EOG Resources Inc (EOG) 2014 Q3 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources third-quarter 2014 earnings results conference call. 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. Thanks for joining us. We hope everyone has seen the press release announcing third-quarter 2014 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in our earnings release and EOG's SEC filings, and we incorporate those by reference with 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 and investor relations page of our website.

Participating on this call this morning are Bill Thomas, Chairman and CEO; Billy Helms, Executive VP, Exploration and Production; David Trice, Executive VP, Exploration & Production; Maire Baldwin, Vice President, IR; and Lance Terveen, Vice President, Marketing Operations. An updated IR presentation was posted to our website yesterday evening, and we included fourth-quarter and full-year guidance in yesterday's press release.

This morning we will discuss topics in the following order. I will first review our 2014 third quarter net income and discretionary cash flow; and then Bill Thomas, David Trice and Billy Helms will provide operational results. I will then address EOG's financials, capital structure and hedge position. Finally, Bill Thomas will provide concluding remarks.

As outlined in our press release for the third quarter 2014, EOG reported net income of $1.1036 billion, or $2.01 per share. EOG's third quarter 2014 adjusted non-GAAP net income, which eliminates the mark-to-market impacts and certain nonrecurring items as outlined in the press release, was $720.6 million or $1.31 per share.

Non-GAAP discretionary cash flow for the third quarter was $2.2 billion. At September 30, 2014, the debt to total cap ratio was 25%. Adjusting for cash, the net debt to total cap ratio was 20%, down from 23% at December 31.

I will now turn it over to Bill Thomas to discuss operational results and key plays.

Thanks, Tim. EOG continues to deliver outstanding production growth and financial metrics by consistently executing on our strategy of investing in high return organic crude oil growth. For the third quarter, all three of our production components exceeded our expectations and our unit costs were below our forecast.

Total Company crude oil and condensate production was up 27% for the third quarter, and 33% compared to the first nine months of 2013. Total liquids production including NGLs increased 27% for the third quarter, and 31% for the first nine months.

Based on these results, we are raising our full-year crude oil growth target for the second time this year to 31% from 29%. We are increasing our total Company production growth target to 16.5% from 14%, based on outperformance from our Eagle Ford and Delaware basin assets.

I will now address the Eagle Ford; then David Trice will provide an operational update on the Permian, and Billy Helms will discuss the Bakken and Rockies plays.

In the Eagle Ford, I can characterize our current activity in three points. One, the Eagle Ford is on track for multi-year growth. Two, we continue to make enhancements in completions. And three, the Eagle Ford is the industry's best crude oil asset, and we have captured a sweet spot.

I will now address each point in more detail. First point, the Eagle Ford is on a growth trend for the next ten years. On the May earnings call, we indicated our model was based on making a modest increase to 520 net wells we had initially planned this year, and holding that will count flat through 2024.

In this scenario, the oil production grows for ten years. Based on our production this year, we are set up to achieve this upward growth curve.

Second point, our well quality continues to improve with completion enhancements. Even after five years, we are still experimenting with completion designs, and we continue to see improved well productivity and higher overall NPV.

Our completions are customized for specific rock properties, not only in each well, but in each and every stage within the well. We have been testing what we call high density fracs.

In one area, we saw a 39% improvement in well productivity from this new frac design relative to adjacent wells. Year-to-date, we have seen a 10% average improvement in well performance from our Western Eagle Ford acreage drilling activity. We have included illustrations in our accompanying IR slides for reference.

Third point, the Eagle Ford continues to be the industry's and EOG's premier crude oil play in North America for both production growth and financial returns. Our drilling program will remain very profitable despite fluctuations in oil prices.

At $80 oil, the Eagle Ford will still generate direct after tax rates of returns in excess of 100%. At less than $40 oil, we would still achieve a minimum 10% direct a tax rate of return. The Eagle Ford remains EOG's highest rate of return asset.

While we still see some cost pressure in completion services, we are able to control cost increases largely with our self-sourced sand and other completion materials. We also continue to make progress reducing drilling days during the second and third quarter. Year-to-date, we have decreased our average drilling days by 12% in the Eagle Ford.

One final point: we would caution those who use monthly Texas Railroad Commission's state data as a measure of Company current production and a forecasting tool for future production. Remember, the state data tends to lag, and is potentially incomplete on a month to month basis for a variety of reasons.

To wrap up the Eagle Ford, EOG's long term oil growth will be anchored by this world-class asset, where we are still improving well productivity through new completion designs and by lowering well costs. I will now turn it over to David Trice to discuss EOG's activity in the Permian.

Thanks, Bill. In the Delaware basin, we continue to test and drill step out wells to confirm the viability of each of our three plays across our acreage. In the Wolfcamp, we had exciting news in the third quarter. After testing some of our northern Delaware basin acreage, we confirmed that a majority of it is in the highly over-pressured crude oil window, where we expect the wells to be 50% crude oil.

We completed two upper Wolfcamp horizontal wells, which flowed 46-degree API gravity crude oil. The Voyager 15 #3H was completed at a maximum oil rate of 1,890 barrels of oil per day, with 385 barrels per day of NGLs and 2.5 million cubic feet a day of natural gas from a 4,400-foot treated lateral. The well had a 30 day average rate of 1,500 barrels of oil per day, with 365 barrels per day of NGLs and 2.3 million cubic feet of gas per day.

The Voyager is located along the Texas-New Mexico state line in Loving County, Texas. EOG has a 48% working interest in this well.

The Diamond SM-36 State #1H flowed at a maximum rate of 1,340 barrels of oil per day, 195 barrels of day of NGLs, and 1.3 million cubic feet of gas from a 2,200-foot treated lateral. This well is north of the Voyager in Lee County, New Mexico in the heart of our Red Hills acreage, and EOG has 100% working interest in this well.

We have done some preliminary G&G work, and have confirmed that 90,000 net acres of our high-graded 140,000 net acres in the Delaware Wolfcamp are in a highly over-pressured crude oil window. We plan to increase our Wolfcamp drilling activity in this crude oil window, where we expect to achieve reinvestment returns much higher than the Combo window and competitive with our Second Bone Spring Sand and Leonard plays.

In the Second Bone Spring Sand, we drilled our third well in the Red Hills area during the third quarter. It was a 20-mile step out from our first two wells to further confirm the viability of our acreage.

The State Magellan #2H near the state line in Loving County, Texas was completed with a 4,900-foot treated lateral and flowed at a maximum rate of 1,825 barrels of oil per day of 44-degree API gravity oil, with associated production of 295 barrels of NGLs per day, and 2.2 million cubic feet of gas per day. These wells are 70% crude oil. The State Magellan well gives us additional confidence in the play's early extent, and following additional geological work on our existing acreage, we have increased the prospectivity of the Second Bone Spring Sand to at least 90,000 net acres.

The Leonard shale also continues to deliver solid well results. In the third quarter, we have turned the State Pathfinder 1H to sales with a maximum rate of 1,370 barrels of oil today, 245 barrels per day of NGLs, and 1.3 million cubic feet of gas per day. The well was part of a 450-foot spacing test and has a 4,800-foot treated lateral.

Going forward, we plan to develop the Leonard on 300 to 450-foot spacings. We have also modestly increased our holdings to 80,000 net acres in this play.

We plan to increase our activity in the Delaware basin from four rigs at the end of the third quarter to eight rigs by year-end. We plan to drill additional wells in the Wolfcamp, Second Bone Spring Sand and Leonard, as anticipated in our original plan.

To summarize our activity in the Delaware, we had a very promising result after drilling our first two oil wells in the crude oil window, the Wolfcamp, where we have 90,000 net acres. With an additional data point, we are gaining further confidence in the Second Bone Spring Sand, and we continue to deliver excellent well results from the Leonard, even as we further downspace the wells. With these three outstanding plays, EOG is well-positioned for high rate of return crude oil growth in the Permian for many years to come.

I will now turn it over to Billy Helms to discuss the Bakken and the Rockies.

Thanks, David. We began our downspacing campaign in the Bakken corridor at the beginning of the year by systematically testing spacing patterns starting at 1,300 feet between wells. With confidence from the production profiles of the 1,300 foot spaced wells, we began testing 700-foot spacing earlier this year, and now have data from the wells that have been producing for four to seven months. Simultaneous with downspacing, we have seen improvements in well productivity after introducing new completion technology to the field.

We are encouraged by early indications from the 700-foot spaced wells, but we need additional time to assess the impact on long-term production, reserves, and ultimately the net present value. We also have pilot spacing tests with 500-foot and 300-foot patterns to determine the optimal spacing to maximize the net present value of the field.

We noted a number of new Core wells in our press release. The Parshall 44-1004H came online at 2,710 barrels of oil per day, with 875 Mcf per day of rich natural gas, and the Parshall 46-1004H came online at 2,105 barrels of oil per day, with 860 Mcf per day of rich natural gas. We have 69% working interest in both of these wells.

As we noted on our press release, in the Antelope Extension area we had success from the Three Forks first, second and third benches. We completed our first well in the third bench of the Three Forks, the Mandaree 134-05H which came online at 1,410 barrels of oil per day, with 2.2 million cubic feet of natural gas. We have 70% working interest in this well. We will continue testing the potential of the Three Forks across our Antelope acreage, and we will expand our Three Forks testing in the Core in 2015.

In the DJ Basin, we completed our first seven well development pattern on a multi-well pad consisting of four Niobrara and three Codell wells. The wells were drilled with long laterals spaced at approximately 700 feet between wells in the same zone.

The seven wells came online at a combined rate in excess of 7,800 barrels of oil per day with 5.4 million cubic feet per day of rich natural gas. We have 75% working interest in these wells.

We plan to test spacing patterns in various completion types for the balance of the year. Early production results verify initial type curves and provide confirmation of our EUR estimates.

This program is delivering consistent initial production rates of 1,000 barrels of oil per day per well. We are rapidly climbing the operational learning curve in this play, and expect to achieve our well cost targets in the near-term.

In the Powder River Basin, we have maintained our one rig program and are on track to drill 34 net wells this year, targeting the Parkman and Turner reservoirs. In the Turner Sand, we completed two wells, the Mary's Draw 24-13H and 25-13H for a combined rate of 1,880 barrels of oil per day, with 3.1 million cubic feet per day of rich natural gas.

We have one new well from the Parkman: the Mary's Draw 412-1527H came online at 1,190 barrels of oil per day, with 270 Mcf per day of rich gas. In Trinidad, we are actively drilling on three well -- a three net well development program, which will allow us to maintain flat natural gas production in coming years.

I will now turn it over to Tim Driggers to discuss financials and capital structure.

Thanks, Billy. For the third quarter capitalized interest was $14.5 million. Total cash, exploration and development expenditures were $2 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $184 million.

Year-to-date total exploration and development expenditures were $5.8 million, excluding asset retirement obligations. Expenditures for gathering, processing plants and other property plant and equipment were $587 million.

We had $17 million of proceeds from asset sales during the quarter, and there were no acquisitions. At the end of September, total debt outstanding was $5.9 billion. At September 30, we have $1.5 billion of cash on hand. The effective tax rate for the third quarter was 36% and the deferred tax ratio was 81%.

Yesterday, we included a guidance table with the earnings press release for the fourth quarter and full year 2014. For the fourth quarter and full-year the effective tax rate is estimated to be 32% to 37% and 34% to 37%, respectively. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the fourth quarter and for the full year.

In terms of our hedge positions, for the period November 1 through December 31, 2014, EOG has crude oil financial price swap contracts in place for 192,000 barrels of oil per day, at a weighted average price of $96.15 per barrel. For the first half of 2015, we had 47,000 barrels per day of crude oil hedged at an average price of $91.22 per barrel.

For the second half of 2015, EOG has 10,000 barrels per day of crude oil hedged at an average price of $89.98 per barrel. These numbers exclude options that are exercisable by our counterparties.

For the month of December, 2014, EOG has natural gas financial price swap contracts in place for 330,000 MMBTU per day at a weighted average price of $4.55 per MMBTU. For the period January 1 through December 31, 2015, EOG has natural gas financial price swap contracts in place for 175,000 MMBTU per day at a weighted average price of $4.51 per MMBTU. For the same period, we have a 175,000 MMBTU per day of options that could be exercised by our counterparties at an average price of $4.51 per MMBTU for each month.

Now I will turn it back to Bill to discuss EOG's overview for 2015 and provide a summary.

Thank you Tim. Now for our 2015 overview. Although our planning process won't be complete until the beginning of the year, I want to provide some color regarding our 2015 capital allocation. EOG has key positions in the top domestic crude oil plays. We have tremendous reinvestment opportunities in the Eagle Ford, Bakken and Delaware Basin that will generate after-tax rates of return of 100% or greater at $80 WTI.

We have added a new chart to our presentation showing the minimum oil price that would be required to generate a 10% direct after-tax rate of return. At $40 oil we would still achieve a 10% direct after-tax rate of return in the Eagle Ford, the Bakken Three Forks and the Delaware plays. Our 2015 plan is to manage a balanced CapEx cash flow program, with CapEx plus dividends in line with cash flow.

Our strategy will remain the same. EOG will be physically (sic - fiscally) prudent, with low net debt and a very strong balance sheet. At $80 oil we should have sufficient cash flow to fully fund our Eagle Ford, Bakken and Delaware Basin plays, and sustain double-digit oil growth through 2017 and beyond.

We plan to invest in our highest return crude oil plays and reduce our activity in our Combo plays. We still expect to be a leader in organic growth -- crude oil growth next year.

The dividend continues to be a high priority. Our Board remains committed to increasing shareholder return through both high-return production growth and dividend growth.

Now let me conclude. There are four important takeaways from this call. First, we have talked about our key plays for a couple of years: the Eagle Ford, Bakken and Delaware Basin Leonard. Today's call has highlighted these three plays and our ability to improve our results with leading-edge completion technology.

We continue to make better wells, while lowering costs with self-sourced sand and drilling efficiencies. Our excellent base of key plays keeps getting better.

Second, as a result of continuous productivity improvement in the Eagle Ford and Delaware basin, we have increased our oil growth target for the second time this year. Third, we continue to organically add new high return plays to our drilling portfolio, as well as high-grading existing plays through improved completions, enhanced targeting and the identification of sweet spots on our acreage. The Second Bone Spring Sand and Delaware Wolfcamp oil plays are good examples of this strategy.

Although we are expanding our portfolio, the Eagle Ford will remain our foundation, a high return production growth driver for many years. And finally, EOG is focused on returns, and our large high-quality drilling portfolio still generates exceptional returns with $80 oil. With best-in-class horizontal crude oil assets and a strong balance sheet, EOG will continue to be a leader in absolute organic US crude oil production growth in 2015 and beyond.

Thanks for listening, and now we will go to Q&A.

Thank you.

(Operator Instructions)

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

Thank you, good morning, everybody. Thanks for all the additional color in the presentation this morning. Bill, I have got one question on CapEx, and maybe one for Billy on the Permian. On CapEx, you guys have become very -- fairly well-known as living within cash flow. Obviously, with the oil price down, and you have given us fairly consistent production guidance for next year, how should we think about your spending relative to cash flow given your strong balance sheet? Do you still intend to live within cash flow, or would you allow the spending to go up a little bit given the strength of your balance sheet?

Yes. Good morning, Doug, and thanks for the question. In next year we need to be thinking about continuing to have a very strong balance sheet. And as we talked about in our opening remarks, our capital spending plus the dividend will be balanced to our cash flow. So the disciplined spending fundamentals of the Company are not going to change as we go forward. And we are only focused in reinvesting in the highest return plays, and we are not really interested in exceeding cash flow by trying to accelerate production in the combo plays, or certainly not the gas plays.

So just to be clear, I mean, I guess the overall level of activity though in a lower oil price environment -- is it fair to assume that the overall drilling activity would have to slow? So I am guessing bigger wells but fewer wells, if you see what I mean?

Yes, the -- as we look, let's just assume, Doug, if we have an $80 oil environment next year, we are going to be -- have enough cash flow to fully fund our Eagle Ford, Bakken and our Delaware programs. And all those programs generate in excess of 100% rate of return at $80 oil.

What we would cut back on is the combo plays, certainly the Barnett combo; some of our drilling in South Texas; in the Mid-Continent at East Texas. And even in the Permian, where we have the Wolfcamp combo, we would not spend as much money on those. But we need to be thinking that we would fully fund the Eagle Ford, the Bakken and the Delaware Basin plays, and that we would have a very strong double-digit production growth next year, oil growth. And we would continue to be a leader in organic oil growth in the US.

Thanks for that. My follow-up hopefully quickly is on the Permian. I guess, first of all, congratulations on your very strong results there. It has underlined by the step up in the rig count, but I think historically you had raised some question about infrastructure constraints. So I am just wondering with your move to four to eight rigs, how -- do you now believe you have resolved any restrictions on EOG? Or is that still an issue for the basin as a whole? And I will leave it there. Thank you.

Doug, this is David. On the Permian, the great thing is that we have got three plays there that are all really high rate of return. And they are each slightly different, and so we have got a lot of options there as far as play selection. And for instance, the Second Bone Spring Sand tends to be a lower GOR play, so that gives us a lot of options if there is any type of gas takeaway restrictions or anything. So we have got a lot of options -- we have got a lot of options on the marketing side. I will let Lance follow up with the marketing questions.

Yes, Doug, just to follow up on -- I mean, it's very encouraging on the midstream infrastructure that is going to be coming online especially over the next year. So we have really aligned ourselves with the new capacity that is going to be coming online. So there might be a little bit of potential; as the new timing comes on, it could be a little tight. But we have contracted ourselves and aligned ourselves with a lot of these midstream providers that -- we feel at this time we are going to be in good shape.

I appreciate your answers guys, thank you.

(Operator Instructions)

We will take our next question from Leo Mariani with RBC Capital Markets.

Hey guys, I was hoping maybe you could kind of talk to a little bit of the dynamics around your fourth-quarter US oil production guidance? I am kind of looking at what you guys have laid out, and my math is indicating about a 0% to 2% sequential oil growth in the US. You guys did about 7% in the third quarter versus 2Q sequential growth. Can you maybe just kind of address why the lower growth on the fourth quarter?

Yes, good morning, Doug -- I mean, Leo; that is a good question. Thank you for that. In the fourth quarter our production growth is really highly predicated on timing of the completions. And so, we have a good number of wells; the majority of the wells will come on very late in the quarter and most of them, a lot of them will be in December. So when you bring them on late in the year, obviously they don't add as much impact to the quarter.

Okay, that's helpful for sure. I guess then in terms of the Permian plays, it looks like you guys certainly have made a step forward there recently. I guess, a couple of just sort of quick questions around that. Just trying to get a sense of what kind of inning you are in there? I mean, obviously you have been at the Eagle Ford for quite a bit longer than the Delaware basin. And additionally, can you maybe talk to potential improvements there that you might see down the road in EURs and well costs; and is there any potential to add more acreage?

Yes, Leo, this is David. I would say on the Permian we have been very deliberate on testing new zones and testing the extent of these -- of the plays. And I would say we are very early on; we are probably third or fourth inning, if you want to put into baseball terms. And so, we are going to continue aggressively test these new zones and the extents of these plays and test the spacing of these plays, and potentially -- to go to your second part of your question -- with oil prices at $80, there is potential going forward that we could add some acreage.

All right. That's really helpful. Thanks, guys.

The next question is from Paul Sankey with Wolfe Research.

Hello, good morning, everyone. There was an interesting inflection point coming in terms of free cash flow to you guys. And now we have had this inflection point with the oil price. I think what you are saying clearly is that you will have trimmed back your CapEx in some of the more marginal areas. If oil prices were surprising to the upside next year, would you be pushing perhaps towards generating free cash flow for cash return to shareholders? Or do you think you would reaccelerate your activity? Thanks.

Yes, thank you, Paul, good morning. As we think about 2015, obviously our goal is to fully fund the Eagle Ford, Bakken, and Permian plays with those very high returns. But we are going to also continue to be very committed to the dividend, and the dividend growth. We have had 15 years -- and we have increased the dividend 16 times in 15 years, and we don't expect that pattern to decrease as we go forward.

So we are always focused on returning value to the shareholders through that way. Obviously, with better prices next year, that would help us to fully fund more drilling. But we are very confident, even with the low price environment, we are going to be able to have very strong double-digit growth going forward, and continue to be a leader in US organic production growth -- so.

I guess my point was, you are already a leader in organic production growth. Wouldn't you be now in the situation where at the margin, you would be looking for even more rapid increases in cash return as opposed to extending your lead in growth?

Yes, I think that's something that our Board will certainly consider as we go forward. And they are -- obviously, as we look at the commodity price next year, the higher the price, the more flexibility we will have to work on the dividend as well as increase drilling activity in some of the other plays.

Sure, I've got you. And then the second follow-up question is, we have had an interesting announcement from BHP today with regard to exports. I assume it is not a coincidence at the same time as the Republicans have taken control of the Senate. Is there -- can you just give your perspective on that move, and what it means for you? Thank you.

Hey, Paul. Yes, it's Lance. Obviously, we are closely watching everything that is going on out in the market. But a lot of what you are seeing is on ultra light oil, which is very high gravity condensate. So when we look at our three big plays, essentially EOG has very, very little condensate. So we really have an ability to blend the condensate in with our crude oil. So kind of a follow-up there. We are going to continue to watch it but -- and strike as necessary.

But the actual export is less relevant to you as such in terms of your own activity?

That is correct, Paul.

Okay. Thank you all.

The next question is from Joe Allman from JPMorgan.

Thank you, operator, and good early morning, everybody.

Good morning Joe.

So just a clarification on the plans for 2015 spending. So are you saying that you plan to spend within cash flow from operations, or potentially would you be contemplating some asset sales to help fund some CapEx?

Yes, Joe. The -- we are going to keep the cash flow in balance with the CapEx, plus the dividend. But also, we have sold properties over the years, and that is something that we will be considering next year also. And those properties obviously will be kind of non-core properties, properties that will help us be more efficient as a Company, reducing LOE costs, and properties that don't have scale, that don't have maybe the potential as some of the others. So yes, that will be part of our plans next year is continue to sell additional properties.

Okay. That's helpful. And then a follow-up, in the Eagle Ford the high-density frac results are pretty impressive. So what are the main parameters around the high-density fracs that really give you that uplift from even early this year production results?

Yes, these are new techniques, Joe, and they are experimental and really proprietary. So we don't want to give out a lot of details on what we are doing, other than to say that we have made significant improvements in distributing the frac more evenly along the lateral. And that has contacted more rock, and we have this one example in our IR book; it is on slide 26. You may want to look at that in detail.

But it shows that 2014 wells, kind of the current completion practices versus several of these high-density fracs in close proximity, the wells are in close proximity. And there is a 39% increase in the first 60 days. So we are very excited about it, and we have only completed high-density fracs on really kind of a handful of wells. So as we go forward, this gives us a lot of encouragement that there is still considerable room left to go in the Eagle Ford, and really all of these plays on improvements in completion technology.

All right. Very impressive. Thank you, Bill.

Our next question is from Bob Brackett with Sanford C. Bernstein.

If we stayed in a lower crude price environment through next year, what would your interest be in acquiring distressed assets or operators that might be in trouble?

Good morning, Bob. Yes, good question. EOG is -- our focus and our success has been really generating new potential through organic exploration.

And we see no lack of opportunity in that direction, and those we were able to generate -- and we generated five new plays this year. And we have a good list going forward that we have -- we are hopeful will be a good addition to the Company at very low costs. So the acquisition business, as you all know, historically there's a lot of competition in M&As and acquisitions, and usually they turn out to be very, very low return. So we are going to continue to maintain our focus on growing the Company organically through exploration, and low cost acreage acquisitions and that process.

Great, thanks. And you've had a couple of competitors talk about East Texas a bit more in the last quarter. You've got a position up there. How does that stack in your portfolio? Or is it still too early to know?

Bob, that's -- again, yes, it is too early to know there. And we as everybody knows, we are drilling wells there, and we are testing concepts. And when we have meaningful results on that, we will be able to update everybody on, but it is still really early.

And as we talked about before, we have a very high cut off; because our asset quality is so strong in the Company, we are not interested in going forward with, you know, plays that would generate less than a 50% return. So we are working on only plays and spending a lot of money and going forward with very high quality plays. So we are taking our time, and we will let everybody know when we have some meaningful results.

Thanks.

The next question comes from Irene Haas with Wunderlich Securities.

Yes, hey, guys. This is really interesting, so it is becoming sort of a mining operation. So I am curious as to -- as you continue to improve these resource plays, for example, in the Eagle Ford, what percent recovery we are up to like right now with your assessment?

Yes, good morning, Irene. In the Eagle Ford we have quit giving a percent recovery factor there, because we are still, I think, trying to re-look at what the oil in place is there. But it is certainly going up all the time. And we continue -- as we showed and demonstrated in some of the charts, and we have talked about this morning -- we continue to make very significant increases in the completion technology. Being able just to contact more rock along the lateral, and keep the contact closer to the wellbore so that we can drill additional wells closer together as we go forward. And so we think we are in about the sixth inning in the Eagle Ford, so there is a lot of room left to go there.

Great. If I have one follow-up, I am going to hit you up on the macro view in this very volatile time.

Are you talking about the price of oil?

Oil, gas, yes, because usually you guys would have a few lines on that.

Yes, we are pretty good at some things. But the world's oil supply and demand situation is not an area that we have a lot of expertise in, and special insight in. We've read a lot of the same reports and follow the same analytics that many of you do, and we are going to kind of leave it up to them to kind of give direction on. There is a lot of opinions out there on what oil prices could do.

Okay, thank you.

The next question is from Pearce Hammond with Simmons & Company.

Good morning.

Good morning, Pearce.

What level of flexibility do you have regarding oil services, like rigs and completion crews, et cetera, in your contracts if you needed to adjust activity in a low oil price environment?

Yes, Pearce, good question. We have about 33% -- about a third of our frac spreads are under long-term contracts, and about 50% of our drilling rigs are under long-term contracts, company-wide. So we have a lot of flexibility to lower activity if we need to, or increase activity if that is warranted. And we also have a lot of flexibility to take advantages of any kind of price decreases that may happen. We are already beginning to see, especially in the frac equipment business, we are already seeing some price reductions. And certainly if prices stay at these levels, we could see a bit more of that going forward.

Thank you. And then my follow-up, if under a low oil price environment, will you prioritize away from exploration and focus more on development? And then as a leader, how do you balance the need for exploration to drive future growth of the Company with lower cash flows and the need to maybe focus on development?

On that, Pearce, as we go forward and if we stay at a pretty low price environment, we don't really expect to pull back on much of our exploration efforts, because they are very, very low cost. Our entry cost on these plays is extremely low, because we are out front in areas where nobody really else is looking. And so, we don't expect to have a significant pullback on that.

We are generating significant amount of new inventory each year. This year we have generated two times the amount of drilling inventory that we have actually drilled this year. Some of that of course is in the existing plays, but again, were generated in new plays too. So the Company is a very prolific organic prospect generating machine, and we think that we can continue to do that at very, very low cost. As we -- in the last few years, our exploration costs have been relatively low in the Company, and a very small part of our budget.

Thank you very much.

Our next question is from Arun Jayaram of Credit Suisse.

Good morning. Bill, I wanted to get your thoughts on the overall development strategy from here in the Eagle Ford. I know you have 6,000 locations; you are drilling 520, 540 wells per annum. So I just wanted to get your thoughts on how you develop it from here. I guess the reason I ask that question is I have noted that you have downshifted activity in the last couple of quarters in Gonzales County and perhaps increased some activity on the western side of the play, the Atascosa, so and just trying to get some thoughts on how do you move -- plan on the rig moves, et cetera.

Yes, good morning, Arun; thank you for that question. As we go forward, the mix of wells in the Eagle Ford will be relatively what they have been in the last several quarters. In the third quarter, it was about 52% of the wells were in the West, and 48% were in the East. And as we look going forward, that mix will stay about the same.

We did drill in the third quarter some retention wells, and holding some of that acreage that would be kind of classified as less than 60% [a tax] rate of return kind of acreage. So we just drilled the initial wells on that to hold that. We don't plan on developing that acreage anytime soon going forward, but we wanted to hold it. But just directionally, the mix of well should be relatively consistent with what we have been doing in the last several quarters.

Okay. So just to clarify that, Bill -- Q3 perhaps the mix of wells was towards a lower rate of return than typical on lease retention, and you would expect that to normalize maybe going forward? Is that fair?

Yes, we drilled 28 wells to do lease -- excuse me -- lease retention in some of those lower return acreage in the third quarter. And going forward, we don't have that many wells planned to do that going forward. So that will drop off as we go forward.

That is very helpful. My follow-up, Bill -- as you have talked about expanding opportunity set in the Delaware; you are moving from four to eight rigs by year-end -- so I just wanted to ask you, do you think you have the appropriate level of scale in the Delaware? Are there opportunities through leasing, where you would like to get a little bit bigger in the Delaware?

Yes, Arun, this is David. We have laid out the three big plays, you know, that we announced today. And those, we have numerous locations in those. We have got many, many years of drilling just in those plays. And like I said before, we have been very deliberate about testing new ideas and continuing to push the boundaries of these existing plays. So I think we have plenty of scale there in the Delaware basin.

Thank you very much.

We will take the next question from Brian Singer with Goldman Sachs.

Thanks, good morning.

Good morning, Brian.

Without trying to tie you down to a production or CapEx guidance for next year, in the plays you do plan to focus on, the Eagle Ford, the Bakken, the Delaware basin, can you run through how you see required spending from HBP or infrastructure versus discretionary spending evolving next year -- i.e., what efficiency gains do you see on the horizon where you could keep the growth engine running without having to spend as much capital? And perhaps an estimate for how much capital that could represent?

Yes, Brian, thanks for the question. As far as acreage retention or explorations, we have very little requirements in that area. For example, this year -- at the end of the year in the Eagle Ford, we will be 80% of our acreage is HBP. And by the end of 2015, it will be 95%. So the actual retention drilling in the Eagle Ford will be less next year than it is this year. And then in the Permian, we have just a little bit that we have to do for retention drilling, and then in the Bakken, it is all held by production.

So we have a lot of flexibility to make sure that we are focusing on drilling and on high return. And so, there was another part of your question. You have to remind me again; what was that?

Yes, the infrastructure -- it is just a bit of the same question for infrastructure. In each of those areas, do you see your infrastructure needs to support growth rising or falling?

Yes, that's a good question. We see, I think, next you are a bit less spending in infrastructure than we did this year. Because, again, a lot of the infrastructure this year was in the Eagle Ford, and we were doing a lot of step out or retention drilling, and you have to build out to that. As that dies off, the need for infrastructure is less.

Great, thanks. And then if well performance is driving your stronger than guided to production results, do you see your rates of return in the Eagle Ford, Bakken and Delaware improving as a result? And in each of those areas, how much would you attribute to greater first year production, versus greater overall recoveries, versus better production mix?

Yes, as the well productivity increases with the completion designs, it is very additive to the return. So as you bring the oil, obviously, forward quicker, the returns go up; and we are also able to continue to lower costs at the same time, too, and be more efficient in that area. So the rates of return, given a constant commodity price, are improving.

And to your point was -- you're pushing up production earlier on with the completion technique, which might be a little more different than your recovering more overall?

Yes, I think -- Brian, this is Billy Helms. I think I would also add to that is, yes, Bill is right. The rate of return is certainly increasing; we are increasing initial production rates, too. But we are also increasing the recoveries of the wells. So overall recovery is going up, too. So we are not just accelerating early time production at the sake of longer-term production. We are seeing an uplifted overall curve.

Great, thank you.

We will go next to David Tameron with Wells Fargo Securities.

Hello, good morning, Bill. Question, can you guys talk about what you -- how you are completing these wells in the Permian? I know you had in there one of those little yellow boxes on one of those slides that talked about your advanced completion technology. So I imagine you don't want to give all the secrets, but can you give us like some framework around the way you are completing these?

Yes, David. In the Permian, just like we do in all our other plays, it is a constant experiment. In the Eagle Ford, you have seen the track record that we have had there. We just continue to experiment and to push it. So a lot of the techniques that we have learned in these other plays have been applied to the Permian. And like Bill had mentioned earlier, we don't want to give out any specific details on that. But we do spend a lot of time experimenting with each play, and each play is a little bit different. So -- but we have got a good process in place.

Any reason that the 4,500-foot lateral versus the longer lateral, or you just haven't got to that yet? Or is this just -- anything you can comment on that? Is that geologic, or can you talk about that?

Your question is, why don't we drill longer laterals than 4,500 foot?

Yes, have you tried the longer laterals? And it seems like just most of the stuff you mentioned, at least in the slide deck, was on the shorter 4,500 foot.

Yes, I mean, each play is different. And so, we have done longer laterals, both in the Delaware and in the Midland basin. And it just depends on the cost of drilling the added footage, and then -- and also the performance of the wells. And so, what we have generally seen is, at least there in the Delaware basin, that we tend to prefer to go with more of the 5,000- to 4,500-foot lateral. And it also helps -- that tends to be kind of the lease size configuration as well.

Okay. And then just back to the Eagle Ford. I think it was Bill, you mentioned the ROC data. Could you give us any framework just around what the Eagle Ford is doing, as far as overall basin production quarter over quarter, sequentially, or can you give us anything along those lines?

David, no, I don't have that in front of me right now; I may have to get back with you on that. You are talking about the whole field for all operators?

No. No, just for your specific Eagle Ford. I mean, there is so much concern about your Eagle Ford production levels. I was just looking for some -- directionally -- or just some type of comfort, I guess, you can give us on your end?

Yes. No, I mean again we have talked about -- we have got a 10 year growth profile in the Eagle Ford, as we go forward, and we are on target for that pretty consistent. We are drilling 540 wells this year, and again, the mix of wells that we drill going forward will be relatively the same. So we are planning a long-term growth profile there.

All right. I will circle back later. Thanks, I appreciate it.

The next question is from Charles Meade with Johnson Rice.

Yes, good morning, Bill, and to the rest of your team there.

Good morning.

I was wondering if I could go back to the Three Forks, and get you guys to maybe decompose a bit the results you are seeing there? And what I'm really curious about in the end is, is there any chance for the Three Forks to -- I know it's pretty already high in the stack of your plays there, but is there a chance for it to either move higher or get bigger? And I guess, the little bit of the detail to add there is, the rates you guys have on those Mandaree wells are good, but they are even more impressive when you look at the lateral lengths you guys had on them.

And as I understand it, a lot of the Three Forks has kind of been puzzling to people, and sometimes there is a undifferentiated log response, and it's hard to predict what is going to be good, and what is not. So can you talk about what the prospects for that to grow in your portfolio are?

Yes, Charles, this is Billy Helms. On the Three Forks, we are probably going a little bit slower than we are relative to the Bakken. Most of our activity in that area will be focused on the Bakken, because that is what we consider the higher rate of return, the more consistent development play in that program.

In the Three Forks, however, we do realize the potential in that play, and we are anxious to get some more tests in. And as you can see with the results we have had this quarter, they are all testing out fairly strong. I would say we are still delineating what the ultimate extent of that play will be across our acreage position, and what each zone will contribute across the acreage position. So I think we are still little bit early in that play, and again, most of our activity will be focused on the Bakken as we go forward. I think there is -- we are certainly pleased with the upside we see there, and we will continue to test that with some encouragement from these wells.

Thank you, Billy.

We will go next to Matt Portillo with TPH.

Good morning.

Good morning, Matt.

Just two quick questions for me. My first question revolves around your international asset base. So I was wondering if you could give us an update on your thoughts around East Irish Sea and the production potential coming on stream in 2015?

Yes, on our Conwy project -- that's going to be coming on in the second quarter of 2015. And what we expect there is, that we will have kind of a ramp-up phase, and probably max out at around -- about 20,000 barrels a day for a couple of months there.

Great. And then, I guess, just back on the CapEx question: as we look at your programs for 2014, is there any color you could provide us in terms of the capital that you are spending currently this year, on assets outside of the main three? You have talked about -- the Eagle Ford, the Delaware and the Bakken? Maybe that would help us with some of the context as we head into 2015 from an expectation perspective?

Matt, we are -- we have active drilling programs, a one rig program in the Barnett Combo. We have a rig or two running in the Mid-Continent, a couple of rigs running in East Texas, and a couple of rigs running in South Texas. So we do have activity this year outside the Eagle Ford, the Bakken and the Permian. Plus, we also, as we talked about earlier in the year these new plays in the Rockies, we are running a rig or two in the Powder River. And I believe we are running two rigs in the DJ -- actually it's four rigs in the DJ basin. So we have quite a bit of activity in plays outside of the core plays.

Thanks very much. That's very helpful.

This concludes today's question and answer session. At this time, I would like to turn the conference over to today's speakers for any additional or closing remarks.

Well, thank you very much for listening and for your continued support.

I would just like to say that -- concluding -- that we are confident as we head into 2015 -- and been with the Company 35 years; every time we go through one of these price cycles, EOG outperforms. And we come out of that price cycle in better shape than we entered it. So the Company is in great shape with a sweet spot in the best horizontal plays in the US. And along with our low cost and our industry-leading technology, EOG is going to be a strong performer in the years to come, and a leader in the US oil growth.

So again, thank you for listening.

This concludes today's call. Thank you for your participation.