Mark Papa - Executive Chairman of the Board Bill Thomas - Chairman of the Board, President, Chief Executive Officer Tim Driggers - Chief Financial Officer, Vice President

Leo Mariani - RBC Doug Leggate - Bank of America Merrill Lynch David Tameron - Wells Fargo Pearce Hammond - Simmons & Company Charles Meade - Johnson Rice Irene Haas - Wunderlich Securities Brian Singer - Goldman Sachs Biju Perincheril - Jefferies Phillips Johnston - Capital One

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 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.

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, Investor Relations. 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 discuss third quarter net income and discretionary cash flow.

Bill Thomas will review operational results. Then Tim Driggers will then discuss financials and capital structure.

Finally, I will 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 non-recurring 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 analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $2.0 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 unit cost 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's 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 and ROCE ratios. This quarter's oil results provide further confirmation regarding our five-year plan where we expect to achieve most profitable and highest oil growth rate of any large cap independent as we have done in the past six years.

No other large cap oil company has even remotely matched EOG's oil growth rate either in 2013 or for the six-year average and I am 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 we will continue the high margin oil focus. I will 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 [after-tax] rate of return from both, the Western and Eastern portions of our 565, 09,000 net acres in the Eagle Ford, continuous improvement in well productivity and operational efficiency are driving cost down and production up. As a result, we now expect to drill and complete 460 net wells in the Eagle Ford this year, which is an increase of 20 wells since last quarter.

We have been able to increase the planned well count every quarter this year, because we are going well faster and more cost effectively. In the West, we completed a number of the Mitchell Unit wells in order to earn acreage and establish multi-well development patterns.

The [Unit] #1H began production at 2,195 barrels of oil per day plus 1.0 million cubic feet of rich gas per day. The press release noted.

The Kaiser Junior unit #1H has the best well to-date in the West. The well came online at 2,815 barrels of oil per day plus 1.3 cubic feet of rich gas per day.

The Nelson Zella Unit #1H and 2H began production on 1,960 and 2,810 barrels of oil per day plus 1.0 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 1.0 and 1.1 million cubic feet per day of rich gas.

EOG has 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 of 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 the #5H, #6H and #7H, falling 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 Justiss Unit #1H, #2H and #3H flowing 3,885, 3,560 and 3,940 barrels of oil per day plus 4.4, 5.0 and 5.6 million cubic 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 100% working interest in each of these Western wells.

As noted on our second quarter call, we continue to test downspacing patterns in both the East and West. The downspacing process takes time.

The ultimate goal is to maximize oil recovery in the net present value of the acreage. In summary, EOG's Eagle Ford position and our operational team are proven to be the most powerful all 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 will shift to the Bakken Three Forks. We continue to seek outstanding results from the technical renaissance in frac technology that we started in 2012 in conjunction with our downspacing program in the core.

Recent downspaced wells in the core including 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 and 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 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 2.0, 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 are. We completed an excellent well in the second bench early this year and plan to test the third bench during 2014.

We are now achieving direct a-tax rates of return in excess of 100% in both the Core and Antelope areas. We added two new slides to the IR presentation showing EOG's outstanding 2013 results.

Page 23 shows EOG's 2013 completions have 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 going oil volumes and setting new production records. On our second quarter call, we increased our drilling inventory in the Bakken Three Forks from 7 to 12 years.

With excellent results and our 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 of wells in Lea County, New Mexico. The Endurance 36 State Com #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 tests and initial rates are excellent. We completed two new wells in the A zone.

The Endurance 36 State Com #3H, 735 barrels of oil per day with 1.2 million cubic feet per day of rich gas. We are completing a number of wells the A zone and drilling a number of wells that we will test multiple targets zones and well spacing patterns.

Year-to-date direct a-tax rate of returns have exceeded 100% of 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 [legally] and high margin oil growth through 2017. In the Delaware Wolfcamp play, we have previously said that we were 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 microseismic to determine frac geometry and monitor production in order to determine optimal development patterns for our Delaware Wolfcamp acreage. We have more than 1,100 locations in inventory currently generating direct a-tax rates returns of 60%.

Drilling for the remainder of this year and next will be focused on establishing optimal well spacing, completion techniques and evaluating multiple target zone the set this play for full scale development in 2015 and beyond. We now have approximately 134,000 net acres in the play.

In Trinidad, we completed our Osprey platform drilling program, which should provide for flat production in 2014 versus 2013. In the East Irish Sea, the startup of our Conwy 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 continue 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 return.

We continue to focus on delivering high margin oil growth, increasing recoverable reserves and existing assets and generating new plays to ensure that EOG remains best-in-class through 2017 and beyond. I will 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 investing cash outflows.

Year-to-date, we have closed on asset sales of approximately $620 million and we expect approximately $750 million in total asset 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 $5.0 billion for a net debt to total cap ratio of 25%, 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 CapEx 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 on the dollar amount of the current taxes that we expect to record during the fourth quarter and for the full year. Now, I will turn it over to Mark.

Thanks, Tim. Now I will provide our views regarding the macro environment, hedging and 2014 activity.

Regarding oil, we believe that absolute 2013 total U.S. oil growth will be less than 2012 and this trend will continue in subsequent years.

Through August, the EIA monthly data indicate 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 to the counterparty 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 to us at $96.60 on or about June 30, 2014.

Regarding North American gas prices, I suspect I have a reputation as the most various CEO or former CEO in E&P business and I am not going to change that reputation on my last earnings call. I believe the 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 a harbinger of chronic Appalachian price dislocations that we will 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 U.S. oil price realization was $2.74 above WTI within $0.01 of our guidance.

This premium over WTI has shrunk considerably compared to our first half realization because WTI has increased relative to LOS. As EOG has done in the past, we will discuss our detailed 2014 business plan on the February earnings call.

However, we can provide a few conceptual thoughts at this time. Assuming oil and gas prices are similar to the current NYMEX, EOG will likely ramp its 2014 activity in 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 see no light at the end of the gas oil supply tunnel until 2018.

Now I will turn it over to Bill for summary remarks.

Thanks, Mark. Now let me conclude.

There are four important takeaways from this call. First, our third quarter and nine-month year-to-date results confirm that EOG's oil growth momentum is not diminishing.

Our six-year compound annual growth rate is 38%, which is awesome when you consider this growth is 100% organic. Each of our three 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 today's results and the full year guidance provided yesterday.

Third, the vast majority of our CapEx is going into three plays yielding 100% direct after-tax rates of return, the Eagle Ford, the Bakken and the Leonard. These returns are showing up in the bottom line with nine-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 30th.

Finally, the board now have asked Mark to stay on as the a director after he retires at year end. I am happy to report that Mark has agreed to do so.

This will provide additional continuity and experience to our board. Now I will 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, buy and sell side for investing your time and patience in EOG story.

I have enjoyed working with all you and have a sincere appreciation for all that you do. I am 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.

Hi, guys. A question on fourth quarter guidance here.

Clearly you had really robust oil production growth in 3Q. You guys are guiding to sort of a lower increases in 4Q.

Just can you give us some color on that that is a function of trying to stay within our CapEx budget this year?

Leo, let me put in a little bit of context. If you go back t 2012, in 2012 over 2011, we grow oil production 39% that year and actually our 4Q oil production actually declined versus 3Q.

If you remember, there was a lot of concern as we exited 2012. People were saying, oh boy I am nervous by EOG's 2013 oil growth, because the trend line is 4Q production was falling relative to 3Q and it doesn't look good.

Then look at results for 2013. We grow production again 39%, so if you look at it on a historic context, people shouldn't too nervous.

Actually we are going to not fall in oil production, we are going to slightly grow in oil production 4Q over 3Q. There are some reasons for that.

One is, we are going to be drilling some isolated leaseholder wells more than typical which as opposed to drilling more groups of wells, particularly in Eagle Ford and also some potential weather conditions in the Bakken, but if you just look at the 2012 trend and look at what we are projecting for 2013 and the fourth quarter, I think that should ameliorate any concerns now about what we are likely to do 2014. I am not projecting we are going to do another 39% oil growth in 2014, because obviously there are a lot of big numbers that's going to catch up with this one percent year-over-year, but no one should view the situation that oil growth in the fourth quarter is likely a slowdown our trend of a significant oil growth in 2014.

Okay. That's really helpful color.

I guess just in terms of frac technology. Obviously, you guys had talked about a lot better completions in the Bakken and I am certainly assuming that that's going to be applicable to other areas, Eagle Ford, Permian, et cetera.

I mean, could you guys give us a kind of a ballpark on kind of what inning we are in in terms of just improving frac techniques and completions? I mean, it's just kind of the early days here and can we expect a lot better improvements in recovery in your key plays going forward?

Yes. That's a good question, Leo.

The frac technology that's really making a big impact of the Bakken as actually we brought that from on the shale plays with mainly the Eagle Ford cut completion process that we have been so successful in that play with. So it is improving really in all of our plays.

Basically, there is a lot of simple fundamental things. We have had a big advantage with our EOG sand.

As a company, it has not only provided very low cost and help us reduce our completion cost, 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 are probably in the fifth or sixth inning, if you had put in baseball terms, on where we are on the completion technology process.

We continue, quarter-by-quarter, to make advances and we are learning all the time. The EOG culture is that we are 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 are hopeful that we will have continued new improvements as we move along.

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

Mark, hi. Congratulations.

You have left a heck of a legacy behind you. I have got a couple questions, if I may.

Maybe a follow-up on Lea zone on the completion. There has been a lot of chatter, obviously.

I think you guys have been out and about talking about some of the things you have been doing in particular in the Bakken as you transferred some of your Eagle Ford (inaudible). Could you just help us a little bit with how you are seeing the impact of some of these changes in terms of very, very high IP rates, obviously but is this also translating into higher recovery rates?

And if so, I guess I asked this question on the last call, why have you not yet decided to lift your EURs, particularly in the Eagle Ford?

Yes, that's a good question there, Doug. Thank you.

The whole process on all of these horizontal wells is connecting more rock to the well and so we are 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 recoveries and the total recoveries of the field will go up, but we have not really proven that yet.

We have proven it two times with two generations of downspacing in the Eagle Ford and we are currently on the third one. So we are really watching what we are doing.

It takes 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 are just not there yet on this third generation in the Eagle Ford. So when we get that done, we will certainly pass that on.

That is going to take a bit more time. We want to be able to technically be accurate any numbers that give to you.

So we are very careful to do our homework and to do our work right and to provide you really with record numbers and that process does take some time.

Okay, thank you for that.

Yes, Doug. Sorry, a little addition on that.

Our view is that the industry has just been a little bit flippant with numbers. Reserves had been just floated about on essentially all plays.

Billion barrels, 5 billion barrels, BOEs and it is just numbers that we think is just keep in the reserve estimating system a little bit but people just throwing number that 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 have given and we like to think we set our standards a little bit higher than most other companies have done when they issue reserve numbers and particularly with Eagle Ford.

We just take a lot longer to qualify our numbers before we issue them. So that's a little bit of a difference.

I would like to say, our standards are higher before we issue numbers on Eagle Ford, but we are certainly reviewing. When it meets our standards for potential reserve upgrade, we will certainly let everyone in the investment community know.

Thank you. My follow-up, a really quick one, I guess we were all watching your balance sheet improve and expecting stuff like free cash flow next year, but should we given your comments and stepping up activity, should we be thinking that you are again spending cash flow next year, but obviously with a substantial step up in activity and I will leave at that.

Thanks.

What you should read through on the comments on the comments we made on the 2014 CapEx is that if oil prices stay where they are now then we will likely step up our CapEx over the 2013 levels. That's the only thing we are really saying at this point.

We have not made any comments relating to free cash flow and we think at this point we should be in a decent position relating to that, but we are looking at accelerating our overall CapEx. The degree of acceleration is yet to be determined though.

All right. Thanks again.

Congratulations yet again, Mark.

Thank you.

Hi. I will echo what Doug said, Mark, congratulations on (Inaudible) the company and doing what you have done there.

Thanks, David.

Let me just take the free cash flow question one step further. If we think about, if we start looking at next year and you can choose whether or not generate free cash flow, but if you look at the 15 pretty powerful cash flow generation.

How should we think about how are you guys going to allocate capital over the next two years?

Yes, David. We are set to have very, very strong cash flow growth in the company and we have given guidance on the counter priorities that number one, we want to continue to have a healthy increase in the rate of dividend growth in the company, so that is number one.

Number two, you know we are committed to be 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 plays. We are going to be very very focused on capital discipline and capital efficiency and we are going to focus the capital where we can achieve the highest rates return.

Fortunately for EOG, we have a lot of opportunities. Of course, you we are getting very high rates return on the Eagle Ford, and the Eagle Ford will continue to get more money each year.

The Bakken, with the dramatic improvements we have had in it is now equal you know to the Eagle Ford in returns in excess of 100%, so it will get more money each year and we have built the Leonard play into a very successful play and have a very large inventory in the play also with 100% rates of return, so those plays will be first on the list to get more capital each year. The company is really in great shape to continue to grow cash flow strongly and also to have very strong capital returns and capital efficiency as we go along.

Okay. Let me ask a little bit different way.

[2015], could you draw - can the organization today handle another $1 billion, $1.5 billion capital, what you do in '14 or first should we look for - Obviously balance sheet is down. I mean, are you guys looking at dividend increase (Inaudible) '15free cash flow numbers.

What happen to that?

Yes. I think we are going to have to lag and be a bit caution on giving guidance for '15 at this point and we will see how that all go along.

I mean, we are going to be, as I said the capital efficiency in 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 are going to be very focused on that and be very diligent about spending and staying disciplined. As I said the dividend increase certainly will be the first part of our priority and will just discuss that as we go along and kind of watch the returns of the company and where we on the capital.

All right. I will let somebody else jump on.

Thanks for the color.

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

Thanks, Pearce.

My first question is, in the Eagle Ford, you have a nice downtick in your drill times. Down to nine days.

Previously you were less than 12 days. Just curious, using that baseball analogy from earlier, how many handy flips or innings do you think you are in as far as this drill times in the Eagle Ford?

As far as the Eagle Ford, with us saying nine days, we would say, probably again we are in the sixth, seventh inning there. We are just continuing to work on our consistency.

We have had many wells that are quite a bit faster than that. So we are please with the improved consistency with our drilling operations here.

Our record day is five days.

Thank you, and then my follow-up, just coming back to the activity, as it relates to next year, reading on the '14, guidance that you have 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 higher well count?

We expect that our rig count is going to be similar to what we had this year. We had a peak this year of 56 rigs and we probably averaged somewhere around 50, but we expect just continued improvement with rig efficiencies.

We have upgraded our entire rig fleet and we fortunately now have, what I would just classify, is just premium rigs.

Excellent. Thank you very much and congratulations, Mark.

Thank you.

Good morning, everyone and thank you for taking my question. If I could first just go to the capital allocation part of your discussion here.

Looking at the results up in the Bakken, it looks like you have had great results not only with that infill program in Core but also with the Three Forks over in Antelope Extension. So could you talk a little bit about how you are thinking of prioritizing the incremental ramp in that area between those two efforts?

Yes, Charles. We have had some very excellent results.

As we talked about, we have 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 these recent wells have all been done with the same new completion technology that we are using in the Core. It has been very successful.

So we have, and 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. So as time goes along, we will be testing those and working on what kind of development patterns and spacing that we can develop the Three Forks (inaudible) and there other areas in the Bakken in the Williston Basin Bakken acreage that we do feel like that could be additional Three Forks potential that we have not drilled.

So that's the step-by-step process we go along and learn more about the Three Forks. So as we said, we are getting extremely strong rates of return in the Bakken.

We have 12 years of inventory there. So as next year and the years go along, we believe that we will be drilling more wells each year in the Bakken and that's really the whole Bakken Three Forks has, even with our modest drilling this year, we have been able to continue to grow production there and we are setting production records there quite often in the pocket, even with the modest programs.

So we have got some good expectations as we go forward.

Got it. Thank you for that detail, Bill.

Then one other thing, and this maybe a little bit more conceptual. When we look at the, and I really appreciate this new slide where you are showing the 2013 mini drills versus the 2012 and how the cumulative production you have had that in 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 capital that you are putting into the well whether through more stages or big fracs and how much of it is more kind of a free benefit from a better design?

Yes. There are several things going on.

Obviously those are normalized on a per foot basis, so that takes out the lateral length. As we have learned in all these plays as I said before, connecting more rock and connecting that rock that closer to the wellbore is the goal that we are working on.

As increase the amount of sand that we put in the Bakken, we feel like we are also doing a much better job of distributing that sand and the fluid frac along the lateral more evenly, so that helps to connect more lock and get more of the oil in contact with the well, so what we are seeing on these wells with the new improved frac is that when they come on really knocks our peace as we reported, but they also have a little slower decline rate than the initial wells. They hold up better and so the initial whether it's a 30-day rate or the 100-day cumulative production are showing quite a bit of improvement, because we are moving that oil forward in the production lot for the well, so it's nice, good, successful technical renaissance that we are achieving there in the Bakken and seeing really good results because of it.

Hello. Mark.

This is Irene. Congratulations and we will very much miss you in this capacity, but we look see around oil hedge and one last question, why 2018 is the year that we would see the light at the end of the tunnel and then a way out to the gas glut.

I am going to miss you too, Irene. I believe in 2018 is when we will have the first significant impact of the of gas exports in way of LNG from these converted former LNG import terminals.

I think that's when we will really have the first meaningful impact and I think that may have some impact on prices, so that is kind of the that way I see things.

Okay. Great.

Thank you.

Thank you. Good morning.

Mark, congratulations and best of luck as well. You mentioned Greenfield exploration remains a commitment, I wonder even if you 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 shale could be?

Yes, Brian. Certainly, as you said there and noted that exploration has not lost any focus [Leonard] EOG.

We still have 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. As you also noted, we are reticent 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.

Then in the secondary recovery efforts, I think, EOG will also be a leader. We don't know any other companies really working on secondary recovery in the Eagle Ford.

As we reported earlier, we have a dry gas injection pilot program going on in 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. Then we also have water injection pilot going on in the Bakken, and that will take some time too, so we fully are committed and I really do expect that EOG will be a technical leader in the shale plays, and new plays and secondary recovery and also cost reduction.

We just got a culture in the company that is very focused on all that and we are going to be taking that forward.

Brian, this is Mark. Let me add something to that, because I did get a chance to (inaudible) note this morning where you made a comment or words to the effect that EOG's valuation was still quite low because there seems to be a perception that EOG didn't have the reserve life that company didn't generate the production growth that we had or exhibiting because of difference in reserve life and EOG was perceived to have great production growth but not its own reserve life.

Here is to real-world examples from the two biggest oil assets in North America relating to EOG. At the beginning of this year, I think most everybody viewed EOG's Bakken position as a static position, kind of a non-growth position and look at it now.

Now, we are making the best wells in the Bakken. We view it as a considerable growth position and we are 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 the 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 is not going to do as well in the Western Eagle Ford.

That was just 12 months ago. Look at our results now.

We are getting 100% rate of return in the Western Eagle Ford and we are getting 200% rate of return in the Eastern Eagle Ford. But the highlight of our last two earnings calls in the 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 can 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 has shown up here in the last year and certainly take a look and say, who is generating the results among all the E&P companies. We think results matter and we will stack our results up against any company in the business.

Thanks. That's helpful.

Go ahead.

Okay.

Yes, thanks. that's helpful.

I guess as a follow-up, shifting to the Permian Basin. You mentioned in your opening comments that you are shifting more to, you are going to start doing the multiwell spacing in targets in the Delaware Basin stating with the microseismic.

Can you just add some color on what your base case expectations for multiwell development would look like and how play zones you are planning on developing there?

Yes, in the Delaware Wolfcamp, we will focus on a very nice sweet spot in the Wolfcamp there and today we have completed four wells there in three different play zones and those play zones are located in the upper part of the Wolfcamp. The upper part of the Wolfcamp, we believe will tend to be a bit more oily than the lower part of the Wolfcamp.

So we will 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 play zones that we have not targeted or tested yet but the goal is, we are completing a couple of patterns now on different spacing, well spacing and different targeting geometries and we will do some microseismic on some of those and work on the frac geometry on how to contain the frac close to the well and to make it complex to where we are connecting more rock and just see what that is in respect to the spacing that we are drilling the wells on and also production, results of all those different things we are going to do.

It's a process that 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.

Our goal would be to hopefully increase those recoveries as we go along, so, we have got a lot of work to do there but the good side of all this is that this Delaware Wolfcamp, had target rates of return of 60%, and so it is a very strong rate of return play for us already and hopefully we can improve as we go along.

Thanks. Good morning.

Congratulations, Mark. My question is if I would go back to the completions one more time and look at the - Bill, I think you mentioned that you are seeing 30 day rate and I think 90 day rates, but if you look at the decline curves of the new completions versus the previous completions?

Are you seeing the higher rate holding up or do you see a curve eventually converging? Wondering why the hesitancy on (Inaudible).

Biju, do you have it on speaker?

Can you hear me better now?

Yes, Biju. Thank you.

Okay. Sorry about that.

Yes. I was wondering about the declined curves on the new completions versus the older completions.

Are you seeing 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.

It's because the fracs are bigger and more expensive and we are just connecting more rock to the new completions than we did with the original wells that we completed in there. In the Eagle Ford, we have got multiple things going on there.

We are downspacing as well as working on frac technology at the same time, so we are still in the process of learning of that and so I would say comparing the Eagle Ford decline rate is maybe a bit more difficult than the Bakken at this point.

Then the hesitancy on commenting on reserves whether you are seeing how much of an EUR uplift that you are 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 comp, 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. Again, as Mark commented, we are very, very cautious about coming out with new EURs per well, our new recovery fractures for any of our plays until we have had the very thorough technical review of that and had enough time to really evaluate it and to make a good call on it.

Hi, guys. You alluded to this in your prepared remarks, but your Eagle Ford wells continue to generate returns above 100% even in the West now, which likely suggests suboptimal spacing.

Obviously, downspacing continues to be a work-in-progress and it's going to take more time and I am just wondering how you are thinking about the tradeoff just 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 means that our returns fall down in the, call it the 50% to 75% range.

Yes, that's exactly what we are doing. We are very focused on that NPV of the asset and the particular lease.

So the returns are certainly a part of that but we are also reducing cost at the same time on the wells and it's a balancing act. So we are very, very focused on generating the maximum NPV for that particular lease of that particular asset and that's the goal that we are focused on.

And 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 wells enough time to respond and to monitor that and to model that.

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

No, accelerating the NPV is the goal.

Okay, got it, and then just 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 am just wondering if you have reconsidered at all this strategic value of keeping some of your mature legacy assets and if so, does it now make sense to monetize some just to highlight NAV of your growth assets?

I think we have, over the last several years, sold $4 billion of assets. Though it's not likely in our 2014 plan that we are going to have significant asset sales as we see it now.

I think right now maybe $700 million worth of assets sales but not a larger amount of asset sales, as we see it now. So don't look for a big strategic repositioning, as you may be suggesting.

(inaudible).

Okay. Thanks, guys.

Yes.

Well, in my remark, I would say, I am going to miss you all. Thanks for everything.