Good day, everyone, and welcome to the EOG Resources Second Quarter 20 14 Earnings Results Conference Call. As a reminder, this call is recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.
Good morning. I'm Tim Driggers, CFO. Thanks for joining us. We hope everyone has seen the press release announcing Q2 2014 earnings and operational results. This conference call includes forward looking statements.
The risks associated with forward looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. This conference call also contains certain non GAAP financial measures. The reconciliation schedules for these non GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines.
We incorporate by reference the cautionary note to U. S. Investors that appears at the bottom of our press release and Investor Relations page of our website. Participating on the call this morning are Bill Thomas, Chairman and CEO Gary Thomas, Chief Operating Officer Billy Helms, Executive VP, Exploration and Production and Moira Baldwin, Vice President, IR. An updated IR presentation was posted to our website yesterday evening and we included Q3 and full year guidance in yesterday's press release.
This morning, we'll discuss topics in the following order. I'll first review our 2014 second quarter net income and discretionary cash flow and then Bill Thomas and Billy Helms will provide operational results. I'll then address EOG's financials, capital structure and hedge position. Finally, Bill Thomas will cover EOG's macro view and provide concluding remarks. As outlined in our press release for the Q2 2014, EOG reported net income of $706,400,000 or $1.29 per share.
EOG's Q2 2014 adjusted non GAAP net income, which eliminates the mark to market impacts and certain non recurring items, as outlined in the press release, was $796,000,000 or $1.45 per share. Non GAAP discretionary cash flow for the 2nd quarter was $2,200,000,000 At June 30, 2014, the debt to total cap ratio was 26%. The net debt to total cap ratio was 22%. I'll now turn it over to Bill Thomas to discuss operational results in key plays.
Thanks, Tim. Once again, EOG had an outstanding quarter. We posted year over year U. S. Oil growth of 33% with total company production growth of 17%, which drove excellent financial metrics.
We increased the dividend on the common stock by 34%, the second increase this year and we also announced our success in yet another high return U. S. Crude oil play. EOG's Workhorse assets, the Eagle Ford and Bakken continue to meet or in most cases exceed our high expectations. Although we've been in the Bakken since 2 1006 and the Eagle Ford since 2010, we are steadily improving individual well results in both plays through continuing advances in completion designs.
Also due to our ongoing ability to improve efficiencies, we continue to maintain good cost control, which was evident in our 2nd quarter results. Together, these plays are continuing to drive high return oil growth and are far from mature. We realized cost reductions during the first half, partially due to efficiency gains from the increase in pad drilling in the Bakken and Eagle Ford. In both plays, we're drilling longer laterals and utilizing larger fracs because we have secured sand supplies. With pad completions, a large number of offset wells are taken offline, wells take longer to flow back and new wells are brought on production in packages.
As a result, production growth can be lumpy rather than linear as many of you who follow state data have noticed. This doesn't change EOG's long term growth profile. As mentioned in yesterday's press release, we announced success in the 2nd Bone Spring Sand, which lies beneath our Leonard Shale acreage in the Delaware Basin. This is the 5th oil our combo play EOG has added to its drilling inventory this year. Now I'll turn it over to Billy Helms to discuss this play and our operations.
Thanks, Bill. In the first half of twenty fourteen, we were in an exploratory phase on our Delaware Basin Leonard acreage. As we mentioned on our May call, we were testing various spacing pilots and zones across our acreage. We also tested the potential of the 2nd Bone Spring sand. The 2nd Bone Spring sand sits beneath our Leonard acreage position primarily in Eddy and Lea Counties, New Mexico.
We drilled our first horizontal wells here 10 years ago then shifted capital to the Leonard and Wolfcamp shale plays and now we've gone back to our proprietary completion techniques. In Southern Lea County, we drilled and completed 2 very successful wells in the 2nd Bone Spring sand. The first was a short length lateral and the second was drilled with a 4,500 foot lateral. The Mars 3 State 1H and the Jolly Roger 16 State 1H had initial production rates of 12.70.1450 barrels of oil per day with 150 and 210 barrels per day of NGLs and 1,100,000 and 1,500,000 cubic feet per day of natural gas respectively. The production stream is 70 percent 45 API gravity oil.
We have 73 1,000 net Leonard Acres and estimate the 2nd Bone Spring sand is highly prospective over the majority of this acreage. We still need additional drilling to test all portions of our acreage, but these initial results combined with industry data from over 500 wells raise our expectation for the play's high rate of return growth potential. The estimated completed well cost is $6,000,000 with gross reserves of 500 MBOE per well yielding 100% direct after tax rate of return. We are very pleased with the addition of the 2nd Bone Spring sand to our drilling portfolio. It's a high rate of return black oil play on existing acreage.
We plan to drill a few more wells this year and increase activity in the play in 20 15. Over time, we will determine proper spacing and the ultimate resource potential to EOG. In the Leonard Shale, we are still testing down spacing in the same zones and across zones. Over the last 12 months, we've tested numerous patterns from 6 60 foot spacing down to the 300 foot space Gemini wells highlighted in the press release. We are very pleased with the preliminary production results.
We've also had initial results from 2 recent B zone wells and from tightly spaced wells drilled in a pattern across the A and B zones. It is a little too early to reach firm conclusions on optimum spacing or the ultimate number of possible well locations from East Zone, but we are encouraged by our results to date. In the Delaware Basin Wolfcamp, we're focused on making improvements in well productivity through the application of completion technology. In Reeves County, the State Apache 50 7 1107H was completed with an initial production rate of 1600 barrels of oil per day with 460 barrels per day of NGLs and 3,000,000 cubic feet per day of natural gas. This is the best Wolfcamp well we've drilled to date.
We're testing various spacing patterns and the prospectivity of different pay intervals in the play. We're on track to complete 14 net wells this year and have been encouraged with our progress and results to date. In the Bakken, we've shifted to more multi well pad drilling this year with most of our activity focused in the core area. We're encouraged by the very early production flowback results from our first 700 foot spaced wells. As Bill mentioned earlier, these are wells drilled from pads and completed with larger fracs.
The wells are taking longer to flow back and therefore it is too early to report any individual well results. We've noticed a marked improvement in production rates that reflect changes we made to completion techniques over the last 2 years. After achieving peak rates, the well production is flattening out nicely, delivering excellent rate of return. During the second half, we plan to drill both Bakken and Three Forks wells on our Antelope Extension acreage. We also plan to test various benches of the Three Forks formation on both our core and Antelope Extension acreage.
Later this year, we expect to get our 1st data point after we test the 3rd bench of the Three Forks on our Antelope Extension acreage. In the Wyoming DJ Basin, we plan to drill 39 net wells this year in the Codell and Niobrara. One notable new well completed in the Q2 in the Codell was the Jubilee 586 1705H. It came online at 11.45 barrels of oil per day with 4.45 Mcf per day of rich natural gas. We have a 75% working interest in the well.
Since May, we've added 13,000 net acres in the Codell increasing our position to 85,000 net acres. In the Powder River Basin, we plan to drill 34 net wells this year in the Parkman and Turner reservoirs. 2 recently completed Parkman wells are the Mary's Draw 404-21H and 468 34H, which had initial production rates of 10.45 and 9.80 barrels of oil per day respectively. We have 99% and 100% working interest in the wells respectively. And we are drilling on multi well pads in both the Powder River and DJ.
I'll now turn it over to Bill to discuss the Eagle Ford and our international operations. Thanks, Billy. In the Eagle Ford, we're in the 6th ending of understanding and progress in the play and we've not yet reached the peak from a learning curve standpoint.
We're constantly experimenting with completion designs and are seeing improved production responses from these tweaks. We still have ongoing spacing pilots in certain areas. We highlighted multiple high initial production rate wells in our press release. During the Q2 of the 29 wells we drilled in Gonzales County, 21 had IP rates exceeding 2,500 barrels of oil per day. This succinct statement shows our Eagle Ford quality is holding up quite nicely.
During the Q2, we drilled a number of lease retention wells. Our drilling plans for the second half include fewer of these one off wells, so we expect to realize efficiency gains from pad drilling and other improvements in cost and logistics. We are drilling longer laterals with a 50% increase in the number of stages from where we were 3 years ago. We're also seeing productivity improvement during early flowback, but we need more time to evaluate the results. We're on track to drill 520 net Eagle Ford wells this year.
By mid year, we had brought 260 wells to sales. On our last earnings call, we talked about the depth and longevity of oil growth from our Eagle Ford asset. Nothing has changed in our view. In Trinidad, we have a 3 well net well development drilling program planned for 2014, which will allow us to maintain flat natural gas production in coming years. In the East Irish Sea, the Conway project is now expected to be online early 2015 due to certain scheduling matters with the platform operator.
I'll now turn it over to Tim Driggers to discuss financial and capital structure. Thanks, Bill.
Before getting into the specifics on CapEx and guidance, I want to point out a new IR slide on page 14. Using actuals and sell side estimates, we compared EOG's 20132014 estimated ROE and ROCE to the average of the majors, integrated and independent E and Ps for the same period. What stands out from the chart is EOG's financial returns relative to the other sectors. In the energy space, there are sectors known for growth and those known for returns, but rarely does a company or sector combine high production growth with outstanding financial returns. We believe EOG is currently exhibiting among the best financial returns in the entire industry combined with excellent production growth.
For the Q2, capitalized interest was $14,000,000 Total cash exploration and development expenditures were $2,000,000,000 excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $237,000,000 EOG made $74,000,000 of acquisitions during the quarter. At the end of June, total debt outstanding was $5,900,000,000 At June 30, we had 1 $200,000,000 of cash on hand. The effective tax rate for the 2nd quarter was 36% and the deferred tax ratio was 62%. Yesterday, we included a guidance table with the earnings press release for the Q3 and full year 2014.
For the Q3 and full year, the effective tax rate is estimated to be 35% to 40%. We have also provided an estimated range of the dollar amount of current taxes that we have that we expect to record during the Q3 and for the full year. In terms of our hedge positions, for the period August 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 194,000 barrels of oil per day at a weighted average price of $96.19 per barrel. For the first half of 2015, we have 69,000 barrels per day of crude oil options that could be put to us at an average price of $95.20 per barrel. For the period September 1 through December 31, 2014, EOG has natural gas financial price swap contracts in place for 330,000 MMBtu per day at a weighted average price of $4.55 per MMBtu.
For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBtu per day at a weighted average price of $4.51 per MMBtu. These numbers exclude options that are exercisable by our counterparties. For the period January 1 through December 31, 20 15, we have 175,000 MMBtu per day of options that could be put to us at an average price of $4.51 per MMBtu for each month. Now I'll turn it back to Bill to provide EOG's views regarding the macro environment and a summary.
Thanks, Tim. We remain bullish on crude oil prices. We are advocates of free markets and are proponents of both condensate and crude oil exports. While the opening up of crude of condensate exports will create more headroom for refiners to process light oil, Even without exports, we still see several years of headroom in the U. S.
Refining complex. Regarding North American natural gas, we don't have any plans to reinvest in dry gas drilling opportunities at current prices. As we expected, the strength we saw in gas prices earlier this year was only a temporary and driven by the coldest winter weather in 14 years. Recent high storage injection numbers again have verified the enormous supply deliverability of untapped shale gas in the U. S.
This provides solid support for rapid approval of additional LNG export terminals. Our 20 14 plan remains consistent with what we outlined at the beginning of the year. We continue to reinvest in high rate of return crude oil weighted drilling opportunities. We increased our crude oil growth forecast in May to 29%. And this quarter, we are increasing EOG's total company production growth estimate to 14% from 12% based on growth from associated NGL and natural gas production from our crude oil place.
Our CapEx estimate remains unchanged. We've now increased the common stock EOG is focused on returns. EOG's high return production growth is showing up as strong growth in cash flow, net income and through increasing ROE and ROCE metrics. The Bakken, Eagle Ford and Leonard have the potential to sustain above average long term growth with very high returns. EOG is well positioned to be a long term leader in returns on capital in the energy sector.
2nd, EOG is a growth leader and it's organic. EOG's estimated 2014 oil growth on a barrel per day basis is greater than any other company in the peer group and this growth all organic. We have the assets and the inventory debt to sustain this growth. Please take a look at the new IR slide on Page 7. Growing oil as we did 33% in the Lower 48 this quarter is a remarkable achievement.
3rd, exploration and technology focus. We've again increased our high return drilling inventory on existing acreage with the addition of the 2nd Bone Spring sand. We also reported good preliminary downspacing results from the Leonard A and B zones. The 2nd Bone Spring Sand and the Leonard Downspacing results are two examples of how EOG generates new plays through exploration and the use of in house technology. 4th, we're committed to generating long term value for our Ship Stockholders.
We increased the dividend on the common stock for the 2nd time this year. This combined with net debt reduction has been our plan for discretionary cash flow. Finally, our return and growth profile is unique. As Tim pointed out, based on 2014 estimates, we are at the head of the class in terms of combined production growth and financial returns among all upstream sectors including the majors, integrators and independents. That's a powerful statement and our IR slide on page 14 is quite impressive regarding financial returns.
And we plan to maintain this lead by continuing to reinvest in high rate of return oil plays. 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 Amir Aras with Stifel.
Thanks. Good morning, guys. Just a quick question on the Bone Springs. The 73,000 acres that you talk about for the 2nd Bone Springs, is that just on the New Mexico side? Or does that also include acreage on the Texas side?
Yes, Amir, that's a good question. I'll let Billy Helms talk about that. Yes, Amir. Our 73,000 acre position both in the Leonard and the Bone Springs does cross the state line. So it is both located in New Mexico and Texas.
What's interesting to note about these 2nd Bone Springs wells is they are about 5 miles apart. They do help confirm the potential on a lot of our acreage. And certainly with the well control we have in the play, we feel good about the extent of what we've seen so far. We are early in the testing of those zones, but it is they do represent 2 of the most southeast wells in the play as far as wells completed in the 2nd Bone Spring sand. So we certainly feel good about what we see so far, but we'll have to evaluate the long term production to assess the potential to the company.
Okay. And as a follow-up, I know it's still early days in the plate like you just mentioned, but could you just give us how you're thinking about the development right now in terms of the Leonard AB and the Bone Springs in terms of is one going to be your primary target or infrastructure build out? Does it support 1 versus the other? Or each one given the returns each one could be a primary target target at its own?
Well, I think that's a good way to think about it. I think each one can be a primary target on its own. Infrastructure is certainly in place for our current activity and takeaway capacity. And certainly we try to stay ahead of that as we develop the plays. We will be testing as we mentioned in the call or in the press release, we have tested a number of patterns for the Leonard, especially the A Zone.
And our Gemini wells are spaced to 300 feet apart in the Leonard A Zone. And certainly, we're very excited about the potential we see there. But we'll have to determine what the ultimate spacing will be in each zone as we progress. These two wells in the Bone Springs that I mentioned earlier they are about 5 miles apart. So there has not been any spacing tests conducted on the Bone Springs yet.
And so we'll have to go through that exercise. And it will take several months to work through that and we'll have additional wells planned in the rest of the year to try to assess how we move forward with that program.
Okay. Thank you.
We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, everybody. I wonder if I could try 2 quick ones. First of all, Bill, in your prepared remarks, you did mention the Eagle Ford. I wonder if you could help just maybe dig a little bit deeper into the impact of the need to change to drill retention wells, I guess, is the way you put it on the call.
And if we might expect to see the growth rate accelerate again in the second half as you get back to your more normal order of business? That's my first question. I've got a follow-up please.
Yes. Good morning, Doug. Yes, the retention wells we talked about we were mainly in the West, in part of our acreage where we go out and we drill 1 or 2 wells on an initial unit just to hold the acreage. And we've completed most of that drilling for this year in the first half of the year. So in the second half of the year, we will be doing as we talked about in the early remarks, we'll be doing considerably more pad drilling.
So that means we come back in and follow those retention wells and other areas and we drill multi well pads and we drill these wells in large groups and we complete these wells in large groups. And so they when we do this, we do get more efficiencies and cost, but the production is a bit more lumpy as we go forward as we do more of the pad drilling. So the main benefit is the efficiencies and costs due to drilling being able to drill wells on multi well pads.
Bill just to be clear that so I'm guessing your average we don't obviously have the full disclosure on this, but the average well rates then out of the average well in the second quarter would presumably been lower, but you're basically saying that's a that really is more of an anomaly than something that's changing in the program. Is that a good way to think
about it? Yes. The average rate on the wells have been improving over time. We're still making completion improvements steady. We have a slide in our IR presentation particularly on the Western wells.
And so the new better completion techniques we're doing on the wells continue to make better wells. But really we don't see a significant change probably from the first half to the second half.
Thank you for that. My follow-up is really more of a kind of philosophical question. As obviously you've done a terrific job on the returns per your slide presentation compared to the different peer groups. But by putting yourself in that kind of starting to look at those kind of big oil metrics if you like, I wonder how you think about the dividend. Obviously, a big dividend bump this quarter again, but it's still a very modest yield.
How do you think longer term about what the right level of dividend is for a company of your size with a growth trajectory and calls on capital that you have? Because again, when you start to compare yourself to that wider peer group, some of those guys have 3%, 4%, 5% dividend yields and obviously you're substantially below that. So longer term how should we think about your allocation of capital to the dividend on a go forward basis?
Yes, that's a good question. Doug, we don't have a policy. And so as we go forward, the Board will just continue to look at our cash flow and where we are at the company on what we need to do to continue to grow the company. And we'll give dividends appropriately based on the situation of the company. So certainly we've had a good track record 16 increases in 15 years and we're certainly committed to long term shareholder value creation.
Appreciate the answer, Bill. Thank you.
We'll go next to Leo Mariani with RBC Capital.
Hey, guys. Just wanted to kind of dive into some of the new plays. Obviously, you talked about the 2nd Bone Springs here today. Last quarter, you introduced a number of new Rockies plays as well. Can you just give us a sense of how you kind of plan to allocate capital to these new plays sort of this year or next?
Are there any plays there that are a priority? Are there any limitations on infrastructure or any need to kind of hold acreage that sort of governs any of that? Maybe just kind of talk to how we should see activity levels in those new plays over the next year or 2?
Yes. Thanks for the question, Leo. As far as the new plays, they're all in a bit different situation. Certainly, the plays that we talked about in the Q1 call in the Powder River Basin and DJ Basin, we're moving ahead with development on those. Most of it's on multi well pad drilling And we're defining spacing patterns and optimizing our completions and costs.
And those will get capital allocation as we see the results of the wells. And again the plays with the best rate of return will get the most capital as we go forward. On the Bone Springs, we're new into that as Billy talked about. We'll drill 2 really strong wells and we'll be evaluating that play as we go forward. But as we look into the future, everything EOG does is focused on return on capital invested.
So each play will get rewarded based on that.
Okay. I guess just switching gears a little bit. You guys did take your gas and NGL production guidance up here in 2014. You talked about associated gas and liquids from your oil plays. Can you give us a little bit more color on specifically where that's coming from in terms of the incremental associated gas here?
Yes, Leo. We had a couple of things in the first half of the year, the second quarter. We have added infrastructure particularly in Midland that's helped our gas takeaway situation there and deliverability. We did in our Barnett combo play, we had a number of wells on restricted flow rates due to pressure control and we did open up some of those in the second quarter a little bit. But just in general, as we stated in the opening remarks, we increased our oil in the Q1 and this is kind of a follow-up as we have associated gas with all of our crude oil plays.
Our base decline in our natural gas is slowing due to not much natural with no natural gas drilling and no property sales. And so our associated gas with our crude oil plays is beginning to overcome that decline.
All right. That's helpful guys. Thanks.
We'll go next to Pierce Hammond with Simmons.
Good morning.
Good morning, Pierce.
Bill, I noticed a change in the completed well cost in the Eagle Ford. It looked like it moved up to $5,700,000 from $5,500,000 Is that just more longer lateral, more sand? And does that $5,700,000 yield bigger wells?
Yes. Let me Pierce, let me direct that question to Gary to add some color.
Yes, you're exactly right. We're drilling the longer laterals. They're about 10% larger longer. And with that, of course, roughly $1,000 for the treated lateral That's adding quite a bit of additional cost. But we've been able to reduce that with just continued efficiencies.
And our number of days per well has dropped quite a lot here this last quarter. As a matter of fact, we set a new record this quarter once again with a 4.3 day well to 15,600 feet. So we are seeing improved wells. I think that was page 20 in our chart shows that the wells were about 15% better this year than last.
Excellent. Thank you. And then my follow-up is Bill can you provide some color on your 15 oil hedging strategy?
Yes, Pierce. Historically and I think we business wise, we would like to have a good hedge position going forward in oil and gas. The difficulty has been the backwardation in the forward curve on both gas and oil, we don't see as reflective of what's going to happen in the future. So it's difficult to get a good hedge. But we're certainly looking for opportunities as we go forward in the second half of the year to add some hedges in oil and gas if they're available.
Thank you so much.
We'll go next to Shubharsh Chandra with Jefferies.
Yes. Hi. Permian question for my first one. So casual reading of these well results sort of indicate that there's not a vast difference in the IPs that were quoted. Yet Wolfcamp much higher EURs expected and a much higher resource potential expected out of the Wolfcamp itself.
Could you just add perhaps maybe a bit more color to what you saw after these IPs that indicate that the Wolfcamp is 60% higher in terms of URs per well than say a Leonard and a comp to the 2nd Bone Springs?
Yeah. Thanks for the question. This is Billy Helms. I'll answer this Permian question. For the Leonard and both the Wolfcamp, we each one independent zones.
The Leonard is more of an oil play. It has a different production profile certainly than the Wolfcamp, which is more of a combo ish kind of play. So the production profiles, although they may start at somewhat similar IPs on oil, this production profile is certainly different because they're different types of reservoirs. So the decline rates will be different. The product mix is certainly different.
And so it's going to yield different EURs over the life of the well. We're also that will also play into how we develop the fields and the ultimate spacing of the wells as well. So the Leonard as you saw we're testing down to some wells that are at 300 foot spacing. In the Wolfcamp we're generally testing closer to 7 50 foot spacing as we go through the play. So those are just some differences between the 2 different reservoirs.
They are quite a bit different certainly and have different zones of targets, but that's the basic difference between the 2.
Got it. And Billy what do you see happening with the rig count in the various Permian plays over the next year?
Well certainly I expect this with success we would expect activity to increase in the Permian over time. The luxury we have right now is we have just a large number of really high quality plays in the company where we can allocate capital. So what it does is it gives us the time to go through and make sure we understand the proper completion techniques and the proper spacing before we really start increasing activity in each play. That helps make us a little bit smarter on the overall development and still provide long term growth for the company. So we're pretty excited about the potential we see there in the Permian and we're taking our time to really make sure that we understand how to complete and what the proper spacing of each one of those zones will be before we really ramp up activity too quickly.
Okay. And my follow-up, I don't know if EOG participated in the Turner Mason study or not. But I guess the conclusion is that they're arguing for a higher riskier packaging number, but essentially no change in the type of railcar to carry Bakken crude. As you're obviously on the upstream and the midstream side of the transportation side of it, what are your takeaways?
I would Shweta, that's we are certainly conservative on everything we do. We're concerned about safety and we're certainly all in favor of many of the things that have been proposed. And I guess the new guidelines didn't really catch us by surprise. We're prepared for those as we go forward. And we're slowly behind the activity to increase the safety of rail as we go forward.
Or more specifically, do you think there needs to be a change in the 111 railcars to carry Bakken Group?
We're very well positioned there with the contracts that we have. And we're still reviewing these rules. But as our cars that go off a lease, we'll be going with the cars of the future. So we really like the way we're positioned to be able to have the most safe and regulatory compliant rail fleet.
Okay, great. Thanks very much.
We'll go next to Irene Haas with Wunderlich Securities.
Hey, good morning.
Good morning,
Irene. Yes, my question is on the land and it's also called Avalon. You mentioned earlier that it's a different beast from sort of the Wolfcamp Shell. So can you shed a little light on whether it's a true shell or is it something else? And then does it have really high IPA and how does it drop off?
Because I think it can get pretty steep. And also in your past PowerPoint in July, I think mentioned about 3 zones in the Leonard and these are my questions.
Thanks Irene for that. Yes, the Leonard is a shale and it's really the 3rd best reservoir in terms of shale we really have in the company. It's a the and the content of the reserves is about 50% oil and they start off at very high rates and have excellent rates of return in the shale. So we're fortunate Our acreage position, we believe, has captured much of the sweet spots of the play. And we've had, as Billy talked about, we've had very good success on increasing the per well productivity with our new completion techniques and also being able to test wells at very tight spacing with at least initial good results.
So we think we can continue to improve the play and add value as we go forward in our development process.
How's the declines?
Yes. I'd say the decline in the Leonard play, I'd say it's not too different than many of our other shale plays in that they're very they're hyperbolic in nature. They fall off fairly fast. And I don't couldn't quote you a number right now as far as the initial decline the well. But they're very similar to most of our other shale plays, very hyperbolic in nature.
But they produce they level out and produce it for a long time at a very good rate. So they do provide excellent economics as we would as we've quoted earlier. The current rate of return for that play is over 100% as well. So we're very excited about the potential of the development of the play and the economics of that play.
Great. Thank you.
We'll go next to Joe Allman with JPMorgan.
Thank you. Good morning, everybody.
Good morning, Bill.
Just one quick question on down spacing.
It seems like there's an awful
lot of down spacing going on at EOG. And so could you run us through the various plays? So for example, on the Leonard Shale, I know you did 300 foot interlateral spacing and you're doing some additional pilots. Are you testing down to 150s? And then in the Eagle Ford, you're doing some additional pilots.
Are you going down to 20s there? And could you talk about the downspacing in the Bakken and in Wyoming? And what the implications are for the increase in locations?
Yes, Bill. Let me just go through that's a good question. Each one of those plays a bit, Joe. In the Eagle Ford, we're currently developing that play on about 40 acre spacing and there are some areas where and that's about 300 feet between wells on an average. There are some wells where the well spacing is greater than 300 feet and we are doing a bit of infield work in some of those areas.
We don't have any news to report on that other than the early results look good and but we need some long term results on that before we can determine if that's the best way to do those areas. In the Bakken, we're on our 3rd set of downspacing in the Bakken and we have had very good success with 1300 feet between wells, which is approximately 4 wells per section. Now we're testing approximately 700 feet between wells and that would be 8 wells per section. And as Billy reported on that, we have a few wells that are flowing back and those initial results look good. But we do need quite a bit more time to watch the long term production of those wells and then also watch additional wells as we bring them online on those spacing patterns.
And then in the Leonard, we've gone from 6 60 foot spacing and we've tested various spacing patterns down to 300 feet between the wells. We do not have any plans to go less than 300 feet in the same zone between wells. So where we are in that process is we're just evaluating all those different spacing patterns to determine what's the proper spacing to fully develop the field.
Okay, great. So if
you could comment on Wyoming as
well, that'd be great. And then a follow-up question and then comment on the implication for locations, if you can give us any specifics on that. But Bob's question would be, you're talking about increasing E and P activity in 2015 versus 2014. So is your plan to be free cash flow positive in 2015 and increase the balance sheet as you suggest in some of your comments? Or do you plan on matching fairly closely cash flow to CapEx?
And talk about what the optimal debt level is in that context?
Yes. Joe, that certainly we're beginning to think about 2015, but we just don't have any specific guidance on that other than we're going to reinvest the majority of our growing cash flow. We're going to continue to reinvest that back into the highest rate of return plays that we have. And we'll be looking at certainly the drilling program this year and the results and all these different spacing patterns and the well productivity and the return on all these. And we'll just allocate that to continue to grow the company very strongly, but to really to focus on returns.
And our net debt to cap ratio continues to fall in the company and we want to continue to strengthen the balance sheet as we go forward and to allocate our capital based on those metrics.
Okay. Any comments on the spacing pilots you're doing in Wyoming?
Yes, Joel. In Wyoming in the DJ Basin, we're drilling alternating Niobrara and Codell targets and those spacing patterns on various different spacing between wells, but they're approximately 800 feet apart.
And so we'll
be looking at those initial patterns and see how those respond. And then in Apartment zone, we're currently developing on 1300 feet between wells and drilling longer laterals in that particular play. And then in the Turner, we're developing on 13 55 feet between zones. And again, each one of these, we'd like to get multiple patterns established and we'd like to get long term results to see how much sharing if any sharing there is between the wells and then we make appropriate adjustments as we go forward. So it's kind of a long term process And we're very focused on maximizing the net present value of each one of these properties and to maximize the reserve recovery and the value of the property.
So that's kind of the status on those plays.
Very, very helpful. Thank you.
We'll go next to Bob Brackett with Bernstein.
Good morning. Quick question on new ventures. Can you talk a little about the lower tests in the Three Forks and maybe anything on East Texas you're willing to share?
Yes. Good morning, Bob. Thanks for the question. In the Three Forks, we do have some wells planned, particularly on our Antelope acreage. We do have a 3rd bench planned to test later in the year and some I believe probably first and second events also test to continue to evaluate that.
And East Texas?
Yes. I would say, Bob, on East Texas, everybody knows where we are drilling a few wells over there and evaluating the play as well as plays in other parts of the country too. So it's just a part of our continuing exploration effort in the company to define new play potential. As you know, we have a very, very high cutoff for new plays. So we're not interested in pursuing plays that have a 20% or 30% rate of return potential.
We've really set the bar high and we're looking for plays that only would be able to generate say north of 50% rates of return going forward. And we're still we're very focused on crude oil plays. So the East Texas is just a part of that mix and we'll continue testing that. And when we get some information that's meaningful and something that we will go forward on, we can talk about that later. But right now, that's all the information we have.
Great. Thanks.
We'll go next to Brian Singer with Goldman Sachs.
Thanks. Good morning.
Good morning, Brian.
I wanted to follow-up on
a couple of earlier topics starting with the Leonard. The potential for a 300 foot spacing at your in the Leonard would seem to imply tighter spacing at least at your base case lateral length relative to some of the other plays out there. Can you just talk about unique characteristics you see in the Leonard relative to other plays in other parts of the Delaware Basin and how you're thinking about both recovery rates and the trade off of longer laterals versus tighter spacing?
Yes. Brian, this is Billy Helms. On the spacing for the Leonard, this is the same approach we really take in every play that we undertake is to try to understand what's the right spacing given the current state of our completion technology in each lateral to maximize the net present value of every acre that we have under lease. And so for the Leonard, we started out with 6 60 foot spacing and we continue to test tighter spacing in each one of our subsequent patterns to understand what is the right formula to maximize our net present value. And certainly the Gemini wells that we value.
And certainly the Gemini wells that we highlighted in the press release are encouraging for a 300 foot spaced well. I would say that we need a little bit more production time to really understand what the optimal spacing pattern is going to be for that Leonard A zone as we go forward. And then similarly, we'll do the same thing for the Leonard B zone as well as the Wolfcamp zones in the Delaware as we start through development in each one of those. So it's a similar process we go through in each play. For the Leonard, it's just a it's a really high as Bill mentioned earlier, it's a high quality shale, good porosity, good mechanical properties that allows us to really focus the fracs near wellbore and maximize the recovery of each well.
And that's different than some of the other plays of course. Each play has its own characteristics and mechanical properties that dictate what the proper spacing will be. And that's why these very methodical spacing tests are needed to try to determine what the optimal will be on each pattern.
Got it. Thanks. And then on the Eagle Ford, you have a slide 20 where you're showing further improvement in well performance this year relative to last year. You talked about the greater the more complex fracs and slightly higher well costs. Is that what's reflected here or is there further upside to EURs?
Are you just getting oil out of the ground earlier via completion efficiencies? And are there any changes to your thoughts on recovery rates in oil in place in the Eagle Ford?
It's a little early to determine what the recovery factors is now with these enhanced completions. But yes, we're really excited about what's transpired here just this year in the Eagle Ford, because more of our wells are being drilled in the west side, which previously thought we thought was maybe less productive. But with more wells there then we're drilling longer laterals, enhanced completions then overall wells the average of the wells drilled in 2014 is quite a lot better than the wells the average of the wells drilled in 2013. So it's just improved completions. Okay.
And are you seeing any change in the decline rates being greater? Or should one expect that these greater rates should carry into and well performance 360 days should carry into EUR?
We would expect that we would see with us seeing higher IPs and the wells even holding up better 60, 90 days that we would see improvement there as well as far as long term production. Because we do have longer laterals and we just need additional time on these.
Yes. I think the important thing on that Brian is that it's really critical that we get long term data on each one of these plays and that goes for the Eagle Ford in particular is that we just want to see more than 90 days production to determine what the ultimate EUR will be, especially as we continue to work the spacing issues. It's very critical to take our time and to get enough data before we can say whether there's an EUR increase or not.
Great. Thank you.
We will take our next question from Arun Jayaram with Credit Suisse.
Bill, how are you? I thought the returns is very refreshing. Good morning. I did want to talk to you a little bit maybe a follow-up to Joe's question. But as you sit here today Bill, you have a bigger opportunity set than you had perhaps 6 or 12 months ago given the Rockies oil opportunity, the Delaware Basin opportunity looks bigger.
So I just wanted to get your thoughts on potentially as you look forward to perhaps increasing CapEx beyond cash flows, you're pretty bullish on oil, your debt to cap is down to 21 percent and you did have a big dividend increase. So just some thoughts given the increasing opportunity set at EOG to take that CapEx to accelerate your returns profile even more?
Yes, Arun, I think what you can expect from EOG going forward is discipline. Capital discipline is at the top of our list. And so we are really focused on operating the company relatively within our cash flow going forward. We're very focused on keeping the balance sheet solid as we go forward, that net debt, the cap at a low level and really discipline. Each one of these plays, as you focus on rates of return, capital rates of return and maximize the value of the plays, it's important not to grow or accelerate them too fast.
And so we're really focused on doing that correctly and continuing to focus on crude oil, not interested in gas drilling. And we're really focused on growing the cash flow of the company forward from investments in our crude oil drilling.
And that would again suggest maybe staying within cash flows?
Yes. I think we want to operate the company with discipline in spending and certainly not outrun the cash flow of the company.
Okay. And just a quick follow-up switching gears to the Delaware Basin. Bill, you talked about kind of 550,000,000 barrel kind of resource opportunity in the Leonard two zones there. Just wondering what that what the spacing assumptions were that underpin that? And perhaps given the success of down spacing tests, you're perhaps looking at maybe even 16 wells for each of the zones.
So I was just wondering if you could maybe comment on what that 550 was underpinned by from a spacing perspective?
Yes. We'll ask Billy Helms to give some color on that.
Yes. Arun, excuse me. The Leonard we originally arrived at our EURs or the ultimate recovery from that field from that play using a 6 60 foot spacing for all the Leonard wells. And certainly we have potential for some multiple pay zones in some areas, although we wouldn't have considered all the targets perspective over all the pay zone over all the acreage. But in general, it's a 6 60 foot between wells, which is roughly an 80 acre spacing per well.
And as I mentioned, we are our Gemini wells, we did test down to 300. And while it's still early, we still need some production time to understand what the ultimate spacing will be for that play.
And that would be for the A and B zones?
Yes. That's what we used in our initial estimates. Yes.
Okay. And Michael,
I would mention too that we wouldn't have considered all the zones perspective over all the acreage. So I caution you there.
Okay. And I know it's early days, but how is the Bone Spring a little bit more oil content, the returns compared to the Leonard at least on your initial wells similar?
Yes. I'd say they're very similar as far as returns. We're honestly, we've just had the first two wells down this acreage position and we're very excited about it. But as you mentioned, it is early and we'll certainly need to watch production for a while. And as Bill mentioned, we like to have a little more than 90 days of production, I'd say more than 90 days production to evaluate the ultimate recovery from all these wells.
Thanks, gents.
At this time, I'd like to turn it back to Mr. Thomas for any additional or closing remarks.
Well, thank you for listening and thank you for all the good questions. And just know that EOG as we go forward is a company that's unique. We're focused on returns continuing to improve our ROE and ROC numbers and strong crude oil growth.
Thank you for listening.
This concludes today's conference. Thank you for your