Good day everyone and welcome to the EOG Resources 2016 Third Quarter Conference Call. At this time for opening remarks and introduction I would like to turn the call over to the Chief Financial Officer of EOG resources Mr. Tim Driggers. Please go ahead sir.

Thank you. Good morning and thanks for joining us. We hope everyone has seen the press release announcing the third quarter 2016 earnings and operational results. This conference call includes forward looking statements. The risk associated with the forward looking statements have been outline in the press release and EOGs SEC filings and they incorporate those by reference of 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 filing with the SEC to disclose not only crude reserves but also probably 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 the quarter not contemplated by the SECs 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. In addition for the purpose of this call the reserve estimates for basin and low level resources are net after resources unless otherwise states. In reference to well location, wells drilled and wells completed are after EOGs interest unless otherwise stated. Participating on the call this morning are: Bill Thomas, Chairman and CEO; Gary Thomas, President and Chief Operating Officer; Billy Helms, EVP, Exploration and Production; David Trice, EVP, Exploration and Production; Lance Terveen, VP, Marketing Operations; and Cedric Burgher, Senior VP, Investor and Public Relations. An updated IR presentation was posted to our website yesterday evening, and we included guidance for the fourth quarter and full-year 2016 in yesterday's press release. This morning we'll discuss topics in the following order. Bill Thomas will review our shift to premium drilling and the updated 2020 growth outlook. Billy Helms will provide an update to our premium Delaware Basin resource and David Trice will discuss notable achievements in the other select plays. Gary Thomas will go over our operational accomplishments and I will discuss EOG's financials, capital structure. And Bill will provide concluding remarks. Here's Bill Thomas.

Thanks, Tim, and good morning, everyone. EOG has responded to the downturn at oil process with an unrelenting focus on capital turns. In 2016 we increased well productivity and lowered well and operating cost at a record pace. The company projects an all-in return on the 26 capital program on the company record and we achieved this on the lowest commodity price environment that we have experienced in a long time. Our tremendous success in proving capital return this year and combined with the addition of the Yates acreage has also increased the company resource potential in both size and quality at a record pace. As a result we reset the company to deliver high return oil growth with in-cash well with $50 oil environment. We believe this is unique to the industry. In this price environment our ability to generate high capital rates of return and achieve strong double digit growth with the balance CapEx that cash flow program sets the industry apart, leader in capital efficiency. In early 2016 the town working each player across identified 3200 locations representing 2 billion barrels of oil reserve potential. That meant a new rate of return standard we designated premium. To meet the premium standards a well has to earn a minimum of 30% direct after tax rate returns at $40 oil. The process at first refining premium and second identifying the inventory will ensure that during 2016 year 2 we did not spend a single dollar during the un-economic wells. We did anticipate about the new premiums standard is the fire it would light under each as a team working EOGs play across the company. Since it is all of 2016 we have converted more than 1000 additional locations to premium on our existing acreage. The Yates merger added another…

Thanks, Bill. 2016 is turning out to be a tremendous year for EOG in the Delaware Basin. Secondly highlighted in a couple of ways. First, our Permian teams progress delivering increased well performance and cost reduction has been outstanding. As illustrated on Slide 11, EOG continues to deliver exceptional industry leading well productivity. This outperformance was accomplished in multiple ways which I will discuss in more detail in a moment. Second, with the combination of technology gains, cost reduction and the Yates transaction we increased the Delaware Basin's resource by 155% bringing the new total to a massive $6 billion barrels of oil equivalent from 6300 net drilling locations. The increase is 3.7 billion barrels of oil equivalent larger than our total announced just one year ago on the third quarter call. Now that the resource potential has been further defined, our efforts will focus on converting the identified locations to premium, approximately 55% of the 6300 locations are currently premium and we are confident that the majority of the non-premium locations will be converted overtime. There are two ways to convert the inventory. One is by increasing oil productivity through technology since it is our precision targeting process and improved completion techniques. Two is through lowering costs, both capital costs as well as operating expenses. It is like the Eagle Ford, we are confident that our premium inventory in the Delaware Basin will continue to increase overtime. As we have discussed in the past the Delaware Basin was a large very complex geological basin. Our first step entering any play is to focus our exploration team on understanding the details of the rock characteristics. And then acquire our acreage position in areas that exhibit high quality rock potential. Majority of the acreage required in the Yates transaction demonstrates strong…

Thanks, Billy. In Eagle Ford we continue to make tremendous progress in costs. In the third quarter we drilled and completed 47 wells or remarkable $4.6 million per well. Well costs are being driven lower for all he reasons we mentioned in our last call. More efficient rate of operations are driving drilling days down to less than 6 days a well. Completions are also getting more efficient. In 2014 we were 600 feet of lateral per day. During this downturn, we have taken a harder look at completion operations and logistics and are now completing wells 66% faster at almost a 1000 feet per day. At the same time we continue to enhance the effectiveness of our completion as shown on Slide 28. Additionally Eagle Ford well performance continues to grow even as we push well closer together. During the third quarter we completed a set of 5 interim wells down spaced to 200 feet that were some of our best performing wells for the quarter. Core unit 10H through 14H averaged over 2000 barrels of oil per day per well for the first 30 days of production. We have been drilling the Eagle Ford for seven years and we still have so much to learn in this world class pay. Also in the Eagle Ford our enhanced oil coverage or EOR is progressing on schedule. We completed on schedule the initial phase of the 32 well pilot, our largest to date. We look forward to having results with you sometime in 2017. In the Rockies we continue to get excellent results from the firm sand in the bottom of the Basin. Our drilling program there is delivering consistent premium level returns and we are looking forward to expanding actively there next year. The 9 wells we drilled in…

Thanks, David. EOGs operational performance in 2016 in terms of cost and efficiency gains has been one of the best in company history. In addition to making huge improvements in well productivity, we have driven so much cost and time out of our operations that we significantly increase the number of wells we are drilling into completing. EOG will now drill approximately 90 more wells and complete 80 more wells than were originally forecast for 2016. While only increasing our development capital by $200 million. As a result our fourth quarter domestic oil production before the addition of the Yates is forecast to be 36,000 barrels of oil per day above our forecast at the start of the year. That's an amazing accomplishment and the testament is the tremendous capital efficiency gains we have made this year. When we had Yates in international volume we expect the EOGs all exit rates will be near the company's all time high set in the fourth quarter of 2014. Now let's talk about cost reduction and efficiency gains. In 2014 EOGs drilling days and total well cost in our large, 80 Bakken [ph], in working place are down 25% to 45%. Another measure of a drilling efficiency is number of wells drilled per rig per year which increased 40% in our top three place. For example, we are drilling 32 wells per rig year. On operating side we reduced cash in cost 29% and 2016 LOE alone has come down almost a $0.5 billion compared to 2014. While the major driver of cost reduction has been efficiency gains we are also benefitting from approximately half of our high-cost drilling and completion contract being replaced by rates that are 40% lower. In addition, tubular and well head cost will come down 25% with our…

Thanks Gary, Capitalized interest for 2016 was $8 million. Exploration and development expenditures were $660 million excluding property acquisitions which was 32% less as compared to third quarter 2015 while our production volumes decreased by just 3%. In addition expenditures for gathering systems, processing plants and other property, plant and equipment were $16 million. We are increasing full year capital expenditure guidance from $2.6 million to $2.8 million. At the end of September, 2016 total debt outstanding was $7 billion and the debt to total capitalization ratio was 37%. At September 30 we had more than $1 billion of cash at hand leaving us non-GAAP net debt of $5.9 billion or net debt to total cap ratio of 33%. Year-to-date we have sold assets generating approximately $625 million of proceeds and associated production of 80 million cubic feet per day of natural gas. 3400 barrels of oil a day and 4290 barrels per day of NGLs. Assets sold include midland basin, Colorado DJ Basin and Hanesfield properties. The effective tax-rate for the third quarter was 30% and the deferred tax-ratio was 132%. Now I will turn it back over to Bill.

Thanks, Tim. Our micro view has not changed. Over the long-term we believe oil in the 40s will not sustain enough production to meet demand worldwide. While EOG can deliver strong oil growth within cash flow with $50 oil, we believe that US industry as a whole needs to sustain $60 oil prices and extended lead time to provide a moderate level of growth. Worldwide Base decline rates are slowly reducing supply and consensus view is the current large inventory overhang could return to normal levels by late 2017. We plan to issue official guidance in 2017 along with our year end results early next year. Our overarching goal in 2017 is to build momentum of the foundation of premium inventory EOG has established in 2016 as Gary explained we are completing 180 more wells than previously forecasted so we are exiting 2016 with strong oil production and we will complete a higher percentage of premium wells in 2017 versus 2016. After two years of this down cycle we are more than ready to resume high return oil growth. EOGs vision for 2017 to 2020 can be summed up with four goals; be the leader and return on capital employed. Be the US leader in oil growth, be one of the lowest cost producers in global oil market and remain committed to safety and the environment. EOGs long-term forecast has not wavered during the downturn. Our purpose is to create significant long-term shareholder value. And as we enter our recovery our unique and resilient culture has positioned the company to achieve strong results for years to come. Thank you for listening. Now we will go to Q&A.

Thank you. The question and answer session will be conducted electronically. [Operator Instructions] We'll take our first question from Scott Reynolds from RBC Capital Markets.

Good morning.

Good morning.

Impressive job this quarter and congratulations on the increased outlook. If you step back and look at the big opportunity, we all have the premium that you described. Can you give us a sense on generally how are you looking at developing that, in terms of what formations may be high on the top of the list over the next couple of years. And how do you see pad development going forward in that play.

Yes, Scott, the is Lloyd W. Helms. So on the Delaware we do expect with this increase there our activity over time will continue to increase. Especially going into next year. And our actively today has been focused largely on the Wolfcamp, I think that will stay of the majority the focus will stay on the Wolfcamp. Just to reiterate all three plays are considered premium today and we're excited about the potential. We're further along in our development at the Wolfcamp. And so, for that reason will continue that it’s next an excellent volume growth generator, extremely high rate return play. And what really need first, it also allows us to take a look at, this shallower objectives as we drove around through those, that gives us a better idea of long-term potential and how the drilling program in those place will develop. And in the future. In the second part your question there about pad, drilling, we are continuing to develop pads that are drilling, as we develop the field now. And that will continue as we add the shallower zones as well. The good thing about that is we putt in the infrastructure once, for all those wells to share, in the future. So I incrementally - of return for those programs in the future will continue to increase. As we share that infrastructure, that's no doubt for the initial completions.

Great, that's good and then in my follow up. This quarter you guys are now producing more oil than - it's over 50% which was a - it was a pretty good heavy lifting here over the last few years to get there. And when you look at your long-range outlook, could you give us a sense of how some of the resource pieces contribute to that, so specifically what is the premium producing today with EOGs [ph] for producing today and in your long range outlook, where did those plays go.

Scott, we never broke it out but - And so I think really what I think about the company is that we have a very strong diversified portfolio. And from year-to-year from actually maybe even quarter-to-quarter we shift our capital to where were we are ceding the highest rate returns. And I think changed over time. As Billy said, obviously the Delaware is giving that bigger and better for us, so it will get more capital next year than it got this year. And the EOG - will still get a lot of - lot of capital, in the Rockies play, particular the Powder River Basin will get a lot of capital. But I think, you need to be thinking of my view, very balanced, very large and very diversified portfolio.

Thank you.

We'll take our next question from Subash Chandra with Guggenheim.

Hi, good morning. First question is, when I think about the number of locations in the Wolfcamp. Is it two zones, that you're thinking about, in each of the oil and combo plays? And what the status of the lower Wolfcamp if you had any results there.

Yes Subash, this is Billy Helms again, So when the Wolfcamp we generally think about yes two, mainly two, we have two zones, the upper middle is what we assess resource potential too. But within each one, there are multiple target intervals. So you can think about is having multiple targets with each play and we assess the potential mainly and in areas where we tested each one, and we've based that on our confirm test, comparing results of each one. That's how we've kind of rolled up the resource potential there. I'm sorry. What was second part of your question? Yes, the lower Wolfcamp. So you have a lower Wolfcamp we have had some test, I'd say the majority of our test so far have been in the upper part of the zone. But we have said some testing what we call the middle of camp. And those results are encouraging as well.

Okay. So if I hear you correctly, it's a very highly risk [ph] measure your locations that you published to-date but if I just did not resource map across multiple levels I can get many more locations and what you publish.

Yes, I think the way you think about that is; our results are based on our confirm test, in each one of the intervals and then we allocate that to sticks on the map kind of the approach, where we - is not just taking them - not total number breakers and dividing it by well spaces, it's actually geologically looking at where those perspectives intervals are exists, we mapped them out, pretty extensively and then place well locations on the spot to assess the potential. So, but you're right it only goes to the zones we tested and we do collect additional intervals to test going forward.

Thank you.

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

Thank you, good morning everybody. But I wonder if I could as you about the 22 well on Delaware this quarter. There is still the shorter wells but with well rates appear to still be - maybe I'm getting this wrong but it was but there still substantially better, than you can go longer lateral implied type. Can you help me understand what the implications are, the run rate that been on those recent locations [ph].

Yes, this is Billy Helms, we are excited about the potential that we're seeing in these - in these zones more recently in there. We along the laterals are giving us a lot more efficiently, lot more reserved per well, higher production rates. And our EUR assessment for the play, though is taking what we've tested across the play. And some of those tests are a little older, so we're trying to cooperate all the test we have. And all of the wells are not benefiting from the latest results, so and - so our results continue to improve and we assess that as time goes forward, and I think the tremendous thing that we are seeing it's just the benefits from our targeting and how that's really enhancing the productivity, and that really comes from our detailed working in continual work on assessing that geological potential to play. And so, that's why we're confident, that as we continue to improve that technique, and gain more understanding that we're going to see additional intervals [ph]. That will add to the resource over time. So we fully expected the resource in the play will continue to increase.

Thanks, Billy. [Indiscernible] Wolfcamp oil at 1.3 million. It was quite a while you completed in the third quarter.

No, that's exactly what I - and the wells were completed in the third quarter are including and actually year-to-date the results are still stronger than what our resource update is. So again, I think it's a testament to the technology and the things we're continued to expand on and learn. So yes, I think there is additional upside potential there.

Yes, if I could add a little more color there. This is bill Thomas. The water [ph] quality drive the productivity all the plays and so, we're getting better and better at identifying them the better quality lock [ph] in each one these plays and they were giving considerably better at locating the lateral with a precision targeting in keeping the lateral in that good rock, for long period long part of the lateral, so there is a process for learning. We probably learn more about rock quality and targeting, and execution on that part of the process in the last year, so that we've ever wanted. So there's a lot of upsides as Billy, said and talked about which he does a lot of upside left to go in that process.

My follow up is quicker; it is kind of related question. If you can achieve 15% to 25%, $50 to $60 oil. If these wells continue to get better, would you choose to raise the growth rate again or do more with less? I'm thinking about constraints on the infrastructure on things about nature [ph]. Thank you.

Well, there is a limit on how fast we want to go, in each one these plays. Because you don't want to go faster than a learning curve and certainly you do have to stay ahead of the infrastructure process. And we don't want to use less than the capital efficiency, we like to continue to increase the capital efficiency as we go along. But we're going to be very disciplined and are spending approach. And the rates-to-return just to say a bit about that the rate-to-return that we're getting on the premium, is that the minimum return, that means the lowest return well, in the 6,000 well inventory generates a 30% rate of return. At $40 in 2015 flat gas prices. So the returns on the average well is much, much higher than 30% of these are exceptionally strong well.

Thanks for the clarification, Billy, appreciate it.

We'll take our next question from Evan Calio with Morgan Stanley.

Good morning guys, and impressive results again. Bill my first question is you got about $2 billion resource and indicated that's likely to rise over time. That is the best it has been in 40 years. So you're clearly not resource constraints, so how do you think about potential asset sales given acreage prices and given it appears like lots of BMPs [ph] are reaching a similarly conclusion at a similar time, and it's first mover advantage, what would your thoughts there.

Evan, as we continue to generate more potential. And we continue to high grade that, if those give us a lot more opportunity for just high grading our asset portfolio good property sale. So we're going to continue that process, evaluating each asset - and fits into the future of the company. And on core assets, that are the ones that don't reach the premium category, it'll certainly be candidates for our asset sales in the future. And that will help keep balance sheet strong, and we want to operate from our spending stand point we want to operate within cash flow. But the property sale proceeds will continue to help us keep our balance sheet strong. And by increasing the quality of things we drill over time, obviously increases the returns, but we are also lowering the cost which will filter back down through the base, we will hire a company and lower the drilling rate. So it's a process of just getting better in all areas through times.

Great. And my second question, it's a follow up to Doug's [ph] you introduced the high or low growth guidance here 15%, 25%. I mean the entire industry from small cap to chevrons projecting an impressive rising growth targets, in largely in Texas low prices. So I mean how do you - what do you think is the limitations of growth are made for EUG or where they are levels and how are you - what differentiated the EUG execution and how are you preparing to deliver that in execute better than the industry, thanks.

Well, I think the real advantage we have, Evan, is the rates of return that we're generating of each one of these wells, is we believe is significantly higher than industry and so that will filter down through the financials. And in due time it will show up in ROCE so our first goal as I mentioned; is to meeting the US leader in terms of [indiscernible]. And, that's a position that we historically held and I think it's a big distinguishing factor in the company.

And in your rating level, if you think about it maximum growth rate achievable within the organization outside of your sheet?

Well, I don't want to speculate on that. We want to stay efficient and we want to continue to get better so as I talked about before there we want to stay discipline and under control. And so the goal is to get better not just to get there. We're going to try to tackle at from that standpoint.

Great, thanks guys.

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

Good morning, Bill, to you and the rest you're team there. I'd like to ask a question about the estimate resources assessments the Yates of transaction, I think you get pertinent information on your slides specifically Slide 9. You have the resource per well. For the Yates acquisition around 9-20 of next year, higher than what you had to give an incumbent in your portfolio. Can you talk about what the factors - what factors that product that higher per well resource reflects and it may be is that up a piece of a bigger picture that in general the rock qualities are higher as you. As you move up into Mexico whether you get deeper higher pressure perhaps longer, lateral life that driving that.

Yes, Charles, this is Billy Helms. So when we assess most of the Yates on the average, it was generally on the basis one-mile laterals. And we sense that we come back in and assess the potential across all the plays. And as you've noticed lateral link on the most of the across the whole portfolio, has increased to about 7,000 feet per well in the old window. And even greater in the combo window. And so, I think the allowed the initial estimate you saw their Slide 9, were based on our assessment only made the transaction. And per Yates and those were based on the essentially one mile a well. So that's the - that's the majority of the difference.

Okay, thanks.

But as we move into this, the one thing that the Yates does allow us to do is to block it out with our existing acres. So we fully expect to be able to drill these longer laterals across all the portfolio.

Got it thank you and then, Bill I thought I could ask a question about the 15%, 25 % that you put out you touched on this I believe on the last conference call about how that - how that trajectory might shift or evolve over the 2017 to 2020 framework. Do you see that whether we're talking about that $50 low end or the $60 high end? Do you see that being back end weighted or you have a growth accelerating to that two-year timeframe, or it more likely the front end weighted.

Charles, as you look at the slides, in the front part of the slide deck it shows in 2017 the growth rate is smaller, and it grows over time. So in 2017 it's less than 15% at $50, and into 2020 it's probably more than 15% at $50, it's a more back end weighted.

Got it, that's detailed look, thank you, Bill.

Our next question will come from Pearce Hammond with Simmons Piper Jaffray.

Good morning and thanks to the helpful color in the release on the Delaware base. My first question Bill is on our rigs and what the rig count could look like based upon this long-term production oil production growth plan. Kind of where are you right now on rig count and I know you haven't given seventeen guidance but looking at this long-term oil production growth plan, where do you see rigs reversing to, any color you can provide on that would be helpful.

This is Gary Thomas. Right now we have 15 rigs operating domestic, we got one international that being in traded at. And we as you say we have disclosed what we had planned for 2017. However, just with the rig efficiency that we've seen over the last two years and what the type rigs we have in place. We will not be required to ramp up the number rigs very much for both standing plan that we put in place. Just have a tremendous amount of flexibility. The one thing that we've 2016 most of our rigs were under long-term contracts high rates, as we mentioned Yates will have only about half that number for 2017, that we have put in place right that about 40% lower for especially the same number rigs.

Great. Within those 15 great, how are those broken out right now?

Right now, we've got five in Midland that's really what we very average this year and that is that Delaware Basin, we have six now in San Antonio. So we have four in rocking mountains because we have one rig that was required on the Yates position in the Powder River Basin. And we will let it go but as we've mentioned earlier, we're going to be taken up an additional rig for the Delaware basin year end. And also for San Antonio for the Eagle.

Great. As of my follow up, after pertains to sand loading. In just curious in the Delaware basin specifically, where you on sand loadings right now, you have you reached a point of diminishing returns on sand loading or we not there yet.

This is Gary Thomas. We're still experimenting near the Delaware basin, I might just take you back to the Eagle Ford operated for so many years. We found the point of diminishing returns as a matter fact here sand loading for 2016 on the average is slightly less than what it was in 2015. So we got a pretty good hand as to what we anticipate has an optimum sand loading rate there for the Delaware basin.

Can you share with that is that like an Eagle Ford, on a pallet per foot basis?

This is Billy Helms. Just to add a little more color on that. It will vary in each area and we've tested as much is maybe 3,000 pounds per foot which is probably not going to be applicable across all the plays, in every area, is probably an average somewhere between 2,000 to 2800 probably in that range. Down the zone and where it is but it's it'll be a broad range depending on that play and where it is in that play.

Thank you very much.

Well, that's what we're in the process of trying as Gary, mentioned.

Thank you.

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

Thank you, good morning.

Good morning, Brian.

First couple questions on the Eagle Ford, can you add more color on the stacked - staggered spacing test put 200 foot spacing into context in terms of how widespread that that may be applicable, and then the total locations per unit that would represent. And how do you view well economics and you are as a given that you pin that applying some enhanced targeting and completion over a more for more than a year.

Brian, this is David Trice. On the stack stagger targeting and the spacing we've had - we've been working on that for well over a year, and we're seeing good results on that and as we noted there on the quarter, we're not seeing any degradation the areas that we're doing that. So it's not applicable over the entire position. Some places we do have a too good targets in the lower Eagle Ford. And so, we were certainly doing that there but I think over time will continue to just seeing that improves the targets in a little bit better. And we work on the on the compilations. But again, it's not applicable on all areas, because some areas are - have little just one target, so it really throughout the play we're looking at anywhere from a 200 foot spacing 3 or 350 depending on the area.

Got it, thanks. And then shifting over that Poweder River Basin which that seems like your employing similar strategy here as with that - you are in the premium can you talk to the potential cost savings for BOE from deploying longer laterals in the PRB. And then what type of activity do you think we can see and how prospective, do you view opportunities beyond the turners sand.

This is David, again. In the Powder River, we're still really early endings there, we've been testing very stones that were we've been focused mainly on the Turner lately, but we do see a lot of upside as far as extending these laterals like we mentioned earlier that we're seeing a big up lift on the economics, and about our rivers as we do in other places. So we do think going forward, is going to be a bigger part of the program.

Got it, thanks, and just in area that you mentioned exploratory the potential for further exploration and this may not count as exploration because you already have some premium locations built, but how does the Powder fall in, in terms of incremental opportunities for EOG on the trajectory.

Well again, I think the area where we have stacked by nearly got 4,000 to 5,000 feet of potential there is similar to the Delaware Basin. But like I mentioned we are we are early we are still testing a lot of targets. And we did have a substantial acreage position there. We got 200,000 net acres really in core of the play. But really across the basin we've got to kind of more than exploration we have got more like 4,000 acres. So again not that big thing that there's potential for progression additional activity here in the Poweder [ph].

Thank you.

We'll take our next question from Ryan Todd with Deutsche Bank.

Thanks, and good morning. A longer term strategic question for you guys, how do you - how do you think about the potential to generate free cash flow prior to the collapsing crude we seen you reach a point where all you cash return for shareholders became slightly more meaningful component of shareholder return as reflected by some pretty substantial increases to the dividend. When you look out over the next few years. Do you vision dividend growth becoming more meaningful again are the outlook for growth change enough that we should expect all incremental cash flow going to drilling for the foreseeable future.

Ryan, the dividend certainly very important to us. And as the business environment improves, and process improves we'll start considering increasing the dividend again, and then certainly generating free cash flow as we go. I think we want to begin to do, we generate just a slight amount in the fourth quarter. So that's a goal that we want to continue to focus on as we go forward. So free cash flow and dividend growth will be a part of game plan. As the business environment improves.

Okay. Thank you. Then maybe one just as we think about the infrastructure, I know you talked about a little bit, any constraints in the permanent infrastructure side. In terms of kind of [indiscernible] through what we should expect to spend on like its 15% of the capital budget a reasonable amount or anything the ballpark how much what your needs are going to be as you ramp over the next three or four years.

Ryan, this is Gary Thomas. Just to address you on the infrastructure spending for next year, it will be a very similar to what we've had the last several years. We want to stay up a little bit a head and they'll be in that 18% to 20% of our capital. Will let - address our position on infrastructure there

Yes, Hi Ryan, good morning. The thing is we have done a great job on gas take away and when you think about the expenses gas gathering and we're going to have multiple market connections in the area, so we plan on exiting this year with over $300 million today of strong, so when we think about that coupled with our NGL transportation of vaccination capacity, we really don't see any constraints on the gas at all. And then also maybe just to add on oil too, we're actually finalizing agreements renewable terminal that's going to be all the - service and late 2017. The work that will have all the market diversification whether that's the Gulf coast - and also just continuing to align ourselves with our strategic providing partner. So, we wouldn't be more excited about the development, to say nothing have occurred.

Okay, thanks.

And that does conclude our Q&A session, I would now like to turn the call back over to Mister Thomas for any additional or closing remark.

In closing, I want to say thank you to all the tremendous EOG employees were making the record setting accomplishments went down this year of reality. Everyone listening, do you not think EOG is maxed out, we are willing to improve, and we've seen modeled on the trade opportunities ahead of us and we look forward to 2017 and beyond. So thank you for listening and thank you for your support.

This does conclude today's conference call, thank you all for your participation you may now disconnect.