40% decrease from 2014.
As Bill mentioned earlier, we are not interested in growing oil production in a low price environment. The budget for exploration and development facilities accounts for approximately 12% of the total CapEx budget for 2015, and midstream accounts for 8%. We plan to concentrate our spending on infrastructure in the Eagle Ford and Delaware Basin to support our drilling programs in those areas and enhance operating efficiencies. In terms of hedges, for February 1 through June 30, 2015, we have 47,000 barrels of oil per day hedged at $91.22 per barrel. For the second half of 2015, we have 10,000 barrels of oil per day hedged at $89.98 per barrel. This represents a small portion of our estimated oil production in 2015, and we will look to hedge further volumes opportunistically throughout the year.
We have contracts outstanding for 37,000 barrels of oil per day that could be put to us at various terms. Please see the press release for further details. For natural gas, we have 182,000 MMBtu per day hedged at $4.51 per MMBtu from March 1 through December 31, 2015. We also have a number of contracts on natural gas that could be put to us at various terms. If counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtu per day at an average price of $4.51 per MMBtu for each month during the period March 1 through December 31, 2015. Now I'll turn it back over to Bill.
Thanks, Tim. I'll talk about the macro view. We are encouraged that Congress is taking a look at lifting the ban on crude oil exports. Doing so will bring a wide range of economic geopolitical benefits, including strengthening the U.S. energy sector, growing the U.S. economy, creating jobs, dramatically improving the U.S. trade deficit, providing our European allies with more secure supplies, and lowering gasoline prices to U.S. consumers. As I mentioned earlier, EOG will be very focused this year on preparing for the recovery in oil prices. The current supply-demand imbalance is not very large, and current prices are far short of what is necessary to sustain the supply need to meet world demand growth. When prices recover, EOG will be prepared to resume strong double-digit oil growth. For now, EOG is intentionally choosing returns over growth. That's the way it's always been here at EOG.
In summary, I want to leave you with some important summary points. Year in, year out, EOG consistently approaches capital planning by focusing on returns. 2015 is no different. Second, we have halted production growth deliberately. While EOG is one of the few companies that can earn a healthy return at today's oil prices, we are not interested in growing oil into a low price environment. As we compare today's oil prices to our expectations for a more balanced market, it makes economic sense to slow production until an industry-wide supply response is realized and prices respond accordingly. This strategy maximizes the value of our assets. It's the right strategy to create long-term shareholder value. Third, our balance sheet places EOG in a strong position. We intend to use our financial flexibility to take advantage of opportunities to grow our inventory by acquiring low-cost, high-quality acreage.
Fourth, with a substantial inventory of high-volume wells to complete, we will be ready to return to double-digit oil growth as oil prices improve. Finally, we fully expect to emerge from this commodity price down cycle in a stronger position than we entered it. In 2015, we have more opportunity than ever to lower finding costs and development costs and improve returns in 2016 and beyond. Thanks for listening, now we'll go to Q&A.
Thank you, sir. The question and answer session will be conducted electronically today. 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 phone. If you are using a speakerphone, please make sure that your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touch tone phone to ask a question. If you find that your question has been answered, you may remove yourself from the queue by pressing the star key followed by the digit 2. We'll pause for just a moment to give everybody the opportunity to signal.
ladies and gentlemen, star one to ask a question, we will take our first question from Doug Leggate from Bank of America Merrill Lynch. Sir, your line is open. Please check your mute function. We will take our next question from Paul Sankey from Wolfe Research.
Hi, good morning, everybody. Can you hear me okay?
Yes, Paul, go ahead. Good morning.
Great. Thanks very much. Good morning. You've clearly stated, guys, that you're now targeting flat year-over-year crude production in 2015, you also stated clearly that you're not interested in growing oil production in a low oil price environment. I wanted to confirm that the overarching decision you've made here is to get CapEx in line with expected cash flows, secondly, that by increasing efficiency, allowing for lower service costs, even if oil prices remain low for another year, you would be able to deliver growth in 2016 while keeping CapEx within cash flows. If oil prices remain low, would you reduce CapEx and leave volumes flat again next year? Thanks.
Yes, Paul. Your first statement is generally correct. Number one, we do not think it's wise or prudent to accelerate oil when oil prices are low, especially if the rebounded price could come certainly this year, the end of this year, or maybe even next year. There's no use in trying to accelerate. It makes much more prudent business decision to wait, and that will give us much more capital returns if we do that. We are very committed to maintaining a very strong balance sheet. We don't want to outspend trying to grow oil in a low price environment. We want to keep our balance sheet clean and low, and we want to keep our powder dry, so that we'll be able to take some advantage of what could be some unique opportunities in this downturn.
In 2016?
Yes. Yes, sir. On 2016, yes, if things go as we think they might could, we would have, say, a $65 oil environment in 2016, we believe that we could return to our very strong double-digit oil growth that we've been marching towards over the last few years, and that we would be able to generate very high rates of return on our capital. We would be able to stay free cash flow neutral.
I guess the specific part of that was that if you did another year of $5 billion CapEx next year, you would be able to re-accelerate growth because of the increased efficiencies and lower service costs that you'll be seeing throughout this year.
Certainly, we do think costs will come down this year due to services and, again, efficiency gains. We're making really good progress in that. As we look forward to 2016, we haven't set a capital goal on that yet. We'll look at that when we get there.
Okay, that's great. Thanks. Then could I just confirm, you're building effectively an inventory of stuff that you can do if you want to. Would that mean you're less likely to get into M&A, or would you not follow that statement through?
Well, the kind of opportunities that we're looking for, to take advantage of is, number 1 this low price environment helps us to pick up acreage that we're working on in certainly our core areas. We were able to pick up 11,000 acres last year in the Eagle Ford, and we're targeting to pick up more there just from leasehold. That goes more easily this year. The second is that we have historically, we do think that we'll have opportunities to earn acreage through farm-ins or drill to earn type things, commitments. We'll look for partners that we can join in with that will be a win-win situation and earn acreage in our core areas and maybe some emerging areas. Then we look for tactical acquisitions.
They won't be the large acquisitions, they will be certainly bolt-on acreage, and they will be opportunities that we see primarily in our top-tier plays.
Okay, great. Thank you very much.
We'll take our next question from Phillip Jungwirth with BMO.
Yeah, good morning. EOG has been at the cutting edge of completions technology and proven to be a premier operator. Is there any way to quantify the operational synergies you think can be achieved through an acquisition strategy in terms of NPV per well or however you think is best to think about it? Can this technology advantage be maintained in a way that's accretive through acquisitions?
Yeah, Phillip, thank you for the question. I think certainly when we look at potential acquisitions, the thing we let help guide that is our exploration expertise and our understanding of the rocks. We really are only focused on
That kind of opportunities where we see very sweet spot type acreage in either existing core areas or in emerging plays. We certainly have a lot of expertise, and we've been in the shale business, I think, longer than most people, and we've developed very strong efficiencies and technology improvements. We think that we would certainly bring that to bear on, and we apply that, and the upside that we see on that we could bring to the table on any kind of acquisition that we might pursue. We have certainly our built-in cost of reduction mechanisms like our self-source sand and other materials that we use in our fracs. That gives us an advantage from an economic standpoint to be competitive on acquisitions.
Hey, Gary. How much of the 2015 capital being spent isn't additive to production this year just solely due to the decision to defer completions during the year just so we can get a sense of what a clean number on a capital efficiency basis would be?
As far as the number of wells that we're deferring, really the number is we had 200 wells at the start of 2015, and we're going to end the year with about 285 wells waiting on completion. About an additional 85 wells. Were we to complete that cost would be somewhere $450 million-$500 million. As far as the wells that we're drilling and not to be completed, that's a $200 million additional cost that we're spending this year, 2015.
Great. Thanks a lot.
We'll take our next question from Charles Mead with Johnson Rice.
Yes, good morning to everyone there. Bill, I wonder if I could get you to go back to some of the macro comments that you closed out your prepared comments with. My recollection is that in some of your comments back in December, some of your public comments, you had the opinion that we were looking at more of a V-shaped recovery in oil prices and maybe activity as well. I wonder, can you talk about how your view of the macro landscape has changed over the last couple of months, and what you think, I know you just referenced $65 oil in a year. Is that a reasonable point to anchor on as far as your expectations for 2016?
Charles, I don't think that I've talked about a shape of the recovery. Our view now is that we really believe, with the consensus opinion, that as we go forward due to the response of the industry, that we could have flat to maybe even negative U.S. production growth on a month-over-month basis by the end of this year. That's certainly going to slow down U.S. production growth this year. As that slows down, there should be a price response, and I'm not going to predict whether it's going to be V or U or W or really what the price is. Certainly, the forward curve is very indicative that prices will increase in the future. We're just going to wait and see how that goes, and we'll respond accordingly.
Got it. That's actually a good segue to the next question I'd like to ask. It really gets to this inventory and what set of conditions would lead you to start really wanting to work that down? The current forward curve has us at, I think January crude is right around $60, January 2016 crude. Would $60 crude be sufficient for you to start wanting to work that down? Perhaps that in combination with some other factors on completion costs or that sort of thing? Can you just elaborate a bit how you're thinking about it?
Yeah, certainly because we're deferring these completions because we do believe that prices would be better in the future, and even a $10 increase in oil price gives us a significant additional return on our investment and NPV upside. Really our rate of return focus and our capital return focus is really what's driving the deferral. Let me walk you through. There's two parts of this deferral. One is, as Gary said, we're starting out 2015 with about 200 uncompleted wells in our inventory, and that uncompleted well inventory will grow throughout 2015. If oil prices improve, and they look something like the forward curve in the $60 range, we would begin completing many of those wells starting in the third quarter of 2015, and that would reflect additional growth in the fourth quarter, heading into 2016.
We want to head into 2016 on an uptick in production growth. Our curve in 2015 will be U-shaped. It will be the lowest production will be in the second quarter and in the third quarter, and then production will begin to increase in the fourth quarter as we head into 2016. At the end of the year, we'll have about 285 wells in inventory to start the 2016 process. That will give us a bit of an advantage as we go into 2016, and we'll be able to grow oil at very strong double-digit rates, and be able to stay free cash flow neutral in a $65 oil price environment. Hopefully, that gives you a bit of more understanding of what we're thinking.
Bill, that's great insight into your thinking. Exactly what I was looking for. Thank you.
You're welcome.
We'll go now to Leo Mariani with RBC Capital Markets.
Yeah. Hey, guys. I was just hoping you can speak a bit until sort of how quickly once the price response is in place where you can start working down the backlog of completions. Is that just a matter of a month or two? Additionally, just following up on what you had just mentioned there, in terms of if we got to $60 oil, say, by midsummer where you might start completing more wells in 3Q, is that contemplated in the production guidance in 2015 for EOG?
What we have contemplated is just as Bill was saying, is we'll ramp up in the fourth quarter. You're right, it would take us about one month since we have wells drilled, wait on completion to go ahead and see the impact of that production. Yes, we would start somewhere like September and start the ramp up if we've been encouraged with oil prices improving.
Yes, that is included in our production guidance for 2016.
Okay. No, that's helpful. I guess I noticed that you guys did have a relatively healthy increase here in the dividend this quarter. Can you talk a little bit about how you balance returning cash to shareholders through the dividend with drilling wells? Obviously, the returns on the wells are still quite strong here at $55 oil. How do you think about the increase in dividends just given where oil is right now?
Yes. No, we didn't increase the rate of dividend in this quarter. We did increase it twice last year by two healthy amounts. That's just to give back to the shareholders, share with them the success of the company. As we're in this lower price environment, the opportunity to further increase the rate is a bit more limited. We'll really just have to see how oil prices respond in the future, and to consider additional increases in the dividend. The company is very committed to that part of the business and to the shareholders in that way. It's a very top priority for us, but we need a bit better business environment to work on that.
All right. Thanks.
We'll take our next question from Pearce Hammond from Simmons & Company.
Thank you for taking my questions. My first question is, what % of total well cost is completion, and where do you expect that to go with service cost decreases?
Well, our drilling cost is roughly 25%-30% of the cost of a well. There gives you the completion. Of course, I guess we could put facilities in there. The facilities would be somewhere around 10%. The balance being completion. The other part of the question was what, Pearce?
Was just how you see those service costs decreasing, those completion costs decreasing over the course of this year.
Yes. When we put our budget together, we were seeing 5%-10% cost reduction. Now we're seeing 10%-30% cost reduction. That of course, depends on the sector. Just to illustrate that, I might just mention in the Eagle Ford, you've noticed in our Exhibit 18, we're showing our well cost at 6.1%. We're setting our target. We hope to see somewhere around 5.5% or about a 10% reduction. In the Bakken, we've got 9.3%. Our target would be to further lower that. Well, 9.3% before we've got 8.2% is our plan number. We've got a target that's slightly less than that, maybe 19%. Overall, we're expecting our cost to come down somewhere around the 10%-20% from 2014.
Thank you, Billy. What is the base decline for the company?
Yeah, Pearce, we haven't given that number out. The decline rate, and the reason we haven't, the decline rate is slowing over time. There's three reasons for that. One is every year that goes by our
Well base gets more mature. We've got older wells, a bigger percentage of older wells all the time. That's slowing the process. Number two, our completion technology is really beginning to start to flatten out our decline rates on a per-well basis. Specifically, the high density fracs that we talked about in the last quarter that we're applying in the Eagle Ford, are not only increasing the initial rates, but they're also decreasing the decline rates there. We're very encouraged about that. Number three, as we go forward, we are targeting plays that have better rocks with better permeability and better ability to flow oil. Those rocks, such as the sandstone plays in the Delaware Basin and in Wyoming, have lower decline rates also.
The mix of our decline rate in the company is slowing over time due to a number of different reasons.
Thank you very much.
We'll go now to Joseph Allman from J.P. Morgan.
Thank you, operator. Hi, everybody.
Good morning, Joe.
First question's on production. I heard what you said about the U-shape production for 2015. I just want to get a better understanding. The first part of the question is: why is the first quarter 2015 production below fourth quarter, especially on the oil side? I know you sold Canada, so I'm factoring that in. Could you just give us just a better understanding of the trajectory? It sounds as if you're going to be down in first quarter, down in second, down in third, and then up in fourth. Will the fourth quarter oil be flat with fourth quarter 2014 oil, especially in the U.S.? I understand what's going on in the East Irish Sea. You're bringing on that field in the third quarter.
Yes. Joe, the reason the first quarter volumes are down is because we began ramping down our completions spreads really quickly in the year. As our oil continued to drop, we wanted to drop CapEx quickly and not focus on growing oil when we have the lowest prices in the first part of the year. Again, as I described, the second and third quarters should be the lowest production. The fourth quarter, we'll ramp back up. We don't have a number to give you on a guidance on that number, but it will ramp back up significantly heading into 2016.
Okay. That's helpful, Bill. On the cash flow from operations, to get the cash flow from operations to cover the CapEx, what benchmark prices do you assume? In that, are you assuming the midpoint of your production guidance?
Yes. We go CapEx to discretionary cash flow should be balanced at about $58 average price this year. The second part of your question was?
Are you assuming to generate the cash flow? First, I'd love to get the WTI assumption, Brent assumption, and then the natural gas assumption, too. Are you assuming the midpoint of your guidance when you say you're going to cover the CapEx with cash from operations? For example, if you hit the low end of your guidance, maybe you'd be deficit spending somewhat.
No, it's the average midpoint of our production for 2015.
Yes, Joe.
Okay. How about natural gas assumptions and Brent oil? Have you got that?
Yeah. On the gas, we use a five-year strip. Yeah, we just use a five-year strip on that. Then on the NGLs?
NGLs is basically a % of oil price-
Yeah
in our assumptions. Then gas, again, is a five-year strip.
Yep.
Okay. All right. Very good. Thank you.
We'll go now to Bob Brackett from Bernstein Research.
Some clarifications on some of the other questions. One, I'm trying to do the math on, you start the year with 200 uncompleted. You drill about 465 wells, and then you end the year, was it 285 or 350 uncompleted?
Yes, Bob, that's a good question. That 350 was an incorrect number. Correct that back to 285. We end the year at 285. Here's the numbers, just to be completely clear. We start with 200, we drill 550, and we complete 465 during the year, and we exit the year at about 285 wells uncompleted.
Great. That's helpful. A quick follow-up. On acquisitions, you used two definitional terms. You contracted bolt-on versus large acquisitions. Is there a monetary value associated with those two numbers or those two adjectives?
No, there's not a monetary number. We just want to distinguish that we're open certainly to any kind of acquisition that would be very highly beneficial to the company. Most likely, the type of acquisitions we do are not in the very large, I'm talking multi-billion dollar kind of acquisitions. They're really more directed towards the tactical acquisitions, and they're really at very specific acreage pieces that we think are very highly productive according to our geology.
You said core areas, that's Bakken, Eagle Ford, Permian?
Well, certainly those would be the first choices. Obviously those are the most competitive. We do from time to time, consider those type of things in some of the emerging plays. Again, we're very discriminatory there in that we're only looking for acreage that will be additive to our inventory, and that means it has to be equal to or better than our Eagle Ford, Bakken, and Permian plays.
Great. Thank you.
Thank you.
We'll go now to Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
You talked of the potential for 10%-30% vendor cost savings. I wondered, as a company more vertically integrated than others, can you talk more specifically where you see this potential beyond the more normal course efficiency gains you highlighted in your presentation and your comments, and whether you think the 10%-30% is merely cyclical or secular?
Brian, let me let Gary Thomas answer this question.
The good thing is the vendors are working so well with EOG, we're seeing that 10%-30% across drilling, completion, production, all areas. I guess the thing that'd be a little unique for EOG is we believe that we're going to be seeing maybe in the 10%-15% reduction in the areas. EOG has three sand plants. We also have at least a half a dozen other vendors. There's a combination of cost of sand and distance from well sites. We'll be able to use some of the lower cost sand, with us having half the number of frac fleets running in 2015. That'll benefit us as well. As far as more granular, yes, in the tubing and casing area, it may be lower, in the 5%-7% range.
We are seeing stock tanks, those discounts coming down as much as 25%.
To follow up, do you think that's cyclical or secular? It sounds like from your comment on just the cost, it's the distance that's more high grading, is there a secular element you see as well?
No, not appreciably.
I think the secular part, Brian, would be in the efficiency gains, particularly in the technology side of it. Those will stay with us for years, they keep improving. The service cost comes and goes, obviously, with the activity, so it'll be a bit more short-term. We build in long-term, I think, cost savings in the company, that will continue to stay with us. As an example, we gave this earlier, we now see better returns in our Eagle Ford with $65 oil than we had with $95 oil two or three years ago. That is mainly due to the efficiency gains we've been able to accomplish with our completion technology and the efficiency and the cost reduction on the wells.
That's helpful. Along those lines, you talked about the acquisition strategy, let's say oil prices do quickly recover, the acquisition opportunities are not accretive as you're hoping for. What potential do you see from your higher rate of return legacy areas to further extend your inventory beyond the 15+ years you're at now? Where are we in that ballgame?
Brian, we see upside in really all of them. To start with the Eagle Ford, again, we still believe we're in the sixth inning there in the Eagle Ford. We're still testing new zones like the Upper Eagle Ford, and we're working on down-spacing. Again, we've added acreage there in the last year, about 11,000 acres, that is very high quality acreage. We think there's additional room there. In the Bakken, we've not upgraded our Bakken well count or reserve potential after we started this down-spacing process, we see upside there. In the Permian, we are diligently working on spacing and targeting, and specifically in the Second Bone Spring sand. We're working on bringing the spacing patterns closer together and identifying maybe even two targets in that particular zone.
In the Leonard, we're working on spacing there, and we haven't upgraded that well count in a long time. In the Wolfcamp, we have multiple pay zones and spacing that we're working on there, and we haven't upgraded that in a while. Really each one of our core areas, we believe, will continue to provide additional high-quality inventory as we go forward.
Thank you.
Ladies and gentlemen, this does conclude today's question and answer session. Mr. Bill Thomas, at this time, I would like to turn the conference back over to you for any additional or closing remarks.
Thank you. I would just like to leave you with this last one thought. EOG is very long-term focused. We could have taken a short-term approach this year and just picked out the very best wells in the company to drill and focus on those and cut our capital back to really only a short-term focus. We do not believe that's the right way to grow the company and to manage the company. We are focused on long-term shareholder value, and that's our focus. As we said, we are going to not grow oil while oil prices are low. We're going to wait for the recovery, and that will be able to give us much higher returns, and it's the right business decision as we go forward. We appreciate everybody. Great questions, and thank everybody for their support.
Ladies and gentlemen, this does conclude today's conference, and we do thank you for-