Ladies and gentlemen, thank you for standing by. Good day and welcome to the EOG Resources First Quarter 2015 Earnings Results Conference Call. Just as a reminder, today's call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers.
Please go ahead, sir.
Thank you. Good morning and thanks for joining us. We hope everyone has seen the press release announcing Q1 2015 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, President and Chief Operating Officer Billy Helms, EVP, Exploration and Production David Treiss, EVP Exploration and Production Lance Terveen, VP Marketing Operations and Cedric Berger, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening and we included guidance for the Q2 and full year 2015 in yesterday's press release. This morning, we'll discuss topics in the following order.
Bill Thomas will review our 2015 plan and Q1 highlights. David Treiss and Billy Helms will review operational results. I will then discuss EOG's financials, capital structure and hedge position and Bill will provide concluding remarks. Here's Bill Thomas.
Thanks, Tim, and good morning. Our strategy this year is to remain laser focused on returns and position EOG to resume peer leading oil growth when oil prices recover. We laid out a plan 2 months ago on our year end call and I'm pleased that our first quarter results are right on track. We are quickly Objective number 1, maximize 2015 return on capital invested and position the company to resume strong growth oil prices recover. As we discussed earlier this year, our drilling operations are focused on our top three plays, the Eagle Ford, Delaware Basin and Bakken, where 85 percent of our 2015 capital is directed.
We generate a direct after tax rate of return of 35 percent or greater with a flat $55 WTI oil price in each of these plays and returns improve as we lower costs and improve well productivity. We've also stated that we have no interest completions on a significant number of wells known as DUCs until oil prices improve. A $10 increase in the price of oil with a 6 month deferral adds about $300,000 of net present value to a typical well. This amounts to a significant value creation from our drilled but uncompleted well inventory. It is the right business decision to drill the wells defer completions instead of buying out drilling contracts or growing oil in a low price environment.
By deferring completions and accelerating oil growth in a better price environment, we maximize 2015 return on capital invested and build momentum as we head into 2016. We plan to enter 2016 with approximately 285 BUCs. If oil prices recover and stabilize around $65 WTI, EOG can resume strong double digit growth with a balanced CapEx to discretionary cash flow program. Objective number 2, focus on improving well productivity and operational efficiencies to position EOG to exit this downturn stronger than we entered it. There are 2 primary drivers that will improve our per well and total asset returns.
The first is well productivity enhancements and the second is well cost reductions. For well productivity, we are expanding our use of high density completions and testing down spacing to maximize NPV per section. For the next productivity game changer, we are beginning to look at ways to improve horizontal target selection. It's still early, but initial results have been promising. On the cost side, the slowdown in activity is giving us more time to focus on efficiency improvements.
While much has been made of service cost reductions, we expect we will gain the most long term benefits from efficiency gains. Our efforts are driving down both well costs and operating expenses. Current well costs are already running at or below 20 15 plan levels across all our major plays. You will hear more specifics on cost reduction and productivity gains in a few minutes as we discuss individual play highlights. Objective number 3 protect our balance sheet by meeting our cash flow and CapEx expectations for the year.
As a result of existing service contract commitments and projects set in motion in 20 14, capital spent for this year is front end loaded. We outspent discretionary cash flow in the Q1, but for the remainder of the year, expect discretionary cash flow and CapEx to be balanced if oil price remains near recent levels. Capital discipline and the strong balance sheet are key to our long term strategy. This allows us to manage our company through a low commodity price environment as such as today's. In addition, that strength allows EOG to continue to make smart long term rate of return driven operational decisions such as infrastructure investments and acreage additions that will pay dividends for years to come.
Objective number 4, take advantage opportunities during the down cycle to add acreage. We're using our exploration skills to define high quality acreage and are having good success capturing leasehold interest in emerging place, competition is down, acreage is available and leasing costs are low compared to previous years. And we're optimistic more opportunities will materialize as the year progresses. We're also evaluating tactical acquisition candidates. Now let's take a moment to discuss our production performance and the outlook for the remainder of the year.
We're not interested in growing oil at the bottom of the commodity price cycle. While oil production did come down sequentially in the Q1, it was slightly over the high end of our guidance. The driver of our outperformance was primarily improved well results. Our integrated completion technology, which combines improvements in target selection and geosteering with our latest techniques in high density completion design is providing the next step change in our well performance. The best rocks respond best and big fields keep getting bigger.
EOG's combination of sweet spot acreage and industry leading technology enables us to continue to outperform expectations. As we described on our February call, our production profile will be U shaped this year. If the current forward oil curve continues to improve, our plan is to increase well completions in the Q3. Therefore, we expect our oil production to return to growth in the 4th quarter, building momentum as we head into 2016. We're right on track with this plan.
Now let's turn our attention to a discussion of our 3 high return oil plays. I will start by discussing the Eagle Ford, then David Trice will discuss the Delaware Basin and Billy Helms will follow with a discussion of the Bakken and the Rockies plays. In the Eagle Ford this year, we are reducing drilling rigs from 23 at year end 2014 to an average of 15. We plan to complete about 345 net wells, which is a 35 percent reduction in completions compared to 2014. As we reduce activity, we have a full core press to continue to reduce well costs and improve well productivity.
And I'm happy to report that excellent progress in both areas is underway. Year to date, we have reduced total well total completed well costs by 10 percent from an industry leading $6,100,000 average well cost in 2014 to our current well cost of $5,500,000 The reduction is driven by a combination of efficiency gains and lower service costs. For 2015, increased pad drilling and fewer drilling requirements lease retention have contributed to the efficiency gains. This year approximately 75% of the wells will be drilled and completed on pads and over 80% of our acreage is currently held by production. By year end, we expect to have more than 90% of our acreage held by production.
We are targeting $5,300,000 well costs by the end of this year, which if accomplished would be 7% below our 2015 plan for the Eagle Ford. In addition to cost reductions, we continue to make significant improvements in our integrated completion process, which combines target selection, shield steering and high density completion designs, identifying the best rock to drill the lateral, keeping the lateral in that rock longer and using the latest completion technology is making a significant difference in well productivity and decline curves. When we compare wells with high density completions versus wells with low density completions, we see a 23% increase in cumulative oil production in the 1st 90 days. We also see that that production rates are holding up longer. With this success, we plan to complete about 95% of our 2015 Eagle Ford wells with high density completion designs.
With lower declines, production growth will be easier to achieve than in previous years and returns on investment will continue to increase as we move forward. Finally, we're still experimenting with various techniques and spacing patterns such as using enhanced target selection methods and experimenting with W patterns within the Lower Eagle Ford. We are optimistic this process will continue to increase our drilling inventory in the future. The slowdown in activity is allowing us to further evaluate this world class asset. With better wells and lower costs, EOG's Eagle Ford asset is in great position to deliver strong growth and returns for many years to come.
I'll now turn it over to David Truss to
cover our Permian Basin activity. Thanks, Bill. If you'll recall, we increased capital spend this year in the Permian where we are still in the early innings of evaluating the ultimate potential of our Delaware Basin asset. As we've ramped up activity in the Delaware Basin, we've made quick progress using our integrated completions process. We identify the best drilling targets within the best reservoirs while making sure we keep our laterals in these discrete intervals.
During the Q1, we were most active in the 2nd Bone Spring sand play, where we are testing various targets as well as different well spacing patterns. Microseismic data we have gathered throughout the play indicates good fracture containment within the individual Second Bone Spring sand targets. For example, we drilled 3 wells in Lea County, New Mexico on the Jolly Roger 16 state lease. The wells tested 3 different Second Bone Spring sand targets at 600 foot well spacing. All three targets are very productive with IP rates ranging from 1030 to 13 15 barrels of oil per day.
And the technical data we collected does not indicate any production sharing between these wells. Going forward, we will continue to push the spacing limits and test new targets. Another notable Second Bone Spring Sand well we brought on in the Q1 was the Brown Bear 36 State No. 502H, which IP ed at a rate of 1700 barrels of oil per day. We are very pleased with these results and expect our individual well performance and recoveries to continue to improve as we refine our drilling targets and implement high density completions.
In addition to impressive well results, we are pushing down cost. Our current well cost is $6,000,000 which is down 22% from 14. We expect this trend to continue and have a target cost of $5,700,000 by year end. The overpressure oil window in the Wolfcamp continues to deliver excellent results in rate of return. The Brown Bear 36 State 701H was drilled in Lea County, New Mexico and came on at 2,165 barrels of oil per day.
We are planning to increase our activity in this play throughout the remainder of the year and we are confident we can achieve increased well performance and lower cost as we move toward development mode. In the Leonard Shale, we created a 300 foot spaced, 4 well pattern during the Q1. The Excelsior 12, 3H, 4H, 5H and 6H were brought online producing from 955 to 11 65 barrels of oil per day. The Leonard Shale is the most mature of our current plays in the Delaware Basin. The well economics continue to improve as we tighten spacing and lower cost.
In fact, much like the Western Eagle Ford, we make better returns at $65 oil now than we could in 2012 at $95 oil. We are optimistic similar trends will emerge in the Wolfcamp and Second Bone Spring sand in the coming years. Even as EOG increases activity in the Delaware Basin, the overall industry slowdown is helping us lower well cost, add additional acreage and optimize long term infrastructure needs such as water handling and takeaway capacity. We are very excited about the potential of the Delaware Basin and its key role in EOG's future growth. Billy Helms will now discuss the Rockies place.
Thanks, David. As we previously stated, most of our 2015 capital in our Rockies plays will be focused in the Bakken with minimal activity in the DJ Basin and Powder River Basin. Each of these are well established plays with significant remaining potential and now all are benefiting greatly from the pullback in activity. Plans are in place and steady progress is being made in lowering cost in each phase of our operations. In the Bakken, the slowdown in activity is allowing us to focus on 3 things.
First, we have made tremendous progress on operational efficiencies and lowering well cost. Our typical 10,000 foot lateral is now drilled in just over 10 days and the well cost is currently 14% less than the 2014 well cost. We anticipate this year's well cost will be as much as 20% below 2014 levels with a target of $7,400,000 2nd, we're using new technical data from our integrated completions process to further adjust and tailor our high density completion designs to specific formation properties. Understanding and using this data gives us insight into how to adjust the completion along the lateral to effectively optimize each stage. These modifications are leading to improved results.
And 3rd, we're able to maintain a more stable production base with minimal downtime associated with offset completion interference. This allows us to better evaluate the production from various spacing patterns to determine our ultimate development plan. In the Q1, we began producing 8 wells in 2 500 foot space patterns in the partial area. Initial per well production rates from a 5 well pattern averaged 12.35 barrels of oil per day and a 3 well pattern averaged 13.45 barrels of oil per day. We are encouraged by the results from these downspacing patterns and are confident in our ability to maximize the recovery and ultimately the net present value of this asset.
In the Diche basin, we continue to refine our targeting in the Codell and experiment with modified completion designs. Recent examples of improved targeting completions are 2 Jubilee wells that each had initial production rates of over 1,000 barrels of oil per day. Further 2015 activity in the DJ will be limited to drilling wells needed to maintain leasehold and finishing completion operations on a few wells. In the Powder River Basin, activity will be focused on delineation and target selection of this profitable stacked resource play. The Turner formation is one of these stacked pay intervals and continues to generate good results as evidenced by the recently completed Flat Bow thirteen-13H with an IT of 8 60 barrels of oil per day.
Our commitment to the long term profitability of our Rockies plays is emphasized by the additional infrastructure capital being invested that could reduce our future well cost by $300,000 to $500,000 per well. These investments include building more pipelines to move water to well sites and adding water handling infrastructure for recycling and disposal. As a result, we will not only reduce upfront capital, but also reduce long term LOE. These investments will decrease our need for trucking services and also help our communities by reducing truck traffic. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
Thanks, Billy. Capitalized interest for the Q1 2015 was $12,000,000 Total cash exploration and development expenditures were 1 point 5 excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $117,000,000
Drilling activity is expected to decline in the 2nd quarter and flatten out and we have maintained our full year capital expenditure guidance of $4,900,000,000 to $5,100,000,000 At the end of March 2015, total debt outstanding was 28%. At March 31, we had $2,100,000,000 of cash on hand, giving us non GAAP net debt of $4,800,000,000 or net debt to total cap ratio of 21%. In April, Moody's confirmed EOG's A3 rating with a stable outlook. The effective tax rate for the Q1 was 28% and the current tax expense was $31,000,000 For the period May 1 through June 30, 2015, EOG has crude oil financial price swap contracts in place for 47,000 barrels of oil per day at a weighted average price of $91.22 per barrel. For the period July 1 through December 31, 2015, EOG has crude oil financial price swap contracts in place for 10,000 barrels of oil per day at a weighted average price of $89.98 per barrel.
These numbers exclude options that are exercisable by our counterparties. For the period June 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for approximately 203,500 MMBtu per day at a weighted average price of $4.31 per MMBtu. These numbers exclude options that are exercisable by our counter parties. Now I'll turn it back over to Bill.
Thanks, Tim. We continue to believe that current oil prices will discourage oil exploration and development worldwide and will encourage demand growth. This will correct the current oversupply situation and the market will continue to rebalance. We believe there is more upside to the forward curve than downside. In summary, here are some important points to take away from this call.
1st, EOG remains disciplined. We're committed to maintaining our strong balance sheet. We do not plan to increase 20 15 CapEx. And at recent oil prices, our CapEx to discretionary cash flow will be balanced for the remainder of the year. 2nd, the company's priority remains squarely focused on returns.
We have directed 2015 capital to our highest oil return plays, which generate 35% or better after tax rates of return at $55 WTI price environment. Returns are improving on each of these assets as we go forward. Well costs are going down and well productivity is going up. Even as oil prices have retreated, our direct rates of return are improving and EOG will be more than competitive in the world markets as we go forward. 3rd, we continue to organically grow reserve potential in our existing plays through down spacing and completion enhancements.
We believe the Eagle Ford, Delaware Basin and Bakken will continue to grow in drilling potential. We're also optimistic that we will find new potential through our exploration efforts. As we test and confirm meaningful results, we will update you with the new potential reserve estimates in the future. 4th, we've said all along that we're preparing to return to growth in 2016 when oil prices improve. If we have $65 WTI price environment in 2016, we can resume our strong oil growth profile with a balanced CapEx to discretionary cash flow program.
And finally, EOG is in this business for the long term. We've not made short term decisions this year that would hinder our future growth. This year, we are even more committed to in technology, exploration, cost reduction and operational execution. The company is building on the culture that has set EOG apart and resetting the bar to be successful in a lower commodity price environment. As we look to the future, we fully expect to remain the North America growth leader and the peer leader in returns on capital employed.
Thanks for listening. Now we'll go to Q and A.
Thank you. The question and answer session will be electronically. And we'll take our first question from Doug Leggate with Bank of America Merrill Lynch.
Thank you, again. Good morning, everyone. Phil, I wonder if I could touch on your completion strategy. What would it take what would you need to see in order to re up the I guess the pace of completions to match your drilling pace? And I guess on a related question as the backlog that you've talked about coming out of 2015, what kind of pace would you expect to move those towards production?
And I've got a quick follow-up please.
Yes. Doug thanks for the question. Yeah. The reason we defer to completions is to really substantially increase the rate of return. So as we go forward this year, it's really important for us to be patient and allow the process to continue to firm up.
As I said, every the first $10 in oil price increase with a 6 month deferral is a $300,000 net CV add to a typical well. So we want to make sure that we allow process to firm up and that the process will continue to be firm in not short term. And then on a as you see, we're getting significant cost reduction as we go forward. We're gaining on that every day and we're gaining on
well productivity as we go forward.
So we don't want to get in a We certainly don't want to jump start completions and We certainly don't want to jump start completions and the price maybe fall back. So if the forward curve continues to stay firm, then our plan as we said is to begin completing wells in the Q3. And we'll really look at what the outlook on 2016 prices are. That's what we're targeting and that's what we're really focusing on. So we'll just continue to watch the fundamentals and certainly we want to be convinced that they're strong going forward.
And we'll really make the call for the 3rd quarter activity probably in July or so after we get a little bit more data.
So just to be clear on the pace of I mean, you can obviously bring those completions by very, very quickly and turbocharge your growth. So I don't know how easy it is to frame the pace, but I mean would you plan to have the backlog reduced to I guess a level that was equivalent to your current drilling rate within a period of time. Can you help kind of walk us through how you might think about that? Just trying to see what the upside is to the growth outlook when you come when you go back to completing those wells?
Yes.
We're going to I guess the answer to that Doug is we're going to be really patient and disciplined about it and kind of gradually increase the activity as we go forward making sure that the price is going to hold up. And we really do as a company, you know EOG, we're very, very focused on returns. So every time that price increases a little bit and every time we get the productivity of wells up and get the cost down, we're making make higher returns. So there's no use pushing that too quickly. And so the ramp up will be as we talked about the production shape is going to be U shaped this year and the 2nd and third quarters will be the low point.
But the 4th quarter with the current plan is to ramp up production growth and be heading into 2016 on a very strong note.
I appreciate that. But Bill, my very quick follow-up, hopefully I'm not taking up too much time here, but just on the comment on tactical acquisitions. I just wonder if I could indulge you if you could indulge me to maybe elaborate a little bit on further your you see a pipeline that has sufficient closure between the bid and ask if you like. And there's been some speculation that you folks might have been interested or may still be interested in looking at some of the resource available in California. And I just wonder if you could add that in your answer and I'll leave it there.
Thank you.
Yes. I'm going to ask Billy Hamz. He's very engaged in that process. And so he can bring us up to date on that.
Yes. Good morning, Doug. We're yes, we are looking at a lot of opportunities. As you know, there's a lot of opportunities out there. There's still a pretty good spread between the bid and the ask on the acquisition front.
I think we'll be very selective. We continue to be very selective in our approach and what we're looking for. And I think we'll see some opportunities as we go forward. But there'll be smaller, more tactical acquisitions as well as just continuing to be able to accrete leasehold in some of our key plays and emerging plays. So I think that's going to be our approach.
I don't think you'll see us doing any large M and A kind of things in the future. They'll be more targeted to the small things that we've traditionally done as a company. And so we'll continue to be very selective and review those on a one case a case by case basis.
And we'll move to our next question that will come from Paul Sankey with Wolfe Research.
Hi, good morning, everyone.
Good morning.
Sorry to press on the drill down completed, but I guess a follow-up is trying to get a sense of the pace at which the 285 would come back relative to how much drilling you would do simultaneously? I think what you're saying is that a $65 plus price you would be ramping up I guess the DUCs or the drilling both simultaneously? Could you just go into that again? Thanks.
Yes, Paul. That's a good question. And as we head into the last half of this year and think about 2016, we'll be on a pretty good uptick. So what we want to do is get the equipment and the people in place and get the process started certainly very strongly in the second half of the year. And then when we hit 2016, if oil prices continue to hold up, we will continue to increase our activity
accordingly. Of
course, the goal is and the plan is to continue to remain CapEx to price of oil is, the more obviously capital we'll have to work with and the more we'll continue to increase our activity. As we look at the 2nd part of this year, part of the process we'll be evaluating is how many drilling rigs to continue to have drilling wells versus releasing rigs and that certainly will be a function of what the oil price is. And so we won't get too far out in front on the drilling side. The 285 BUCs that we start the year with most likely over the first half of the year will reduce significantly as we go forward. And we'll exit the year next year with considerably less DECs than we're exiting this year
with. Yes. I think I understand. So I think if to reinterpret the closer you are to 65 the more DECs will be used to generate the double digit return, but the essentially excuse me the double digit growth. But what you're essentially saying is that if we're 65 or above you will be delivering double digit growth next year?
Yes. I think that's correct. Yes. Good.
Thank you. And then the follow-up is there some criticism always about the relationship between the IRRs of individual wells and how they flow through to corporate returns. Could you just add anything that you have to add on how the current environment and the outlook will flow through if you like to your overall corporate return on capital employed?
Yes. The rates of return that we talk about the direct rates of return and we use direct after tax numbers when we quote our plays. Those are on capital for the well cost and the production facilities of that well. And that's the only cost in there. Of course, the full corporate returns on ROCE are all capital and all capital spent from the history of the company.
And so you've got legacy gas properties in there and lots of other things in there over time. And that's the real difference in the thing. As you everybody has noted over the last several years, EOG's ROCE numbers have continued to improve rather strongly. And over the last year, our ROCE numbers were higher certainly than the E and P peer group and they were even higher than the average of the interim ratings and the majors. So we have one of the strongest track record and one of the strongest ROCEs in the business.
And that just reflects EOG's continued focus on returns. Rates of return on our capital drives every decision in EOG and it is a fundamental metric that we use to manage the company. So as we talk about this year, we're deferring wells. That's really just to drive up the returns on our capital. And all the things we're doing to decrease well cost and increase productivity are very, very focused on driving up the returns of the company as we go forward.
So really that's the main difference.
Appreciate that. Thank you.
And next we'll go to Leo Mariani with RBC.
Hey guys. I was hoping you could give us a little bit more color around your 2nd quarter U. S. Oil production guidance. If I look at the I guess the midpoint in the second quarter, it's down roughly 10% sequentially versus the Q1.
Could you guys kind of provide some color around that, whether or not the number of completions is extremely limited here in the Q2? When you guys talk about deferring, is that deferring almost all of them or just a majority? Could you just kind of give us some color around that?
Yes. The reason that we're our guidance from the 2nd quarter is down is because we've had a significant reduction in the amount of wells we complete. That's really the driver. We were down 39% in completions in the Q1. And then in the second quarter, we're down an additional 36%.
And that is really just the process of deferring the wells and not completing the wells and just really taking off the spin rate as we move into the Q2. So that's really just driving it. And of course those will we still have maintained our full year guidance and we'll be making that back up that production back up in the second half of the year and it will be at much higher returns because we waited.
All right. I guess, obviously, you guys talked about sticking to your capital budget here at all costs. But at the same time, you're also talking about starting to accelerate some completions at $65 oil which could happen as soon as 3Q. Just to clarify is that accelerated activity in 3Q and 4Q if we get to the right oil price? Is that actually in the CapEx budget for 2015 already?
Yes, Leo. Let me let Gary Thomas address that.
Yes, Leo. We do have those incorporated in our capital with our ramp up there as Bill said maybe starting in July just watching oil prices, but then we'll ramp up through the year. As a matter of fact, yes, we're doing less completions. We're trying to keep our frac fleets in place. We've dropped them down from 7 days to 5 days, just everything that can serve capital here in the first half.
All right. That's helpful. And I guess, you guys talked about some down spacing results that you all had. I guess, in particular, it looks like in the Bakken and the Leonard. It looks like some of the IP rates reported in some of those areas a little bit lower than some of the previous wells.
Am I interpreting that you maybe have seen some initial interference on those? Or is that incorrect?
Yes. Leo, this is Billy Helms. For the Bakken, as we continue to experiment with our completion designs, we're seeing different areas of the field have different rock properties and we're tailoring those completion designs to match those rock properties. So we have as you can imagine the quality of the rock varies across the field. So you've got some areas that generate a little bit higher production rates than other areas.
So it's just a function of the properties of that particular area of the reservoir. And we're very confident that our down spacing patterns and our approaches that we're testing are going to lead to our best recovery and net present value
for those
assets. And next we'll go to Subash Chandra with Guggenheim.
Yeah. Hi, good morning. So a question on the Eagle Ford. I guess the W pattern and staggered pattern I guess being described there and some of the other things you're trying, is it too early to hazard a guess as to the inventory gains you might have come out of this process? And similarly in say the Bakken where you're doing similar work?
Yes. It's too early on that to give some guidance on the inventory possibilities. But certainly, we're optimistic there's going to be upside. But really what we're doing there is we're using some enhanced identification tools to really identify the very, very best targets in the Lower Eagle Ford. The rock quality varies as you go vertically up and down the section and we're we believe have the ability to identify better rock in certain parts of the Eagle Ford and then make target selections based on that.
So it's not just a geometric pattern. It really is got a lot of technical work behind it and a lot of high grading as we pick each one of those targets. And so we're really just starting that process and we're optimistic about it, but it's really too early to give guidance on the amount of upside it might be.
Okay. It is fair to say though I think in your commentary you said that because my initial impression was that individual wells would be better, but I think you talked about increasing inventory there. So is it fair to say that as you target these laterals, you might actually be accessing or getting a lot more locations out of more of the rock within say a section?
Yes. That's definitely true. We're hopeful that it will continue to build our inventory up. We have to prove that, but certainly that is a strong possibility.
And next we'll go to Charles Meade with Johnson Rice.
Yes. Good morning to everyone there. Bill, if I could ask a question again on your 15 plants, but maybe from a little different angle. The way it seems to me what you've articulated this morning, it's pretty much the same as what you talked about 2 months ago with ramping activity towards the end of the year into 2016. But I'm curious, can you maybe speak about at the margin?
Has there been any shift in your thinking, especially we're looking at crude over close to 61 here today? And is there maybe some subtlety in a shift from what you were thinking a couple of months ago on when you talked about Q4 results that you want to direct us to?
No Charles. That's a good question. We really don't have a lot of different outlook on the macro or our 2015 plan than we had back in our February call. We made the call to defer drilling because we thought this would be or could be a short term cycle and we're hopeful and certainly we're encouraged by the current firming of the price. So we're hopeful that's what will turn out.
And but we still as I said earlier, we're more optimistic in the forward curve than what it is right now. So we believe being patient and waiting on that price to continue to come up, while also continuing to take advantages of the price cost reductions in the wells and the well productivity improvements. Those will all make a very significant difference in the returns we get on the wells when we begin to complete them. So you're correct. The plan is in the process of thinking is really basically the same as it was in February.
Right. Thank you for that clarification. And then if I could ask about the you guys talked a few times in your press release about these integrated completion designs and tailoring the completion to the individual wellbore. Can you talk a bit about what that means, whether it means varying the stage spacing along the wellbore, whether it's choosing different pump rates or sand loadings for one stage versus the next? And perhaps also offer an idea of how big an opportunity is this?
Yes, Charles this is David. Yes, on these integrated completions, it's not a whole lot different than what we've always done. We've always really focused on the very best rock and the very best interval within the overall section. And we try to keep our lateral in that. And then when it comes to the completions, we integrate that in as well.
And we do vary. We basically design each stage for the well and for that specific portion of the lateral. So it's really an overall process. And we've seen dramatic results over the years and even over the last several quarters in the well results. We really think really think as a it's really kind of part of the EOG culture and gives us a big competitive advantage going forward.
All right. Thanks for that, David.
And next we'll go to Irene Haas with Wunderlich Securities.
Yes. So, hello. My question has to do with Delaware Basin. You are in full development mode in the second Bone Spring. Just maybe a little more color on the Wolfcamp, your successful wells, are they coming from the upper or middle interval?
And ultimately, how many benches within the Wolfcamp could be productive in this part of Delaware Basin, sort of in the Central North?
Yes, Irene, this is David. As far as the Wolfcamp goes, we've mainly been targeting the Upper Wolfcamp. We think that there is a very large potential throughout the Wolfcamp, but our focus has mainly been on the upper. And with regard to the 2nd Bone Spring sand, we're moving towards development mode there. We obviously have a lot of work to do.
We're testing a lot of targets. We're testing spacing there and we're continuing to refine our completions. But we see quite a bit of upside left really in all those plays.
Great. Thank you.
And moving on, we'll go to David Tamarong with Wells Fargo.
Hi, good morning. I'll leave the acceleration question alone. I won't hit on that anymore. But just to clarify, you guys in the presentation you put in well costs, which are running ahead of plan and then you put some target well costs. Are those achievable are those targets achievable?
Is that a 2015 goal? Is that a 2016 kind of outlook? Or how should we think about those target well costs?
This is Gary Thomas. And last February, we just mentioned that we were expecting to see our well cost down in the 10% to 20% range. And we're really pleased with the progress that we've made there and the various teams. But it looks to me that our costs are going to be in the 20 to 20 plus. In most all these areas we've got target wells or record wells that have exceeded our targets.
So yes, we're making good strides there and we're also pleased that about half of that gain has been in vendor cost reduction, but the other half has been in our efficiency gains. And we're really pleased with the efficiency gains because you can see that on the number of days per well. And that's why we had the one exhibit comparing, yes, the Barnett we had worked in for several years versus the Eagle Ford and there's still quite a lot of room, which is the EOG mantra, yes, pleased, not satisfied. We're going to continue to make gains there.
All right. Thanks.
Thank you.
Moving on, we'll go to Pierce Hammond with Simmons and Company.
Good morning. Thanks for taking my questions.
Good morning. Bill,
service providers have highlighted refracs as a significant opportunity. Do you see such an opportunity for EOG with refracs?
Pierce, we get that question quite a bit and we've looked at it and talked about it internally. And we've not tried any refracs. Our outlook on that is that it really technically we believe that just drilling a new well and kind of starting fresh and making sure your lateral is in the very best target and making sure that you can redistribute the frac very evenly along the wellbore with a new well is probably the preferred way to go. We just think that the upside on the completion will be much greater than if you tried to refrac the well. Then the other thing obviously that contributes to that is that the well cost on the drilling side as we can see are just getting lower and lower and becoming a smaller percentage of the total well cost.
So drilling a new well from the drilling side standpoint just a pretty low cost item today and there's a lot more upside in just drilling the well redrilling the well and doing it right.
Great. Thanks for that color.
And then my follow-up is how quickly do you think the industry and this includes obviously the service companies who've had to lay off a lot of people. How quickly do you think the industry can respond to higher prices? Is there going to be a substantial lag to adding activity? Or do you think there's enough capacity out there service capacity that it can come back in fairly rapid order?
No. It appears it depends on how much longer this goes. If we were ramping up here in the next month or 2, I think it can wrap up pretty rapidly. And that's why many of us operators are trying to keep as many services in place even at reduced work levels just to maintain that support by service companies. So as we've said before, yes, we'll be able to ramp up pretty rapidly on our production with just our DUCs that we have in inventory.
But then it will take possibly a little longer just to wrap the drilling side.
Great. Thanks for the color.
And next we'll go to Brian Singer with Goldman Sachs.
Thanks. Good morning.
Good morning, Brian.
I wanted to just see if you could provide some clarity on how your decline rates are trending versus your expectations on a few fronts. It seems you're naturally seeing sharper 1st year decline rates that complement your higher initial production rates from enhanced completions. What trends are you seeing overall versus your type curves in the Eagle Ford, Bakken and Permian when it comes to declines? And then any efforts you're making on longer term decline rate mitigation in this environment? The wells
in the better pay zones and then doing a better job of the wells in the better pay zones and then doing a better job of placing the completions along the lateral is we're seeing actually that the declines are flattening over time. So a little bit less decline over time. And I think that's transferring itself also to the company level. I think as the base of production gets more mature and larger and relative to the new wells we're bringing on that our production decline is flattening over time as well. So I think we're seeing a lot of advantages to this new completion technique that we're still yet to fully realize and will mature with time.
Got it. Thank you. And then shifting back to the Delaware Basin and the Wolfcamp area, you highlighted the Brown Bear Wolfcamp well. Can you put into context what a 24 hour rate of 2,165 barrels a day means relative to your 900 MBOE typical Wolfcamp EUR? It seemed like the oil mix there was much higher versus your typical well.
And whether this is an area that you already assumed was commercial or whether it represents a step out in Lea County? Just kind of want to see whether this is a normal well and above average well or something that's more substantive from a resource and productivity perspective?
Yes, Brian. This is David. I would say certainly this is a very good well and we're not necessarily surprised by it. Lea County is a good area. We've drilled some good Wolfcamp wells there in the past.
I think as far as how it compares to the model, I think it'd be fairly close to the model. And but we're we continue to see progress on these wells. And I think over time, we're hopeful that we'll even see better wells.
And our final question will come from Marshall Carver with Heikkinen Energy Advisors.
Yes. Regarding the W shaped patterns in the Eagle Ford, are you testing that in several areas? And how much of the acreage do you think might work for that? And how far a part of the wellbore is in those patterns? How much tighter is it than what you were doing before?
Marshall, the W patterns, we'll do multiple pilots patterns on that. And it really will apply to I think the bulk of our Eagle Ford acreage. And what we're doing is we're bringing the wells in. We've been drilling wells anywhere from 300 to 500 feet apart in our typical patterns, but we're bringing those closer. And we'll be doing that at various spacing closer than 300 to 500 feet.
And it really will vary a bit on the spacing depending on the area. But the general concept of picking out multiple targets within the Lower Eagle Ford using these advanced techniques to identify the best rock will be applicable across the bulk of our acreage.
Okay. Thank you. And one follow-up if I could. The current 2016 strip is at $65 but you mentioned seeing more upside than downside on the strip. How would hedges potentially factor into your plans to accelerate?
If the Strip moves up, could we see it how are you thinking about that hedges and how it could going to do your plans for acceleration?
Yes, Marshall. We're certainly evaluating that all along and we're really again a bit more optimistic about the forward curve even than it is today. But we want to put some hedges in going into next year. And we'll just be looking at that and trying to find the opportunistic entry point as we kind of go forward. So really kind of watch the fundamentals of supply and demand and really pick the point that we think is the right point to make an entry there.
And that does conclude our question and answer session. I'll turn it back to Mr. Bill Thomas for any additional or closing comments.
We're very excited about what's happening in EOG this year. We said at the beginning of the year that when this downturn started that we wanted to emerge in better shape than we entered it. And what you're seeing today and what was exactly that happening. And in my 36 years with the company, I've never seen a company respond better. The company is driving down cost and improving the productivity of the wells rapidly.
And whether oil prices remain where they are today or continue to improve, EOG is resetting the bar to be successful for many years to come. And we thank you for listening today and thank you for all your support.
Thank you. And once again, that will conclude today's conference. We'd like to thank everyone for their participation.