Tim Driggers - Chief Financial Officer Bill Thomas - Chairman and CEO Billy Helms - Executive VP, Exploration and Production David Trice - Executive VP, Exploration and Production Gary Thomas - Chief Operating Officer Cedric Burgher - Senior VP, Investor and Public Relations Lance Terveen - Vice President, Marketing Operations.

Paul Sankey - Wolfe Research Phillip Jungwirth - BMO Charles Meade - Johnson Rice Leo Mariani - RBC Capital Markets Pearce Hammond - Simmons and Company Joe Allman - JP Morgan Bob Brackett - Bernstein Research Brian Singer - Goldman Sachs.

Please standby. Good day and welcome to the EOG Resources’ Fourth Quarter and Full Year 2014 Earnings Results Conference Call. At this time for opening remarks and introductions, I would like to turn the call over to Chief Financial Officer of EOG Resources, Tim Driggers. Please go ahead, sir..

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 2014 earnings and operational results. This conference call includes forward-looking statements.

The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures.

The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves, but also probable reserves, as well as possible reserves.

Some of the reserve estimates on this conference call and webcast may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's reserve reporting guidelines. We incorporate by reference the cautionary note to U.S.

investors that appears at the bottom of our press release and Investor Relations page of our website.

Participating on the call this morning are, Bill Thomas, Chairman and CEO; Gary Thomas, Chief Operating Officer; Billy Helms, EVP, Exploration and Production; David Trice, EVP, Exploration and Production; Lance Terveen, VP, Marketing; 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 first quarter and full year 2015 in yesterday's press release. This morning we will discuss topics in the following order.

Bill Thomas will review 2014 highlights and our 2015 capital plan, David Trice and Billy Helms will review operational results and year-end reserve replacement data. Then I’ll discuss EOG's financials, capital structure and hedge position, and Bill will provide concluding remarks. Now here is Bill Thomas..

Thank you, Tim. 2014 was another record year for EOG. Our results continue to demonstrate our return-focused capital discipline and EOG’s superior ability to apply technology to the exploration and development of [tight] plays. Here are the highlights. Number one, EOG demonstrated its capital efficiency by earnings peer leading returns.

ROE for 2014 was 16% and ROCE was 14%. For the year we increased crude oil production by 31% driven by our top three oil plays, the Eagle Ford, Bakken and Delaware Basin. NGL production increased 23% and natural gas production held flat, yielding total company production growth of 17%.

We announced five new plays, four in the Rockies, DJ and Powder River Basins, and the Second Bone Spring Sand play on the Delaware basin side of the Permian. These plays add flexibility to our portfolio of options to grow production in the coming years. Also in the Delaware Basin we identified an oil window in our existing Wolfcamp acreage.

Early in 2014, we increased the reserve potential in the Eagle Ford to 1 billion barrels of oil equivalent to 3.2 billion barrels of oil equivalent net to EOG. Between that Eagle Ford reserve increase and the new Rockies play alone, we added 1.4 billion barrels of potential reserves to our portfolio and 2300 high return net drilling locations.

In recent years, we have consistently added twice as many locations as we drilled. Finally EOG remained laser focused on cost by driving down per well expenses in all of our major plays while simultaneously driving up well productivity. Before I move on to 2015 I would like to expand on that last highlight.

We have demonstrated a unique ability to get the most out of tight oil plays from both a cost and well productivity standpoint. Over the last 10 years, we have developed expertise over all the disciplines required to drill in shale and other tight rocks and make that drilling highly economical.

This proven ability is why we posted strong returns in 2014, and why we are so well positioned to not only weather the current low price environment, but to take advantage of it. So now let us talk about EOG’s goals for 2015. First, our overarching goal this year is to prepare for oil price recovery.

It is clear that current prices are too low to meet the world’s supply needs and the market will rebalance. We would be ready to respond swiftly when oil prices improve and resume our leadership and high return oil growth.

Second, we do not believe that growing oil in what could turn out to be a short cycle low price environment is the right thing to do. And let me repeat, we do not believe that growing oil in what could turn out to be a short cycle low price environment is the right thing to do.

We remain committed to maintaining a strong balance sheet at today’s scrip prices. 2015 cash flows should fund our CapEx budget of approximately $5 billion. Third, returns are what matter. Therefore we will focus capital on the Eagle Ford, Bakken and Delaware Basin plays.

At $55 oil, these premier assets deliver a direct after-tax rate of return greater than 35% without factoring in the potential for additional service cost reductions. I will now explain in further detail how we plan to prepare for the oil price recovery.

First, we will reduce average rigs 50% down to 27% for 2015 and intentionally delay any of our completions, building a significant inventory of approximately 350 uncompleted wells. This allows EOG to use rigs under existing commitments and when prices improve we will be poised to ramp up completions.

Oil price improvement of even a few dollars generates incremental MPV. So delaying completions and wait for improved prices as evidenced by the forward curve will add significant value. Please see Slide 8 of our investor presentation for a play specific example.

Second, we remain focused on driving down finding costs and improving per well production rates. This is our best hedge against low oil prices. For example, as a result of cost and oil productivity improvements in the Eagle Ford Western acreage, we can now generate better returns with $65 oil than we did with $95 oil just two or three years ago.

We illustrate this on Slide 11 of the investor presentation. Due to low oil prices we have already seen service cost reductions in many areas and see the potential for 10% to 30% vendor savings during this downturn. Additionally, every one of our plays has room to reduce cost further through ongoing efficiency gains.

We believe our integrated approach to completion technology is industry leading. Quarter after quarter we make improvements to well productivity and that will continue to be a high priority this year for EOG. Third, low oil prices mean unique opportunities to add low-cost, high-quality acreage.

We will continue to grow our acreage portfolio through leasehold, farm-in or tactical acquisitions. We view our strong balance sheet and excess liquidity as a strategic asset for opportunities in times like these.

We are already benefiting from the oil down cycle, adding new leases at lower cost than last year and we are optimistic that additional opportunities will become available.

Finally in my 36 years with the company I have seen many downturns, and each time EOG stays disciplined, performs well and emerges on the other side in better shape than we entered it. in 2015, EOG plans to build a stronger position and be ready to resume long-term, high return production growth when prices improve. I will now address the Eagle Ford.

David Trice will discuss the Permian Basin and Billy Helms will provide an update on the Bakken and Rockies plays along with a review of our year-end reserves. 2014 was another remarkable year in Eagle Ford. Oil production from the play increased 45% and EOG achieved several key milestones.

Number one, down spacing and improved completion techniques enabled us to increase our total potential reserve estimate in 2014 by 1 billion barrels of oil equivalent to 3.2 billion barrels equivalent net to EOG. We continue to advance our technical expertise as evidenced by ongoing improvements in productivity across the field.

Slide 17 in our updated investor presentation shows an 8% increase in productivity for wells completed in 2014 versus 2013. We continue our progress with high density completions across the entire play. A high density completion is simply various techniques used to maximize the amount of rock connected to the well bore.

Due to geologies those techniques will change from one county to the next and we are making progress determining how to tweak those techniques across our acreage. Number four, after five years in the Eagle Ford we are still making drilling time and cost improvements. Please see Slide 18 in the investor presentation.

And number five, at the end of 2014 our acreage in the Eagle Ford was over 80% held by production. We had a number of lease retention commitments in our Western acreage that we successfully fulfilled in 2014, bringing up drilling flexibility going forward.

Eagle Ford activity in 2015 will continue to be balanced between the West and East sides of the field. As I mentioned we are intentionally delaying completions while we wait for improved [oil prices]. Thus our inventory of uncompleted well is expected to increase.

This strategy allows us to maximize the value of our existing contractual commitments while waiting on improved pricing before we bring on newly completed wells with high oil production rates. Delaying completions will also provide an opportunity to take advantage of lower service costs that will likely materialize in the coming months.

The Eagle Ford remains EOG’s premier play. We have about 5500 net oils to drill on our acreage, and over 10 years of inventory. The Eagle Ford represents a huge call option on oil that EOG can exercise at any time to take advantage of a favorable oil price environment. We often refer to the Eagle Ford as our technology laboratory.

Our understanding of this field and how to increase its recovery rate has led to improvements in plays across the entire company. The first to benefit from this technology transfer was the Bakken beginning in late 2012, and now the Permian Basin is experiencing the latest step change in our application of technology.

I will now turn it over to David Trice to discuss activities in the Permian..

Thanks, Bill. In 2015 EOG’s capital budget in the Permian will expand to take advantage of new Delaware Basin targets, advancements in well performance and cost reductions achieved in 2014.

If you will recall, last year we shifted capital from the Midland Basin to the Delaware Basin, which allowed us to advance our technical understanding of the Delaware. In 2015, we will have fewer drilling commitments to hold acreage in the Midland Basin, which frees up capital and provides more flexibility.

Let us quickly review the 2014 achievements that set this play up to be major contributor to EOG’s returns and long-term growth. First we made significant advancements in our most mature oil play in the Delaware Basin, the Leonard Shale, by increasing oil productivity 17%.

In 2015 we will continue to push wells closer together, developing and further testing down to 300 feet. We are encouraged with the initial results and expect to see further advancements throughout the year. Second, in our Delaware Basin Wolfcamp play we made great progress in 2014 as the play moved into development mode.

We greatly increased well productivity as evidenced by the three wells we highlight in our press release. At $7 million completed well cost, the Wolfcamp play delivers very strong returns. Also in the Wolfcamp during 2014 we identified and delineated 90,000 new acres in the oil window.

Third, we tested and improved the second Bone Spring Sand to be another high return oil direct in our Delaware Basin acreage. Initial results were promising, and we did extensive G&G work to delineate this play. The second Bone Spring Sand produced 70% oil in our Red Hills acreage in Mexico, and promises returns on par with our premier oil plays.

We will move the second Bone Spring Sand into development mode this year and it will receive the largest relative increase in capital. In summary, the Leonard Shale is in full development mode and continues to deliver impressive results.

The Delaware Basin Wolfcamp finished its first year of development drilling, the wells are outstanding and the costs are dropping and we are excited to have the second Bone Spring Sand to the drilling program and bring it forward into full development mode.

We are confident that we will see the same progress in the second Bone Spring Sand that we have seen from the Leonard Shale over the last two years.

While the Delaware Basin is still in the early innings of its exploration and development, the returns we are already generating from multiple targets to make it very competitive with Eagle Ford and the Bakken. Billy Helms will now discuss the Bakken, the Rockies and year-end reserves..

Thanks David. 2014 was a successful year for the Bakken program. We began down spacing, testing various spacing patterns and continued experimenting with completion techniques to improve the performance of the field. Here are some of the highlights for 2014 activity.

First we made significant advancements in improving drilling times and reducing well cost. A typical 10,000 foot lateral is now drilled in just over 10 days with a completed well cost of $9.3 million. This represents a cost reduction of 11% from 2013, and we expect more efficiency gains and service cost reductions in the current environment.

Second, we now have production data from each of the various spacing patterns and began to determine the optimal development plan. We have tested wells at 1300 foot, 700 foot and 500 foot spacing patterns and have just started producing oils in the 300 foot spacing pattern.

Similar to the Eagle Ford, we expect that the spacing will vary depending on the specific rock characteristics in each area of the field. One of our latest test is a 6 well pattern with wells spaced 700 feet apart in the Bakken core.

The initial production rates of these wells range from 1000 barrels of oil per day to 1900 barrels of oil per day and represent a customized completion design tailored for the rock properties in this particular area of the field.

Third, we are confident that there is a significant amount of remaining potential in the Bakken, and that down spacing will be highly economic. As I mentioned earlier, evaluating the production from each spacing pattern will lead us to the appropriate spacing and the ultimate reserve potential.

While the Bakken will receive less capital in 2015 it remains a core, high return asset in our drilling program. A typical 10,000 foot lateral in the Bakken core generates greater than 35% after tax rate of return with a $55 flat oil price. In addition, maintaining activity allows us to retain momentum on operational efficiencies.

For example, we recently drilled an 18,600 foot well to total depth in just over seven days. We continue to believe that EOG has the premier acreage position in the play with many years of development drilling remaining and the potential for long-term production growth. In the DJ Basin EOG made significant progress in both the Codell and Niobrara.

We’ve been experimenting with web or targeting inter well spacing and modifications to the completion design for both intervals. For the Codell, we’ve identified a specific statrographic interval within the pay section that when targeted rightly enhances the performances of the well.

The improved completion techniques we used are even more effective when we focus o this target. Please see our press release for notable well results. Back to Codell we’ve tested several targets within the Niobrara.

With this additional testing we’ve determined a correlation between the amount of lateral focused within a specific target interval and the protection performance of the well. In 2014, we made progress in several areas that contributed to reaching our well and operating cost wells in the DJ Basin.

These include drilling and completion efficiencies and oil and gas gathering system and water gathering and distribution system and the infrastructure needed to obtain EOG self-source sand.

Our activity in the 2015 in the DJ Basin will be limited, drilling wells needed to maintain leasehold and finishing completion operations on a few remaining wells drilled last year. The Powder River Basin is stack pay system we’ve drilled primarily in apartment and tunnel oil reservoirs similar to other areas within EOG’s portfolio.

In 2014, we focused on well targeting and completion designs and inter well spacing to determine the optimal development plan. We made significant improvements in all aspects during 2014. Please see our press release for some excellent fourth quarter well results in both department and internal place.

We plan to have limited activity in the Powder River Basin in 2015 while we wait for commodity prices to improve. I’ll now address reserve replacements and planning cost. Excluding revisions due to commodity price changes, we replaced 249% of our 2014 production at a low planning cost of $13.25 per Boe.

Proved reserves increased 18% and more than half of our reserve growth was driven by proved. In addition net proved developed reserves increased 20%. For the 27 consecutive year, the DeGolyer and MacNaughton did an independent engineering analysis of our reserves. And their estimate was within 5% of our internal estimate.

Their analysis covered about 76% of our proved reserves this year. Please see the schedules accompanying the earnings press release for the calculation of reserve replacements and finding cost. I’ll now turn it over to Tim Driggers to discuss financials and capital structure..

Thanks Billy. Let me start by addressing an unusual item affecting the fourth quarter. In early December we announced the sale of most of our producing assets in Canada, the proceeds of approximately of $400 million.

As a result volumes were lower than our previous guidance for the fourth quarter by approximately 2,300 barrels of oil per day and 15 million cubic feet per day of natural gas. Also G&A for the quarter was higher due to $21.5 million of exit costs related to the sale.

Now, I’d like to make a few comments about our capital spending last year and in the fourth quarter. Capitalized interest for the quarter was $14.5 million, for the fourth quarter 2014, total expirations and development expenditures were $1.8 billion excluding acquisitions and asset retirement obligations.

In addition, expenditures for gathering systems, processing plans and other property plant and equipment were $140 million. There were $66 million of acquisitions during the quarter. For the full year 2014, capitalized interest was $57.2 million.

Total expiration and development expenditures were $7.6 billion excluding acquisitions and asset retirement obligations. In addition expenditures for gathering systems, processing plans and other property plant and equipment were $727 million.

For the full year capital expenditures excluding acquisitions and asset retirement obligations were $8.3 billion. Total cash flow from operations was $8.6 billion exceeding total cash expenditures. In addition proceeds from asset sales were $569 million. Total acquisitions for the year were $139 million.

At year-end total debt outstanding was $5.9 million for debt to total capitalization ratio of 25%. Taking into $2.1 billion of cash on hand at year-end, net debt to total cap was 18%, down from 23% at year end 2013.

In the fourth quarter of 2014, total impairments were $536 million, $445 million of these impairments were the result of significant declines in commodity prices during the fourth quarter.

For the full year 2014, total impairments were $744 million, $501 million of these impairments result the declines in commodity prices and negotiated sales prices of property sales. The remaining impairments for both the fourth quarter and full year 2014 were ongoing lease and producing property impairments.

The effective tax rate for the fourth quarter was 61% and the deferred tax ratio was 104%. Yesterday we included a guidance table with our earnings press release for the first quarter and full year 2015. Our 2015 CapEx estimate is $4.9 billion to $5.1 billion excluding acquisitions.

The expiration and development portion excluding facilities will account for approximately 80% of the total CapEx budget. 2015 CapEx represents a 40% decrease from 2014. As Bill mentioned earlier, we’re not interested in growing oil production in a low price environment.

The budget for expiration and development facilities accounts for approximately 12% of the total CapEx budget for 2015 and midstream accounts for 8%, we plan to concentrate our spending on infrastructure in the Eagle Ford and Delaware Basin to support our drilling programs in those areas and enhance operating efficiencies.

In terms of hedges, for February 1 thru June 30, 2015 we’ve 47,000 barrels of oil per day hedged at $91.22 per barrel. For the second half of 2015, we’ve 10,000 barrels of oil per day hedged at $89.98 per barrel.

This represents a small portion of our estimated oil production in 2015 and we’ll look to hedge further volumes opportunistically throughout the year. We’ve contracts outstanding for 37,000 barrels of oil per day that could be put to us at various terms. Please see the press release for further details.

For natural gas, we’ve 182,000 MMBtu per day hedged at $4.51 per MMBtu for March 1 thru December 31, 2015. We also have a number of contracts on natural gas that could be put to us at various terms.

The counter parties exercised also its options, the notion of volume of EOG’s existing natural gas derivative contracts were increased by 175,000 MMBtu per day at an average price of $4.51 per MMBtu for each month during the period March 1 thru December 31, 2015. Now, I’ll turn it back over to Bill..

Thanks Tim. Now, I’ll talk about the macro view. We’re encouraged that Congress is taking a look at lifting a ban on crude oil exports. Doing so will bring a lot of range of economic geopolitical benefits including strengthening the U.S. energy sector, growing the U.S. economy, creating jobs, dramatically improving the U.S.

trade deficit, providing our European allies with more secure supplies and lowering gasoline process to U.S. consumers. As I mentioned earlier EOG will be very focused this year on preparing for the recovery in oil process.

The current supply demand imbalance is not very large and current process are far short of what is necessary to sustain the supply need to meet world demand growth. When process recover, EOG will be prepared to resume strong double-digit oil growth. For now, EOG is intentionally choosing returns over growth.

In fact that's the way it’s always been here at EOG. In summary, I want to leave you with some important summary points. Year in, year out, EOG consistently approaches capital planning by focusing on returns. 2015 is no different.

Second, we’ve halted production growth deliberately while EOG is one of the few companies that can earn a healthy return at today's oil prices we are not interested in growing oil into our low price environment.

As we compare today’s oil prices to our expectations for a more balanced market, it makes economic sense to slow production until an industry wide supply response is realized and prices respond accordingly. This strategy maximizes the value of our assets and it’s the right strategy to create long term shareholder value.

Third, our balance sheet places EOG in a strong position. We intend to use our financial flexibility to take advantage of opportunities to grow our inventory by acquiring low cost, high quality acreage.

And fourth, with the substantial inventory up high volume levels to complete, we will be ready to return to double-digit oil growth as oil prices improve. And finally, we fully expect to merge the commodity price down cycle and the stronger position that we entered in.

In 2015, we have more opportunity than ever to lower finding costs and development costs and improve returns in 2016 and beyond. Thanks for listening and now we will go to Q&A..

Thank you, sir. [Operator Instructions] And we will take our first question from Doug Leggate from Bank of America Merrill Lynch. Sir, your line is open please check your mute function. And we will take our next question from Paul Sankey from Wolfe Research..

Hi, good morning everybody.

Can you hear me okay?.

Yes Paul go ahead..

Good morning. You have clearly stated guys that you are now targeting flat year-over-year crude production in 2015 and that you also stated clearly that you’re not interested in growing oil production in a low oil price environment.

I wanted to confirm that the overarching decision that you have made here is to get CapEx in line with expected cash flows and secondly by increasing efficiency allowing for lowest service cost that even if oil prices remain low for another year you would be able to deliver growth in 2016 while keeping CapEx within cash flows or if oil prices remain low which you reduce the CapEx and leave volumes flat again next year? Thanks..

Yes Paul that – the first statement is generally correct. Number one, we do not think it’s wise or prudent to accelerate oil when oil prices are low especially if the rebound and price could come certainly in the next – this year, the end of this year or maybe even next year. So, there is no use in trying to accelerate.

It makes much more prudent business decision to wait and that will give us a much more capital returns if we do that and we are very committed to maintain the very strong balance sheet, so we don't want to out-spend trying to grow oil in a low price environment.

And we want to keep our balance sheet clean and low and we want to keep our patter drop so that we will be able to take some advantage of what could be some unique opportunities in this downturn.

2016, yes if we – if things go as we think they might could and we would have say a $65 oil environment in 2016 and we believe that we could return to our very strong double-digit oil growth that we have been marching towards a last few years and that we will be able to generate very high rates of return on our capital and we would be able to stay free cash flow neutral..

And I guess, the specific part of that was that if you – another year $5 billion CapEx next year you would be able to re-accelerate growth because of the increased efficiencies and lower service cost that you will be seeing throughout this year?.

Certainly, we do think costs will come down this year due to services and again efficiency gains, we’re making really good progress in that and as we look forward to 2016 we haven't set a capital goal on that yet and we will look at that when we get there..

Okay. That's great.

Thanks and then can I just confirm you are building effectively an inventory of stuff that you can do if you want to, would that mean you are less likely to add into M&A or would you not follow that statement through?.

Well, the kind of opportunities that we are looking for is take advantage of is number one, this low cost environment. It helps us to pick up acreage that we are working on in our certainly our core areas.

We are able to pickup 11,000 acres last year in the Eagle Ford and we are targeting to pick up more there just on leasehold so that goes more easily this year.

The second is we have historically and we do think that we will have opportunities to earn acreage through farmings or drill to earn top things commitments and we will look for partners that we can join in with that will be a win-win situation and earn acreage in our core areas and maybe some emerging areas.

And then, we look for topical acquisitions that won’t be the large, large acquisitions that they will be certainly bolt on acreage and they will be opportunities that we see primarily in our top tier place..

Okay. Great. Thank you very much..

And we will take our next question from Phillip Jungwirth with BMO..

Yes, good morning.

EOG has been the cutting edge of completion technology and proven to be a premiere operator, but is there any way to quantify the operational synergy you think can be achieved during acquisition strategy in terms of MPB or how big you think it’s best to think about it and can this technology advantage be maintained in a way that's accretive through acquisitions?.

Yes Phillip, thank you for the question. I think certainly when we look at potential acquisitions, the thing we let help guide that is our expiration expertise and our understanding of the locks and so we really are only focused on that kind of opportunities where we see very sweet spot top acreage and use existing core areas or in emerging place.

And then, we certainly have a lot of expertise and we’ve been in the shale business I think longer than most people and we developed a very strong efficiencies and technology improvements and we think that we would certainly bring that to bear.

And we apply that and the upside that we see on that that we could bring the table on any kind of acquisition that we might pursue.

Also we’ve certainly our built-in cost of reductions, mechanisms like our self-sourced sand and other materials that we use in our fracs, so that gives an advantage from an economic standpoint to be competitive on acquisitions..

Thank you.

And how much of the 2015 capital being spent isn’t additive to production this year just solely due to the decision to defer completion during the year just so we can get a sense of what a clean number on a capital efficiency basis would be?.

Okay. As for as the number of wells that we’re deferring really the number is we had 200 wells at the start of 2015 and we’re going to end the year with about 285 wells waiting on completion. So they have additional 85 wells and were we complete that that cost would be somewhere $250 million to $500 million.

But, as far as the wells that we’re drilling and not to be completed that’s a couple of 100 million additional costs that we’re spending this year, 2015..

Great, thanks a lot..

And we’ll take our next question from Charles Meade with Johnson Rice..

Yes, good morning to everyone there. Bill, if I can get you to go back to some of the macro comments that you closed at your prepared comments with.

My recollection is that some of your comments back in December, some of your public comments, you had the opinion that we were looking at a more of a V shaped recovery in oil prices and maybe activities well, but I wanted to, can you talk about how your view of the macro landscape has changed over the last couple of months and what you think, I know you just referenced $65 oil in a year, is that a reasonable point to anchor on as far as your expectations for ’16?.

Charles, I don’t think that I’ve talked about our shape of the recovery. But, our view now is that we really believe with the consensus opinion that as we go forward due to the response of the industry that we could have flat to maybe even negative U.S.

production growth on a month-over-month basis by the end of this year, and that certainly going to slowdown U.S. production growth this year.

So, as that slows down there should be a price response and I’m not going to predict whether it’s going to be V or U or W o really what the price is, certainly the forward curve is very indicative that prices will increase in the future and we’re just going to wait and see how that goes and we’ll respond accordingly..

Got it.

And that’s actually good segway to the next question I would like to ask, it really gets to this inventory and what are the set of, what set of conditions would lead you to start really wanting to work that down, I mean, current forward curve as I said I think January crude read around $60 bucks, January ’16 crude would that be, would $60 crude would be sufficient for you to start, want you to work that down or perhaps that in combination with some other factors on completion costs or sort that of thing.

Can you just elaborate a bit on how you’re thinking about it?.

Yes certainly, we’re deferring these completions because we do believe that prices will be better in the future and even at $10 increase in oil price gives us a significant additional return on our investment and NPV upside. So, really our rate of return focus and our capital return focus is really what’s driving the deferral.

And let me kind of walk you through, there is two parts of this deferral, one is as Gary said we’re starting out 2015 with about 200 uncompleted wells in our inventory and that uncompleted well inventory will grow throughout 2015.

And if oil prices improve and they look something like the forward curve in the $60 range then we would begin completing many of those wells starting in the third quarter of 2015 and that would reflect additional growth in the fourth quarter heading into 2016. So, we want to head in the 2016 on an uptick in production growth.

So our curve in 2015 would be U-shaped. It will be the lowest production, will be in the second quarter and then in the third quarter and then production will begin to increase in the fourth quarter as we head into 2016.

Then at the end of the year, we will have about 285 wells and inventory to start to 2016 process and that will give us a bit of an advantage as we go into 2016 and we will be able to grow oil at very strong double-digit rates and be able to stay free cash flow neutral in our $65 oil price environment.

So hopefully that gives you a bit of more understanding of what we are thinking..

Bill that's great insight into your thinking, exactly what I was looking for, thank you..

And we will go now to Leo Mariani with RBC Capital Markets..

Yes guys.

I was just hoping you can speak a bit into sort of how quickly once the price response is in place where you can start working down the backlog of completions, is that just the matter of a month or two and then additionally just following up on what you have just mentioned there in terms of if we have got to $60 oil say by midsummer where you might start completing more wells in 3Q is that contemplated in the production guidance in 2015 for EOG?.

What we have contemplated is just as Bill was saying is we will ramp-up in the fourth quarter and you are right, it would take us about one month since we have wells drilled wait down completion to go ahead and see the impact of that production.

So yes, we would start somewhere like September and start the ramp-up if we have been encouraged with oil prices improvement..

And yes that is included in our guidance. Production guidance for 2015..

Okay. That's helpful. And I guess I notice that you guys did have a relatively healthy increase here in the dividend this quarter.

Can you talk a little bit about how you balance kind of returning cash to shareholders through the dividend with drilling wells obviously the returns on the wells are still quite strong here at $55 oil so how do you think about the increase in dividend just given where oil is right now?.

Yes, now we didn't increase the rate of dividend in this quarter. So, we did increase it twice last year, but too healthy now, so that's just the give back to the shareholders share within the success of the company as we end this lower price environment, the opportunity to further increase the rate is a bit more limited.

And so, we will really just have to see how oil prices respond in the future and to consider additional increases in the dividend. The company is very committed to that part of the business and to the shareholders in that way. So it’s a very top priority for us, but we need a bit better business environment to work on that..

Alright, thanks..

And we will take our next question from Pearce Hammond from Simmons & Company. .

Thank you for taking my questions.

My first question is what percent of total well cost is completion and where do you expect that to go with service cost decreases?.

Well our drilling cost is roughly 25% to 30% of the cost of the well. So that gives you the completion, of course, I guess we could put facilities in there so the facilities would be somewhere around 10%.

So, the balance being completion and the other part of the question is what Pearce?.

How you see those service costs decreasing, those completion costs decreasing over the course of this year?.

Yes. When we put our budget together we were seeing 5% to 10% cost reduction. Now, we are seeing 10% to 30% cost reduction that of course depends on the sector.

But just to kind of illustrate that not just mentioned in the Eagle Ford you noticed in our exhibit 18, we are showing our well cost to 6.1%, we are expecting, we are setting our target, we hope to see somewhere around 5.5% or about a 10% reduction.

In the Bakken we have got 9.3%, our target would be to further lower that growth of 9.3% in ’14 we have got 8.2% is our planned number, but we have got a target that’s slightly less than that maybe 19%. So overall, we are expecting our cost to come down somewhere around to 10% to 20% from 2014..

Thank you Billy and then what is the base decline for the company?.

Yes Pearce, we haven't given that number out. The decline rate in the region we have decline rate is slowing overtime. So there is three reasons for that. One is every year that goes by, our well by its gets more matured then we have got older wells bigger percentage of older wells all the time. So that's slowing the process.

Number two, our completion technology is really beginning to starting to flatten out our decline rates on a per well basis specifically the high density fracs that we talked about in the last quarter that we are applying the Eagle Ford are not only increasing the initial rates, but they are also decreasing the decline rates so we are very encouraged about that.

And then number three, as we go forward, we are targeting place that have better rocks with better probability and better ability to flow oil and those rocks such as the Sandstone place in the Delaware Basin and in Wyoming have lower decline rates also.

So the mix of our decline rate in the company is slowing overtime due to a number of different reasons..

Thank you very much..

We will now go to Joe Allman from J.P. Morgan..

Thank you operator. Hi everybody..

Good morning Joe..

Just first question is on production.

So, I heard what you said about the U-shape production for 2015, I just want to get a better understanding so the first part of the question is why is the first quarter 2015 production below fourth quarter especially in the oil side, I know you sold Canada and some factor in that end and could you just give us a better understanding of the trajectory so it sounds that you are going to be down in the first quarter, down in second,, down in third and then up in fourth and like will the fourth quarter oil be flat with fourth quarter 2014 oil especially in the U.S.

and I understand what’s going on in the East – on that field in the third quarter?.

Yes Joe, the reason the first quarter volumes are down is because we began ramping down our completion spread really quickly in the year.

So we wanted to and so oil continued to drop, we wanted to drop CapEx quickly and not focus on growing oil when we have the lowest prices in the first part of the year and then again as I described, the second and third quarters should be the lowest production and then the fourth quarter we will ramp back up.

We don't have a number to give you on guidance on that number, but it will ramp back up significantly heading into 2016..

Okay. That's helpful Bill.

And then, on the cash from operations, so to get the cash from operations to cover the CapEx what benchmark prices do you assume and in that are you assuming the midpoint of your production guidance?.

Yes, we go CapEx to discretionary cash flow should be balanced at about $58 average price this year and the second part of your question was?.

Just are you assuming, to generate the cash flow, first I would love to get WTI assumption, brand assumption and then natural gas assumption too and then are you assuming the midpoint of your guidance when you say you are going to cover the CapEx of cash from operation so for example, if you hit the low end of your guidance you maybe sort of you would be spending somewhat?.

It's an average midpoint of our production for 2015, yes Joe..

And how about natural gas assumptions and brand oil if you get there?.

Yes, on the gas we issue a five year strip, and yes we issue the five year strip on that and then on the NGL, the NGL is basically a percent of oil price in our assumptions and then gas again it’s a five year strip..

Okay. Very good, thank you..

And we will go now to Bob Brackett from Bernstein Research..

Some clarifications on some of the other questions.

One, I am trying to do the math on you start the year with 200 uncompleted, you drill about 465 wells and then you end the year with 285 or 350 uncompleted?.

Yes Bob, that's a good question. That 350 was an incorrect number, so correct that back to 285, we end the year with 285. So here is the number just to be completely clear, we start with 200, we drill 550 and we complete 465 during the year and we exit the year at about 285 wells uncompleted..

Great. That's helpful.

Quick follow-up on acquisitions you – two definitional terms, you contrasted bolt on versus large, large acquisitions is there a monetary value associated with those two numbers or those two additives?.

No that is not a monetary number, we just want to distinguish that we are open certainly to any kind of acquisitions that would be very highly beneficial to the company. But most likely the type of acquisitions we do are not in the very large I’m talking multi-billion dollar kind of acquisition.

They are really more directed towards the tactical acquisitions and they are really at very specific acreage pieces that we think are very highly productive according to our geology..

And you said core areas, so that's Bakken, Eagle Ford and Permian?.

Well certainly, those would be the first choices but obviously those are the most competitive, but we do from time to time consider those type of things and so many emerging place.

But again, we are very discriminatory there and that we are only looking for acreage that will be additive to our inventory and that means it has to be equal to or better than Eagle Ford, Bakken and Permian place..

Great, thank you..

Thank you..

And we will go now to Brian Singer with Goldman Sachs..

Thank you. Good morning..

Good morning Brian..

You talked the potential for 10% to 30% vendor cost savings and I wondered as a company more vertically integrated than others can you talk more specifically where you see this potential beyond the more normal course efficiency gains you highlighted in your presentation and your comments and whether do you think the 10% to 30% is merely cyclical or secular?.

Let me let, Brian, let me let Gary Thomas answer this question..

The good thing is as the vendors are working so well with the EOG and we are seeing that 10% to 30% across drilling, completion, production all areas.

And I guess the thing that be a little unique for EOG is we believe that we are going to be seeing maybe in the 10% to 15% reduction in some of our self-sourced areas because that EOG has 3 sand plants. We also have at least a half of dozen other vendors. So there is combination of cost of sand and distance from oil site.

So, we will be able to use some of the lower cost sand with us having half the number of frac fleets running in 2015. So that will be in the fit as well. As far as more granular yes, in the tubing and casing area it may be lower in 5% to 7% range. But, we are seeing stock tanks those discounts coming down as much as 25%..

And to follow-up, do you think that's cyclical or secular, it sounds like from your comment on just the cost of split the distance that's more high grading, but is there a secular element you see as well?.

No. not appreciably. I think the secular part Brian would be in the efficiency gain particularly in the technology side of it those will stay with us for years and they keep improving. The service cost comes and goes obviously with activity and so we will be a bit more short term.

But, we build in long term I think cost savings in the company that will continue to stay with us. As an example, we gave this earlier we now see better returns in our Eagle Ford with $65 oil than we had with $95 oil two or three years ago.

And that is mainly due to the efficiency gains we have been able to accomplish with our completion technology and the efficiency and the cost reduction on the wells..

That's helpful. Along those lines you talked about the acquisition strategy, but let’s say oil prices do quickly recover, the acquisition opportunities are not accretive as you are hoping for.

What potential do you see from your higher rate of return legacy areas to further extend your inventory beyond the 15 plus years you are at now, where are we in that ball parking?.

Brian, we see upside in really all of them just to start with the Eagle Ford again we still believe we are in the sixth inning there in the Eagle Ford. So, we are still testing new zones like the upper Eagle Ford and we working on down spacing and again we have added acreage there in the last year about 11,000 acres that is very high quality acreage.

So, we think there is additional room there, in the Bakken we have not upgraded our Bakken well count our reserve potential after we have started this down spacing process.

So, we see upside there and then in the Permian, we are diligently working on spacing and targeting and specifically in the second bond spring sand we are working on bringing the spacing patterns closer together and identifying maybe even two targets in that particular zone in the [indiscernible] we working on spacing there and we haven't upgraded that well count in the long time and then in the Wolf Camp we have multiple play zone spacing that we are working on there.

We haven't upgraded that in a while. So really each one of our core areas, we believe we will continue to provide additional high quality inventory as we go forward..

Thank you..

And ladies and gentlemen this does conclude today's question-and-answer session. Mr. Bill Thomas at this time I would like to turn the conference back over to you for additional or closing remarks..

Thank you. I would just like to leave you with this last one thought, EOG is very long term focused. We could have taken a short term approach this year and just picked up the very best wells in the company to drill and focus on those and cut our capital back to really own a short term focus.

But, we do not believe that's the right way to grow the company and to manage the company. We are focused on long term shareholder value and that's our focus.

So, as we said, we are going to not grow oil while oil prices are low, we are going to wait for the recovery and that will be able to give us much higher returns and it’s the right business decision as we go forward. So we appreciate everybody. Great questions and thank everybody for their support..

And ladies and gentlemen this does conclude today's conference and we do thank you for your participation..