Good day, everyone, welcome to the EOG Resources first quarter 2013 earnings results conference call. Just as a reminder, today's call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chairman and Chief Executive Officer 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 first 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, including those for the Delaware Basin and Eagle Ford, may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release in Investor Relations page of our website. With me this morning are Bill Thomas, President, Gary Thomas, Chief Operating Officer, Tim Driggers, Vice President and CFO, and Moira Baldwin, Vice President, Investor Relations. An updated IR presentation was posted to our website yesterday evening, we included second quarter and full year guidance in yesterday's press release. This morning, we'll discuss topics in the following order. I'll first discuss our 2013 first quarter net income and discretionary cash flow. Bill Thomas and I will provide operational results.
I'll discuss our 2014-2017 business plan, Tim Driggers will discuss financials and capital structure. Finally, I will cover our macro view, hedge position, and concluding remarks. As outlined in our press release, for the first quarter 2013, EOG reported net income of $494.7 million, or $1.82 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 first quarter 2013 adjusted net income was $489.9 million, or $1.80 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the first quarter was $1.7 billion. I'll now address our operational results in key plays. We hit on all cylinders in the first quarter.
Our oil, NGL, and North American gas volumes considerably exceeded our guidance, and for the second quarter in a row, our unit costs beat guidance and domestic oil prices were at a significant premium to WTI. Therefore, we beat on volumes, costs, and net backs. The biggest profit driver, of course, was oil, and 100% of our oil outperformance emanated from the Eagle Ford. Oil production from all other sectors of the company was at expected levels during the quarter. Taken as a whole, EOG's first quarter financial performance shows the power of scale and efficiency when applied to sweet spot oil resource plays. I'll now discuss our key oil plays, starting with Eagle Ford. The Eagle Ford surprised us in an upside manner similar to what it did during each of the first three quarters of 2012.
You may recall that EOG grew its oil production domestically 46% last year, primarily because the Eagle Ford significantly outperformed for the first nine months. During the fourth quarter, we reduced the Eagle Ford CapEx for budget reasons, and the production scaled back accordingly. Some people may have misread the fourth quarter as an indicator that the Eagle Ford growth rate was slowing. During the first quarter 2013, EOG's U.S. oil production increased 24,200 barrels per day over the fourth quarter 2012, primarily due to the Eagle Ford. As these first quarter results indicate, the Eagle Ford continues to outperform our estimates as it did over the course of 2012. The rate of change from this asset is not slowing. During the first quarter, we completed 27 monster wells in the Eagle Ford with IP rates greater than 2,500 barrels of oil per day.
Nine of these had IP rates greater than 3,500 barrels of oil per day. Note that these rates are oil per day, not barrels of oil equivalent per day. Additionally, the wells on our western acreage continue to improve as we drill longer laterals and improve our fracs. Many of these western wells exhibit flatter declines than the prolific wells from our eastern acreage and have net reserves of 500,000 to 600,000 barrels of oil equivalent per well, which is outstanding. As we continue to develop this asset, we continue to add additional drilling locations in both the east and the west. As expected, our first quarter direct drilling after-tax reinvestment rate of return in the Eagle Ford exceeded 100%. To summarize the Eagle Ford, this asset has the best large play economics in North America and continues to provide upside production surprises.
One additional positive occurrence we've noted throughout our domestic operations is that there's currently more downward rather than upward pressure on service costs. Because our CapEx dollars will go farther, we now plan to drill 425 net Eagle Ford wells this year. I'll now turn it over to Bill Thomas to discuss other domestic plays.
Thanks, Mark. I will start with our good news from the Bakken Three Forks. We have two important items to report from the first quarter. First, we continue to have excellent results from our 160-acre downspacing test in the Parshall Core area. Second, we tested the second bench in the Three Forks on our Antelope extension acreage with outstanding results. Two recent 160-acre downspace wells in the Parshall Core area are the Van Hook 20-107H and 127-107H, which came on production flowing 2,375 and 2,170 barrels of oil per day, respectively. We have 55% working interest in these wells. Along with the new wells, our previously reported 160-acre wells continue to outperform our expectations. The vast majority of the planned 53 completions in 2013 will be drilled on 160-acre spacing.
As we continue to gain confidence in downspacing results over the course of 2013, we will likely increase the level of drilling activity in 2014. As I noted, we just completed our first well in the second bench of the Three Forks in the Antelope extension area with outstanding results. The Riverview 3-3130H came online producing 3,150 barrels of oil per day. We have 94% working interest in this well. We also completed another Three Forks well in the first bench or our uppermost zone. The West Clark 101-2425H had initial production of 2,205 barrels of oil per day. We have 100% working interest in this well. The Three Forks and Bakken results on our Antelope extension acreage continue to look strong. We are particularly excited about the potential of the Three Forks second bench.
Early looks indicate that this target may have better potential than the first bench and the Bakken pays in this area. We plan to test the third bench of the Three Forks in this same area next year. In summary, we are encouraged by our solid downspacing results in the Parshall Core area and excellent results from multiple Three Forks pays in the Antelope extension area. As we reported on our February call, we are applying new frack techniques in the Parshall Core and Antelope area. The new wells are outperforming the original wells that we drilled several years ago. This has resulted in improved direct after-tax rate of returns from our drilling program, giving us current Bakken returns that are comparable to our Eagle Ford program. The results continue to set us up for many years of excellent drilling in the play.
With our new techniques, we believe EOG will continue to lead the industry in Bakken and Three Forks drilling results. In the Delaware Basin, we continue to have excellent results in the Leonard play. We have four new wells to report. During the first quarter, we completed the Vaca 24 Fed Comm 2H, 3H, and 4H, flowing 1,230, 1,410, and 1,205 barrels of oil per day, respectively, with 140 and 230 barrels of NGL per day and 780, 760 and 1,290 MCF per day of natural gas, respectively. We have 90% working interest in these wells. We also completed the Vanguard 30 State Comm 1H with an initial flowing rate of 1,540 barrels of oil per day, 165 barrels of NGL per day, and 915 MCF of gas per day. We have 100% working interest in this well.
Our Leonard results remain strong, and we continue to work on improving the recovery factor by identifying multiple pay targets, improving frack technology, and testing the optimal downspacing. We also completed our third Delaware Wolfcamp well, which confirms our positive outlook on the potential of our newest play, which we discussed in February. We completed the Apache State 571101H in the Upper Wolfcamp pay and turned it to sales flowing 815 barrels of oil per day, plus 600 barrels of NGL per day and 3.8 million cubic feet of gas per day. We have 100% working interest in this well, which is located in Reeves County, Texas. Pilot logs from this well confirm excellent Wolfcamp pay on our acreage, and a microseismic survey performed on our second completion, the Harrison 56-1001H, provides further confirmation of good frack geometry.
Every piece of data we receive on the Delaware Wolfcamp is most encouraging. This particular play has excellent shale rock properties and when combined with the massive amount of resource in place on our sweet spot acreage, has the characteristics of a high-quality horizontal resource play. In this new play, we've identified over 1,100 drilling locations with EURs of 700,000 barrels of oil equivalent net per well. On our 114,000 net acres in the play, we've estimated 800 million barrels of oil equivalent of net potential reserves. We've now drilled three horizontal wells to date and regionally have over 200 penetrations and data points from previously drilled vertical wells. In summary, the Delaware Basin and Wolfcamp plays have a combined reserve potential of 1.35 billion barrels of oil equivalent net to EOG, using a conservative 2%-3% recovery factor. We hope to improve this over time.
Regarding the Midland Basin Wolfcamp play, during the first quarter, we continued to make steady progress on optimizing our frack technology. This is an important process to help determine the optimal well spacing and to increase the recovery factor of the play. Recent pattern completions include the Munson 105H, 106H, and 107H, flowing 965, 970, and 1,290 barrels of oil per day, plus 55, 60, and 100 barrels of NGL per day, and 400, 430, and 730 MCF of gas per day, respectively, from the middle zone of the Wolfcamp. We have 85% working interest in the Munson wells. Other new wells are the University 40D, 701H, and 702H that began producing at 705 and 660 barrels of oil per day, plus 95 and 75 barrels of NGL per day, and 685 and 550 MCF of gas per day, respectively.
We have 80% working interest in these wells, which are also producing from the middle zone. The Midland Basin Wolfcamp is a solid play. It is technically more challenging than our Delaware Basin play. It is taking more time to establish optimal frack techniques and spacing. We are making progress and will update our reserve potential in this play as we learn more in the future. In our Barnett Combo play, a combination of good well results and lower well costs netted solid returns during the first quarter. This is an area where we've accomplished excellent drilling and completion performance and seen reductions in service costs. We are seeing a 10%-15% decrease in well cost for the play as compared to last year.
Examples of excellent wells are the Reed B unit number 1H and 2H, which came online flowing 605 and 515 barrels of oil per day, with 65 and 60 barrels per day of NGLs, and 445 and 390 MCF per day of gas, respectively. We have 100% working interest in these wells. We have reduced our Barnett Combo activity to three rigs, but drilling times and well costs continue to improve, and we are still on track to drill approximately 130 net wells in 2013. We are also continuing to look for new greenfield North American liquid plays. We believe we have a technical advantage in identifying the best rock and capturing the best acreage. Our positions in the Bakken and Eagle Ford confirm this. Now I'll turn it back to Mark.
Thanks, Bill. I'll briefly discuss our plays outside North America. In Trinidad, our first quarter production was as projected. We're in the midst of a drilling program off our Osprey platform that will help to maintain flat overall production in 2013 and 2014. In the East Irish Sea, the startup of our Conwy Oil project has been delayed until early 2014. For this reason, we're keeping our full-year total company oil growth target at 28%, even though we significantly outperformed in the first quarter. We have, however, increased our U.S. oil growth estimate by 4% this year due to our Eagle Ford strength. In addition to having captured sweet spot positions in crude oil resource plays, another EOG differentiator is our domestic crude oil realizations and margins.
During the quarter and currently, our Eagle Ford crude is priced off an LLS index, as is our Bakken and part of our Permian crude, which is being railed to our St. James terminal. The majority of our domestic crude volumes are linked to LLS rather than WTI prices. This access to premium markets resulted in a $12.23 per barrel premium over WTI during the first quarter for EOG's U.S. crude oil volumes. We expect to achieve a $9.25 premium in the second quarter using the midpoint of yesterday's guidance. Now I'll discuss some longer-term implications emanating from our asset base. On this call, we've described our three main domestic oil assets in the Eagle Ford, Bakken, and Delaware Basin.
We feel the addition of the Delaware Basin, Leonard, and Wolfcamp assets that we announced in February moves EOG past a key threshold and allows us to talk with confidence about what EOG will look like five years out. Today, we have sufficient confidence in our asset base to provide directional guidance for 2014 through 2017, with the caveat that WTI oil prices remain at or above $85. Under that assumption, we believe EOG will continue to have the highest oil growth rate during 2013 to 2017 of any large cap independent, similar to our performance of the past three years. We expect our 2014 to 2017 NGL growth to be at or near top tier. Our 2014 to 2017 North American gas production should reverse its negative trend and begin to increase, even though we'll drill very few dry gas wells.
This is a result of our combo play activity and associated natural gas production. Outside of North America, EOG produces natural gas in Trinidad and China. We expect that production to be essentially flat during the 2014 to 2017 timeframe. When you combine this mix, you'll likely calculate strong overall total company production growth underpinned by very strong high margin oil growth. The conclusion from this overview is that EOG is likely to exhibit one of the highest overall production growth rates, combined with the single highest oil growth rate of the large caps for at least the 2014 to 2017 period. All the growth is sourced domestically. This should yield significant net income and overall free cash flow even at a flat $85 WTI oil price. When considered on a debt adjusted basis, the growth rate is even higher.
EOG can accomplish this production net income and cash flow growth while maintaining a strong balance sheet. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, Mark. Capitalized interest for the quarter was $10 million. For the first quarter 2013, total cash exploration and development expenditures were $1.6 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant, and equipment were $92 million. As compared to the first quarter of 2012, total cash expenditures decreased by $350 million. There were no acquisitions during the quarter. Through May 1, we have closed on asset sales of approximately $500 million. At the end of March 2013, total debt outstanding was $6.3 billion, and the debt to total capitalization ratio was 31%. At March 31, we had $1.1 billion of cash on hand, giving us non-GAAP net debt of $5.2 billion, for a net debt to total cap ratio of 27%. The effective tax rate for the first quarter was 35%, and the deferred tax ratio was 75%.
Yesterday, we included a guidance table with the earnings press release for the second quarter and for full year 2013. For the second quarter, the effective tax rate is estimated to be 30%-40%. For the full year, the effective tax rate is estimated to be 35%-45%. We've also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. I'll turn it back to Mark.
Thanks, Tim. I will provide our views regarding the macro environment, hedging, and crude by rail. Regarding oil, we believe full year WTI prices will average in the low 90s, similar to the past two years. However, as our total company cash flow becomes more dependent on oil, we have changed our oil hedging philosophy, such that we plan to target an approximate 50% hedge position for the forward year. For the second half of this year, we have 93,000 barrels of oil a day hedged at $98.44. Currently, we have 42,000 barrels of oil a day hedged for the first half of 2014 at $95.86. These numbers exclude options that are exercisable by our counterparties. Regarding North American gas, we recently added some May through October 2013 and some full year 2014 hedges.
We don't have a target hedge percentage. We have viewed the April gas price upsurge as a hedge opportunity. Although the WTI-LLS differential has recently contracted from $20-$11 a barrel, it's still very advantageous for us to move oil by rail from the Bakken, Permian, and Barnett Combo to St. James. We have contracted capacity on a Houston to Houma pipeline later in the year and will have the flexibility to move our Eagle Ford oil east from Houston to refineries in Louisiana, which are priced off the LLS index. I'll now briefly address our 2013 business plan, which is consistent with what we outlined on our February call. We still expect our total CapEx to be between $7.0 billion and $7.2 billion, and proceeds from dispositions to be approximately $550 million.
Our full year production growth targets are unchanged at this time. We've slightly reduced our full year LOE and DD&A estimate. Even though natural gas prices have strengthened, we don't intend to drill any additional dry gas wells this year. Now, let me conclude. There are eight important takeaways from this call. First, as evident by our results, EOG is firing on all cylinders: volumes, unit costs, price realizations, and returns. Second, our first quarter reinvestment rate of return on our drilling capital program was the highest in the company's history, led by the Eagle Ford and North Dakota Bakken investments. Third, the Eagle Ford is leading the pack and drove our first quarter oil outperformance.
Fourth, our first quarter Bakken drilling rate of return rivaled our outstanding Eagle Ford triple-digit returns. Our initial test of the second bench of the Three Forks flowed at 3,150 barrels of oil per day. Our overall North Dakota results are much better than the industry average because we are drilling 160-acre down space wells in the best acreage in the entire play. Fifth, our recent Delaware Basin Leonard performance has been excellent and will ramp up this play in 2014. Our third Delaware Basin horizontal Wolfcamp test confirms this area as a third key asset in our portfolio. Sixth, we're seeing downward cost pressure across the board. Seventh, I've walked you through our five-year outlook.
We have all the assets in place to achieve best-in-class, organic, high rate of return, domestic crude oil and NGL growth. Our North American natural gas production should flatten out next year and then begin to increase. Beginning in 2014, provided WTI oil prices stay at current levels, we expect to have strong total company production growth and begin to generate free cash flow. Finally, our succession plan is consistent with what we previously reported. I will step down as CEO on July 1st of this year. Bill Thomas will succeed me at that time as CEO. I will remain as Executive Chairman until Bill replaces me when I retire on December 31st with the title of Chairman and CEO. Thanks for listening. Now we'll go to Q&A.
Thank you. The question and answer session will be conducted electronically today. If you would like to ask a question, you may do so by pressing the star key followed by the digit 1 on your touchtone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to 1 question and 1 follow-up question. We will take as many questions as time permits. Once again, please press star 1 on your touchtone telephone to ask a question. We'll pause for just a moment. We'll take our first question from Leo Mariani with RBC.
Morning, Leo.
Hey, guys. Hey, how are you here? Great quarter here. Just a question on your second bench well in the Three Forks. Looked like a very strong well. I think you guys drilled out in the Antelope extension area. Do you guys think that the second bench can be prevalent across a lot more of your acreage? Just trying to get a sense of your geologic mapping and where you think that might exist on your acreage.
Yeah, Leo, we certainly think it's prospective across our Antelope Ridge area. We have enough logs and data there to verify that. On the remainder of our acreage, like in the core area, it may be prospective. We're taking additional looks at that as we speak. It's not as clear there as it is in Antelope. We're real excited about the second bench, and we're going to be testing another second bench well down the road, and then I think next year we've got plans for drilling down in the third bench. We're very excited about the Three Forks potential there at Antelope.
All right. That's great. I guess in terms of gas production, you guys said you won't drill any more dry gas wells this year, but you did say that you probably see gas production flat in North America to slightly up next year. Would you anticipate any dry gas drilling next year, or is that going to be exclusively from associated gas?
No, in the outlook through 2017 that we gave you, we generally are assuming no dry gas drilling or essentially no dry gas drilling throughout 2017 in the outlook we provided there, Leo.
I guess you guys obviously didn't necessarily quantify your overall growth, but should we think of EOG as firmly being in double-digit growth as a company over the next four years there?
Yeah, we don't want to give specific numbers, but I just say that some of the numbers that might have been penciled in previously for overall growth are probably too low, and I think we'll have surprising overall growth during the next four or five years, really. The 4% growth that we're projecting this year is not what you should expect in the 2014 through 2017 period.
Next, we'll hear from Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, everybody, and again, congratulations on a great quarter, Mark. My first question's on your guidance. Obviously, the costs have been pretty strong here and relative to what you were expecting in the first quarter. Your guiding is higher again for the back end of the year on a whole number of levels. What's different? Why should costs move back up again given the level of success that you're having? Are you just being conservative, or should we be thinking about Q1 as the more repeatable?
In terms of the budget expenditures, CapEx?
Unit costs.
More the unit costs, both the LOE and the transportation and the exploration guidance and so on.
Yeah. We're a little bit surprised by how well we came in on our overall costs for the first quarter. We're a little bit conservative in the guidance that we've given for the rest of the year, although we do think it'll be a little bit back-end loaded. I'd say on a unit cost, there is a possibility we may beat the full-year guidance on some of those. We're going to wait another quarter to see how repeatable this first quarter really is.
That would apply to the other guidance items as well? I mean, the impairment charges and the exploration charges, you've guided that back up as well. Obviously, that's a big-ticket item. Is there any reason why that should be trending higher?
We'll just be looking at it at the end of the second quarter. We just want to see what the trend is. Right now, we just want to be fairly conservative. On the production side, though, we're not signaling that we may beat on production on there at that time. We would guide you to the full-year production of the 28% oil growth and not higher than that at this time. There may be some room on some of the costs, though, and we'll reevaluate that at the end of the second quarter.
Next, we'll hear from Irene Haas with Wunderlich Securities. Hey, good morning. Sounds like a lot of good news coming out of the Bakken. My question is: What's your feeling on the Bakken differential as it stands now, understanding that Brent has come down a little bit? Just want a little color from you.
Yeah. Hard for us to guess on these differentials, where they're going, Irene. I'd be hard pressed to really hazard a specific guess. We do believe that the differential of the Gulf Coast to WTI is likely to stay more compressed than it was in the first quarter. We don't see that ballooning out. Where the Bakken is relative to WTI or the Gulf Coast, I can't give you any specific guidance on that. That would be very specific, unfortunately.
Okay. How about a little on natural gas? I noticed you guys put on some hedges, your general view probably still has not changed.
Yeah. Unfortunately, I guess our view at this point is we don't see any return to the high twos or low threes for gas in terms of 2013 or 2014 or 2015. We think we're now in a time frame when 2013, 2014, and 2015, we're somewhere in the range of likely $4 to $5 gas prices. We have become slightly more bullish than in the past, but we certainly are not in a hyper bullish mode.
Next, we'll hear from Joseph Magner with Macquarie.
Good morning. Thanks. Just curious how we should think about the guidance through 2017. I know you don't want to get into specifics, but should we expect to see a rolling update on what you're going to guide to on an annual basis? Will there be more framework to it if you have more visibility on future commodity price?
Yeah, Joe. We will probably continue just to give an annual update. It's been our experience that companies that try and give a three-to-five-year guidance, they almost immediately miss their guidance the first or second year. We're not likely to do that. It'll be likely that in February, we'll give full year 2014 guidance, and we might give a little more framework around the 2015 to 2017 guidance. Don't look for us to provide firm numbers for more than one year out as we go forward.
Along those lines, how should we start to think about the CapEx required to support that growth? To date, you've been pretty disciplined with the balance sheet, if you have continued confidence in the quality of your assets, will your treatment of the balance sheet change, or will this growth be supported by internally generated cash flow?
Our look down to an oil price, I'll just say that we ran a case at a flat WTI oil price of $85. We believe that over the aggregate period of 2014 to 2017, we will generate some significant free cash flow during that period at a flat $85 WTI oil price. During that entire period, we'll be guided by the same maximum debt limit of no higher than 30% net debt to total cap. We think that we should be in a free cash flow mode during this period, certainly at current oil prices. If you just take flat oil prices at current levels through 2017, we will be at a significant free cash flow machine based on our internal growth projections.
Next, we'll hear from Pearce Hammond of Simmons & Company.
Congrats on a great quarter. Mark, given the prolific nature of your Eagle Ford acreage, do you think there's upside to a prior forecast you'd put out on some slides where you talked about total U.S. oil production growing by 2 million barrels a day by 2015?
Pearce, we still are of the belief that the total U.S. oil production growth that happened in 2012 was perhaps the peak that is going to occur. That production growth was about 800,000 barrels of oil a day, and we expect the total growth in 2013 to be less than that, and 2014 to be less than that. We're already seeing a lesser rate of growth in the Bakken. The Eagle Ford, of course, is still steaming ahead at quite a high rate of growth. We believe that we're not going to see stupendous overall U.S. growth rates as we go forward. We think there's only really two major driving forces of U.S. oil growth, Bakken and Eagle Ford. Eagle Ford is going to surpass the Bakken, likely this year, as the biggest oil growth rate. Bakken is slowing down.
Permian is really not on that fast of a track. There's what I'd classify all others, and the all others are not growing at a very fast pace at all. We're not as concerned as others that U.S. oil growth is going to flood the total market and ruin global oil prices.
Thank you. My follow-up, in the earnings release related to the Eagle Ford, you stated that if crude oil prices remain at or above current levels, that you'll further augment your drilling program in 2014. How many rigs do you think that augmentation might imply?
In terms of rigs, not all that many rigs. To give you an idea of rigs, in the first quarter of 2012, we ran up to 76 rigs. In the first quarter of 2013, we ran 52 rigs. Now, some of those rigs in last year were drilling some gas wells. This year, we weren't drilling hardly any gas wells. What we're seeing is the rig count's probably not going to go up that much, even if we ramp up the number of wells we plan to drill, because we continue to drill at a faster pace in days per well. What I would say is, if the constant oil price continues to occur in 2014, we'll probably ramp up activity in the Eagle Ford, the Bakken, and the Permian from the activity level that we expect to achieve in 2013.
we expect we can do that and still have significant free cash flow in 2014.
Thank you.
Next, we'll hear from Charles Meade with Johnson Rice.
Morning, everyone. Thanks for taking my question. Just a clarification there. With respect to the increased activity in both the Bakken and Eagle Ford in 2014 at current prices, does current prices mean 95, or are we more talking the flat 85 that you referenced in your five-year plan?
The current prices I was just referring to would be the $94, $95.
Got it. Thank you, Mark. Then the second question I had, on those Karnes County wells, I think my impression and the general impression has been that has been maybe a tier below the fabulous acreage you have up there in Gonzales County. With the results that you turned in here, it seems like the rate of change of the results there, the second derivative of what you're getting there is better. I'm curious, has your view evolved on the relative prospectivity of these two areas, and does Karnes have a chance to be as good as Gonzales?
Yeah. As an overview, I'd say Karnes is still not as good as Gonzales. On the rate of change, are we continuing to make better wells given equal acreage? The rate of change is still quite positive in Eagle Ford. In other words, if you take essentially any piece of our acreage, whether it's in the west, the middle, or the east, are we making better wells today than we were a year ago, than we were two years ago, or three years ago? The answer is unequivocally yes.
That's why you're seeing the fact that we continue to beat our production targets relating to the Eagle Ford, because we project and say, "Okay, based on what we think the productivity is going to be based on drilling X wells for the rest of this year," we project a number, and we give it to you as our 8-K estimate. Then what we find out is, gee whiz, the actual productivity of those wells is better than we projected based on typically our completion efficiency. I can't overestimate the quality of this Eagle Ford asset. I think a lot of people, when we purposely restricted the money in the fourth quarter to the Eagle Ford, and we had clearly signaled this to the investment community before we did it.
We said we're going to slow down activity in the fourth quarter to the Eagle Ford because of budget constraints. Production slowed down. I think a lot of people misread the production slowdown in our fourth quarter and felt that the Eagle Ford rate of change had inflected downwards. That was clearly not the case. It was just that the capital, the coin-operated machine received less coins in the fourth quarter. We upped the coinage in the first quarter, and you see the results. That's why we're so optimistic, not only of what we can do this year, but what we can do in the period 2014 through 2017.
Great. Thank you.
Okay.
Next, we'll hear from Arun Jayaram with Credit Suisse.
Hello, Arun.
Good morning, guys. I wanted to elaborate a little bit more on that rate of change topic. I guess going to your slides on 21, saw a real noticeable improvement in the 30-day averages. I'm just wondering, Mark or Bill, if you could put this in context, given your shift towards tighter spacing patterns and the move out west. I just wondered if you could put that into context.
Yeah, that's a new slide we put in there, and glad you caught that there, Arun. It's pretty impressive, really, as to what we're seeing on these averages in terms there. This is on our IR slides we posted on the website this morning. You can see a steady increase if anyone wants to go take a look at that. We've got a chart there that shows 30-day production average, and then on the right-hand side of that chart, it shows on the number of drilling days versus time, and you can see improvement in there. Generally, the 30-day average is a function of the completion efficacy of what we're doing, and it also could be a function of the location of the wells.
On the completion efficacy, I'd say that we do have a bit of a secret sauce in our fracs that we're really aren't going to talk much about, but we are doing some things differently than other operators down there. This has been a change that we fully implemented really in just the last six months, and we are seeing clearly differentiating results from that. At this point, we'll just call it our own secret sauce.
Mark, the follow-up is if this continues, do you see some upward momentum perhaps to your EUR that you updated last quarter?
Yeah, we won't update that. I would look at that EUR. First point is at the current 400 MBOE net after royalty and our current well cost, we're achieving greater than 100% after-tax direct reinvestment rates of return. That for a large hydrocarbon play, I would say is likely the absolute best rate of return anyone's achieving clearly in North America, perhaps the world except for the NOCs. It's very adequate return, certainly more than adequate. We will look maybe annually at whether we could bump that reserve estimate, that's not something we're going to adjust on a quarterly basis, Arun.
Next, we'll hear from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Hey, Brian.
In the fourth quarter, you slowed activity in the Eagle Ford to stay within your CapEx budget. I wanted to see if there are any operational benefits to an end-of-year slowdown, and whether for financial or operational reasons you're expecting any slowdown in activity and completions this year.
Well, at this juncture, no, we're not anticipating any year-end slowdown as we would see it, Brian. Yeah, there probably was a kind of a catch-your-breath kind of the advantage, particularly in the Eagle Ford last year in the fourth quarter, in that we were running so hard and so fast that there probably was a bit of an advantage to just slowing down for a period. I would say at this point, it would be best to project that we will not slow down at this point. In terms of our CapEx burn rate, if you check the numbers, we consumed almost exactly 25% of our CapEx in the first quarter. Right now, our burn rate is pretty much where if we continue to burn at that rate, we'll be exactly on our budget plan. Right now, that's pretty much our plan.
Great. Thanks. Much has been made so far here on the call about the end of the period of negative free cash flow and the forthcoming positive free cash flow. In your expectations for superior growth as well as free cash flow, assuming $85 a barrel, what's your plan on what to do with that free cash flow? Would you have even more superior growth by reinvesting back in the ground to further accelerate activity? Would you more meaningfully reduce your debt or debt to tangible capital below the 30%? Would you more actively return cash to shareholders? How soon can we see some manifestation of that?
Yeah. That's a high-class problem to have. At this juncture, I would say that our priorities would likely be to establish some kind of a meaningful dividend increase, whether it's a % per year or something linked perhaps to cash flow increases or something like that. The second thing would be we potentially might set some sort of floor as to what would be the minimum net debt to cap, debt level that we think would be reasonable for an E&P company. We wouldn't just plan to pay our debt down below a certain minimum level. We're not aiming to be debt-free company or anything like that. The third thing would be likely to, once we hit that minimum debt level, would be to look at ramping up the CapEx.
We have so many projects that at these kind of reinvestment rates return, ramping up the CapEx further might be the proper path. That would be an evolutionary type decision, obviously, on a year-to-year basis and would depend on the price of hydrocarbons. The key takeaway I think that we want to convey to you at this point is that during this forthcoming four-year period, that the company would be able to achieve, even at a flat $85 WTI oil price, twin goals. A very robust production growth, particularly oil growth, as well as free cash flow, significant free cash flow. That's pretty important to note. I'm not sure there's many companies at a flat $85 oil price that would be able to say they could achieve those dual objectives.
Thank you.
Next, we'll hear from David Tameron with Wells Fargo.
Hi.
Hey, David.
Hi. Thanks for taking the questions. In the Bakken, can you talk about the downspace wells? Can you talk about how much production history you have and what those wells are doing as you get out to 60, 90 days? Do you have any color there?
Yeah, David, we've got 15 or so wells that are in various stages of production that we've completed as downspace wells. Certainly, as we talked about earlier, the original wells, which were more like 320 acre spaced wells, they certainly, with the improved frack techniques that we use, they're certainly on a per foot of lateral basis, when you normalize that, they're outperforming our older wells. It's still really early on the tighter spacing wells, the ones that we're calling, they're equivalent really of 160 acre wells. Of course, these are long laterals, and the per acres per well is variable along the thing, but they're tighter spacing. We don't have a lot of production history on those.
We put the first ones online early in the first quarter, we've only got maybe 90 days of production on those, and we're really watching that carefully because we certainly want, before we do a lot of accelerated drilling, we want to be careful and make sure that we're adding NPV. We're not over-drilling or sharing production between wells. We're watching that, our plans are is to drill the remainder of the wells this year. It's about 53 wells we're going to complete this year. Most of those will be the 160 acre type downspace wells. It's really kind of a pilot program, we're going to watch the production throughout the year. It usually takes six to nine months to verify that you're doing things correctly. We're in the middle of that, in the first part of that process.
And so
Hopefully by the end of year, we'll know a whole lot more about that and be able to give you more color on that. Certainly, we think the improved frac techniques, certainly, at this point, we're very positive about it, and we think we're contacting more rock, and that we're going to really enhancing the recovery factor of the Bakken on our core acreage. It's going well right now.
Okay. Thanks. That's helpful. Then as a follow-up to that, if I start to think about the industry, obviously it's moving, whether you believe the land grab or not is over. It seems like it's moving a much more toward a manufacturing type phase as opposed to a exploration phase. I just wanted to see how either you or Mark, whoever wants to answer the question, what do you think about that concept and how you think what North America looks like three years down the road or just lower 48? However you want to run with that. I just wanted to throw that out there and see if you had any comments on that.
Yeah. Certainly, as far as the oil plays, as we talked about, I think we're not really expecting to get another Eagle Ford or Bakken resource play of that quality and that size all tied together. As we've discussed, we have a decent list of new greenfield plays we're working on the oil side. The quality of rock for oil plays in shales is really limited. Then the thermal maturity of the oil, the window there of the right maturity of the oil is very critical too. The sweet spots are really small. What I think you're going to be seeing is, I think you're correct on this, you're not going to be seeing people announcing billion barrel new oil play discoveries and of that nature.
Hopefully, we'll be able to announce some success on some plays that would be maybe in the 50-100 million barrel or maybe even bigger than that, which is a significant value in North America. We're not going to lose our exploration edge. The industry as a whole, I think certainly is in a point right now where they really have a lot of acreage leased. The people are testing a lot of ideas and plays. I think as we've talked about all along, you're seeing the cream of the crop of the plays rise to the top, which are certainly the Bakken and Eagle Ford, we feel very fortunate that we have very large, substantial positions in those, we hope to add a few more smaller ones as we go along.
Yeah, I'll just add one thing to that. There are some combo plays that we hoped to uncover that could be substantially larger in terms of their oil content that I think are yet to be found, and we're still chasing those. There are still some substantial plays, I think, that will be uncovered that may be similar to what we're talking about out there in the Delaware Basin. Next question?
Next question will come from Joe Allman with JPMorgan.
Yes. Good morning. Thanks, everybody. In the core of the Bakken, what kind of Three Forks drilling have you done so far? Is it possible that the Three Forks 2 or 3 could be prospective without the Three Forks 1 being prospective?
Joe, in the core, I believe we've only completed maybe three or four wells in the Three Forks there. Those are, I think, I believe, are in the first bench. I think what we're noticing industry-wide, that there's a bit more success in the Three Forks than what maybe we had anticipated a few years ago. We're really taking a second look at all that, and we'll just have to see how that goes as we move on down the road. I'm sure that we'll be analyzing that and thinking about maybe drilling more Three Forks well in our core acres as we go forward.
Got you. Then in the Midland Basin, in the Wolfcamp, you indicated that it's more technically challenging than, say, the Delaware Basin. Could you talk about in what way it's more technically challenging, and what would you expect to be the outcome after you do your analysis? Are your wells overall there in line with your 430,000 BOE type curve or EUR estimate?
Yeah. The answer to the first question is, yeah, we haven't changed our EUR per well. It's still a gross 430 MBOE per well. The challenge there is kind of twofold. Number 1 is the rock quality in the Midland Basin is not quite as strong as what we see in the Wolfcamp and the Leonard plays in the Delaware Basin. The second thing is frac containment is more of an issue in the Midland Basin. As you know, at least in the areas we're working, we have three potential pay zones, so you drill a lateral in one of the pay zones, and you frac a well, and it has a tendency to grow up into the other pay zone. Also laterally, horizontally away from the well bores, we're seeing that you have interference between wells there if you're not careful.
I would say this, we're optimistic that we'll be able to solve those issues and to be able to contain the frac better vertically and horizontally. That's what it's going to take to add multiple pays to the play, multiple pay targets, and also to decrease the spacing size. We're working diligently on that, but it's more challenging than the plays in the Delaware Basin.
That is all the time that we do have for questions today. Mr. Papa, I'll turn things back over to you for any additional or closing remarks.
I have no additional remarks. Thank you everyone for listening in.
That does conclude today's teleconference. Thank you all for joining.