EOG Resources Inc (EOG) 2015 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Good day, and welcome to the EOG Resources first-quarter 2015 earnings results conference call.

(Operator Instructions)

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 first-quarter 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 in 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 US investors that appears at the bottom of our press release in the 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 Trice, EVP, Exploration and Production; Lance Terveen, VP, Marketing and Operations; and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, and we included guidance for the second quarter and full-year 2015 in yesterday's press release.

This morning we will discuss topics in the following order. Bill Thomas will review our 2015 plan and first quarter highlights. David Trice 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 two months ago on our year-end call, and I am pleased that our first quarter results are right on track. We are quickly transforming the company to be successful in this low price environment.

There are four basic objectives to our 2015 plan. Objective number one: maximize 2015 return on capital invested, and position the company to resume strong growth when 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% of our 2015 capital is directed. We generate a direct after-tax rate of return of 35% 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 have also stated that we have no interest in accelerating oil production at the bottom of the commodity price cycle. Instead, we are drilling but deferring completions on a significant number of wells known as DUCs until oil prices improve. A $10 increase in the price of oil with a six-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 and 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 DUCs. 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 two: focus on improving well productivity and operational efficiencies to position EOG to exit this downturn stronger than we entered it. There are two 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 is 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 2015 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 three: 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 2014, capital spent for this year is front-end loaded. We out-spent discretionary cash flow in the first quarter. But, for the remainder of the year we expect discretionary cash flows 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 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 four: take advantage of opportunities during the down cycle to add acreage. We are using our exploration skills to define high quality acreage, and are having good success capturing leasehold interest in emerging plays. Competition is down, acreage is available, and leasing costs are low compared to previous years, and we are optimistic more opportunities will materialize as the year progresses. We are 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 are not interested in growing oil at the bottom of the commodity price cycle. While oil production did come down sequentially in the first quarter, it was slightly over the high end of our guidance. The driver of our out-performance 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 third quarter. Therefore we expect our oil production to return to growth in the fourth quarter, building momentum as we head into 2016. We are right on track with this plan.

Now let's turn our attention to a discussion of our three 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 the 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% reduction in completions compared to 2014. As we reduce activity we have a full court press to continue to reduce well costs, and improve well productivity, and I am happy to report that excellent progress in both areas is underway.

Year-to-date, we have reduced total completed well costs by 10%, from an industry-leading $6.1 million average well cost in 2014 to a current well cost of $5.5 million. The reduction is driven by a combination of efficiency gains and lower service costs. For 2015, increased pad drilling and fewer drilling requirements for 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 $5.3 million 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, geosteering and high density completion designs. Identifying the best rocks 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 first 90 days. We also see 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 are 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 will now turn it over to David Trice to cover our Permian Basin activity.

Thanks, Bill.

If you will 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 have ramped up activity in the Delaware Basin we have 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. This, combined with our use of advanced EOG completion techniques has resulted in dramatically improved wells.

During the first quarter we were most active in the Second Bone Spring Sand play, where we are testing various targets, as well as different well spacing patterns. Micro seismic data we have gathered throughout the play indicates good pressure containment within the individual Second Bone Spring Sand targets.

For example, we drilled three wells in Lea County, New Mexico on the Jolly Roger 16 state lease. The wells tested three different Second Bone Spring Sand targets at 600-foot well spacing. All three targets are very productive with IP rates ranging from 1,030 to 1,315 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 first quarter was the Brown Bear 36 state number 502H which IP'd 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 costs. Our current well cost is $6 million, which is down 22% from 2014. We expect this trend to continue and have a target cost of $5.7 million by year-end.

The overpressure oil window in the Wolfcamp continues to deliver excellent results in rate of return. The Brown Bear 36 state number 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 completed a 300-foot spaced, four-well pattern during the first quarter. The Excelsior 12 number 3H, 4H, 5H, and 6H were brought online, producing from 955 to 1165 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 Wolf Camp and Second Bone Spring Sand in the coming years.

Even as EOG increases activity in the Delaware Basin, 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 plays.

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 all are benefiting greatly from the pull-back 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 three 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 $7.4 million.

Second, we are using new technical data from our integrated completions process to further adjust and tailor our high density completions 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 third, we are 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 first quarter, we began producing eight wells in two 500-foot space patterns in the partial area. Initial per-well production rates from a five-well pattern averaged 1,235 barrels of oil per day, and a three-well pattern averaged 1,345 barrels of oil per day.

We are encouraged by the results from these down-spacing patterns and are confident in our ability to maximize the recovery, and ultimately, the net present value of this asset. In the DJ Basin, we continue to refine our targeting in the Codell, and experiment with modified completion designs. Recent examples of improved targeting completions are two 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 Flatbow 13-13H with an IP of 860 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 will now turn it over to Tim Driggers to discuss financials and capital structure.

Thanks, Billy.

Capitalized interest for the first quarter 2015 was $12 million. Total cash exploration and development expenditures were $1.5 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property, plant, and equipment were $[170] million.

Drilling activity is expected to decline in the second quarter and flatten out. And we have maintained our full-year capital expenditure guidance of $4.9 billion to $5.1 billion. At the end of March, 2015 total debt outstanding was $6.9 billion and the debt to total cap ratio was 28%.

At March 31 we had $2.1 billion of cash on hand, giving us non-GAAP net debt of $4.8 billion, for a 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 first quarter was 28% and the current tax expense was $31 million.

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 counter-parties.

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 will 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 re-balance. 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. First, EOG remains disciplined. We are committed to maintaining our strong balance sheet. We do not plan to increase 2015 CapEx, and, at recent oil prices, our CapEx to discretionary cash flow will be balanced for the remainder of the year.

Second, 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.

Third, 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 are also optimistic that we will find new potential through our exploration efforts. As we test and confirm meaningful results, we will update you with new potential reserve estimates in the future.

Fourth, we have said all along that we are 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, double digit oil growth profile with a balanced CapEx to discretionary cash flow program.

And finally, EOG is in this business for the long-term. We have not made short-term decisions this year that would hinder our future growth. This year we are even more committed to advancements in technology, explorations, 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 will go to Q&A.

(Operator Instructions)

We will take our first question from Doug Leggate with Bank of America Merrill Lynch.

Thank you again. Good morning, everyone.

Bill, I wonder if I could touch on your completion strategy? What would you need to see in order to re-up the pace of completions to match your drilling pace? On a related question, the backlog you've talked about coming out of 2015, what kind of pace would you expect to move those toward production?

And I have a quick follow-up, please.

Yes, Doug, thanks for the question.

The reason we have deferred the completions is to really substantially increase the rate of return. So as we go forward this year, it is really important for us to be patient and allow the process to continue to firm up. As I have said, the first $10 in oil price increase with a six-month deferral is a $300,000 net PV add to a typical well. So we want to make sure that we allow prices to firm up and that the prices will continue to be firm and not short term.

And then as you see, we are getting significant cost reduction as we go forward. We are gaining on that every day, and we are gaining on well productivity as we go forward. We do not want to get in a hurry. We want to stay disciplined. 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've said, is to begin completing wells in the third quarter.

We will really look at what the outlook on 2016 prices are. That is what we are targeting, and that is what we are really focusing on. So we will just continue to watch the fundamentals. And certainly we want to be convinced that they are strong going forward. And we will really make the call for the third-quarter activity probably in July or so, after we get a little bit more data.

So just to be clear on the pace. I mean you can obviously bring those completions back very quickly and turbocharge your growth.

I don't know how EOG has defined the pace. But would you plan to have the backlog reduced to a level that was equivalent to your current drilling rate within a period of time? Can you walk us through how you might think about that? Just trying to see what the upside is to the growth outlook when you go back to completing those wells.

Yes. I guess the answer to that, Doug, is we are 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 are very, very focused on returns. So every time that price increases a little bit, and every time we get the productivity of the wells up and get the cost down, we're making higher returns. So there is no use pushing that too quickly.

The ramp-up will be, as we talked about, the production shape is going to be U-shaped this year; and the second and third quarters will be the low point. But the fourth 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 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 wondered if I could indulge -- if you could indulge me to maybe elaborate a little bit on whether you see a pipeline that has sufficient closure between the bid and ask, if you like. 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 was wondering if you could add that in your answer, and I will leave it there.

Yes, I'm going to ask Billy Helms. He's very engaged in that process, and so he can bring us up to date on that.

Good morning, Doug.

We are looking at a lot of opportunities. As you know, there are a lot of opportunities out there. There is still a pretty good spread between the bid and the ask on the acquisition front. I think we will be very selective. We continue to be very selective in our approach and what we are looking for.

I think we will see some opportunities as we go forward. But they will 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 is going to be our approach.

I don't think you'll see us doing any large M&A kind of things in the future. They will be more targeted to the small things that we have traditionally done as a Company. So we will continue to be very selective and review those on a case-by-case basis.

We will 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 at a $65 plus price, you would be ramping up the DUCs or the drilling, both simultaneously? Can you just go into that again? Thank you.

Yes, Paul, that is a good question. And as we head into the last half of this year and think about 2016, we will 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. 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 discretionary cash flow balanced. So that will really govern our activity. The stronger the price of oil is, the more, obviously, capital we'll have to work with; and the more we will continue to increase our activity.

As we look at the second 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. We won't get too far out in front on the drilling side. The 285 DUCs that we start the year with, most likely over the first half of the year we'll reduce significantly as we go forward. We will exit the year next year with considerably less DUCs than we are exiting this year with.

Yes, I think I understand. To reinterpret, the closer you are to $65, the more DUCs will be used to generate the double-digit return -- excuse me, the double-digit growth. But what you are essentially saying is if we're $65 or above, you will be delivering double-digit growth next year.

Yes, I think that's correct. Yes.

Thank you.

And then the follow-up is there is some criticism always about the relationship between the IRRs of individual wells and how they flow through to corporate returns. Can 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? Thank you.

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 costs and the production facilities of that well, and that is 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. So you've got legacy gas properties in there and lots of other things in there over time. That is the real difference in the thing.

As 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&P peer group. And they were even higher than the average of the integrateds and the majors. So we have one of the strongest track records 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 the fundamental metric that we use to manage the Company. As we talk about this year, we are deferring wells. That is really just to drive up the returns on our capital. And all the things we are doing to decrease well costs and increase productivity are very, very focused on driving up the returns of the Company as we go forward. So really that is the main difference.

I appreciate that. Thank you.

Next we will go to Leo Mariani with RBC.

Hi, guys. I was hoping you could give us a little bit more color around your second quarter US oil production guidance. I look at the midpoint in the second quarter, it's down roughly 10% sequentially versus the first quarter. Can you kind of provide some color around that -- whether or not the number of completions is extremely limited here in the second quarter?

When you talk about deferring, is that deferring almost all of them or just a majority? Can you just give us some color on that?

Yes. The reason that our guidance on the second quarter is down is because we have had a significant reduction in the amount of wells we complete. That is really the driver.

We were down 39% in completions in the first quarter. And then in the second quarter, we are 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 second quarter. So that is really just driving it.

And of course those will -- we still have maintained our full-year guidance. And we will be making that production back up in the second half of the year, and it will be at much higher returns because we waited.

All right. Obviously you 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 will ramp up through the year. As a matter of fact, yes, we are doing less completions. We are trying to keep our frac rates in place. We've dropped them down from seven days to five days -- just everything to conserve capital here in the first half.

That's helpful.

You talked about some downspacing results that you all have had -- I guess in particular it looks like in the Bakken and the Leonard. It looks like some of the IP rates you 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?

Leo, this is Billy Helms.

For the Bakken, as we continue to experiment with our completion designs, we are 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 have 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 are very confident that our downspacing patterns and our approaches that we are testing are going to lead to our best recovery and net present value for those assets.

Next we will go to Subash Chandra with Guggenheim.

Good morning. So a question on the Eagle Ford.

I guess the W pattern -- the staggered pattern being described there -- and some of the other things you are 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 are doing similar work?

Yes, it is too early on that to give some guidance on the inventory possibilities. But certainly we are optimistic there's going to be upside. But really what we are doing there is we are 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 work. We believe we have the ability to identify better rock in certain parts of the Eagle Ford and then make target selections based on that. So it is not just a geometric pattern. It really has got a lot of technical work behind it and a lot of high grading as we pick each one of those targets.

So we are really just starting that process, and we are optimistic about it. But it is really too early to give guidance on the amount of upside it might be.

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 is definitely true. We are hopeful that it will continue to build our inventory up. We have to prove that, but certainly that is a strong possibility.

Next we will go to Charles Meade with Johnson Rice.

Good morning to everyone there.

Bill, if I could ask a question again on your 2015 plans, 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 two months ago with ramping activity towards the end of the year and into 2016.

I am curious. Can you maybe speak about at the margin, has there been any shift in your thinking? We are looking crude over $60, close to $61 here today. Is there maybe some subtlety in a shift from what you were thinking a couple of months ago when you talked about Q4 results that you want to direct us to?

No Charles, that is 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. We are hopeful, and certainly we are encouraged, by the current firming of the price. So we are hopeful that is what will turn out.

But we still, as I said earlier, we are 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 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 are correct; the plan and the process of thinking is really basically the same as it was in February.

Right, thank you for that clarification.

Then if I could ask about the -- you talked a few times in your press release about these integrated completion designs and tailoring the completion to the individual well bore. Can you talk a bit about what that means? Whether it means varying the stage spacing along with the well bore; whether it's choosing different pump rates or sand loadings from one stage versus the next; and perhaps also offer an idea of how big an opportunity is this?

Charles, this is David.

On these integrated completions, it is not a whole lot different than what we have always done. You know we have 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. When it comes to the completions, we integrate that in as well. We do vary. We basically design each stage for the well and for that specific portion of the lateral.

So it is really an overall process. And we have seen dramatic results over the years, and even over the last several quarters, in the well results. We really think it's part of the EOG culture and gives us a big competitive advantage going forward.

All right, thank you for that, Dave.

Next we will go to Irene Haas with Wunderlich Securities.

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 the Delaware Basin or in the Central North?

Yes, Irene, this is David.

As far as the Wolfcamp goes, we have 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 Second Bone Spring Sand, we are moving towards development mode there. We obviously have a lot of work to do. We are testing a lot of targets. We're testing spacing there, and we are continuing to refine our completions. But we see quite a bit of upside left really on all those plays.

Great, thank you.

Moving on, we will go to David Tameron with Wells Fargo.

Hi, good morning. I will leave the acceleration question alone. I won't hit on that anymore.

But just to clarify, 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 outlook? 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 costs down in the 10% to 20% range. And we are really pleased with the progress that we have made there and our various teams. But it looks to me that our costs are going to be in the 20% to 20%-plus. In most all of these areas, we have target wells -- or record wells that have exceeded our targets. So, yes, we are making good strides there. And we are also pleased that about half of that gain has been in vendor cost reduction.

But the other half has been in our efficiency gains. I'm 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 [against] the Barnett that we had worked in for several years versus the Eagle Ford, and there is still quite a lot of room. It's just the EOG mantra: pleased, not satisfied, we're going to continue to make gains there.

All right. Thanks.

Moving on, we will go to Pearce Hammond with Simmons & Company.

Good morning. Thanks for taking my questions.

Bill, service providers have highlighted refracs as a significant opportunity. Do you see such an opportunity for EOG with refracs?

Pearce, we get that question quite a bit. And we have looked it and talked about it internally, and we have not tried any refracs. Our outlook on that is that 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 well bore with a new well is 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 costs on the drilling side, as we can see, are just getting lower and lower and becoming a smaller percentage of the total well costs. So drilling a new well, from the drilling-side standpoint, is a pretty low-cost item today. And there is a lot more upside in just redrilling the well and doing it right.

Great. Thanks for that color.

My follow-up is how quickly do you think the industry -- and this includes obviously the service companies, who have 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 could come back in fairly rapid order?

Pearce, it depends on how much longer this goes. If we were ramping up here in the next month or two, I think you can ramp up pretty rapidly. And that is 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 have said before, yes, we will 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 ramp up the drilling side.

Great, thanks for the color.

Next we will go to Brian Singer with Goldman Sachs.

Thanks, good morning.

Good morning, Brian.

I wanted to see if you could provide some clarity on how your decline rates are trending versus your expectations on a few fronts. It seems you are naturally seeing sharper first-year decline rates that complement your higher initial production rates from enhanced completions. What trends are you seeing overall versus your tight 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.

Yes, Brian, this is Billy Helms.

What we are actually seeing on our new completion approaches by targeting the wells in the better pay zones and then doing a better job of placing the completions along the lateral, is we are seeing actually that 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. As the base of production gets more mature and larger relative to the new wells we are bringing on, our production decline is flattening over time as well. So I think we are seeing a lot of advantages to this new completion technique that we are 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 have already assumed was commercial or whether it represents a step out in Lea County? I just want to see whether this is a normal well, an above-average well, or something that is more substantive from a resource and productivity perspective.

This is David.

I would say certainly this is a very good well, and we are not necessarily surprised by it. Lea County is a good area. We have drilled some good Wolfcamp wells there in the past.

I think as far as how it compares with the model, I think it would be fairly close to the model. We continue to see progress on these wells. And I think over time we are hopeful that we will even see better wells.

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 your acreage do you think might work for that? And how far apart are the well bores in those patterns? How much tighter is it than what you were doing before?

Marshall, the W patterns -- we will do multiple pilots, patterns, on that; and it really will apply to the bulk of our Eagle Ford acreage. What we are doing is we are bringing the wells in. We have been drilling wells anywhere from 300 feet to 500 feet apart in our typical patterns. But we are bringing those closer.

And we will be doing that at various spacing, closer than 300 feet 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, how are you thinking about that -- hedges and how it could fit into your plans for acceleration?

Marshall, we're certainly evaluating that all along. And we are really, again, a bit more optimistic about forward curves, 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 go forward. So we're going to watch the fundamentals of supply and demand, and really pick the point that we think is the right point to make an entry there.

(Operator Instructions)

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 are very excited about what is 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 are seeing today and what we are reporting today is exactly that happening. And in my 36 years with the Company, I have never seen a Company respond better.

The Company is driving down costs 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.

So 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.