Day, everyone, and welcome to the EOG Resources First Quarter 2013 Earnings Results Conference Call. Just as a reminder, today's call is being recorded. And 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, and thanks for joining us. We hope everyone has seen the press release announcing Q1 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 and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non GAAP financial measures.
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 and 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 and we included 2nd 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 1st quarter net income and discretionary cash flow, then Bill Thomas and I will provide operational results.
I'll then discuss our 20 fourteen 2017 business plan and 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 Q1 2013, EOG reported net income of $494,700,000 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 Q1 2013 adjusted net income was $489,900,000 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 Q1 was $1,700,000,000 I'll now address our operational results in key plays.
We hit on all cylinders in the Q1. Our oil, NGL and North American gas volumes considerably exceeded our guidance. And for the Q2 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 netbacks. 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 Q1 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 1st 9 months.
During the Q4, we reduced the Eagle Ford CapEx for budget reasons and the production scaled back accordingly. Some people may have misread the Q4 as an indicator that the Eagle Ford growth rate was slowing. During the Q1 2013, EOG's U. S. Oil production increased 24,200 barrels per day over the Q4 2012, primarily due to the Eagle Ford.
As these Q1 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 Q1, we completed 27 monster wells in the Eagle Ford with IP rates greater than 2,500 barrels of oil per day. 9 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 1st 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 for the Bakken Tree Forks. We have 2 important items to report from the Q1. First, we continue to have excellent results from our 160 acre downspacing test in the Parshall core area. And second, we tested the 2nd bench in the Three Forks on our Antelope Extension acreage with outstanding results.
2 recent 160 Acre Downspace wells in the Parashall 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 percent working interest in these wells. Along with the new wells, our previously reported 160 acre wells continue to outperform our expectations and the vast majority of the planned 53 completions in 2013 will be drilled on 160 acre spacing. As we continue to gain confidence in down spacing 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 2nd bench of the Three Forks in the Antelope Extension area with outstanding results.
The Riverview 3,30130 H 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 1st bench or our uppermost zone. The West Clark 101-two thousand four hundred and twenty five H had initial production of 2,205 barrels of oil per day. We have 100 percent working interest in this well.
The Threefour and Bakken results on our Antelope Extension acreage continue to look strong, and we are particularly excited about the potential of the Three Fork Second Bench. Early looks indicate that this target may have better potential than the 1st bench and the Bakken pays in this area. We plan to test the 3rd bench of the Three Forks in this same area next year. In summary, we are encouraged by our solid downspacing results in the Parashall Court 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 frac techniques in the partial core and Antelope area and the new wells are outperforming the original wells that we drilled several years ago.
This has resulted in improved direct after tax rate of return from our drilling program, giving us current Bakken returns that are comparable to our Eagle Ford program. The results continue to set up 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 Plate. We have 4 new wells to report.
During the Q1, we completed the Vaca 24 FedComm 2H, 3H and 4H, flowing 1230, 1410 and 1205 barrels of oil per day respectively with 140, 140 and 230 barrels of NGL per day and 780, 760, and 1290 Mcf per day of natural gas, respectively. We have 90% working interest in these wells. We also completed the Vanguard 30 State COM 1H with an initial flowing rate of 15.40 barrels of oil per day, 165 barrels of NGL per day and 9.15 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 frac technology and testing the optimal downspacing.
We also completed our 3rd 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 571101-0.18 in the Upper Wolfcamp A and turned it to sales flowing 815 barrels of oil per day plus 600 barrels of NGL per day and 3,800,000 cubic feet of gas per day. We have 100 percent working interest in this well, which is located in Reeves County, Texas. Pilot logs from this well confirmed excellent Wolfcamp pay on our acreage and a microseismic survey performed on our second completion, the Harrison 56,1001H provides further confirmation of good frac 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 1100 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 800,000,000 barrels of oil equivalent of net potential reserves. We've now drilled 3 horizontal wells to date and recently 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 1,350,000,000 barrels of oil equivalent net to EOG using a conservative 2% to 3% recovery factor. We hope to improve this over time. Regarding the Midland Basin Wolfcamp play, during the Q1, we continue to make steady progress on optimizing our frac technology. This is an important process to help determine the optimal well spacing and to increase the recovery factor of the plate. Recent pattern completions include the Munson 105H, 106H and 107H flowing 9 65, 970, and 1290 barrels of oil per day, plus 55, 60 and 100 barrels of NGL per day and 400, 430 and 7.30 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 6.60 barrels of oil per day plus 9575 barrels of NGL per day and 6.85 and 5.50 Mcf of gas per day, respectively. We have 80% working interest in these wells, which are also producing from the Middle Bone. The Midland Basin Wolfcamp is a solid plate, but it is technically more challenging than our Delaware Basin plate. It is taking more time to establish optimum frac techniques and spacing.
But we are making progress and we'll 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 Q1. This is an area where we've accomplished excellent drilling and completion performance and seen reductions in service costs, we are seeing a 10% to 15% decrease in well cost for the play as compared to last year. Examples of excellent wells are the Reed B Unit 1H and 2H, which came online flowing 605 and 515 barrels of oil per day with 6560 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 burnout combo activity to 3 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 2014. In the East Irish Sea, the start up of our Conway 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 Q1. 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 LOS index as is our Bakken and part of our Permian crude, which is being reeled to our St. James terminal. The majority of our domestic crude volumes are linked to LOS rather than WTI prices. This access to premium markets resulted in a $12.23 per barrel premium over WTI during the Q1 for EOG's U. S.
Crude oil volumes. We expect to achieve a $9.25 premium in the 2nd 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 3 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 5 years out.
Today, we have sufficient confidence in our asset base to provide directional guidance for 2014 through 2017 with the caveat that WT 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 3 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 reduce its excuse me, should reverse its negative trend and begin to increase even though we'll drill very few dry gas wells. This is the result of our combo play activity and associated natural gas production. Outside of North America, GOG 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 1 of the highest overall production growth rates combined with the single highest oil growth rate of the large caps for at least the 14 to 2017 period and 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 $10,000,000 For the Q1 of 2013, total cash exploration and development expenditures were $1,600,000,000 excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $92,000,000 As compared to the Q1 of 2012, total cash expenditures decreased by $350,000,000 There were no acquisitions during the quarter. Through May 1, we have closed on asset sales of approximately $500,000,000 At the end of March 2013, total debt outstanding was 6 $300,000,000 and the debt to total capitalization ratio was 31%. At March 31, we had 1.1 $1,000,000,000 of cash on hand, giving us non GAAP net debt of $5,200,000,000 or net debt to total cap ratio of 27%.
The effective tax rate for the Q1 was 35% and the deferred tax ratio was 75%. Yesterday, we included a guidance table with the earnings press release for the Q2 and for full year 2013. For the Q2, the effective tax rate is estimated to be 30% to 40%. For the full year, the effective tax rate is estimated to be 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the Q2 and for the full year.
Now 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 2 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 twenty fourteen 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 and view the April gas price upsurge as a hedge opportunity. Our crude by rail continues to be a highly profitable venture and although the WTI LOS differential has recently contracted from $20 to $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. Additionally, we have contracted capacity on the Houston to Houma pipeline later in the year and we'll have the flexibility to move our Eagle Ford oil east from Houston to refineries in Louisiana, which are priced off the LOS 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 $7,000,000,000 $7,200,000,000 and proceeds from dispositions to be approximately $550,000,000 Our full year production growth targets are unchanged at this time and we've slightly reduced our full year LOE and DD and 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 8 important takeaways from this call. 1st, as evident by our results, EOG is firing on all cylinders volumes, unit costs, price realizations and returns.
2nd, our Q1 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 and our initial test of the 2nd bench of the Three Forks floated 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 spaced wells in the best acreage in the entire play. 5th, our recent Delaware Basin Leonard performance has been excellent and will ramp up this play in 2014. Additionally, our 3rd Delaware Basin horizontal Wolfcamp test confirms this area as a 3rd key asset in our portfolio. 6th, we're seeing downward cost pressure across the board.
7th, I'll walk you through our 5 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 and 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. And finally, our succession plan is consistent with what we previously reported. I will step down as CEO on July 1 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 31 with the title of Chairman and CEO. Thanks for listening. And now we'll go to Q and A.
Thank you. The question and answer session will be conducted We'll take our first question from Leo Mariani with RBC.
Good morning. Hey guys. Hey, how are you here? Great quarter here. Just a question on your 2nd bench well in the Three Forks.
It looked like a very strong well. I think you guys drilled out in the Antelope Extension area. Do you guys think that the 2nd 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?
Yes, Leo. We certainly think it's perspective across our Antelope Ridge area. I mean, we have enough logs and data there to kind of verify that. On the remainder of our acreage like in the core area, it may be perspective. We're taking additional looks at that as we speak.
But it's not as clear there as it is in Antelope. But we're really excited about the 2nd bench and we're going to be testing another 2nd bench well down the road. And then I think next year we've got plans for drilling down in the 3rd bench. So we're very excited about the Three Forks potential there at Antelope.
All right. That's great. And 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 flatten in North America to slightly up next year. Would you anticipate any dry gas drilling next year? Is that going to be exclusively from associated gas?
No. 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.
And 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 4 years there?
Yes. 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 4, 5 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 question is on first question is on your guidance. Obviously, the costs have been pretty strong here and relative to what you were expecting in the Q1.
But you're guiding us higher again for the back end of the year in the whole number of levels. What's different? Why should cost move back up again given the level of success that you're having? And are you just being conservative? Or are we should we be thinking about Q1 as being more repeatable?
In terms of the budget expenditures, CapEx?
More the unit costs both the LOE and the transportation and the exploration guidance and so on.
Yes. We're a little bit surprised by how well we came in on our overall costs for the Q1. So we're a little bit conservative in the guidance that we've given for the rest of the year, although we do think it will be a little bit back end loaded. So I'd say on the unit costs, there is a possibility we may beat the full year guidance on some of those. But we're going to wait another quarter to see how repeatable this Q1 really is.
It's the best.
And that would apply to the other guidance items as well. I mean the impairment charges and the exploration charges you 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. But 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. So 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 for and we'll evaluate that at the end of the Q2.
Next we'll hear from Irene Haas with Glendlyrif Securities. 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 brand has come down a little bit? Just want a little color from you.
Yes. Hard for us to guess on these differentials kind of 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 Q1. We don't see that ballooning out.
But 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. And how about a little on natural gas. I noticed you guys put on some hedges. So your general view is probably still has not changed?
Yes. Unfortunately, we're I guess our view at this point is we don't see any return to the high-2s or low-3s for gas in terms of 2013 or 2014 or 2015, we think we're now in a time frame 2013, 2014, 2015 were somewhere in the range of likely $4 to $5 kind of gas prices. So we have become slightly more bullish than in the past, but we certainly are not in hyper bullish mode.
Next we'll hear from Joe 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 kind of a rolling update on what you're going guide to on an annual basis? Or will there be more framework to it if you have more visibility on future commodity price?
Yes, Joe. We will probably continue just to give an annual update. It's been our experience that companies that try and give a 3 to 5 year guidance they almost immediately missed their guidance the 1st or second year. And so we're not likely to do that. So it'll be likely that in February we'll give full year 20 14 guidance and we might give a little more framework around the 2015 to 2017 guidance.
But don't look for us to provide firm numbers for more than 1 year out as we go forward.
Okay. And 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, but 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 and 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. So during that entire period, we'll be guided by a maximum the same maximum debt limit of no higher than 30% net debt to total cap. And 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 a significant free cash flow machine based on our internal growth projections.
Next we'll hear from Pierce Hammond of Simmons and 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 put out in some slides where you talked about total U. S. Oil production growing by like 2,000,000 barrels a day by 2015?
Pierce, we still are of the belief that the production growth that total U. S. Oil production growth that happened in 2012 was perhaps the peak that is going to occur. I mean 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 a quite high rate of growth. And so 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 2 major driving forces of U. S. Oil growth Bakken and Eagle Ford. Eagle Ford is going to surpass the Bakken likely this year is the biggest oil growth rate. Bakken is slowing down.
Permian is really not on that fast of a track. And then there's what I'd classify all others. And the all others are not growing at a very fast pace at all. So we're not as concerned as others that U. S.
Growth, oil growth is going to flood the total market with and ruin global oil prices.
Thank you. And then 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. We're really seeing I mean, to give you an idea of rigs in the Q1 of 2020, 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.
But what we're seeing is the rig count is 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. So 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. And we expect we can do that and still have significant free cash flow in 2014.
Thank you.
Next we'll hear from Charles Need with Johnson Rice.
Good morning everyone. Thanks for taking my question. Just a clarification there. With respect to the increased activity in both the Bakken and the Eagle Ford in 14 at current prices, is that does current prices mean 95? Or are we more talking the flat 85 that you referenced in your 5 year plan?
The current prices I was just referring to would be 94, 95.
Got it. Thank you, Mark. And then the second question I had on those Karnes County wells, I think my impression, the general impression has been that that has been maybe a tier below the fabulous acreage you have up there in Gonzales County. But with the results that you turned in here, it seems like the rate of change of the results there, kind of the second derivative of what you're getting there is better. And 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?
Yes. I would as an overview, I'd say Karnes is still not as good as Gonzales. But 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 today than we were a year ago than we were 2 years ago or 3 years ago?
The answer is unequivocally yes. So 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 the number and we give it to you as our 8 ks estimate. And 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. So I can't overestimate the quality of this Eagle Ford asset. And I think a lot of people when we purposely restricted the money in the Q4 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 Q4 to the Eagle Ford because of budget constraints. And then production slowed down. I think a lot of people misread the production slowdown in our Q4 and felt that the Eagle Ford rate of change had inflected downwards. And that was clearly not the case. It was just that the capital, the coin operated machine received less coins in the Q4.
So we upped the coinage in the Q1 and you see the results. So that's why we're so optimistic not only 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 2021, saw a real noticeable improvement in the 30 day averages. And 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.
So I just wondered if you could put that into context.
Yes. That's a new slide we put in there and glad you cut that. 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 and 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. So 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 6 months. And we are seeing clearly differentiating results from that. And at this point, we'll just call it our own secret sauce.
And Mark, the follow-up is if this continues, do you see some upward momentum perhaps to your EUR that you updated last quarter?
Yes. But 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 costs, we are achieving greater than 100% after tax direct reinvestment rates return. So 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.
And so we're it's very adequate return, certainly more than adequate. And we will look maybe annually at whether we could bump that reserve estimate, but that's not something we're going to adjust on a quarterly basis.
Next we'll hear from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Hey, Brian.
In the Q4, you slowed activity in the Eagle Ford to stay within your CapEx budget. But when we see how strong how strongly you grew production during the Q1, 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. Yes, there probably was a kind of a catch your breath kind of advantage particularly in Eagle Ford last year in Q4 and 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. But I would say at this point, it's 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 percent of our CapEx in the Q1. So right now our burn rate is pretty much where we're if we continue to burn at that rate, we'll be exactly on our budget plan.
So right now, that's pretty much our plan.
Great. Thanks. And 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 30% to 30% or would you more actively return cash to shareholders? And how soon can we see some manifestation of that?
Yes. At this I mean 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 kind of a increase whether it's 1% per year or something linked perhaps to cash flow increases or something like that. The second thing would be we potentially might set some floor as to what would be the minimum net debt to cap debt level that we think would be reasonable for an A and P company. And 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. And 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. But that would be an evolutionary type decision obviously on a year to year basis and would depend on the price of hydrocarbons. But the key takeaway I think that we want to convey to you at this point is that during this forthcoming 4 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.
And so 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 Tamarind with Wells Fargo.
Hi. Thanks for taking the questions. In the Bakken, can you just talk about the down space wells? Can you talk about how much production history you have and what those wells are doing on as they as you got to 60, 90 days? And do you have any color there?
Yes, David. We've got 15 or so wells that we they're in various stages of production that we've completed is down based wells. And certainly as we talked about earlier, the original wells which were more like 3 20 Acres spaced wells, they certainly with the improved frac techniques that we use, they're certainly on a per foot of lateral basis when you normalize that, they're outperforming our older wells. And it's still really early on the tighter spacing wells, the ones that we're calling their equivalent really of 160 Acres wells. Of course, these are long laterals and the per acres per well is variable, a lot of 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 Q1. And so 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. So we're watching that and we really continue 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 100 and 60 acre type down space wells. And so it's really kind of a pilot program and we're going to watch the production throughout the year. And it usually takes like 6 to 9 months to kind of verify that you're doing things correctly. So we're in the middle of that kind of 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. But certainly, we think the improved frac techniques certainly at this point, we're very positive about it and we think we're going to we're contacting more rock and then we're going to really enhancing the recovery factor of the Bakken on our core acreage. So it's going well right now.
Okay. Thanks. That's helpful. And 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 much more toward a manufacturing type phase as opposed to a exploration phase.
And I just want to see how either you or Mark whoever question. What do you think about that concept and how you think North America what North America looks like 3 years down the road or just lower 48, however you want to run with that. I just want to throw that out there and see if you have any comments on that.
Yes. It's certainly as far as the oil plays, as we talked about, and I think this we're not really expecting to get another Eagle Ford or Bakken resource play of that quality and that size all tied together. So we have as we've discussed, we have a decent list of new greenfield plays we're working on on the oil side. But there are the quality of rock for oil plays is in shales is really limited. And then the thermal maturity of the oil, the window there of the right maturity of the oil is very critical too.
So the sweet spots are really small. And so what I think you're going to be seeing is and I think you're correct on this, you're not going to be seeing people announcing 1,000,000,000 barrel new oil plate discoveries and of that nature. But hopefully, we'll be able to announce some success and some plays that would be maybe in the 50,000,000 to 100,000,000 barrel or maybe even bigger than that, which is a significant value in North America. So 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.
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 right to the top, which are certainly the Bakken and Eagle Ford. And we feel very fortunate that we have very large substantial positions in those. And we hope to add a few more smaller ones as we go along.
Yes. I'll just add one thing to that. There are some combo plays that we hope to uncover that could be substantially larger in terms of the oil content that I think are yet to be found and we're still chasing those. So 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? And is it possible that the Three Forks 2 or 3 could be perspective without the Three Forks 1 being perspective?
Joe, in the core, I believe we've only completed like maybe 3 or 4 wells in the Three Forks there. And those are I think I believe are in the first bench. And so 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. And so 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 3 porcelain our core acreage as we go forward.
Got you.
And 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 why it's more in what way it's more technically challenging? And what would you expect to be the outcome after you do your analysis? And are your wells overall there in line with your 430,000 BOE type curve or EUR estimate?
Yes. I mean the answer to the first question is yes, 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 Place and the Delaware Basin.
And then the second thing is frac containment is more of an issue in the Midland Basin. As you know, they have at least in the areas we're working, we have 3 potential pay zones. And 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. And then also laterally, horizontally away from the wellbores, We're seeing that you have interference between wells there if you're not careful. But 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.
And 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. So we're working diligently on that, but it's certainly it's more challenging than the things that than the plays in the Delaware Basin.
And 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.
And that does conclude today's teleconference. Thank you all for joining.