EOG Resources Inc (EOG) 2013 Q3 法說會逐字稿

Good day, everyone, welcome to the EOG Resources' third-quarter 2013 earnings results conference call. As a reminder, today's call is being recorded. At this time for opening remarks and introductions, I'd like to turn the call over to the Executive Chairman of the Board of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing third-quarter 2013 earnings and operational results.

This conference call includes forward-looking statements. The risks associated with forward-looking statements have been in 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 US investors that appears at the bottom of our press release and investor relations page of our website.

With me this morning are Bill Thomas, President and CEO; Gary Thomas, COO; Billy Helms, EVP Exploration and Production; David Trice, EVP Exploration and Production; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President IR. And 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'll discuss topics in the following order. I'll first discuss third-quarter net income and discretionary cash flow. Bill Thomas will review operational results. Then Tim Driggers will discuss financials and capital structure. Finally, I'll cover our macro view and hedge position and Bill will provide concluding remarks.

As outlined in our press release, for the third quarter 2013, EOG reported net income of $462.5 million, or $1.69 per share. For investors who focus on non-GAAP net income to eliminate mark-to-market impacts and certain nonrecurring items as outlined in the press release, EOG's third-quarter 2013 adjusted net income was $634.3 million, or $2.32 per share. For investors who follow the practice of industry analyst who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $2 billion.

Similar to the first half, EOG continued to hit on all cylinders in the third quarter. Our oil, NGL and gas production again exceeded guidance and our unit costs beat the lower guidance provided last quarter. Because of continued strong Eagle Ford and Bakken performance, we are again raising our full-year 2013 production growth estimate for oil from 35% to 39%. NGLs from 14% to 17% and total Company growth estimate from 7.5% to 9%. The impact of the high reinvestment rate of return Eagle Ford, Bakken and Leonard investments is also showing up in our EPS and cash flow numbers, as well as our ROE ROCE ratios.

This quarter's oil results provide further confirmation regarding our five-year plan where we expect to achieve the most profitable and highest oil growth rate of any large cap independent as we've done for the past six years. No other large capital oil company has even remotely matched EOG's oil growth rate either in 2013 or for the six-year average. And I'm going to repeat that last sentence because it bears repeating. No other large cap oil company has even remotely matched EOG's oil growth rate either in 2013 or for the six-year average. We continue to have no interest in zero profit North American gas growth and will continue the high-margin oil focus. I'll now turn it over to Bill Thomas to discuss specific operational results.

Thanks, Mark. I will start with our third-quarter 2013 Eagle Ford results. During the third quarter, we continued to achieve 100% direct APEX rates of return from both the western and eastern portions of our [5,659,000] net acres in the Eagle Ford oil window. Continuous improvement in well productivity and operational efficiency are driving cost down and production up. As a result, we now expect the drill and complete 460 net wells in the Eagle Ford this year, which is an increase of 20 wells since last quarter. We've been able to increase the planned well count every quarter this year because we're drilling wells faster and more cost effectively.

In the west, we completed a number of initial unit wells in order to earn acreage and establish multi well development patterns. The Bridgers Unit #1H began production at 2,195 barrels of oil per day plus 1 million cubic feet of gas -- of rich gas per day. The press release noted the Kaiser Junior Unit #1H as the best well to date in the west. The well came online at 2,815 barrels of oil per day plus 1.3 million cubic feet of rich gas per day. The Nelson Zella Unit #1H and 2H began production flowing 1,960 and 2,810 barrels of oil per day plus 1 and 0.8 million cubic feet per day of rich gas respectively.

To continue pattern development of the River Lowe Ranch we completed an additional six wells. The River Lowe Ranch #4H through 9H had initial flow rates of 1,970 to 2,115 barrels of oil per day plus 1 and 1.1 million cubic feet per day of rich gas. EOG has a 100% working interest in each of these western wells. The consistently strong drilling results from the west in the first three quarters have been a significant contributor to EOG's Eagle Ford oil growth in 2013. Page 19 of the IR presentation has an updated chart that shows average IP rates for our western wells are 20% higher in the third quarter than the first quarter of this year. The continuous improvements in well productivity as a result of new frac techniques and the downward trend the well cost through operational efficiencies give us a high confidence level in the strength of our large drilling inventory on our western Eagle Ford acreage.

In the east, we continued the development of the Baker-DeForest Unit with #5H, #6H and #7H flowing 3,200, 3,560 and 4,115 barrels of oil per day with 3.5, 4.1 and 4.4 million cubic feet per day of rich gas respectively. We also began development of several new acreage units with the completion of the Justice Unit #1H, #2H and #3H flowing 3,885, 3,560 and 3,940 barrels of oil per day plus 4.4, 5 and 5.6 million cubic feet per day of rich gas respectively. In addition, the Vinklarek Unit #1H was completed flowing 4,510 barrels of oil per day with 5.9 million cubic feet per day of rich gas. EOG has a 100% working interest in each of these western wells.

As noted on our second quarter call, we continued to test downspacing patterns in both the east and west. The downspacing process takes time. The ultimate goal is to maximize oil recovery and the net present value of the acreage. In summary, EOG's Eagle Ford position and operational team are proving to be the most powerful oil growth offense in North America. Quarter by quarter, this asset continues to get better and better. We have many years of drilling inventory in this high rate of return play.

Now I'll shift to the Bakken/Three Forks. We continued to see outstanding results for the technical renaissance and frac technology that we started in 2012 in conjunction with our downspacing program in the core. Recent downspaced wells in the core include the Van Hook 126-2523H and 130-2526H with initial production rates of 2,235 and 1,910 barrels of oil per day plus 1,115 and 900 Mcf per day of rich gas respectively. The Wayzetta 137-2226H 150-1509H which began producing 2,500 and 2,320 barrels of oil per day with 1.2 and 1.1 million cubic feet per day of rich gas respectively. In the Antelope Extension area, we completed three excellent Three Forks wells in the first bench. The Bear Den 100-2017H, 101-2019H and 23-2019H began flowing 2,100, 1,235 and 1,665 barrels of oil per day plus 2, 1.2 and 1.6 million cubic feet per day of rich gas respectively.

We are encouraged by the Three Forks potential in the Antelope area. We completed an excellent well in the second bench early this year and plan to test the third bench third during 2014. We are now achieving direct APEX rates of return in excess of 100% in both the core and Antelope areas. We added two the slides to the IR presentation showing EOG's outstanding 2013 results. Page 23 shows EOG's 2013 completions at 58% more production in the first 100 days as compared to those completed in 2012. The same slide also shows year-to-date IP rates from these two areas are up 50% as compared to last year.

Page 25 shows EOG compared to 20 different Bakken operators. EOG's average IP this year is 1.9 times better than the peer average. With a modest drilling program, we are growing all volumes and setting new production records. Our second quarter -- on our second quarter call, we increased our drilling inventory in the Bakken/Three Forks from 7 to 12 years. With excellent results and a large inventory, we anticipate increasing drilling activity in the Bakken/Three Forks in 2014.

In our Delaware Basin, Leonard and Wolfcamp plays, our third-quarter activity was centered on drilling multiple well spacing patterns, testing numerous target zones and optimizing frac techniques to improve well economics and recovery factors. In the Leonard Play, we completed a number wells in Lea County, New Mexico. The Endurance 36 State Con #4H was completed in the B zone at an initial rate of 875 barrels of oil per day, with 1.1 million cubic feet per day of rich gas. This is one of our first B zone test and initial rates are excellent. We completed two new wells in the A zone, the Endurance 36 State Con #3H flowed 735 barrels of oil per day with 1.2 million cubic feet per day of rich gas. We are competing a number of wells in the A zone and drilling a number of wells that will test multiple target zones and well spacing patterns.

Year to date, direct APEX rates of returns have exceeded 100% from this drilling program. So we continue to be very excited about the Leonard. We plan to significantly increase activity in the Leonard next year with approximately 1,600 locations in inventory, the Leonard is a powerful part of our offensive arsenal that will enable EOG to continue to lead the league in high-margin oil growth through 2017.

In the Delaware Wolfcamp play, we had previously said that we are waiting on infrastructure. We can now report that as of October 1, gathering infrastructure is in place and operational. We are now ready to complete two multi well patterns to test various spacing and targets. We plan to use micro seismic to determine frac geometry and monitor production in order to determine optimal developing patterns for our Delaware Wolfcamp acreage. We have more than 1,100 locations in inventory currently generating direct APEX rates of return of 60%. Drilling for the remainder of this year and next will be focused on the establishing optimal well spacing, completion techniques and evaluating multiple target zones to set this play up for full-scale development in 2015 and beyond. We now have approximately 134,000 net acres in the play.

In Trinidad, we've completed our Osprey platform drilling program which should provide for flat production in 2014 versus 2013. In the East ROC, the start up of our Conway oil project is now estimated for late 2014. In addition to our ongoing efforts to increase recovery factors in our existing plays through downspacing and completion improvements, we have not lost our momentum or focus on searching for new reserve potential with domestic greenfield plays.

To summarize, EOG has captured the best horizontal oil acreage in North America and our high-performance operational teams continued to execute superbly. Wells are getting better, unit costs are coming down and oil production continues to increase at peer leading growth rates. We have a very strong inventory of crude oil and liquids-rich drilling prospects with high after-tax rates of return. We continue to focus on delivering high-margin oil growth, increasing recoverable reserves in existing assets and generating new plays to ensure that EOG remains best in class through 2017 and beyond.

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

Thanks, Bill. Capitalized interest for the quarter was $12.6 million. For the third quarter 2013, total cash exploration and development expenditures were $1.8 billion excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $87.6 million. There were $89.2 million of acquisitions during the quarter. During the third quarter, net cash provided by operating activities exceeded financing and investing cash outflows. Year to date, we've closed on asset sales of approximately $620 million and we expect approximately $750 million in total assets sales by year end. This is a $200 million increase from our previous estimate.

At the end of September 2013, total debt outstanding was $6.3 billion, and the debt to total capitalization ratio was 30%. At September 30, we had $1.3 billion of cash on hand giving us non-GAAP net debt of $5 billion or net debt to total cap ratio of 25%, a reduction from 29% at year end 2012. On October 1, we paid off $400 million of debt that matured with cash on hand. The effective tax rate for the third quarter was 36% and the deferred tax ratio was 65%.

Yesterday we included a guidance table with our earnings press release for the fourth quarter and full year 2013. Our Cap Ex estimate for the full year is approximately $7.2 billion. For the fourth quarter, the effective tax rate is estimated to be 35% to 40%. For the full year, the effective rate is estimated to be 35% to 38%. We have also provided an estimated range of the dollar amount of the current taxes that we expect a record during the fourth quarter and for the full year.

Now I'll turn it over to Mark.

Thanks, Tim. I will provide our views regarding the macro environment, hedging and 2014 activity. Regarding oil, we believe that absolute 2013 total US oil growth will be less than 2012 and this trend will continue in subsequent years. Through August, the EIA monthly data indicates 2013 oil production is on trend to increase 600,000 barrels per day on an annualized basis compared to 1 million barrels per day in 2012. We continue to be pragmatically bullish regarding oil prices, partially because we don't expect any large international shale oil plays to impact global supply for at least five years.

In terms of 2014 oil hedges, we have 123,000 barrels per day hedged for the first half of 2014 at $96.44. For the second half of 2014 we have 9,000 barrels per day hedged at $95.30 per barrel. We have a number of contracts outstanding that could be put to us at various terms. For the first half of 2014, we have 64,000 barrels a day of options that could be put to us at approximately $99.60 on December 31, 2013 if it is advantageous for the counter party to do so. For the second half, we have 10,000 barrels per day of hedges that could be put to us at $96.60 on or about March 31, 2014. Also for the second half, we have 103,000 barrels per day of hedges that could be put was at $96.60 on or about June 30, 2014.

Regarding North American gas prices, I suspect I have a reputation as the most bearish CEO or former COE in the E&P business, and I'm not going to change that reputation on my last earnings call. I believe gas prices will stay depressed until the 2018 timeframe. So EOG will not be in any hurry to generate a lot of gas deliverability. The current Marcellus location differential is likely just the harbinger of chronic Appalachian price dislocations that we'll see over the next multiple years.

Our gas hedge position is unchanged from last quarter. We also expect ethane prices to remain weak until 2018. For the third quarter, our average US oil price realization was $2.74 above WTI, within $0.01 of our guidance. This premium over WTI as shrunk considerably compared to our first half utilization because WTI has increased relative to LLS.

As EOG has done in the past, we'll discuss our detailed 2014 business plan on the February earnings call. However, we can provide a few conceptual thoughts at this time. Assuming that oil and gas prices are similar to the current NYMEX, EOG will likely ramp up is 2014 activity in the Eagle Ford and Bakken/Three Forks plays above 2013 levels. In the Permian Basin, our overall CapEx will likely be flat but the spend ratio will shift dramatically from this year's allocation of 65% in the Midland basin, 35% in the Delaware, to 15% Midland Basin, 85% Delaware Basin next year. Also we again plan to drill zero North American dry gas wells in 2014 because we've seen no light at the end of the gas oversupply tunnel until 2018. Now I'll turn it over to Bill for summary remarks.

Thanks, Mark. Now let me conclude. There are four important takeaways on this call. First, our third quarter and nine month year-to-date results confirm that EOG's oil growth momentum is not diminishing. Our 6-year compound annual growth rate is 38%, which is awesome when you consider this growth is 100% organic. Each of our 3 key plays has 12 plus years of currently defined inventory, so EOG is built for the long haul.

Second, our unit cost control have been impressive. As evidenced by the today's results and the full year of guidance provided yesterday. Third, the vast majority of our Cap Ex is going into 3 plays, yielding 100% correct after-tax rates of return, the Eagle Ford, the Bakken and the Leonard. These returns are showing up in the bottom line with 9-month non-GAAP net income up 55% year over year, increasing ROEs and ROCEs. Our net debt ratio was reduced from 29% at year end 2012 to 25% at September 30.

Finally, the Board and I have asked Mark to stay on as a Director after he retires at year end. I'm happy to report that Mark has agreed to do so. This will provide additional continuity and experience to our Board.

Now I'll turn it back to Mark for one closing remark.

Thanks, Bill. This is my last earnings call and I want to thank everyone on both the buy and sell side for investing your time and patience in EOG's story. I've enjoyed working with all of you and having sincere appreciation for all that you do. I'm leaving the Company in good hands with Bill Thomas and intend to keep my personal EOG stock holdings for a long time. Thanks for listening and now we will go to Q&A.

(Operator Instructions)

Leo Mariani, RBC.

A question on fourth-quarter guidance here, clearly you had really robust oil production growth in 3Q. You guys are guiding to lower increases in 4Q. Can you give us some color on that, is that a function of trying to stay with your CapEx budget this year?

Yes, Leo, let me put in a little bit of context. If you go back to 2012, in 2012 over 2011 we grew our oil production 39% that year, and actually our 4Q oil production actually declined versus 3Q. And if you remember, there was a lot of concern as we exited 2012, people were saying oh boy I'm nervous about EOG's 2013 oil growth because the trend line is 4Q production was fallen relative to 3Q and it doesn't look good. Then look at our results for 2013. We grew our oil production again 39%. So if you look at it in a historic context, people shouldn't be too nervous. We're projecting -- actually we're going to not fall in oil production, we're going to slightly grow in oil production 4Q over 3Q.

There was some specific reasons for that, one is we're going to be drilling some isolated leaseholder wells more than typical, which as opposed to drilling more groups of wells particularly in the Eagle Ford and also some potential weather conditions in the Bakken. But if you just look at the 2012 trend, and then look at what we're projecting for 2013 in the fourth quarter, I think that should ameliorate any concerns about what we're likely to do in 2014. Now I'm not projecting we're going to do another 39% oil growth in 2014, because obviously the law of big numbers is going to catch up with us on percent year over year. But no one should view the situation that oil growth in the fourth quarter is likely to slow down our trend of significant oil growth in 2014.

Okay that's really helpful color. And I guess in terms of frac technology, obviously you guys have talked about a lot better completions in the Bakken and I'm certainly assuming that that's going to be applicable to other areas, Eagle Ford Permian et cetera. Can you guys give us a ballpark on what inning we are in and terms of just improving frac techniques and completions? Is this the early days here and can we expect a lot better improvements in recoveries in your key plays going forward?

No, that's a good question, Leo. The frac technology that's really making the big impact in the Bakken is actually we brought that from the shale plays which is mainly the Eagle Ford completion process that we've been so successful in that play with. And so it's improving really in all of our plays. It's basically -- there's a lot of simple fundamental things, we had a big advantage with our EOG sand as a Company it's not only provided very low cost and help us reduce our completion costs, it's also really helped us technically to be able to experiment more, to use more sand and that is a big part of the reason our wells are much better.

I would say we're probably in the fifth or sixth inning if you had to put it in baseball terms on where we are on the completion technology process. We continue quarter by quarter to make advances and we're learning all the time. The EOG culture is that we're never satisfied and we never quit thinking and experimenting and trying new things and really thinking out of the box on new technology in all areas. So we are going to continue to press on and we're hopeful that we'll have continued new improvements as we move along.

Well that's great to hear, thanks a lot, guys.

Doug Leggate, Bank of America Merrill Lynch.

Mark, congratulations, you've left the heck of a legacy behind you. I've got a couple questions, if I may. Maybe a follow up on Leo's on the completions. There's been a lot of chatter, obviously, I think you guys have been out and about talking about some of the things you've been doing in particular in the Bakken as you're trying to start some of your Eagle Ford learnings. Could you help us a little bit with how you're seeing the impact of some of these changes in terms of very high IP rates obviously. But is this also translating into higher recovery rates, and if so, I guess I asked this question last call, why are we not -- why have you not yet decided to lift your EURs particularly in the Eagle Ford?

That's a good question there, Doug, thank you. Yes, I mean the whole process on all these horizontal wells is connecting more of the rock to the well and so we're very focused on doing that. And also with a real strong effort on the frac geometry, trying to keep the fracs closer to the well. If you connect more rock, you are hopeful that the recoveries, the total recoveries of the field will go up. But we've not really proven that yet. I mean we've proven two times with two generations of downspacing in the Eagle Ford and we're currently on the third one. And so we're really watching what we're doing.

It takes a quite a bit of time to establish and determine specifically if there is any increase in reserve potential or changing of the EUR per well. And we're just not there yet on this third generation in the Eagle Ford. So when we get that done, we will certainly pass that on. But it's going to take a bit more time. We want to be able to technically be accurate and defined any numbers that we give to you. So we're very careful to do our homework and to do our work right and to provide you really with accurate numbers, and that process does take some time.

Okay, thank you for that.

Yes a little addition on that. It's our view that the industry has just been a little bit flippant with numbers, they -- reserves have been just floated about on essentially all plays, 1 billion barrels, 5 billion barrels, BOEs, and it's just been numbers that we think has cheapened the reserve estimating system a little bit by people just throwing numbers out offhand. And EOG has not really joined that party. We on the other hand have been very cautious, very judicious in the numbers that we've given. And we'd like to think we set our standards a little bit higher than most other companies have done when they've issued reserve numbers. And particularly with the Eagle Ford, we just take a lot longer to qualify our numbers before we issue them. And so that's a little bit of a difference. I'd like to say our standards are higher before we issue numbers on Eagle Ford. But we are certainly reviewing it and when it meets our exacting standards for potential reserve upgrade, we will certainly let everyone in the investment community know.

Thank you. My follow up is also a very quick one. I guess we've all -- we're all watching your balance sheet improve and expecting a [step up] of free cash flow next year. But should we, given your comments in stepping up activity, should we be thinking that you're again spending cash flow next year but obviously with a substantial step up in activity? And I'll leave it there, thanks.

What you should read through on the comments we made on the 2014 CapEx is that, if oil prices stay where they are now, that we will likely step up our CapEx over the 2013 levels. That's the only thing we're really seeing at this point. We haven't made any comments relating to free cash flow or anything at this point but we should be in a decent position relating to that. But we are looking at accelerating our overall CapEx, degree of acceleration as yet to be determined, Doug.

All right, thanks again. Congratulations again, Mark

Thank you

David Tameron, Wells Fargo.

Echo what Doug said, Mark, congratulations on building the Company and doing what you've done there.

Thanks, David.

Let me take the free cash flow question one step further. If we think about -- you start looking at next year and you can choose whether or not to generate free cash flow. But if you look out to 2015, pretty powerful cash flow generation, how should we think about how you guys are going to allocate capital the next two years?

Yes, David, we are set to have very strong cash flow growth in the Company. And we've given guidance on the priorities of that. Number one, we want to continue to have a healthy increase in the rate of dividend growth in the Company. So that's number one.

Number two, we're committed to being a low debt Company and to work that net debt to cap ratio gradually downward over time. And then the big part of the capital, what's left over will go to our best place. We're going to be very focused on capital discipline and capital efficiency. And we're going to focus the capital where we can achieve the highest rates of return. Fortunately for EOG we have a lot of opportunities.

Of course we're getting very high rates of return on the Eagle Ford and the Eagle Ford will continue to get more money each year. The Bakken with the dramatic improvements we've had in it is now equal to the Eagle Ford in returns in excess of 100%. So it will get more money each year. And we've built the Leonard play into a very successful play and have a very large inventory in that play also with 100% rates of return. So those plays will be first on the list to get more capital each year. So the Company is really in great shape to continue to grow cash flow strongly and also to have very strong capital returns and capital efficiencies as we go along.

Okay, let me ask a little bit different way. If I think about 2015, could you throw on it -- can the organization today handle another $1 billion, $1.5 billion of capital above what you do in 2014? Or should we look for -- obviously balance sheets down, are you guys looking at any type of dividend increase or how -- I'm trying to figure out for 2015 free cash flow numbers what happens with that?

Yes, I think we're going to have to be a bit cautious on giving guidance for 2015 at this point and we'll see how that all goes a long. We're going to be -- as I said, the capital efficiency and the return on the reinvestment capital is really our primary focus. And I believe we can continue to improve that over time, which will directly go to the bottom line of the Company. So we're going to be very focused on that and be very diligent about spending and staying disciplined. And so as I said, the dividend increase certainly will be the first part of our priority and we'll discuss that as we go along and watch the returns of the Company and where we are on a capital basis.

All right, I'll let somebody else jump on. Thanks for the color.

Pearce Hammond, Simmons & Company.

Good morning and congratulations, Mark, for a well-deserved retirement.

Thanks, Pearce.

My first question is in the Eagle Ford, you had a nice down tick in your drill times, down to 9 days, previously you were at less than 12 days. Curious using that baseball analogy from earlier, how many innings -- what inning do you think we are in as far as those drill times in the Eagle Ford?

As far as Eagle Ford, with us saying nine days, we would say probably again we're in the sixth, seventh inning there. We're just continuing to work on our consistency. We've had many wells that are quite a bit faster than that. So we're pleased with the improved consistency with our drilling operations here. Yes, our record day is five days.

Thank you. And then my follow up, coming back to the activity as it relates to next year, the preview on the 2014 guidance that you provided in the prepared remarks. Do you think that this means a higher rig count as well as higher well count or more a flattish rig count but given the improvement in drilling times et cetera that we would see a higher well count?

We expect that our rig counts going to be similar to what we had this year. We had a peak this year of 56 rigs. And we're probably averaged somewhere around 50. But we expect just continued improvement with rig efficiencies. We've upgraded our entire rig fleet and we're fortunately now have what I guess you would classify as just premium rigs.

Excellent, thank you very much and congratulations, Mark.

Thank you.

Charles Meade, Johnson Rice.

If I could, first go to this may get to the capital allocation part of your discussion. If -- looking at the results up in the Bakken, it looks like you've had great results not only with that infill program in the core but also with the Three Forks over in the Antelope Extension. And so could you talk a little bit about how you're thinking of prioritizing the incremental ramp in that area between those two efforts?

Yes, Charles. We have had some very excellent results. As we've talked about, we've had a number of good wells in the Three Forks in the first bench and then we did complete an excellent well in the second bench this year. And those were -- these recent wells have all been done with the same new completion technology that we're using in the core that's been very successful. So we have in particularly in the Antelope area, we do believe that we have potential in the third bench and possibly in the fourth bench in the Antelope. And so as time goes along, we'll be testing those and working on what kind of development patterns and spacing that we can develop the whole Three Forks interval.

And there are other areas in our Bakken, in the Williston Basin/Bakken acreage that we do feel like there could be additional Three Forks potential that we've not drilled. So that's a step-by-step process. We go along and learn more about the Three Forks. So yes as we said, we're getting extremely strong rates of return in the Bakken. We have 12 years of inventory there and so as next year and the years go on, we believe that we'll be drilling more wells each year in the Bakken. And that's really -- that whole Bakken/Three Forks has -- even with our modest drilling this year we've been able to continue to grow production there and we are setting production records there quite often in the Bakken, even with the modest program. So we've got some good expectations as we go forward.

Got it. Thank you for that detail, Bill. And then one other thing and this is maybe a little more conceptual, when we look at the -- I really appreciated those new slides where you're showing the 2013 vintage wells versus the 2012 and about how the cumulative production you've had that 20% or 30% or 50%, 60% increase. And I was wondering if you could characterize that as how much of that is a function of more capital that you're putting into the well, whether through more stages or big fracs and how much of it is more free benefit from a better design?

Yes, there's several things going on. Obviously those are normalized on a [per foot] basis, so that takes out the lateral link. And as we have learned in all these plays that I've said before, connecting up more of the rock and connecting that rock up closer to the well bore is the goal that we're working on. And as we increase the amount of sand that we put in the Bakken, we feel like we're also doing a much better job of distributing that sand in the fluid frac along the lateral more evenly. And so that helps to connect more rock and get more of the oil in contact with the well.

And so what we're seeing on these wells with the new improved fracs is that they come on at really nice IPs as we reported, but they also have a little slower decline rate then the initial wells. They hold up better. And so the initial, whether it's a 30-day rate or the initial 100-day cumulative production, are showing quite a bit of improvement because we're moving that oil forward in the production life of the wells. So it's a nice good successful technical renaissance that we're achieving there in the Bakken and seeing really good results because of it.

Thank you very much, Bill.

Irene Haas, Wunderlich Securities.

Hello, Mark, this is Irene, congratulations and we will very much miss you in this capacity. But we hope to see you around the oil patch. And one last question, why 2018 as the year that we would see the light at the end of the tunnel and then a way out to the gas glut?

Yes, I'm going to miss you too, Irene. I believe in 2018 is when we will have the first significant impact of gas imports -- exports, excuse me, in a way of LNG from these converted former LNG import terminals. So I think that that's when we'll really have the first meaningful impact and I think that may have some impact on prices. So that's the way I see things.

Okay, great, thank you.

Brian Singer, Goldman Sachs.

Mark, congratulations and best of luck, as well.

Thanks.

You mentioned greenfield exploration remains a commitment and wonder if even if we can't provide specifics if you could characterize what we should expect from your exploration program in terms of size or production impact in the next few years? And how impactful brownfield opportunities like water floods in the shales could be?

Yes, Brian. Certainly as you said there and noted exploration has not lost any focus or momentum in EOG. We still have the same people, the same culture and the same focus on that and I truly do believe EOG will continue to be a first mover in that area as we go forward. And as you also noted, we've been very -- we're very reticent about talking about new plays for a number of reasons and we really don't want to talk about any specifics of those plays until we have some meaningful results to report.

And then in the secondary recovery efforts, I think EOG will also be a leader. We don't know of any other companies really working on secondary recovery in the Eagle Ford. And we have, as we reported earlier, we have a dry gas injection pilot program going on at Eagle Ford and that will take a good bit of time to determine whether that's going to be successful and whether that's the proper method on that. And then we're also have water injection pilot going on in the Bakken, and that'll take some time too. So I -- we fully are committed and I really do expect that EOG will be a technical leader in these shale plays and new plays in secondary recovery and also cost reduction. We've got a culture in the Company that is very focused on all that and we're going to be taking that forward.

Brian, it's Mark, let me add something to that because I did get a chance to glance at your note this morning or you made a comment or words to the effect that EOG's valuation was still quite low because there seemed to be a perception that EOG didn't have the reserve life that companies who really didn't generate the production growth that we had were exhibiting because the difference in reserve life and EOG was perceived to have great production growth but not as long as reserve life.

Here's two real world examples from the two biggest oil assets in North America relating EOG. At the beginning of this year, I think most everybody viewed EOG's Bakken position as a static position, a non-growth position. And look at it now. Now we're making the best wells in the Bakken. We view it as a considerable growth position and we're quite excited about it and I believe that everybody is looking at it as a growth position for EOG on a go forward basis.

Second one is Eagle Ford. A year ago, everybody said, yes, EOG is hitting grand slams daily in the Eastern Eagle Ford but in the Western Eagle Ford, everybody knows lower quality and EOG's not going to do as well in the Western Eagle Ford. That was just 12 months ago. Look at our results now. We're getting 100% rate of return in the Western Eagle Ford and we're getting 200% rate of return in Eastern Eagle Ford. But the highlight of our last two earnings calls in Eagle Ford has been the Western Eagle Ford. So in the span of 12 months, we have taken our two best oil assets and taken what was perceived to be weaknesses, lack of growth in the Bakken, and Western Eagle Ford, and turned them into major strengths in both areas.

And that's one thing that I think you'll continue to see from EOG is that the Eagle Ford and the Bakken, the two best oil plays in the United States, are going to continue to turn out to be overall grand slams for EOG for at least the next decade plus. In addition to the greenfield work and the secondary recovery work we have. So we hope that our investors would see the lessons that have shown up here in the last year and certainly take a look and say who's generating the results among all the E&P companies. We think results matter and we'll stack our results up against any company in the business.

Thanks, that's helpful. As a follow up, shifting to the Permian Basin, can -- you mentioned in your opening comments that you're shifting more to -- you're going to start doing the multi well spacing and targets in the Delaware Basin starting with some micro seismic. Can you add some color on what your base case expectations for multi well development would look like and how oily the zones you're planning on developing are?

Yes, in the Delaware Wolfcamp we're focused on a very nice sweet spot in the Wolfcamp there. And to date, we've completed four wells there in three different pay zones. And those pay zones are located in the upper part of the Wolfcamp. And the upper part of the Wolfcamp we believe will tend to be a bit more oily than the lower parts of the Wolfcamp. So we'll be testing additional zones there. The actual Wolfcamp thickness there is very thick, like somewhere around 2,000 feet of total thickness to work with, and there are numerous additional pay zones that we have not targeted or tested yet.

But the goal is we're completing a couple of patterns now on different spacing, well spacing, and different targeting geometries and we will do some micro seismic on some of those and work on the frac geometry on how to contain the frac close to the well and to make it more complex to where we're connecting more rock. And see what that is in respect to the spacing that we're drilling the wells on and also the production results of all those different things we're going to do. So it's a process, it will take some time. It will take several years really to figure out the most optimum way to do it just like it has been in the Eagle Ford.

But the recovery factors for the total Wolfcamp at this point are very low, and so our goal would be to hopefully increase those recoveries as we go along. We've got a lot of work to do there but the good side of all this is that this Delaware Wolfcamp we're already have target rates of return of 60%. And so it's a very strong rate of return play for us already and hopefully we can improve as we go along.

Thank you.

Biju Perincheril, Jefferies

Good morning, congratulations, Mark. My question is if I could go back to the new completions one more time and look at the (inaudible) mentioned (inaudible) 30-day rates and I think 90-day rates. But if you look at the decline curves of the new completions versus the previous completions, is that -- are you seeing that through the higher rates holding up or do you see the curves eventually converging? Wondering why the hesitancy on (inaudible) commenting on --

Biju, do you have that on speaker?

Can you hear me better now?

Yes, Biju, thank you.

Sorry about that. Yes, I was wondering about the decline curves on the new completions versus the older completions. Are you seeing the two curves staying consistently -- the new curves consistently staying higher or do you see them eventually converging as you get to the tail portion of the production curve?

In the Bakken?

In the Bakken -- well new completions in general in the Bakken and Eagle Ford.

Yes, in the Bakken specifically, yes we are seeing that the initial part of the production of the well are holding up and the decline rates are a bit flatter than the older wells. And it's because the fracs are bigger and more extensive and we're [dis]connecting more rock with these new completions than we did with the original wells that we completed in there. In the Eagle Ford, we've got multiple things going on there. We're downspacing as well as working on frac technology at the same time. So we're still in the process of learning about that and so I would say comparing the Eagle Ford decline rates is maybe a bit more difficult than the Bakken at this point.

So then the hesitancy on commenting on reserves whether you're seeing and how much of an EUR uplift that you're seeing, is that simply wanting to see more of that data or is there other factors that come into play here?

No, specifically we need more time because you just can't go by the early time of the well, you really need to have enough production time to get a good read on the total production of the well. So again as Mark commented, we're very cautious about coming out with new EURs per well or new recovery factors for any of our plays until we've had the very thorough technical review of that and had enough time to really evaluate it and to make a good call on it.

All right, thank you.

Phillips Johnston, Capital One

You alluded to this in your prepared remarks, but your Eagle Ford wells continue to generate returns above 100% even in the west, which likely suggests suboptimal spacing, obviously downspacing continues to be a work in progress and it's going to take more time. And I'm wondering how you're thinking about the trade off between per well returns and NPV per section, whether or not you think it makes sense for further downspacing to accelerate NPV per section even if it means the return slowdown into call it the 50% to 75% range?

That's exactly what we're doing, we are very focused on the NPVs of the asset and the particular [leaf]. And so the returns are certainly a part of that. But we've also reducing costs at the same time in the wells. And so it's a balancing act. And so we're very focused on generating the maximum NPV for that particular leaf or that particular asset and that's the goal that we're focused on. And that takes -- that's the reason it takes a bit of time to determine that. You have to really give the wells -- you have to do things and then give the wells enough time to respond and to monitor that and to model that.

Is there a minimum per well IRR that you'd be willing to live with if it meant accelerating the NPV?

No, I mean accelerating the NPV is the goal.

Okay got it. And then getting back to the subject of free cash flow. At this point it looks like even your Eagle Ford program is now free cash flow positive. So I'm wondering if you reconsidered at all the strategic value of keeping some of your mature legacy assets? And if so, does it now make sense to monetize some to highlight the NAV of your growth assets?

I think we've -- over the last several years we've sold $4 billion of assets. So it's not likely in our 2014 plan that we're going to have significant asset sales as we'd see it now. I think right now maybe several $100 million worth of assets sales, but not a large amount of asset sales as we see it now. So don't look for a big strategic repositioning as you may be suggesting along those lines.

Okay thanks, guys

And that's all the time we have for questions today, so I'd like to turn it over to Mr. Mark Papa for any more additional remarks

The only remark I'd say is I'm going to miss you all. Thanks for everything.

And that does conclude today's call. We thank everyone again for their participation.