Tim Driggers - Chief Financial Officer Bill Thomas - Chairman and CEO Billy Helms - Executive VP, Exploration and Production David Trice - Executive VP, Exploration and Production Mario Baldwin - Vice President, IR Lance Terveen - Vice President, Marketing Operations.

Doug Leggate - Bank of America Leo Mariani - RBC Capital Markets Paul Sankey - Wolfe Research Joe Allman - J.P. Morgan Bob Brackett - Sanford C.

Bernstein Irene Haas - Wunderlich Securities Pearce Hammond - Simmons & Company Arun Jayaram - Credit Suisse Brian Singer - Goldman Sachs David Tameron - Wells Fargo Securities Charles Meade - Johnson Rice Matt Portillo - TPH.

Please standby, we are about to begin. 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 the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures.

The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves, as well as possible reserves.

Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S.

investors that appears at the bottom of our press release and Investor Relations page of our website.

Participating on the call this morning are, Bill Thomas, Chairman and CEO; Billy Helms, Executive VP, Exploration and Production; David Trice, Executive VP, Exploration and Production; and Mario 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’ll 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 $1,103.6 million or $2.01 per share. EOG's third quarter 2014 adjusted non-GAAP net income, which eliminates the mark-to-market impacts and certain non-recurring items as outlined in the press release was $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’ll 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 productions components exceeded our expectations and are 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 of 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 multiyear growth; two, we continue to make enhancements in completion; and three, the Eagle Ford is the industry's best crude oil asset and we’ve captured the sweet spot. I’ll now address each point in more detail. First one, the Eagle Ford is on a growth trend for the next 10 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 net well count flat through 2004. In this scenario, the oil production rose for 10 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 MPB.

Our completions are customized for specific rock properties not only in each well, but in each and every stage within the well. We've been testing what we call high-density frac. 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 industries and EOG’s premiere crude play in North America for both production growth and financial returns. Our drilling program will remain very profitable, despite fluctuations in oil process. At $80 oil, the eagle ford will still generate direct after-tax rates of return 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 and completion services, we are able to control costs increases largely with our self-source sand and other completion materials.

We also continue to make progress reducing drilling days during the second and third quarter. Year-to-date, we’ve decreased our average drilling days by 12% in the Eagle Ford.

One final point, we would caution those who used 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 it’s 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 confirm 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 flow 46 degree API gravity crude oil.

The Voyager 15 number 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 barrel per day of NGLs and 2.3 million cubic feet of gas per day.

The Voyager is located along the Texas, New Mexico Stateline in Loving County, Texas. EOG has a 48% working interest in this well. The Diamond SM 36 State number 1H flowed at a maximum rate of 1,340 barrels of oil per day, 195 barrels per 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’ve done some preliminary G&G work and have confirm that 90,000 net acres of our hydrated 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 Springs 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 number 2H near the Stateline in Loving County, Texas was completed with a 4,900 foot-treated lateral and flowed at a maximum rate of 1,825 barrels 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 plays they will extend and following additional geological work on our existing acreage, we’ve 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 turned the State Pathfinder 1H to sales with the maximum rate of 1,370 barrels of oil per day, 245 barrels per day of NGLs and 1.3 million cubic feet of gas per day. The well was part of the 450 foot spacing test and has a 4800 foot-treated lateral. Going forward, we plan to develop the Leonard 300 to 450 foot spacing.

We've 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 then anticipate 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 in the Wolfcamp where we have 90,000 net acres.

With an additional data point, we are getting further confidence in the second Bone Springs Sand and we continue to deliver excellent wells result from the Leonard, even as we further downspace the wells. With these three outstanding plays, EOG is well-positioned for higher rate return crude oil growth in the Permian for many years.

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 Core 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 begin 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 product spacing test 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 on line at 2,710 barrels of oil per day, with 875 Mcf per day of rich natural gas and the Parshall 46-1004H came on line 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 in 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 on line 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 on line 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 tasks 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 on line at 1,190 barrels of oil per day, with 270 Mcf per day of rich gas.

In Trinidad, we are actively drilling out 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 $2.0 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 had $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 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 at current taxes that we expect to report 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 weighted average price of $96.15 per barrel. For the first half of 2015, we have 47,000 barrels per day of crude oil hedge 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 hedge 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 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 the summary..

Thanks, 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’ve 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 fiscally prudent with low net debt and a very strong balance sheet. At $80 oil, w 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 talked about our key plays for a couple 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 by 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 U.S. crude oil production growth in 2015 and beyond. Thanks for listening. And now, we will go to Q&A..

(Operator Instructions) And we will take our first question from Doug Leggate with Bank of America..

Thank you. Good morning, everybody. Thanks for all the additional color on the presentation this morning. Bill, I have got one question on CapEx and maybe one for Billy on Permian. On CapEx you guys have become very well-known as living within cash flow.

Obviously with the oil price down and given some fairy consistent production guidance for next year, how should we think about your spending relative to cash flow given your strong balance sheet? Do you intend to still 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. Next year we need to be thinking about continuing to have a very strong balance sheet. And as we talked about in opening remarks, our capital spending plus the dividend will be balanced our cash flow. So the discipline spending fundamentals of the company are not going to change, as we go forward.

And we’re only focused in reinvesting in 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 I guess just to be clear, I mean, I guess the overall level of activity though and the overall price environment, is it fair to assume that the overall drilling activity would have to slow? So I’m guessing bigger wells but fewer wells if you see what I mean?.

Yeah. As we look just -- let's just assume, Doug, if we have an $80 oil environment next year we’re going to be have enough cash flow to fully fund our Eagle Ford, Bakken and our Delaware program. So all of 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, in East Texas and even in the Permian where we have the Wolfcamp Combo. We would not spend as much money in 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 very strong double-digit production growth next year, oil growth and we would continue to be a leader in organic oil growth in the U.S..

Thanks for that. My follow-up hopefully, quickly is on Permian. I guess, first of all congratulations on your very strong results there. It’s been underlying by the step-up in the rig count. But I think historically, you’ve raised some question about infrastructure constraints.

So I’m just wondering with your move to four to eight rigs, do you not believe this result any restrictions on EOG or is that still an issue for the basin as a whole, now even there? Thank you..

Doug, this is David. On the Permian, the great thing is we've got three plays there, they’re all really high rate of return. And they’re each slightly different. And so we've got a lot of options there as far as play selection.

For instance, the Second Bone Spring Sand tends to be a lower QR play and so that gives us a lot of options, if there is any type of gas takeaway restrictions or anything. So we’ve got a lot of options -- we’ve got a lot of options on the marketing side. I’ll let Lance follow up with the marketing question..

Yeah, Doug, just to follow up on -- I mean, it’s very encouraging on the midstream infrastructure that’s going to be come online, especially over the next year or so. We’ve really aligned ourselves with the new capacity that’s going to be coming online. So it might be a little bit of potential as the new timing comes on.

It could be a little tight, but we’ve contracted ourselves and aligned ourselves with a lot of these midstream providers that we feel at this time are going to be in good shape..

I appreciate the answers guys. Thank you..

(Operator Instructions) And we’ll take our next question from Leo Mariani with RBC Capital Markets..

Hey, guys. I was hoping that you could kind of talk to a little bit of a dynamics around your fourth quarter U.S. oil production guidance. Kind of looking at what you guys have laid out, my math is indicating about the 0 to 2% sequential oil growth in U.S. 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?.

Yeah. Good morning, Doug -- I mean, Leo. That’s 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, in terms of the Permian plays, it looks like you guys certainly have made a step forward there recently. I guess couple just sort of quick questions around that.

Just trying to get a sense of kind of what kind of inning you’re in there? I mean obviously, you’ve 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 cost? And is there any potential to add more acreage?.

Yeah. Leo, this is David. I would say on the Permian, we've been very deliberate on testing new zones and testing the extent to these other plays. And I would say, we’re very early on. We’re probably third or fourth inning if you want to put it in baseball terms.

And so we’re going to continue to aggressively test these new zones and the extent 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 $8o there is potential going forward that we could add some acreage..

That’s really helpful. Thanks guys..

The next question is from Paul Sankey with Wolfe Research..

Hi. Good morning, everyone. There was an interesting inflation point coming in terms of free cash flows to you guys. And now we’ve had this inflation point with the oil price. I think what you’re saying clearly is that you will have trimmed back your CapEx in some of the more marginal areas.

If oil prices were surprising the upside next year, would you be pushing perhaps towards generating free cash flow for cash return to shareholders? Or do you think you'd reaccelerate your activity? Thanks..

Yeah. Thank you, Paul. Good morning..

Good morning..

As we think about 2015, obviously our goal is to fully fund the Eagle Ford, Bakken and the Permian plays but those very high returns. But we’re going to also continue to be very committed to the dividend and dividend growth.

We’ve had 15 years that we’ve increased the dividend 16 times in 15 years and we don’t expect that pattern to decrease as we go forward. So we're 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’re very confident even with the low price environment we’re going to be able to have very strong double-digit growth going forward and continue to be a leader in U.S. organic production growth..

I guess, my point was you’re already a leader in the 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 leading growth?.

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

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

Hey, Paul. It’s Lance. Obviously, we’re closely watching everything that’s going on out in the market. But a lot of what you’re seeing is on ultralight oil, which is very high gravity condensate. And we look at our three big plays, essentially EOG has very, very little condensate.

So we really have an ability to blend -- the condensating with our crude oil, so kind of a follow-up there.

We are going to continue to watch it and strike as necessary?.

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

That’s correct, Paul..

Okay. Thank you..

The next question is from Joe Allman with J.P. Morgan..

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 the cash flow from operations or potentially would you be contemplating some assets sales and help fund some CapEx?.

Yes, Joe. We are going to keep the cash flow in balance with the CapEx, plus the dividend. But also, we’ve sold properties over the years and that is something that we will be considering next year also those.

Obviously, the kind of non core properties, properties that will help us to be more efficient as the company reducing LOE cost and properties that don’t have scale, that don’t have maybe the potential of some of the others. So, yeah, 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 were 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?.

Yeah. 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’ve made significant improvement 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’s on slide 26. You may want to look at that in detail. But it shows 2014 wells, the 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’ve 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 this plays on improvements and 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 were able to generate -- we generated five new plays this year.

And we have a good list going forward that we have -- we are hopeful, we will be good addition to the company at very low cost. And so the acquisition businesses as you all know, historically, there is a lot of competition in M&As and acquisitions and usually they turn out to be very, very low return.

So we are going continue to maintain our focus on growing the company organically through exploration and low-cost, acreage acquisitions in that process.

Okay. Thanks. And you’ve had a couple competitors talk about East Taxes 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 a yes. It's 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’s still really early and as we’ve talked about before, we have a very high cutoff because our asset quality is so strong in the company. We are not interested in going forward with plays that would generate less than a 50% return. So we are working on only plays and spending a lot of money in going forward with very high-quality play.

So we are taking our time and we’ll 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’s 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 our with your assessments?.

Yeah. Good morning, Irene. In the Eagle Ford, we have quit giving a percent recovery factor there because we are still, I think trying to relook at what the oil in places there. But it’s certainly going up all the time. And we continue, as we showed and demonstrated in some of the charts and we’ve talked about this morning.

We continue to make very significant increases in the completion technology and 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 you go forward, and So we think we are in about the sixth inning in the Eagle Ford and so there is a lot of room left to go there..

Great.

If I have one follow-up, I’m going to hit you up on your macro view in this very volatile time?.

Are you talking about the price of oil?.

Yeah. Oil, gas, yeah because usually you guys would have few lines on that..

Yeah. We are pretty good at some things, but the world oil supply demand situation is not an area that we have a lot of expertise in.

And a special insight and we 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 to others, 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 crudes, et cetera, in your contracts if you need to adjust activity in a low oil price environment?.

Yes, Pears. 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 companywide. So we have a lot of flexibility to lower activity, if we need to or increase activity if that is wanted.

And we also have a lot of flexibility to take advantages of any kind of price decreases that may happen and we are already beginning to see especially in the frac equipment business and we are already seeing some price reductions and certainly, if prices stay at these levels, we could see a bit more that going forward..

Thank you.

And then my follow-up, is 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 in a fairly low price environment, we don’t really expect to pullback on much of our exploration efforts, because they are really, really low cost. Our entry cost on these plays is extremely low because we are upfront in areas where nobody really else is looking.

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’ve generated two times the amount of drilling inventory that we’ve actually drilled this year, some of that, of course, is in the existing plays, but again, already generated in new plays too.

So the company is a very prolific organic prospect generating machine. And we think it’s -- we can continue to do that as 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’re 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 down shifted activity in the last couple of quarters in Gonzales County.

And perhaps, increase some activity on the western side of the play (indiscernible).

So just trying to get some thoughts on, how do you move playing on the rigs news, et cetera?.

Yeah. 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. And in the third quarter, it is about 52% of 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 with the kind of classify this that 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’ve been doing in the last several quarters..

Okay. Just to clarify that, Bill.

Q3, perhaps, the mix of wells was towards a lower rate of return then typical on lease retention and you 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 returns 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’s very helpful. My follow-up Bill, you’ve talked about expanding opportunity set in the Delaware, you’re moving from four to eight rigs by year end.

So 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 like to get a little bit bigger in the Delaware?.

Yeah. Arun, this is David. And we have got -- we have laid out the three big plays that we announced today. And those -- we have numerous locations in those. We have many, many years of drilling just in those plays. And like I said before, we’ve been very delivered 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..

And we’ll take the next question from Brian Singer with Goldman Sachs..

Thanks. Good morning..

Good morning, Brian..

Without trying to tie you down to your production or CapEx guidance from next year. In the plays you do plan to focus on 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 or you could keep the growth engine running without having spend as much capital and perhaps, some estimate for how much capital that that could represent?.

Yeah, 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 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 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 in the Bakken it’s all held our 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?.

Yeah.

Infrastructure, just a bit of the same question for infrastructure and each of those areas, do you see your infrastructure needs to support growth rising or falling?.

Yeah. No. That’s a good question. We see, I think, next year 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 we have to build out through that, is that by fault, the need for infrastructure is less..

Great. Thanks.

And then, if well performance is driving your stronger than guided your 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, rates of return given the confident commodity price are improving..

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

Yeah. I think the, Brian, this is Billy Helms. I think I would also add to that is, yeah, Bill is right, the rate of return is certainly increasing, we are increasing the 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 uplift of overall curve..

Great. Thank you..

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

Hi. Good morning Bill. Question, can you guys talk about what you -- how you complete these wells in the Permian. I know you had one of those little yellow boxes on one of the slides, you talked about your advance completion technology.

So I imagine you don’t want to give all the secrets but can you give us like same framework around the way you complete this?.

Yeah, David, in the Permian, just like we do in all the other plays, it’s a constant experiment. Eagle Ford, you’ve seen a track record that we had there. We just continue to experiment and to push this. So lot of the techniques that we’ve learned in these other plays have been applied in Permian.

Like Bill 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 plays a little bit different. But we’ve got a good process in place..

Any reason that the 4500 plus lateral versus longer laterals, you should have got to that yet or just -- is there anything you comment on that, is that your larger curve.

Could you talk about that?.

Your question is why don’t we drill longer laterals?.

Yeah.

Have you tried the longer laterals? And it seems like just most of the stuff you mentioned at least in the slide that was on the shorter 4500 foot?.

I mean, each play is different and so we’ve 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 also the performance of the wells.

And so what we’ve generally seen is at least they are in the Delaware Basin that we tend to prefer to go with, more with 5,000 to 4500 foot lateral. It also helps -- it tends to be kind of the resized configuration as well..

Okay. And then just back to the Eagle Ford, I think it was Bill that you mentioned RSC data.

Can 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. We have to get back with you on that. You’re talking about the whole field for all operators..

Yeah -- no, just for your specific Eagle Ford. I mean, there is so much concern about Eagle Ford production levels.

I was just looking for some -- directionally, there are some type of comfort I guess you gave us on your end?.

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

All right. I’ll go back there. Thanks. Appreciate it..

The next question is from Charles Meade with Johnson Rice..

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, that the results you’re seeing there and what I’m really curious about in the end, is there any chance for the Three Forks. I know it’s already pretty high in the stack of your play but is there a chance forward to move higher and get bigger.

And I guess, the little bit of detail to add there is the rates you gives have on those main three wells are good but they will be more impressive when you look at the lateral lengths you guys had on them.

And as I understand the lot of Three Forks is kind of being puzzling the people and some times there is undifferentiated log responses, hard to predict, what’s going to be good, what’s not.

So can you talk about what the prospects for that to grow in your portfolio are?.

Yeah, Charles, this is Billy Helms. On the Three Forks, we’re probably going a little bit slower than we are, relative to the Bakken. Most of our activity in that area will be focused on 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 test. And as you can see, what the results we’ve had this quarter, they are all testing out fairly strong.

Let’s say we’re 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’re still a 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're 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’ll 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 basis.

Wondering if you could give us an update on your thoughts around the East Irish Sea and the production potential coming on stream in 2015?.

Yeah, on our Conwy project, that’s going to coming on in the second quarter of 2015. And what we expect there is that we’ll have a kind of ramp-up phase and probably max out at around about 20,000 barrels a day for 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 you’re spending currently this year on assets outside of the main three you talked about the Eagle Ford, the Delaware, and the Bakken, maybe that would help us with some other context as we head into 2015 from an expectation perspective?.

Matt, we have active drilling programs or one rig program in the Barnett Combo. We have a rig or two running in the mid-continent. A couple of rigs running in the 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 early in the year of these new plays in the Rockies, we’re running a rig or two in the Powder River. And I believe we’re running two rigs in the DJ. Actually there is four rigs in the DJ Basin.

So we have quite a bit of activity in plays outside of the core plays..

Thank you very much. It’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. And I just like to say and concluding that we’re confident as we head into 2015 and been with the company for 35 years. Every time we go to 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 and the best role is on the plays in the U.S. and along with our low cost in our industry-leading technology. EOG is going to be strong performer in the yeas to come and a leader in the U.S. oil growth. So again thank you for listening..

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