Good day, everyone, and welcome to the EOG Resources Fourth Quarter and Full Year 2013 Earnings Results Conference Call. As a reminder, this call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to Tim Driggers, Chief Financial Officer. Please go ahead, sir.

Thank you. Good morning. I am Tim Driggers, CFO. Thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 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 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 in Investor Relations page on our website. Participating on the call this morning are, Bill Thomas, Chairman and CEO, Gary Thomas, Chief Operating Officer, Billy Helms, Executive VP, Exploration and Production, Maire Baldwin, Vice President, IR and Jill Miller, Manager, Engineering and acquisitions. An updated IR presentation was posted to our website yesterday evening and we included a guidance for the first quarter and full year 2014 in yesterday's press release. This morning we will discuss topics in the following order. I will start with fourth quarter and full-year net income and discretionary cash flow, Bill Thomas and Billy Helms will review operational results and year-end reserve replacement data, then I will discuss EOG's financials, capital structure and hedge position. Bill will cover EOG's macro view, our 2014 business plan and provide concluding remarks. As outlined in yesterday's press release, for fourth quarter 2013 EOG reported net income of $580 million or $2.12 per share. For investors who are focus on non-GAAP net income to eliminate mark-to-market impacts and certain nonrecurring items as outlined in the press release, EOG's fourth quarter 2013 adjusted net income was $548 million or $2 per share. For the full year 2013, EOG reported net income of $2.2 billion or $8.04 per share and adjusted basis full year net income was $2.25 billion or $8.22 per share. For investors who follow the practice of focusing on non-GAAP discretionary cash flow, EOG's discretionary cash flow for the fourth quarter was $1.9 billion. Using the same methodology for the full year 2013, EOG's discretionary cash flow was $7.4 billion. For the full year 2013, EOG's net cash provided by operating activities exceeded financing investing cash outflows. At December 31, 2013 debt to total cap was 28%. Net debt was reduced by $841 million during 2013, resulting in an ending net debt to total cap ratio of 23%, down from 29% at year-end 2012. I will now turn it over to Bill Thomas to discuss operations.

Thanks, Tim. 2013 was EOG's best year on record Over the course of 2013, EOG increased crude oil production growth targets three times and ended the year with total company oil production up 40% over 2012. This is a 44% average increase over the last three years. Our key assets the Eagle Ford, Bakken and Leonard keep getting better and we continue to improve well productivities from these plays. The 42% increase in U.S. oil production last year is solid proof of the depth of EOG's drilling inventory. For the year NGL production increased 17% while natural gas production decreased 11% for a total company production growth of 9%. EOG cost structure is a focus area and for the fourth quarter and full year unit costs were lower than expected. The combination of increased growth from high margin oil with the decreasing cost structure flowed through our income statement and balance sheet, further deleveraging the company and generating a 16% ROE for the year, a big increase from 12% for 2012. We updated the ROE and ROCE charts in our IR presentation on pages 14 and 15 showing our improving metrics and a comparison of our results to our peers. While I discuss 2014 business plan in greater detail later on in this call, EOG is targeting 27% oil production growth in 2014. Given the strength of our balance sheet and the depth of our high margin domestic crude oil drilling inventory, we have increased CapEx levels over 2013 to accelerate drilling of the high rate return oil inventory. Last year, we added two new locations for every one well we drilled. With this strong operational momentum in our key areas of activity, we plan to keep it going. The biggest driver of EOG's outstanding crude oil growth during 2013…

Thank you, Bill. During 2013, we made significant progress with our Bakken and Three Forks completions that dramatically improved well productivity and individual EURs. These enhancements and the ongoing implementation of cost saving measures, including the use of EOG sand, have turned what was once a mature producing area into a higher rate of return oil growth assets. We continue to see plenty of opportunity on our Bakken core acreage by bringing the latest technology to this area that was initially sparsely drilled over five years ago. Recent core wells are the Wayzetta 30-3230H and 31-3230H which began production at 2,510 and 2,540 barrels of oil per day respectively. We have 59% working interest in these wells. The Wayzetta 35-1920H had an initial production rate of 2,240 barrels of oil per day with 1.2 million cubic feet a day of rich natural gas. We have 60% working interest in this Mountrail County well. Using the same improved completion techniques in our Antelope Extension area, we are seeing similar enhanced IP rates and EURs. The Hawkeye 2-2501H had an initial production rate of 2,075 barrels of oil per day with 3.8 million cubic feet a day of rich natural gas. We have 80% working interest in this well. In 2014, we expect to again grow crude oil production. Our drilling efforts will be localized in these same two areas, the Bakken Core and Antelope Extension, with the majority of activity in the core. We will continue to downspace in both areas and plan to operate a six rig drilling program. We have existing oil and pipeline infrastructure within the core and with the integration of EOG Sand into our Bakken operations, we will continue our focus on reducing well cost even further, while enhancing the productivity and recovery factor of the…

Thanks, Billy. Regarding new plays, we have been saying for some time now that we haven't lost our focus on looking for new domestic liquids plays, primarily oil. In addition to increasing the recovery on our existing plays, we continue to look for new prospects and test new ideas. In our midstream operations, we are working with our partner rail companies. We have a strong emphasis on safety and our crude-by-rail operations. On our crude-by-rail our crude-by-rail continues to give us flexibility to access markets with premium process and plays a role in the ultimate destination of EOG produced crude. To summarize our operations, EOG has captured the best horizontal oil acreage in North America, and our high performance operational teams continued to execute superbly. Our wells are still getting better, unit cost continue to decrease and oil production continues to increase at peer leading growth rates. EOG has a long life inventory of crude oil and liquids rich drilling prospects with high after tax rates returns. 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 $15 million. For the fourth quarter 2013, total exploration and development expenditures were $1.6 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $93 million. There were $28 million of acquisitions during the quarter. For the full year 2013, capitalized interest was $49 million. For the full year, total expiration and development expenditures were $6.7 billion, excluding acquisitions and asset retirement obligation. In addition, expenditures for gathering systems, processing plants and other property, plant and equipment were $364 million. For the full year, total capital expenditures for all categories were $7.1 billion, excluding acquisitions. We ended the year below our guidance. Total acquisitions for the year were $120 million. During the quarter, net cash provided by operating activities exceeded financing and investing cash outflows. We paid off $400 million bonds that matured in October. For the year, total proceeds from asset sales were $761 million compared to the goal of $550 million. The effective tax rate for the fourth quarter was 37% and the deferred tax ratio was 64%. We announced a dividend increase of 33% and at 2:1 stock split in yesterday's earnings release. The dividend increase is the largest year-over-year dollars increase in EOG's history. Yesterday, we included a guidance table with earnings press release for the first quarter and full year 2014. Our CapEx estimate for the full year is $8.1 billion to $8.3 billion excluding acquisitions. The expiration and development portion, excluding facilities, will account for 80% of the total CapEx budget. The largest increase in spending will come from drilling activity, primarily in the Eagle Ford and Bakken. For the first quarter and full year, the effective tax rate is estimated to be 35%…

Thanks, Tim. Now I will provide our views regarding the macro environment and 2014 operations activity. Regarding oil, we are still waiting for the final 2013 EIA U.S. oil production data, but it looks like the rate of growth in 2013 slowed compared to 2012 and we expect this trend to continue in subsequent years. The October and November EIA monthly data indicates the rate of annualized production growth was approximately 760,000 barrels per day compared to 1.04 million barrels per day for the same period in 2012. We are still bullish regarding U.S. oil process because of slowing domestic oil growth and we are not particularly concerned about a surplus of U.S. light sweet oil. Regarding North American natural gas prices, our long-term view hasn't changed. We have obviously seen some relief this year due to the multiple shifts in the polar vortex this winter. We think natural gas prices will stay around the $4.50 level in 2014 and '15. On the plus side, we have taken advantage of some the recent prospects to layer in hedges. For our 2014 business plan, it is as follows. We plan to focus on high rate of return domestic crude oil growth. We are targeting 27% oil production growth this year and 11.5% total company growth. We have increased our CapEx budgets from last year because we have so many high rate of return opportunities to pursue. The greatest increases are in our highest return plays, the Eagle Ford and Bakken. The amount of CapEx dollars allocated to midstream infrastructure is also increasing. This year we plan to spend approximately 10% of our total CapEx budget on these types of projects to lay the foundation for future growth and to manage operational costs. Also for the sixth year in a row, we…

Thank you. (Operator Instructions) We will go first to Leo Mariani with RBC.

Hey, guys. Can you talk a little bit more about the Eagle Ford in terms of some of the downspacing initiatives, I guess, you talked about in average of 40-acre spacing across your position here. Would you expect to see some interference at that level and is it possible for you guys to quantify that at all?

Yes. Thanks, Leo. That's a good question. The downspacing that we have done across the field we found that has been the spacing is very variable, due to different geology, different faulting situations at this different things across the field that we have to deal with. Some places, you know, we can drill wells as close to maybe 30 acres to 35 acres per well and in some places it's more like 50 to 60 and 65 acres per well, so it is quite highly variable. The number of wells that we have, again, were 7,200 total wells are based on actual well locations that we have put on the map in regard to the geology, the individual geology at each unit and the configuration of the leases, so these are not spreadsheet numbers. As far as the interference between wells, there is some interference in some areas and in some places there are not interference, so again it's really highly variable and that we have been able to overcome the interference and increase the well EURs with our frac technology. So the frac technology has definitely enhanced the productivity of the wells and it has enhanced the EUR per well. So we have quite a bit of confidence that the average EUR for the 7,200 wells we have is 450 MBOE per well.

Okay. That's really helpful. I guess, just jumping over to your thoughts on oil marketing. I guess there is some concern out there among investors that too much oil is coming through the Gulf Coast over the next couple of years. Can you talk at all about your optionality in terms of moving oil going around? Are you guys able to access East and West Coast markets as well with your oil?

Yes, Leo. Our crude by rail system gives us a lot of flexibility and we believe that will come in to play as we go forward. We have established markets in the East and West Coast but really our prime markets still remain on the Gulf Coast or LLS prices and an increasing WTI prices. So as we have seen, just really over the last few months, there's been some variances in the differentials between WTI and LLS prices and we have been able to take advantage of that, and we have been switching back and forth. So again our crude by rail system gives us a lot of flexibility to get our oil to the highest priced markets.

Okay. That's really helpful. Thanks, guys.

We will go next to Doug Leggate of Bank of America Merrill Lynch.

Thanks. Good morning, everybody. Bill, I wondered if I could go back to the 460 EUR average. I am not sure how to ask the question eloquently. So I will stumble through probably. But what I am trying to understand is that's obviously an average and I am guessing there is some variability across the play. So what I am trying to get is, where are you concentrating the drilling inventory in the first part of the 12 years backlog you have got. In other words are you drilling better wells first on average or the lesser wells will be later on in the program? And if so, how should we think about your medium-term growth outlook? Then I have got a follow-up, please.

Yes, Doug. That's a very good question. Our drilling is very well equally spaced and really as we look forward, we need to be thinking about the Eagle Ford as one play, because the Western wells and the Eastern wells are relatively same in the average EUR per well and there is a little bit of variability but there is really not much difference across the whole play. So whether we drill in the West or we drill in the East, our well results we believe will be very consistent going forward and that is certainly not front-end loaded with the best wells in the East and then later on we won't drill wells down the road. So I think you can look at the 12 year inventory we have is very strong and very consistent and we will have good results every year because of that.

Okay, that's very clear. Thanks for that. Then my follow-up is really on the midstream spending. I know you guys have said often the drilling consideration short-term, at least, to maybe do something structurally, by way of an MLP or something like that, but given the scale of your standing, I just wondered if I could ask you to frame your latest thoughts on that, has it even changed and if not, why is that not a thought that EOG would be interested in? And I will leave it at that. Thanks.

Yes, Doug. On midstream, we are very, very selective on how we spend our midstream dollars and the midstream dollars we have allocated this year and particularly have given us a very strong rate of return and are really focused on getting our oil to the market and decreasing our future operational cost and transportation costs. We are not at all interested in working on forming new MLP companies or making the company very complicated. We want to keep the company financially and structurally simple as we go forward. So it is easy to understand. And so our midstream is really just to enhance EOG's acreage positions and getting our products to market and keeping our cost low as we go forward

I guess if I may, why then wouldn't you include the midstream cost when you look at your well economics?

Well, I mean, certainly the midstream costs are part of the whole picture, but really we are really focused on getting the wells drilled and getting the direct return of those the wells at a maximum and we are focused on that. Then we are always looking at the whole picture EOG has a lot of scale and were able to midstream dollars down to a minimum when we have a scale. We are really focused on the company on returns and increasing our ROE and ROEC numbers, so midstream really helps us do that.

Appreciate the answers though. Thank you very much.

We will go next to Charles Meade with Johnson Rice.

Yes. Good morning, everyone. If I could go back to the Eagle Ford spacing question, particularly the average being 40 acres and some other operators in the play are testing - they haven't confirmed - they are testing just down to 175 feet which would get you close to about 20 acre spacing, so I am wondering can you share what the close offset you guys maybe have planned '14 and what supposedly you have done today?

Yes, Charles. I think we have done some in the 300-foot range and that's 200-foot maybe down to 200 feet. Again, we push them pretty close together and the goal of course is to always to maximize the NPV of the acreage. As you push them too close together, you could start destroying the value, so these pilot programs that we put in and tested have given us a pretty solid understanding of the interference between wells and the spacing between wells in terms distance between wells, so we feel pretty solid at this point that on an average 40 acres is probably the optimal spacing pattern.

Got it. Thanks for that detail, Bill. Shifting over to the Permian your slides are very hopeful. It's obvious you look - cut by the Leonard play is a more attractive than the Wolfcamp play, because you are pretty classy there but, but I am wondering if your 2014 plans for the Wolfcamp, you might be able to go North and East from Reeves to perhaps in Worden, I think where you have seen higher oil cuts in that Wolfcamp play and if that's an option for you it is part of your 2014 plans.

Yes. For the Delaware, Wolfcamp our acreage is located kind of central Reeves and we do have some acreage up to the North and to the East in the northern part of Loving County and then in the Lea County that we believe are prospective for the Delaware Wolfcamp. Your correct it does get a bit oilier as you move that way, so into in 2014 we are really probably just focused on the Central Reeves County area. Then will be testing additional the Wolfcamp potential maybe later in the year in 2014 and in the 2015 as we go forward, but we are trying to work the play technically and increase the oil percentages as we go forward.

Great. Thanks. We will stay tuned on that.

We will take our next question from Matt Portillo with TPH.

Good morning. Just two quick questions for me, I was wondering if you can give an update to your Bakken downspacing test and how you I think about the upside to your inventory depths. Then I have a quick follow-up after that.

Yes, Matt. On our Bakken, we are continuing with 160 acre downspacing and we are studying very intensely the possible interference between the new wells in the existing older wells. Obviously the new wells had come in extremely good. We are very pleased with the results so far in our downspacing efforts and we will give some guidance on what all this means later down the road. We haven't given any time commitment on that. We really want to make sure that we technically understand where we are going and what this really means to recovery for our acreage.

Great, and then just a quick follow-up in regards to your out Midland Basin Wolfcamp position. You have a nice footprint there, although the asset looks like it doesn't compete on a rate of return basis within the portfolio today. How do you guys think about that asset from a long-term perspective in terms of it s strategic nature in your portfolio?

Yes, we want to certainly hold on to it. We are making some progress there in the Midland Basin. Our long-term view is that we can continue to improve the results there, establish the right spacing patterns and continue to reduce costs and also increase the well productivity and really focus on increasing the rate of return there. So we are going to leave it in the portfolio right now and see if we can get it up to the point where it can make its way back into our high return inventory.

Thank you.

We will go next to Amir Arif with Stifel.

Thanks. Good morning, guys. First question really on the Leonard Wolfcamp. I know its early days there but I was just curious where do you think the 2% to 3% recovery factor that you are putting out there could go to as you better touch the downspacing and the timing around testing the downspacing to get a comfort on resources?

Yes, Amir. On our Leonard play, we are still doing some testing there, as you can imagine, on spacing and testing different target zones to really understand what the productivity in the long-term performance is going to be. We obviously are seeing improvements in that. So we are optimistic of what we might see on improvements in recovery factor but we still haven't quantified that yet. That's still a work in progress. So we will provide more data on that once we have it fully evaluated.

Yes. Just a follow-up question on that CapEx, the $900 million for facilities. Can you give us some more color in terms of what type of facilities and where that CapEx is going?

Yes. So two thirds of that is going to be in the Eagle Ford and that on lease facilities with us drilling more wells this year and we are going ahead and putting it in our oil and gas gathering lines. Put the new oil on pipeline. It saves us quite a lot on our transportation. Then we are putting it in an oil storage and pipeline facility there for the West. Gas processing facilities, SWD systems, water reuse facilities and that also includes artificial lift. We are putting that on quite a number of wells this year. So all that is just to reduce transportation, our LOE, realize higher prices, all long-term benefits for earnings.

Thank you.

We will take our next question from Joe Allman with JPMorgan.

Thank you. Good morning, everybody.

Good morning.

Hi, Bill. In terms of the increase in the Eagle Ford EUR and resource, what drove your decision to increase the EUR per well in that resource at this time? And then, what could make that EUR or the total reserves go up in the future?

Yes, Joe. The EUR per well increase was certainly up a lot of strong historical data. We have over 1,200 producing wells in the play right now. And then, we have done extensive pilot testing on each one of these downspacing patterns and through our completion technology, we have seen dramatic increases in initial rates per well and then the shape of the decline curve really has not changed. It's relatively the same shape. It's just that the well's initial rates have improved over time with better their completions. So that gives a better total EUR. When you have long-term production, you have enough data, like we do to establish and have a lot of confidence in that. So we have got a lot of confidence in that and as we go forward, we are hopeful that we will be able to continue to improve the well productivity but we certainly have not proven that yet, but we are going to obviously continue to work the technology. We are never going to give up and we are never going quit trying new ideas or new things. So we are in that process right now. We will just see how time will tell .As we go forward, we will see how it all turns out.

Great. Thanks for that. And then, on your gas production forecast for 2014, you are now looking at a decline in gas production, a short time ago you were actually looking over the next few years for a flat to modestly up profile for natural gas, so what changed in terms of your forecast for natural gas?

Yes. Joe, we look at our drilling portfolio and we have continued to shift money to the higher return plays, so one of the things we have been reducing is some of our combo plays, so we continue to reduce dollars from the combo plays which are more gassy, because of just a bit lower return than our high return oil plays, so that's really the shift that we have seen in the gas profile.

Great. Thank you very much.

We will go next to Pearce Hammond with Simmons & Company. Pearce Hammond - Simmons & Company: Yes. Bill, some other operators in Eagle Ford you talked about, the upper and lower Eagle Ford intervals being distinct zones within the play. Are you seeing the same trend cross some of your acreage?

Yes, Pearce. We do have that we have recognized that on a decent portion of our acreage and that's certainly an option that were looking at an exploring and may do some testing on that as we go forward to see if the upper part of Eagle Ford specifically has not been affected and contacted with the existing frac technology that we are using, so we have got that in mind and we are going to be working on that. Pearce Hammond - Simmons & Company: Great. Then my follow-up Bill, in Slide 31 of your presentation, you highlight your gas acreage. While I know right now you are focusing on oil because of the better rates of return, if you were to turn your attention to gas, which of these areas would receive EOGs primary attention?

The best acreage we have are in really probably some of the more combo-ish acreage. The Haynesville combo play is a really strong rate of return play for us. Also the highest quality dry gas that we have is certainly would be in Bradford County in Marcellus. Then we drill a few selective wells in South Texas in the Frio and Vicksburg area. There are good wet gas and combo and also very high rate wells and give us high rate of return, so those are three areas that probably will be high on the list. Pearce Hammond - Simmons & Company: Thank you Bill.

We will go next to Bob Brackett with Bernstein.

Hi. I will do a follow-up. You mentioned Frio Vicksburg wet gas wells. Are those conventional-type sand targets or there are any sort of shale plays you are chasing down there?

Yes, Bob. Those are really conventional plays. They are the typical Gulf Coast.

[Nanodarcy].

Yes. I would say they are mostly nanodarcy top reservoirs and so they are very high rate very, very specific prospects, not regional prospects. They are very specific.

Yes. Then following your language of captured the best asset is one of your strategic goals. Can you give us some flavor of what you might be doing this year, next year against bad objectives?

Yes, Bob. We have a nice working list of new prospect potential that we are working all the time and we are very, very focused of course right now on the oily-type plays and we are focused on only on plays that would be additive to our portfolio, so our portfolio is such a high return for portfolio that for a new play that work itself into our system, we are targeting only plays that we think that could generate after-tax rates of return greater than 50%, so we are being very selective on that. We have a nice list working, so we are taking her time to test those and to evaluate those to make sure that they are the kind of quality plays that we want to invest money in as we go forward, but we are confident that EOG is going to continue to be a leader in generating new plays as we go forward, so that will be certainly a nice part of additional resource potential for the company as we go forward.

Thanks.

We will go next to Joe Magner with Macquarie.

Good morning. With all the updates provided on the Eagle Ford, I noticed that references to specific recovery factors weren't in the presentation any more. I was just curious with what you are seeing and understanding how the reservoir now, are there any changes to your access of original oil plays and/or those recovery rates?

Yes, Joe. That's a very good question. The recovery factor is a work in progress and we are certainly not seeing any decrease of any oil in plays. We are learning about these resource reservoirs. We are learning more all the time. Of course there is no textbook on them. So we are trying to get a better understanding of that as we go forward and as we learn more about that, we will be able to update you with a bit more stronger technical information.

Okay, and then, I guess, just to circle back on the spacing and the prospectivity of your Eagle Ford oil acreage. The final plot of 40 acres to that entire position, it seems like there would be more locations than what you have provided. Just curious how you are thinking about risking and the delineation of that acreage position and if there is more work to be done over time? Just wanted to make sure I got that discussions right in my mind.

Yes, Joe. The 7,200 locations that we have announced or talked about are actual sticks on the map. So they are very specific locations, not a spreadsheet calculation at all and those are all very firm locations. As we look at our acreage, there are other areas of our acreage that could be prospective and those areas, at this moment, we feel like fall below our rate return cut off. And although they would be productive, they are not weighed in our portfolio right now. So we have put a cutoff on rate of return, anything less than the 60% effect rate of return is not included in the 7,200 locations. So there could be additional upside. We are hopeful that we will be able to continue to reduce costs and improve well productivity in all the areas in a specific unit in the areas that are a bit more of return.

Okay. Thank you.

We will take our next question from David Heikkinen with Heikkinen Energy Advisors.

Good morning. Just speculate your midstream CapEx this year. How much does the spending this year impact 2014 in your realize pricing in OpEx guidance? And then should we assume further efficiency gains in 2015?

Yes, but some of this effect 2014 certainly. When we talked about our gathering lines here and on lease and our artificial lift, but you are right, David, what we are doing here is going to have impact certainly beyond 2014. A portion of this share is midstream and also even our sand facilities because we are seeing that, yes as we drill new wells, we have a need for additional sand and we are just ensuring that we have a long-term, low cost sand available to EOG.

That was a perfect segue to my second question. So you saved $500,000 a well in Eagle Ford for using your own sand, roughly. As you take your sand to the Bakken this year and then the Permian next year, how much would you save per well using sand there, the EOG sand?

Yes. We think that we are going to be looking at the same sort of savings and we are working towards having us self-sourcing all of our sand for the Bakken. We are doing some of that now in the Permian. We believe we will be able to do that pretty well across the board for EOG.

Okay. Thanks. That was my two questions.

We will take our next question from Arun Jayaram with Credit Suisse.

Good morning, Bill.

Hello, Arun.

Bill, I just wanted to talk a little bit about the increase in the Eagle Ford resource. You added, I believe, 1,600 incremental well locations. Can you maybe quantify what drove that between downspacing versus opening up new parts of the plays you have done additional delineation drilling?

Yes. That's a good question. I am not saying the majority of it is really due to downspacing at this time, and that is and something we took great care and technically and use multiple downspacing pilot to determine these additional locations, so we found out certainly that it's very variable across the field, but the average is about 40-acre spacing between wells and that gives us the optimal net present value. We have a slide in the in the IR slides that show how that the net present value or per acre basis has increased over time as we downspaced and added additional potential, so it's a really good solid number but really most of the year increase is downspacing.

Okay. Then Bill, as you shift towards '14 and '15, is the development plan now going to be just 16 wells per section? Is that how you plan to developing?

Well, it is variable across the field, so it's not a standard thing. It really varies from lease-to-lease, but certainly I think on an average 40 acres space is that we are proceeding ahead at this time and that looks like that will generate the best returns and the best NPV.

Okay. My follow-up is just on the Leonard. I believe, you guys mentioned optimism to do 8 to 10 wells per in a interval? Could you just comment on some of your early appraisal something in the Leonard?

Yes. It's a good question. Saying it's still early is a good point, because we are still testing multiple spacing patterns there as well. We do believe eight is certainly a very achievable number. We are going to be testing 10 A zone and we are still have additional zones there to test as well, so we are very encouraged about what we are seeing in the Leonard play based on our latest results and so were optimistic that the spacing pattern will prove itself out here as we go forward.

This does conclude today's question and answer session. I would like to turn the call back to Bill Thomas for any additional or closing remarks.

I just want to thank everybody for joining the call this morning and we look forward to a great 2014. Thank you.

This does conclude today's conference. We thank you for your participation.