Good day everyone, and welcome to the EOG Resources Second Quarter 2013 Earnings Results Conference Call. As a reminder, this 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, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing second 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 latest 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; W. Helms, Executive VP, 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 third quarter and full-year guidance in yesterday’s press release. This morning we’ll discuss topics in the following order. I’ll first discuss second quarter net income and discretionary cash flow, then Bill Thomas will review operational results. Tim Driggers will then discuss financials and capital structure. Finally, I’ll cover our macro view, hedge position, and concluding remarks. As outlined in our press release, for the second quarter 2013, EOG reported net income of $659.7 million, or $2.42 per share. For investors who focus…

Thanks, Mark. I will start with our second quarter 2013 Eagle Ford results. EOG’s Eagle Ford acreage continues to prove that it’s the premier horizontal oil position in North America. During the second quarter, we consistently completed strong growth in both the Eastern and Western portions of our acreage that drove our record production results. In addition, drilling and completion improvements continue to drive down oil costs. As a result, we’ve the lower, the average completed well costs in the Eagle Ford from 6 million to 5.5 million and increased the number of wells we plan to drill this year from 425 to 440. Fine tuning this engine with continuous cost reduction and improved well productivity makes EOG’s Eagle Ford acreage the strongest oil growth and capital return machine in North America. And the best part is we have a 12-year drilling inventory on this play that will provide many years of oil growth and superior capital returns. In our Western acreage, we’ve drilled a large number of wells allowing us to fine tune our completion technology. We are now making oils with rate of return that are approaching wells drilled in the Eastern part of our acreage. In La Salle County, The Keller number 1H and 2H had initial daily production rates of 1,855 barrels of oil and 2,050 barrels of oil with 590 and 400 Mcf per day of rich gas respectively. The Smart number 1H and 2H began production at 1,495 and 2,030 barrels of oil per day with 480 and 610 Mcf per day of rich gas respectively. In McMullen County, the Naylor Jones B number 1H started production with 1,830 barrels of oil per day and 1,920 Mcf per day of rich gas. EOG has 100% working interest in each of these wells. To show…

Thanks Will. Capitalized interest for the quarter was $11.8 million. For the second quarter 2013, total cash exploration and development expenditures were $1.7 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property plant and equipment were $91.3 million. As compared to second quarter 2012, total cash expenditures decreased by $278 million. There were $2.6 million of acquisitions during the quarter. During the second quarter net cash provided by operating activities exceeded financing and investing cash outflows in fact we were cash flow positive during the quarter excluding any pro savings from asset sales. Through August 1, we closed on asset sales of approximately $580 million. At the end of June 2013, total debt outstanding was $6.3 billion, and the debt to total capitalization ratio was 31%. At June 30, we had $1.2 billion of cash on hand, giving us non-GAAP net debt of $5.1 billion or net debt to total cap ratio of 26%. The reductions in the year end 2012 ratio of 29%. The effective tax rate for the second quarter was 36%, and the deferred tax ratio was 77%. Yesterday, we included a guidance table with the earnings press release for the third quarter and full-year 2013. Our original CapEx estimate of $7.0 billion to $7.2 billion excluding acquisitions remains unchanged. For the third quarter, the effective tax rate is estimated to be 30% to 40%. For the full-year, the effective tax rate is estimated to be 35% to 45%. We’ve also provided an estimated range of the dollar amounts of current taxes that we expect to record during the third quarter and for the full-year. Now I’ll turn it over to Mark.

Thanks Tim. Now I’ll provide some views regarding the macro environment, hedging, crude by rail and the concluding remarks. Regarding oil, we’re hesitant to provide any short range WTI price predictions considering the volatility we’ve seen over the past months. We note that recent monthly EIA data is consistent with our expectation that 2013 year-over-year domestic oil growth will be less than 2012. We expect EOG’s oil growth performance will be atypical of the industry as other companies with poor quality acreage or plays struggle to grow at rates similar to EOG. We believe the U.S. oil production will continue to grow in future years but at slower rates than 2012 and this is bullish that the global supply and demand picture. Additionally we’re not sanguine regarding any large international shale oil plays affecting global supply within at least the next several years. Overall we continue to be bullish regarding oil fundamentals and prices. For the remainder of 2013 we’re approximately 53% hedged at $98.82 and we have approximately 98,000 barrels per day hedged for the first half of 2014 at $96.48. Because the NYMEX is severely backward dated we currently have only a very small hedge for the second half of 2014. These numbers exclude options that are exercisable by our counterparties. Regarding North American gas prices we consider 2013 to be another and long string of disciplinary years and we expect gas supply to continue to trump demand causing continued weakness over the next several years. Our gas hedge position is unchanged from last quarter. We also expect NGL prices especially ethane to remain weak throughout 2014. Our crude by rail again was a very profitable piece of business for us in the second quarter and our average U.S. well head price was $9.50 over WTI. We expect…

Thank you. The question-and-answer session will be conducted electronically. (Operator Instructions). We'll take our first question from Leo Mariani with RBC.

Hi, guys.

Hi, Leo. How are you?

Great. Great results here. Just a question on the Western Eagle Ford. Obviously as you guys have moved West, it just seems like the results have certainly surpassed your expectations. I think you guys last update on sort of the Eagle Ford average EURs and it was 450,000 boe. Do you guys think that that has got some upward bias here given the strength as you've moved out of your core area?

Yeah, Leo, I'll let Bill answer that but I think the number is 400 boe is the last update we've given on that, so that's the number that we're sticking with at this point. But let me have Bill address that.

No, you're right. I mean that's what we have talked about extensively here is that our Western Eagle Ford results are just like in all of our plays. I mean they are coming up really, really nicely. The main driver for that of course is the completion technology and the cost reduction too goes along with that, but the most important factor in improving the wells is the use of EOG sand. That has been a major factor in improving our wells. And so it also helps us to drive down the well cost and we're certainly watching the per well EURs and the Eagle Ford as we go along here. The thing that we're not going to do is we're not going to rush to change the EURs on a per well basis really until we complete the down spacing program in the Eagle Ford. And we're still actively down spacing both in the East and the West side of the Eagle Ford. And so while we continue to push wells closer together, we want to be careful about that per well EUR and we want to make sure we have enough time to evaluate the long-term effects of the wells on those tight spacing patterns. So, we're going to hold firm with that 400 in boe per well for now.

We'll take our next question from Pearce Hammond with Simmons & Co. Pearce Hammond - Simmons & Company: Good morning and congratulations on another exceptional quarter. Our EOG's EUR improvements in the Bakken is highlighted on slide 26 in your presentation. Is that applicable to your Bakken light acreage as well?

Yes, Pearce, that is. That's a common thing that we completed a few wells in other areas in the Core and Antelope and we've seen excellent results from the new completion techniques in all of our areas. So it would apply across the board. Of course, everybody realizes our Core acreage and our Antelope acreage is the high quality acreage, so the EURs and the other areas might not be as good but certainly the completion techniques are very effective in all of the Bakken.

We'll take our next question from Brian Singer with Goldman Sachs.

Thank you. Good morning.

Hi, Brian.

Wanted to just follow-up on the Eagle Ford here and wanted to see if you could characterize the remaining locations that you have to drill in the Eagle Ford and the quality of those locations, whether it's meaningfully different from those that have been drilling in the last year? And whether you're seeing decline rates that are in line that are worst that your type curve? And I guess there were issues along with whether sand supply and sand supply cost will continue to kind of be available to support the remaining inventory I would think or would all those be key towards your ability to someday raise that EUR?

No, I'd say that our remaining inventory in the Eagle Ford is pretty analogous to what we've drilled so far this year. As far as the sand supply issue, that's definitely not a problem. We have our in-house sand mine, so the sand supply issue is really off the table. There's not a question at all there. I know there have been some questions about our theory that some people have had about us is as we moved West in the Eagle Ford, the quality of our inventory was alleged to deteriorate but I think the one thing that results of this earnings call should dispel is the fact that our inventory in the West is pretty darn strong and we've always had a mix of East to West. We've never preferentially drilled in one area per se. So I think the concern people should have as we drill in later years in Eagle Ford that the rate of change in the Eagle Ford is going to somehow decline, that's just not true and that's why we've been talking so much about this five-year plan of why we are so confident that our oil growth during that period is going to be superior to all other large cap E&Ps because we have the engines of growth with Eagle Ford, the Bakken and the stuff we had in the Permian. And when you think about it, we've got a seven-year run with 38% compound annual oil growth which I'm pretty sure is much stronger than any other company certainly in our peer group and we're telling you the next five years is going to be much stronger than the peer group. And certainly if you look at our first and second quarter results, that's just certainly underpinning that confidence. So we feel very, very good by this and the second quarter data should dispel any notions anyone should have about the range of change in the Eagle Ford being a concern.

We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.

Thanks. Good morning, Mark, and good morning everybody. Mark, first of all, congratulations in your transition. It seems that the quarter hasn't really suffered for it, but if I may ask a question about down spacing in the Eagle Ford. You've talked about 40 in the East and 60 in the West, but it seems from these well results in the West that at least you should be asking the question about how you see the inventory and the down spacing results going forward. Can you speak to whether or not you're continuing to test tighter spacing and what your latest thinking is there? And then I've got a follow-up please.

Yeah, Doug. Yeah, we are continuing to test down spacing in both the Eastern portions of our Eagle Ford acreage and the Western portions of that. And we're going to continue to push that, but we’ve always had is to maximize the net present value of the asset and we really approach that from on a per acre basis. So, as we drive the oil cost down and we push the wells closer together on a spacing pattern, the goal is to maximize the net present value there. And we’re not sure if we reach those limits or not. We’ve been able to improve the net present value over time considerably with both cost reduction and well improvements and certainly that corresponds into additional reserve recovery which we increased several times. So, the process continues in all areas. The completion technology continues to advance and we’re not letting up on that and the cost reductions continues to advance, the increase in the recovery factor that continues to advance and all of that is focused on the net present value of the asset. So everything is moving ahead.

And we’ll take our next question from Matt Portillo with Tudor Pickering & Holt. Matthew Portillo - Tudor Pickering & Holt: Good morning, guys. Just one quick question for me, you mentioned rail marketing and the relative net backs of LLS versus Cushing pricing on pipe and I was just curious if you could provide a little bit more color given the current spread dynamics of how you guys are thinking about railing versus piping crude out of the Bakken and how those economics may change over time? Thank you.

Yeah, what we can say is that because relating to our crude there really isn’t a pipeline option. I mean, the only pipeline is up there is the Enbridge pipeline and we’ve very limited access to the Enbridge pipeline, and so our pragmatic options up there would be trucking the crude versus railing the crude and it’s a slam-dunk there. So for us, railing the crude is the only way to go, so then it just boils down to the – do you bring the crude to Cushing or do you bring it to St. James and so far for us with a differentials were they sit today, its still preferential for us to take at the St. James versus Cushing and – but we have that option if and when the advantage would flip the other way to take it the Cushing or one of the few companies who do – would have a rail option of either place if and when that became advantageous. Next question.

And we’ll take our next question from Irene Haas with Wunderlich Securities.

Hi. Again congratulations on just doing such a great science and turning out really new place year after year and my question is to do Reeves County and the four wells that you’ve drilled thus far, I can see sort of the percentage of oil actually marching out with your newer wells, so it was looking like sort of 40% oil. Can you shed a little light on when all is said and done, sort of what is your EUR composed of in terms of percent, oil, natural gas, liquid and gas?

Yes, Irene, we’ve a slide on that with a pie chart. I believe that is slide 31. And our latest estimate here is that on the typical Wolfcamp well its 34% oil, 34% gas and 33% NGL and we found that the percent oil is a little variable depending on what zone you’re drilling in the Wolfcamp, and so we’re testing multiple zones there. Of course, there is an enormous amount of resource in place there, our Reeves County we’ve been fortunate to be able to lease-up a very strong sweep spot in the Delaware Basin with Wolfcamp where the shale thickness is very thick and also the quality of the shale is very hot. So, we’ll get a better handle I think, we’re going to drill 10 wells this year approximately and we’ll be trying multiple zones there and I think that some time later in the year, I mean by next year we’ll have a little bit better idea kind of what the balance will be on the content of everything. But right now we feel like this 34% oil is probably going to be pretty close to what its going to be.

And we’ll take our next question from Amir Arif with Stifel. Amir Arif - Stifel, Nicolaus & Company, Inc.: Thanks. Good morning, guys. Congratulations on a great quarter. The question really is about your positive free cash flow position that you’re going to start hitting in ’14. I know you lay out through different priorities, but could you just give us some more color in terms of how you’re thinking how useful that excess free cash flow in terms of excess above of steady dividend growth? How much would go to incremental capital spending and the follow-up would be on the incremental capital that you would allocate? How would you think about splitting that between your three core areas of Eagle Ford, Bakken and Permian? Thanks.

Yeah Amir, that’s a good question. We are going to have a lot of cash and certainly the priority is we set out and we’ve given these guidelines as we continue to work on the dividend. We’ve had a nice 14 year increases in dividends and so we want to continue that and reward the shareholders in that way. We also want to focus some of the money, the second priority would be to continuing to reduce the debt of the Company, not to the extremely low levels, but a bit lower than where we’re right now. And then number three, we’ll have additional cash each year to invest in our best place. And certainly the highest rate of return plays will be the priority there and the places where we can invest to grow oil prices – oil production most aggressively and those will not be much different than they’re this year. That will be certainly the focus number one will be the Eagle Ford and the Bakken and as we – as over time, we’ll be focusing more capital into the Leonard. It’s turning into the very high rate of return play for us and very oily also. So, each of those plays have more 10 years of inventory in their extremely high quality plays and that’s what gives us the confidence that we can continue to be the peer leader in oil growth through 2017 and beyond.

And we’ll take our next question from Arun Jayaram from Credit Suisse.

Good morning gentlemen. I just wanted to ask you a couple of quick questions. One Bill, I was just wanted to see if you’ve done any analysis on maybe stratifying the wells drilled on Eagle Ford looking at some of the monster wells versus perhaps some more typical well and any general comments on decline rates you’re seeing over the first year what not relative to both of those?

Yeah, Arun. The stratigraphy of the Eagle Ford is pretty consistent from east to west. There’s not a lot of individual zones developing and coming and going as you kind of go across the play. Some of the changes are I think in the eastern part of the acreage, there’s more faulting and so there is more open fracture systems available and that’s why you see sometimes you see very high IPs from the wells in the east. On the west side there is less faulting, and less open fracture systems and so it takes a little bit of a different completion technique which we obviously – we’re making very good progress with that and maybe the IPs may not ever approach the wells on the east but certainly the results in the west are very, very good. We have been able to develop techniques to increase the amount of rock that reconnect to the wells. One of it is, we drilled longer laterals in the west and we used a different kind of completion style and all that’s designed to connect up to the more of the matrix of the rock and so we’re certainly getting really good results in both areas and both areas as Mark has said we have an enormous amount of locations in both sides and so the quality of our program is certainly not going to deteriorate over time. It's very, very, very strong.

We'll take our next question from Marshall Carver with Heikkinen Energy Advisors.

Yes, good morning. A question on the Bakken. You have 90,000 acres in the Bakken Core. How many acres do you have in the Antelope Extension, State Line and Elm Coulee areas?

Again, Marshall, it's a question – we've not updated our acreage position in Antelope or the Core but you're right, we have 90,000 acres in the Core and this is an estimation that I think is approximately about 20,000 acres in the Antelope area.

We'll take our next question from Barry Haimes with Sage Asset Management.

Hi. Thanks for getting my question in. I had a question in the Bakken. I understand and you alluded to longer lateral lengths and changing completion techniques a couple of times in the call. And I guess in the Bakken you've drilled a few wells with maybe 15,000 foot laterals and maybe four or five times the amount of (indiscernible). I wonder when you're talking about the different completion techniques, is that what you were alluding to? Number one. And then number two, how applicable is that across the Bakken and then maybe also in the Eagle Ford? Thanks very much.

Yeah, in the Bakken we feel we have a completion advantage there and we're happy to disclose that we're using more pounds of (indiscernible) than we have in the past and that we are drilling longer laterals. But as far as giving any more specifics other than that, we feel we'd be giving away some proprietary secrets and so I'm afraid, Barry, we're just going to have to leave it at that. And the same for the Eagle Ford; we have gone to some bigger fracs in the Eagle Ford than we have in the past but again, we feel we clearly have a proprietary advantage in our frac technology in the Eagle Ford also and we just assume to keep it proprietary. Thank you.

We'll take our next question from Ray Deacon with Brean Capital.

Hi. Good morning. I was wondering if you could give a little bit more detail on the Wolfcamp, how many of each zone do you think you will have tested this year.

Yeah, Ray, in the Delaware – are you talking about the Delaware Wolfcamp? I guess so. Yeah, in the Delaware Wolfcamp, Ray, we've tested three zones this year, call them the upper, middle and lower zone there and we've had really good results in each one of them. As I said before there's a little bit of different mix in each zone, on the product mix whether it's oil or gas but the rock quality and the response of the wells on each one of those have been very, very, very strong. So, we feel that we've been very fortunate to lease up a really nice large position of the sweet spot there.

We'll take our next question from Charles Meade with Johnson Rice.

Good morning and thank you for taking my question. I wanted to get a little more detail on the Burrow Unit and particularly I believe it was the 5H or perhaps it was the 4H that had that really fabulous IP. But the one thing that I noticed was a little different that you guys offered the 30-day average and you get to a 30-day cumulative of I think 128,000 barrels which is really impressive. And would I be wrong to read into that that the reason that you guys choose to include that 30-day rate is that it's better than other wells in the past? And that if that's correct to read into it, is that a function of your improved fracture line?

The Burrows did have a longer lateral. It's about 7,500 foot lateral. The other two are quite a bit shorter. But as far as us reporting cumulative, it's relative to other wells. It's not proportionally any larger at all, performing about the same, just longer lateral.

At this time, I'd like to turn it back to our speakers for any closing or additional remarks.

Yeah, I'd just close with two remarks, just again to summarize I think two points you want to take away from the call. First point is, again the Western Eagle Ford is an area that we're particularly proud of with the results. And the second point is for the first time we can highlight three key oil plays on a direct after-tax rate of return basis. In each of these plays, we're achieving 100% or greater rate of return; Eagle Ford, Bakken and Leonard. So thanks for listening and we'll talk again in three months from now.

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