Good day, everyone. Welcome to the EOG Resources third quarter 2013 earnings results conference call. As a reminder, today's call is being recorded. At this time, for opening remarks and introductions, I'd like to turn the call over to the Executive Chairman of the Board of EOG Resources, Mr. Mark Papa. Please go ahead, sir.
Good morning. Thanks for joining us. We hope everyone has seen the press release announcing third quarter 2013 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, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines.
We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and investor relations page of our website. With me this morning are Bill Thomas, President and CEO, Gary Thomas, COO, Billy Helms, EVP, Exploration and Production, David Trice, EVP, Exploration and Production, Tim Driggers, Vice President and CFO, and Maire Baldwin, Vice President, IR. An updated IR presentation was posted to our website yesterday evening. We included fourth quarter and full year guidance in yesterday's press release. This morning, we'll discuss topics in the following order. I'll first discuss third quarter net income and discretionary cash flow. Bill Thomas will review operational results. Tim Driggers will discuss financials and capital structure. Finally, I'll cover our macro view and hedge position. Bill will provide concluding remarks.
As outlined in our press release for the third quarter 2013, EOG reported net income of $462.5 million, or $1.69 per share. For investors who focus on non-GAAP net income to eliminate mark-to-market impacts and certain non-recurring items as outlined in the press release, EOG's third quarter 2013 adjusted net income was $634.3 million, or $2.32 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $2.0 billion. Similar to the first half, EOG continued to hit on all cylinders in the third quarter. Our oil, NGL, and gas production again exceeded guidance. Our unit costs beat the lower guidance provided last quarter.
Because of continued strong Eagle Ford and Bakken performance, we are again raising our full year 2013 production growth estimate for oil from 35%-39%, NGLs from 14%-17%, and total company growth estimate from 7.5%-9%. The impact of the high reinvestment rate of return Eagle Ford, Bakken, and Leonard investments is also showing up in our EPS and cash flow numbers, as well as our ROE and ROCE ratios. This quarter's oil results provide further confirmation regarding our five-year plan, where we expect to achieve the most profitable and highest oil growth rate of any large cap independent, as we've done for the past six years. No other large cap oil company has even remotely matched EOG's oil growth rate, either in 2013 or for the six-year average. I'm going to repeat that last sentence because it bears repeating.
No other large cap oil company has even remotely matched EOG's oil growth rate either in 2013 or for the six-year average. We continue to have no interest in zero profit North American gas growth and will continue the high margin oil focus. I'll now turn it over to Bill Thomas to discuss specific operational results.
Thanks, Mark. I will start with our third quarter 2013 Eagle Ford results. During the third quarter, we continued to achieve 100% direct after-tax rates of return from both the western and eastern portions of our 569,000 net acres in the Eagle Ford oil window. Continuous improvement in well productivity and operational efficiency are driving costs down and production up. As a result, we now expect to drill and complete 460 net wells in the Eagle Ford this year, which is an increase of 20 wells since last quarter. We've been able to increase the planned well count every quarter this year because we are drilling wells faster and more cost effectively. In the west, we completed a number of initial unit wells in order to earn acreage and establish multi-well development patterns.
The Bridgers Unit number 1H began production at 2,195 barrels of oil per day, plus 1.0 million cubic feet of rich gas per day. The press release noted the Kaiser Junior Unit number 1H as the best well to date in the west. The well came online at 2,815 barrels of oil per day, plus 1.3 million cubic feet of rich gas per day. The Nelson Zella Unit number 1H and 2H began production flowing 1,960 and 2,810 barrels of oil per day, plus 1.0 and 0.8 million cubic feet per day of rich gas, respectively. To continue pattern development of the River Lowe Ranch, we completed an additional six wells. The River Lowe Ranch number 4H through 9H had initial flow rates of 1,970-2,115 barrels of oil per day, plus 1.0 and 1.1 million cubic feet per day of rich gas.
EOG has a 100% working interest in each of these western wells. The consistently strong drilling results from the west in the first three quarters have been a significant contributor to EOG's Eagle Ford oil growth in 2013. Page 19 of the IR presentation has an updated chart that shows average IP rates for our western wells are 20% higher in the third quarter than the first quarter of this year. The continuous improvements in well productivity as a result of new frac techniques and the downward trend of well costs through operational efficiencies give us a high confidence level in the strength of our large drilling inventory on our western Eagle Ford acreage.
In the east, we continued the development of the Baker-Deforest Unit with the number 5H, number 6H and number 7H flowing 3,200, 3,560 and 4,115 barrels of oil per day with 3.5, 4.1 and 4.4 million cubic feet per day of rich gas, respectively. We also began development of several new acreage units with the completion of the Justiss Unit number 1H, number 2H, and number 3H, flowing 3,885, 3,560, and 3,940 barrels of oil per day, plus 4.4, 5.0, and 5.6 million cubic feet per day of rich gas, respectively. In addition, the Vinklarek Unit number 1H was completed flowing 4,510 barrels of oil per day, with 5.9 million cubic feet per day of rich gas. EOG has a 100% working interest in each of these western wells.
As noted on our second quarter call, we continued to test down-spacing patterns in both the east and west. The down-spacing process takes time. The ultimate goal is to maximize oil recovery and the net present value of the acreage. In summary, EOG's Eagle Ford position and operational team are proving to be the most powerful oil growth offense in North America. Quarter by quarter, this asset continues to get better and better. We have many years of drilling inventory and this high rate of return play. I'll shift to the Bakken Three Forks. We continue to see outstanding results from the technical renaissance in frac technology that we started in 2012, in conjunction with our down-spacing program in the core.
Recent down-spaced wells in the core include the Van Hook 1262523H and 1302526H with initial production rates of 2,235 and 1,910 barrels of oil per day, plus 1,115 and 900 MCF per day of rich gas, respectively. The Wayzata 1372226H and 1501509H, which began producing 2,500 and 2,320 barrels of oil per day with 1.2 and 1.1 million cubic feet per day of rich gas, respectively. In the Antelope extension area, we completed three excellent Three Forks wells in the first bench. The Bear Den 1002017H, 1012019H, and 232019H began flowing 2,100, 1,235, and 1,665 barrels of oil per day, plus 2.0, 1.2, and 1.6 million cubic feet per day of rich gas, respectively. We are encouraged by the Three Forks potential in the Antelope area. We completed an excellent well in the second bench early this year and plan to test the third bench during 2014.
We are now achieving direct after-tax rates of return in excess of 100% in both the core and Antelope areas. We added two new slides to the IR presentation showing EOG's outstanding 2013 results. Page 23 shows EOG's 2013 completions at 58% more production in the first 100 days as compared to those completed in 2012. The same slide also shows year-to-date IP rates from these two areas are up 50% as compared to last year. Page 25 shows EOG compared to 20 different Bakken operators. EOG's average IP this year is 1.9 times better than the peer average. With a modest drilling program, we are growing oil volumes and setting new production records. On our second quarter call, we increased our drilling inventory in the Bakken Three Forks from seven to 12 years.
With excellent results and a large inventory, we anticipate increasing drilling activity in the Bakken Three Forks in 2014. In our Delaware Basin, Leonard and Wolfcamp plays, our third quarter activity was centered on drilling multiple well spacing patterns, testing numerous target zones, and optimizing frac techniques to improve well economics and recovery factors. In the Leonard play, we completed a number of wells in Lea County, New Mexico. The Endurance 36 State Com number 4 H was completed in the B zone at an initial rate of 875 barrels of oil per day, with 1.1 million cubic feet per day of rich gas. This is one of our first B zone tests, and initial rates are excellent. We completed two new wells in the A zone.
The Endurance 36 State Com number 3 H flowed 735 barrels of oil per day with 1.2 million cubic feet per day of rich gas. We are completing a number of wells in the A zone and drilling a number of wells that will test multiple target zones and well spacing patterns. Year to date, direct after-tax rates of return have exceeded 100% from this drilling program. We continue to be very excited about the Leonard. We plan to significantly increase activity in the Leonard next year. With approximately 1,600 locations in inventory, the Leonard is a powerful part of our offensive arsenal that will enable EOG to continue to lead the league in high-margin oil growth through 2017. In the Delaware Wolfcamp play, we have previously said that we were waiting on infrastructure.
We can now report that as of October 1, gathering infrastructure is in place and operational. We are now ready to complete two multi-well patterns to test various spacing and targets. We plan to use microseismic to determine frac geometry and monitor production in order to determine optimal development patterns for our Delaware Wolfcamp acreage. We have more than 1,100 locations in inventory, currently generating direct after-tax rates of return of 60%. Drilling for the remainder of this year and next will be focused on establishing optimal well spacing, completion techniques, and evaluating multiple target zones to set this play up for full-scale development in 2015 and beyond. We now have approximately 134,000 net acres in the play. In Trinidad, we've completed our Osprey platform drilling program, which should provide for flat production in 2014 versus 2013.
In the East Irish Sea, the startup of our Conwy oil project is now estimated for late 2014. In addition to our ongoing efforts to increase recovery factors in our existing plays through down-spacing and completion improvements, we have not lost our momentum or focus on searching for new reserve potential with domestic greenfield plays. To summarize, EOG has captured the best horizontal oil acreage in North America. Our high-performance operational teams continue to execute superbly. Wells are getting better, unit costs are coming down. Oil production continues to increase at peer-leading growth rates. We have a very strong inventory of crude oil and liquids-rich drilling prospects with high after-tax rates of return. We continue to focus on delivering high-margin oil growth, increasing recoverable reserves in existing assets, and generating new plays to ensure that EOG remains best in class through 2017 and beyond.
I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, Bill. Capitalized interest for the quarter was $12.6 million. For the third quarter 2013, total cash 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 $87.6 million. There were $89.2 million of acquisitions during the quarter. During the third quarter, net cash provided by operating activities exceeded financing and investing cash outflows. Year to date, we've closed on asset sales of approximately $620 million. We expect approximately $750 million in total asset sales by year-end. This is a $200 million increase from our previous estimate. At the end of September 2013, total debt outstanding was $6.3 billion. The debt-to-total capitalization ratio was 30%.
At September 30, we had $1.3 billion of cash on hand, giving us non-GAAP net debt of $5.2 billion, for a net debt to total cap ratio of 25%, a reduction from 29% at year-end 2012. On October one, we paid off $400 million of debt that matured with cash on hand. The effective tax rate for the third quarter was 36%. The deferred tax ratio was 65%. Yesterday, we included a guidance table with the earnings press release for the fourth quarter and full year 2013. Our CapEx estimate for the full year is approximately $7.2 billion. For the fourth quarter, the effective tax rate is estimated to be 35%-40%. For the full year, the effective rate is estimated to be 35%-38%.
We've also provided an estimated range of the dollar amount of the current taxes that we expect to record during the fourth quarter and for the full year. I'll turn it over to Mark.
Thanks, Tim. I'll provide our views regarding the macro environment, hedging, and 2014 activity. Regarding oil, we believe that absolute 2013 total U.S. oil growth will be less than 2012, and this trend will continue in subsequent years. Through August, the EIA monthly data indicates 2013 oil production is on trend to increase 600,000 barrels per day on an annualized basis compared to 1 million barrels per day in 2012. We continue to be pragmatically bullish regarding oil prices, partially because we don't expect any large international shale oil plays to impact global supply for at least five years. In terms of 2014 oil hedges, we have 123,000 barrels per day hedged for the first half of 2014 at $96.44. For the second half of 2014, we have 9,000 barrels per day hedged at $95.30 per barrel.
We have a number of contracts outstanding that could be put to us at various terms. For the first half of 2014, we have 64,000 barrels per day of options that could be put to us at approximately $99.60 on December 31st, 2013, if it is advantageous for the counterparty to do so. For the second half, we have 10,000 barrels per day of hedges that could be put to us at $96.60 on or about March 31st, 2014. For the second half, we have 103,000 barrels per day of hedges that could be put to us at $96.60 on or about June 30th, 2014. Regarding North American gas prices, I suspect I have a reputation as the most bearish CEO or former CEO in the E&P business. I'm not going to change that reputation on my last earnings call.
I believe gas prices will stay depressed until the 2018 timeframe. EOG will not be in any hurry to generate a lot of gas deliverability. The current Marcellus location differential is likely just the harbinger of chronic Appalachian price dislocations that we'll see over the next multiple years. Our gas hedge position is unchanged from last quarter. We also expect ethane prices to remain weak until 2018. For the third quarter, our average U.S. oil price realization was $2.74 above WTI, within $0.01 of our guidance. This premium over WTI has shrunk considerably compared to our first-half realization because WTI has increased relative to LLS. As EOG has done in the past, we'll discuss our detailed 2014 business plan on the February earnings call. We can provide a few conceptual thoughts at this time.
Assuming oil and gas prices are similar to the current NYMEX, EOG will likely ramp up its 2014 activity in the Eagle Ford and Bakken Three Forks plays above 2013 levels. In the Permian Basin, our overall CapEx will likely be flat, but the spend ratio will shift dramatically from this year's allocation of 65% in the Midland Basin, 35% into Delaware, to 15% Midland Basin, 85% Delaware Basin next year. We again plan to drill zero North American dry gas wells in 2014 because we see no light at the end of the gas oversupply tunnel until 2018. Now I'll turn it over to Bill for summary remarks.
Thanks, Mark. Let me conclude. There are four important takeaways from this call. First, our third quarter and nine-month year-to-date results confirm that EOG's oil growth momentum is not diminishing. Our six-year compound annual growth rate is 38%, which is awesome when you consider this growth is 100% organic. Each of our three key plays has 12-plus years of currently defined inventory, so EOG is built for the long haul. Second, our unit cost control have been impressive, as evidenced by today's results and the full year guidance provided yesterday. Third, the vast majority of our CapEx is going into three plays, yielding 100% direct after-tax rates of return: the Eagle Ford, the Bakken, and the Leonard. These returns are showing up in the bottom line with nine-month non-GAAP net income up 55% year-over-year, increasing ROE and ROCE.
Our net debt ratio was reduced from 29% at year-end 2012 to 25% at September 30th. Finally, the board and I have asked Mark to stay on as a director after he retires at year-end. I'm happy to report that Mark has agreed to do so. This will provide additional continuity and experience to our board. I'll turn it back to Mark for one closing remark.
Thanks, Bill. This is my last earnings call, and I want to thank everyone on both the buy and sell side for investing your time and patience in the EOG story. I've enjoyed working with all of you and have a sincere appreciation for all that you do. I'm leaving the company in good hands with Bill Thomas. I intend to keep my personal EOG stock holdings for a long time. Thanks for listening. We'll go to Q&A.
Thank you, sir. The question and answer session will be conducted electronically. If you'd 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're 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'll take as many as time permits, once again, that is star one on your touch-tone telephone to ask a question. If you find that your question has been answered, you may remove yourself from the queue by pressing star two. We'll pause for just a moment to allow everyone the chance to signal. First, we'll go to Leo Mariani with RBC.
Hey, Leo.
Hey, guys. Just a question on fourth quarter guidance here. Clearly, you had really robust oil production growth in Q3. You guys are guiding to sort of lower increases in Q4. Just can you give us some color around that? Is that just a function of trying to stay within your CapEx budget this year?
Yeah, Leo, let me put it in a little bit of context. If you go back to 2012, in 2012 over 2011, we grew our oil production 39% that year. Actually, our Q4 oil production actually declined versus Q3. If you remember, there was a lot of concern as we exited 2012. People were saying, "Oh boy, I'm nervous about EOG's 2013 oil growth because the trend line is Q4 production was falling relative to Q3, it doesn't look good." Look at our results for 2013. We grew our oil production again 39%. If you look at it in a historic context, people shouldn't be too nervous. We're projecting, actually, we're going to not fall in oil production. We're going to slightly grow in oil production Q4 over Q3. There are some specific reasons for that.
One is we're going to be drilling some isolated leaseholder wells more than typical, which as opposed to drilling more groups of wells, particularly in the Eagle Ford, and also some potential weather conditions in the Bakken. If you just look at the 2012 trend, then look at what we're projecting for 2013 in the fourth quarter, I think that should ameliorate any concerns about what we're likely to do in 2014. I'm not projecting we're going to do another 39% oil growth in 2014, because obviously, the law of big numbers is going to catch up with us on percent year-over-year. No one should view the situation that oil growth in the fourth quarter is likely to slow down our trend of significant oil growth in 2014.
Okay. That's really helpful color. I guess just in terms of frac technology, obviously, you guys have talked about a lot better completions in the Bakken. I'm certainly assuming that that's going to be applicable to other areas, the Eagle Ford, Permian, et cetera. Can you guys give us a ballpark on what inning we are in terms of just improving frac techniques and completions? Is this the early days here, and can we expect a lot better improvements and recoveries in your key plays going forward?
Yeah. No, that's a good question, Leo. The frac technology that's really making a big impact in the Bakken is actually we brought that from the shale plays, which is mainly the Eagle Ford type completion process that we've been so successful in that play with. It's improving really in all of our plays. It's basically there's a lot of simple fundamental things. We've had a big advantage with our EOG sand. As a company, it's not only provided very low cost, and help us to reduce our completion cost, it's also really helped us technically to be able to experiment more, to use more sand, and that is a big part of the reason our wells are much better.
I would say we're probably in the fifth or sixth inning, if you had to put it in baseball terms on where we are on the completion technology process. We continue quarter-by-quarter to make advances, and we're learning all the time. The EOG culture is that we're never satisfied, and that we never quit thinking and experimenting and trying new things and really thinking out of the box on new technology in all areas. We're going to continue to press on, and we're hopeful that we'll have continued new improvements as we move along.
That's great to hear. Thanks a lot, guys.
We'll go to Doug Leggate with Bank of America Merrill Lynch.
Doug, Mark, congratulations. You left a heck of a legacy behind you. I got a couple of questions, if I may. Maybe a follow-up on Leo's on the completions. There's been a lot of chatter, obviously. I think you guys have been out and about talking about some of the things you've been doing, in particular in the Bakken, as you've transferred some of your Eagle Ford learnings. Could you just help us a little bit with how you're seeing the impact of some of these changes in terms of very, very high IP rates, obviously, but is this also translating into higher recovery rates? If so, I guess I'll ask this question the last call, why have you not yet decided to lift your EURs, particularly in the Eagle Ford?
That's a good question there, Doug. Thank you. The whole process on all these horizontal wells is connecting more of the rock to the well, we're very focused on doing that. Also, with a real strong effort on the frac geometry, trying to keep the fracs closer to the well. If you connect more rock, you are hopeful that the total recoveries of the field will go up, but we've not really proven that yet. We've proven it two times with two generations of down-spacing in the Eagle Ford, and we're currently on the third one. So we're really watching what we're doing. It takes quite a bit of time to establish and determine specifically if there is any increase in reserve potential or changing of the EUR per well. We're just not there yet on this third generation in the Eagle Ford.
When we get that done, we will certainly pass that on. It's going to take a bit more time. We want to be able to technically be accurate and define any numbers that we give to you. We're very careful to do our homework and to do our work right and to provide you really with accurate numbers. That process does take some time.
Okay. Thank you for that.
Yeah, Doug.
Go ahead, sorry.
Yeah, a little addition on that. It's our view that the industry has just been a little bit flippant with numbers. Reserves have been just floated about on essentially all plays, billion barrels, 5 billion barrels, BOEs, and it's just been numbers that we think has just cheapened the reserve estimating system a little bit by people just throwing numbers out offhand. EOG has not really joined that party. We, on the other hand, have been very cautious, very judicious in the numbers that we've given. We like to think we set our standards a little bit higher than most other companies have done when they've issued reserve numbers. Particularly with the Eagle Ford, we just take a lot longer to qualify our numbers before we issue them. That's a little bit of the difference.
I'd like to say our standards are higher before we issue numbers on the Eagle Ford, but we are certainly reviewing it. When it meets our exacting standards for a potential reserve upgrade, we will certainly let everyone in the investment community know.
Thank you. My follow-up, for a very quick one. I guess we're all watching your balance sheet improve and expecting a step into free cash flow next year. Should we, given your comments on stepping up activity, should we be thinking that you're again spending cash flow next year, but obviously with a substantial step-up in activity? I'll leave it there. Thanks.
What you should read through on the comments we made on the 2014 CapEx is that if oil prices stay where they are now, that we will likely step up our CapEx over the 2013 levels. That's the only thing we are really saying at this point. We haven't made any comments relating to free cash flow or anything at this point, but we should be in a decent position relating to that. We are looking at accelerating our overall CapEx. The degree of acceleration is yet to be determined, Doug.
All right. Thanks again. Congratulations again, Mark.
Thank you.
Next we'll go to David Tameron with Wells Fargo.
Hi, I'll echo what Doug said. Mark, congratulations on building the company and doing what you've done there.
Thanks, David.
Let me just take the free cash flow question one step further. If we think about, you start looking at next year, and you can choose whether or not to generate free cash flow. If you look out to 2015, pretty powerful cash flow generation. How should we think about how you guys are going to allocate capital over the next two years?
Yeah, David. Yeah, we are set to have very strong cash flow growth in the company. We've given guidance on the kind of the priorities that, number one, we want to continue to have a healthy increase in the rate of dividend growth in the company. That's number one. Number two, we're committed to being a low-debt company and to work that net debt to cap ratio gradually downward over time. The big part of the capital, what's left over, will go to our best plays. We're going to be very focused on capital discipline and capital efficiency. We're going to focus the capital where we can achieve the highest rates of return. Fortunately for EOG, we have a lot of opportunities.
Of course, we're getting very high rates of return on the Eagle Ford, and the Eagle Ford will continue to get more money each year. The Bakken, with the dramatic improvements we've had in it, is now equal to the Eagle Ford in returns in excess of 100%, so it will get more money each year. We've built the Leonard play into a very successful play and have a very large inventory in that play also with 100% rates of return.
those plays will be first on the list to get more capital each year. The company is really in great shape to continue to grow cash flow strongly and also to have very strong capital returns and capital efficiencies as we go along.
Okay. Let me ask a little bit different way. If I think about 2015, could you throw out, can the organization today handle another $1 billion, $1.5 billion of capital, above what you do in 2014? Should we look for, obviously, balance sheet's down. Are you guys looking at any type of dividend increase? I'm just trying to figure out for 2015 free cash flow numbers. What happens with that?
Yeah, I think, we're going to have to be a bit cautious on giving guidance for 2015 at this point. We'll see how that all goes along. As I said, the capital efficiency and the return on the reinvestment capital is really our primary focus. I believe we can continue to improve that over time, which will directly go to the bottom line of the company. We're going to be very focused on that and be very diligent about spending and staying disciplined. As I said, the dividend increase certainly will be the first part of our priority, and we'll just discuss that as we go along and kind of watch the returns of the company and where we are on a capital basis.
All right. I'll let somebody else jump on. Thanks for the color.
Next we'll go to Pearce Hammond with Simmons & Company.
Good morning, congratulations, Mark, for a well-deserved retirement.
Thanks, Pearce.
My first question is in the Eagle Ford. You had a nice downtick in your drill times, down to nine days. Previously, you were at less than 12 days. Just curious, using that baseball analogy from earlier, how many innings, what sort of innings do you think we are in as far as those drill times in the Eagle Ford?
As far as the Eagle Ford, with us saying nine days, we would say probably again, we're in the sixth, seventh inning there. We're just continuing to work on our consistency. We've had many wells that are quite a bit faster than that. We're pleased with the improved consistency with our drilling operations here.
What the record day is?
Yeah, our record day is five days.
Thank you. Then my follow-up, just coming back to the activity, as it relates to next year, the preview on the 2014 guidance that you provided in the prepared remarks. Do you think that this means a higher rig count as well as higher well count or more a flattish rig count, but given the improvement in drilling times, et cetera, that we would see a higher well count?
We expect that our rig count's going to be similar to what we had this year. We had a peak this year of 56 rigs. We're probably average somewhere around 50. We expect just continued improvement with rig efficiencies. We've upgraded our entire rig fleet, and we fortunately now have, what I guess you'd classify as just premium rigs.
Excellent. Thank you very much, and congratulations, Mark.
Thank you.
Now we'll go to Charles Meade with Johnson Rice.
Good morning, everyone, and thank you for taking my question. This may get to the capital allocation part of your discussion here. Looking at the results up in the Bakken, it looks like you've had great results, not only with that infill program in the core, but also with the Three Forks over in the Antelope extension. Can you talk a little bit about how you're thinking of prioritizing the incremental ramp in that area between those two efforts?
Yeah, Charles. We have had some very excellent results. As we've talked about, we've had a number of good wells in the Three Forks in the first bench, and then we did complete an excellent well in the second bench this year. These recent wells have all been done with the same new completion technology that we're using in the core that's been very successful. We have, particularly in the Antelope area, we do believe that we have potential in the third bench and possibly in the fourth bench in the Antelope. As time goes along, we'll be testing those and working on what kind of development patterns and spacing that we can develop the whole Three Forks interval. There are other areas in the Williston Basin Bakken acreage that we do feel like there could be additional Three Forks potential that we've not drilled.
That's a step-by-step process as we go along and learn more about the Three Forks. As we said, we're getting extremely strong rates of return in the Bakken. We have 12 years of inventory there, and so, as next year and the years go on, we believe that we'll be drilling more wells each year in the Bakken. That whole Bakken Three Forks has, even with our modest drilling this year, we've been able to continue to grow production there, and we're setting production records there
Quite often in the Bakken, even with the modest program. We've got some good expectations as we go forward.
Got it. Thank you for that detail, Bill. One other thing, this is maybe a little bit more conceptual. I really appreciated those new slides where you're showing the 2013 vintage wells versus the 2012, about how the cumulative production, you've had that 20% or 30% or 50%, 60% increase. I was wondering if you could characterize that as how much of that is a function of more capital that you're putting into the well, whether through more stages or bigger fracs, and how much of it is more kind of a free benefit from a better design?
Yeah. There's several things going on. Obviously, those are normalized on a per-foot basis, so that takes out the lateral length. As we have learned in all these plays, as I said before, connecting up more of the rock and connecting that rock up closer to the wellbore is the goal that we're working on. As we increase the amount of sand that we put in the Bakken, we feel like we're also doing a much better job of distributing that sand and the fluid frac along the lateral more evenly. That helps to connect more rock, and get more of the oil in contact with the well. What we're seeing on these wells with the new improved fracs is that they come on at really nice IPs, as we reported, but they also have a little slower decline rate than the initial wells.
They hold up better. The initial, whether it's a 30-day rate or the initial 100-day cumulative production, are showing quite a bit of improvement because we're moving that oil forward in the production life of the well. It's a nice, good, successful technical renaissance that we're achieving there in the Bakken and seeing really good results because of it.
Thank you very much, Bill.
Now we'll go to Irene Haas with Wunderlich Securities.
Hello, Mark. This is Irene. Congratulations, we will very much miss you in this capacity. We hope to see you around the oil patch. One last question, why 2018 as the year that we would see the light at the end of the tunnel and then a way out to the gas glut?
Yeah. I'm going to miss you too, Irene. I believe in 2018 is when we'll have the first significant impact of gas imports, exports, excuse me, in the way of LNG from these converted former LNG import terminals. I think that's when we'll really have the first meaningful impact. I think that may have some impact on prices. That's kind of the way I see things.
Okay, great. Thank you.
Okay.
Next, we'll hear from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Hey, Brian.
Mark, congratulations and best of luck as well.
Thanks.
You mentioned greenfield exploration remains a commitment. I wonder if even if you can't provide specifics, if you could characterize what we should expect from your exploration program in terms of size or production impact in the next few years, and how impactful brownfield opportunities like water floods in the shales could be?
Yeah, Brian. Certainly, as you said there and noted that exploration is not lost any focus or momentum in EOG. We still have the same people, the same culture, and the same focus on that. I truly do believe EOG will continue to be a first mover in that area as we go forward. As you also noted, we're very reticent about talking about new plays for a number of reasons. We really don't want to talk about any specifics of those plays until we have some meaningful results to report. Then in the secondary recovery efforts, I think EOG will also be a leader. We don't know of any other companies really working on secondary recovery in the Eagle Ford.
As we've reported earlier, we have a dry gas injection pilot program going on at Eagle Ford. That will take a good bit of time to determine whether that's going to be successful and whether that's the proper method on that. Then we'll also have water injection pilot going on in the Bakken. That'll take some time too. We fully are committed. I really do expect that EOG will be a technical leader in these shale plays and new plays, in secondary recovery, and also cost reduction. We've just got a culture in the company that is very focused on all that. We're going to be taking that forward.
Brian, this is Mark. Let me add something to that because I did get a chance to glance at your note this morning where you made a comment or words to the effect that EOG's valuation was still quite low because there seemed to be a perception that EOG didn't have the reserve life that companies who really didn't generate the production growth that we had were exhibiting because of the difference in reserve life. EOG was perceived to have great production growth, but not as long a reserve life. Here's two real-world examples from the two biggest oil assets in North America relating to EOG. At the beginning of this year, I think most everybody viewed EOG's Bakken position as kind of a static position, kind of a non-growth position. Look at it now. Now, we're making the best wells in the Bakken.
We view it as a considerable growth position, and we're quite excited about it, and I believe that everybody is looking at it as a growth position for EOG on a go-forward basis. Second one is Eagle Ford. A year ago, everybody said, "Yeah, EOG's hitting grand slams daily in the Eastern Eagle Ford, but in the Western Eagle Ford, everybody knows lower quality and EOG's not going to do as well in the Western Eagle Ford." That was just 12 months ago. Look at our results now. We're getting 100% rate of return in the Western Eagle Ford, and we're getting 200% rate of return in Eastern Eagle Ford. The highlight of our last two earnings calls in Eagle Ford has been the Western Eagle Ford.
In the span of 12 months, we have taken our two best oil assets and taken what was perceived to be kind of weaknesses, lack of growth in the Bakken and Western Eagle Ford, and turned them into major strengths in both areas. That's one thing that I think you'll continue to see from EOG, is that the Eagle Ford and the Bakken, the two best oil plays in the U.S., are going to continue to turn out to be overall grand slams for EOG for at least the next decade plus, in addition to the greenfield work and the secondary recovery work we have.
We hope that our investors would see the lessons that have shown up here in the last year, and certainly take a look and say, "Who's generating the results among all the E&P companies?" We think results matter, and we'll stack our results up against any company in the business.
Thanks. Oh, go ahead.
Okay.
Yeah, thanks. That's helpful. I guess, as a follow-up, shifting to the Permian Basin, you mentioned in your opening comments that you're going to start doing the multi-well spacing and targets in the Delaware Basin, starting with some microseismic. Can you just add some color on what your base case expectations for multi-well development would look like, and how oily the zones you're planning on developing are?
Yeah, in the Delaware Wolfcamp, we're focused on a very nice sweet spot in the Wolfcamp there. To date, we've completed 4 wells there in 3 different pay zones, and those pay zones are located in the upper part of the Wolfcamp. The upper part of the Wolfcamp, we believe, will tend to be a bit more oily than the lower parts of the Wolfcamp. We'll be testing additional zones there. The actual Wolfcamp thickness there is very thick, like somewhere around 2,000 feet of total thickness to work with. There are numerous additional pay zones that we have not targeted or tested yet.
The goal is, we're completing a couple of patterns now on different well spacing and different targeting geometries, and we will do some microseismic on some of those and work on the frac geometry, on how to contain the frac close to the well and to make it more complex to where we're connecting more rock. Just see what that is in respect to the spacing that we're drilling the wells on and also the production results of all those different things we're going to do. It's a process that will take some time. It will take several years, really, to figure out the most optimum way to do it, just like it has been in the Eagle Ford.
The recovery factors for the total Wolfcamp at this point are very low, our goal would be to hopefully increase those recoveries as we go along. We've got a lot of work to do there. The good side of all this is that this Delaware Wolfcamp will already have target rates of return of 60%. It's a very strong rate of return play for us already, and hopefully, we can improve as we go along.
Thank you.
That's it.
We'll go to Biju Perincheril with Jefferies.
Hi, good morning. Congratulations, Mark. My question is, if I could go back to the new completions one more time and look at the, Mark, I think you mentioned that you're consistently seeing better 30-day rates and, I think, 90-day rates. If you look at the decline curves of the new completions versus the previous completions. Are you seeing that the higher rates holding up or do you see the curves eventually converging? Wondering why the hesitancy on commenting on-
Biju, do you have that on speaker?
Can you hear me better now?
Yes, Biju. Thank you.
Okay. Sorry about that. Yeah, I was wondering about the decline curves on the new completions versus the older completions. Are you seeing the two curves, the new curves consistently staying higher, or do you see them eventually converging as you get to the tail portion of the production curve?
In the Bakken?
In the Bakken. Well, new completions in general in the Bakken and Eagle Ford.
Yeah, in the Bakken specifically, yeah, we are seeing that the initial part of the production of the well are holding up, and the decline rates are a bit flatter than the older wells. It's because the fracs are bigger and more extensive, and we're just connecting more rock with these new completions than we did with the original wells that we completed in there. In the Eagle Ford, we've got multiple things going on there. We're down-spacing as well as working on frac technology at the same time. We're still in the process of learning about that. I would say, comparing the Eagle Ford decline rates is maybe a bit more difficult than the Bakken at this point.
The hesitancy on commenting on reserves, whether you're seeing how much of an EUR uplift that you're seeing, is that simply wanting to see more of that data, or are there other factors that come into play here?
Yeah, no. Specifically, we need more time because you just can't go by the early time of the well. You really need to have enough production time to get a good read on the total production of the well. Again, as Mark commented, we're very cautious about coming out with new EURs per well or new recovery factors for any of our plays until we've had the very thorough technical review of that and had enough time to really evaluate it and to make a good call on it.
All right. Thank you.
Next, we'll go to Phillips Johnston with Capital One.
Hey, guys. You alluded to this in your prepared remarks, your Eagle Ford wells continue to generate returns above 100%, even in the West now, which likely suggests suboptimal spacing. Obviously, down-spacing continues to be a work in progress, and it's going to take more time. I'm just wondering how you're thinking about the trade-off just between per-well returns and NPV per section, whether or not you think it makes sense for further down-spacing to accelerate NPV per section, even if it means the returns fall down into, call it, the 50%-75% range.
Yeah, that's exactly what we're doing. We are very focused on the NPV of the asset and the particular lease. The returns are certainly a part of that. We're also reducing cost at the same time in the wells. It's a balancing act. We're very focused on generating the maximum NPV for that particular lease or that particular asset. That's the goal that we're focused on. That's the reason it takes a bit of time to determine that. You have to do things and then give the wells enough time to respond and then to monitor that and to model that.
Is there a minimum per-well IRR that you'd be willing to live with if it meant accelerating the NPV?
No. Accelerating the NPV is the goal.
Okay. Got it. Just getting back to the subject of free cash flow. At this point, it looks like even your Eagle Ford program is now free cash flow positive. I'm just wondering if you've reconsidered at all sort of the strategic value of keeping some of your mature legacy assets. If so, does it now make sense to monetize some just to sort of highlight the NAV of your growth assets?
I think over the last several years, we've sold $4 billion of assets. It's not likely in our 2014 plan that we're going to have significant asset sales as we'd see it now. I think right now, maybe several hundred million dollars worth of asset sales, not a large amount of asset sales as we see it now. Don't look for a big strategic repositioning as you may be suggesting along those lines.
Okay. Thanks, guys.
Yeah.
That's all the time we have for questions today. I'd like to turn it over to Mr. Mark Papa for any more additional remarks.
The only remark I'd say is I'm going to miss you all. Thanks for everything.
That does conclude today's call. We thank everyone again for their participation.