EOG Resources Inc (EOG) 2014 Q4 法說會逐字稿

Good day and welcome to the EOG Resources fourth-quarter and full-year 2014 earnings results conference call.

At this time for opening remarks, 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 risk associated with forward-looking statements have been outlined in the earnings release and the EOG's SEC filings, and we'll 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 US 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'll 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 will discuss EOG's financials, capital structure and hedge position and Bill will provide concluding remarks. Now, here's 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 earning 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% while 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 coming years.

Also on 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 of 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 pro-well expenses in all of our major plays while simultaneously driving up well productivity.

Before I move on to 2015, I'd 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 a well productivity standpoint.

Over the last ten years, we have developed expertise across all of the disciplines required to drill in shale and other tight rock and make that drilling highly economic. 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's 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 rebound. We would be ready to respond swiftly when oil prices improve and resume our leadership in high return oil growth.

Second, we do not believe that growing oil and 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 and 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 strip prices. 2015 cash flow 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'll now explain in further detail how we plan to prepare for 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 wrap up completions. Oil price improvement of even a few dollars generates incremental NPV, so the main completions to wait for improved prices as evidenced by the forward curve will add significant value.

Please see slide 8 of our investor presentation for our play specific example. Second, we remain focused on driving down finding costs and improving pro-well production rates. This is our best hedge against low oil prices.

For example, as a result of cost in 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 costs 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 leaseholds, 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 costs than last year. And we're optimistic that additional opportunities will become available.

Finally, in my 36 years with the Company I've seen many downturns. And each time EOG stays disciplined, performs well and emerges on the other side in better shape than we ever did. 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 our year-end reserves.

2014 was another remarkable year in Eagle Ford. Oil productions on the play increased 45% and EOG achieved several key milestones. Number one, downspacing and improved completion techniques enabled us to increase our total potential reserve estimate in 2014 by 1 billion barrels of oil equivalent by 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 watt connected to the wellbore. Due to geologies, those techniques will change from one county to the next and we're making progress determining how to tweak those techniques across our acreage.

Number four, after five years in Eagle Ford we're still making drilling time and cost improvements. Please see slide 18 in the investor presentation. 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, freeing 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 on improved product prices. Thus, our inventory of uncompleted wells is expected to increase. This strategy allows us to maximize the value of our existing contractual commitments while waiting on improved pricing before we (inaudible) on newly completed wells with high oil production rates.

The land 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 had about 5500 net wells to drill on our acreage, over ten 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 laboratories. 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'll 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's quickly review the 2014 achievements that set this play up to be a 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 well 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 a play moved into development mode with greatened increase well productivity as evidenced by the three wells we highlighted in our press release.

At a $7 million completed well cost, the Wolfcamp play delivers very strong returns. Also in the Wolfcamp during 2014, we identified and delineated 90,000 net acres in the oil window.

Third, we tested and improved the Second Bone Spring Sand to be another high return oil target 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 a 70% percent oil in our Red Hills acreage in New 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 add the Second Bone Spring Sand to the drilling program and bring it forth 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 our Delaware Basin is still in the early innings of its exploration and development, the returns we are already generating from multiple targets 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 downspacing, 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's activity. First, we made significant advancements in improving drilling times and reducing well costs. A typical 10,000 foot lateral is now drilled in just over ten 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 can begin 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 wells in a 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 tests is a six-well pattern with well space 700 feet apart in the Bakken core. The initial production rates of these wells range from 1,000 barrels of oil per day through 1,900 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 downspacing 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 have been experimenting with wellbore targeting, inter-well spacing and modifications to the completion design for both intervals.

For the Codell, we have identified a specific stratigraphic interval within the pay section that when targeted greatly enhances the performance of the well. The improved completion techniques we use are even more effective when we focus on this target. Please see our press release for some notable well results.

Like the Codell, we had tested several targets within the Niobrara. With this additional testing, we have determined a correlation between the amount of lateral focus within a specific target interval and the production performance of the well.

In 2014, we made progress in several areas that contributed to reaching our well and operating cost goals in the DJ Basin. These include drilling and completion efficiencies, an oil and gas gathering system, a water gathering and distribution system and the infrastructure needed to obtain EOG's self-source sand.

Our activity in 2015 in the DJ Basin will be limited to drilling wells needed to maintain leasehold and finishing completion operations on a few remaining wells drilled last year. The Powder River Basin is a stacked pay system where we have drilled primarily in the Parkman and Turner oil reservoirs.

Similar to other areas within EOG's portfolio, in 2014 we focused on well targeting, improved 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 the Parkman and Turner plays. 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 replacement and finding costs. Excluding revisions due to commodity price changes, we replaced 249% of our 2014 production at a low funding cost of $13.25 per BOE. Proof reserves increased 18% and more than half of our reserve growth was driven by crude oil.

In addition, net proved developed reserved increased 20%. For the 27th consecutive year, (inaudible) 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 replacement 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 $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 15,000,000 ft.³ per day of natural gas. Also, G&A for the quarter was highered to $21.5 million of exit cost 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 exploration and development expenditures were $1.8 billion excluding acquisitions and asset retirement obligations.

In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $140 million. There were $66 million of acquisitions during the quarter.

For the full year 2014, capitalized interest was $57.2 million. Total exploration and development expenditures were $7.6 billion excluding acquisitions and asset retirement obligations.

In addition, expenditures for gathering systems, processing plants 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 account $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 resulted in declines in commodity prices and negotiated sales prices to property sales.

The remaining impairments were 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 the earnings release for the first quarter in full year 2015. Our 2015 CapEx estimate is $4.9 billion to $5.1 billion excluding acquisitions. The exploration 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 are not interested in growing oil production in a low-price environment. The budget for exploration 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 through June 30, 2015 we have 47,000 barrels of oil per day hedged at $91.22 per barrel. For the second half of 2015, we have 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 will look to hedge further volumes opportunistically throughout the year.

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

The counterparties exercise all such options. The (inaudible) of volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtu per day at an average price of $4.51 per MMBtu for each month during the period March 1 through December 31, 2015. Now, I'll turn it back over to Bill.

Thanks, Tim. Now, I'll talk about the macro view. We are encouraged that Congress is taking a look at lifting the ban on crude oil exports.

Doing so will bring a wide range of economic geopolitical benefits including strengthening the US energy sector, growing the US economy, creating jobs, dramatically improving the US trade deficit, providing our European allies with more secure supplies and lowering gasoline prices to US consumers.

As I mentioned earlier, EOG will be very focused this year on preparing for the recovery in oil prices. The current supply demand imbalance is not very large. And current prices are far short of what is necessary to sustain the supply need to meet world demand growth. When prices 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 end, year out EOG consistently approaches capital planning by focusing on returns. 2015 is no different.

Second, we have 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 a 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 a substantial inventory of high-volume wells to complete, we will be ready to return to double-digit oil growth as oil prices improve.

Finally, we fully expect to emerge from this commodity-priced down cycle in a stronger position than we entered it. In 2015, we have more opportunity than ever to lower finding costs and developing costs and improved returns in 2016 and beyond. Thanks for listening. Now, we'll go Q&A's.

(Operator Instructions) Doug Leggate, Bank of America Merrill Lynch. Sir, your line is open. Please check your mute function. Paul Sankey, Wolf Research.

Hi, good morning, everyone. Can you hear me okay?

Yes, Paul, go ahead. Good morning.

Great, thanks very much. Good morning.

You've clearly stated, guys, that you're 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've made here is to get CapEx in line with expected cash flows.

And secondly, that by increasing efficiency allowing for lower service costs that even if oil prices remain low for another year, you would be able to deliver growth in 2016 while keeping CapEx and cash flows or if oil prices remain low, would you reduce CapEx and leave holdings flat again next year? Thanks.

Yes, Paul. 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 in price could come, certainly, in the next -- this year -- the end of this year or maybe even next year. There's no use in trying to accelerate.

It makes much more prudent a business decision to wait. That will give us much more capital returns if we do that. And we are very committed to maintaining a very strong balance sheet.

We don't want to outspend 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 powder dry, so that we will be able to take some advantage of what could be some unique opportunities in this downturn.

Yes.

(Inaudible) -- Yes, sir. On 2016 -- Yes.

If we -- if things go as we think they might could and we would have, say, a $65 oil environment in 2016, then we believe that we could return to our very strong double-digit oil growth that we've been marching towards over the last few years and that we will be able to generate very high rates of return on our capital.

We would be able to stay free cash flow neutral.

The specific part of that was if you did another year of $5 billion CapEx next year, you would be able to re-accelerate growth because of the increased efficiencies and lower service costs that you'll 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.

As we look forward to 2016, we haven't set a capital goal on that yet. We'll look at that when we get there.

Okay. That's great. Thanks.

Can I just confirm you're building effectively an inventory of stuff that you can do if you want to? Would that mean you're less likely to get into M&A, or would you not follow that statement through?

The kind of opportunities that we are looking for to take advantage of is number one, this low-price environment helps us to pick up acreage that we're working on and are certainly our core areas.

We were able to pick up 11,000 acres last year in the Eagle Ford and we're targeting to pick up more there just from leasehold. So that goes more easily this year.

The second is that we have historically and we will -- we do think that we'll have opportunities to earn acreage through farm-ins or drill-to-earn-type things -- commitments. We'll look for partners that we can join in with that will be a win-win situation.

Earn acreage in our core areas and maybe some emerging areas. And then we'll look for tactical acquisitions. They won't be the large, large acquisitions, but they will be certainly bolt-on acreage and they will be opportunities that we see primarily in our top tier plays.

Okay, great. Thank you very much.

Phillip Jungwith, BMO.

Yes, good morning.

EOG has been at the cutting edge of completion technology and proven to be a premier operator, but is there any way to quantify the operational synergies you think can be achieved through an acquisition strategy in terms of NPV per well and how ever 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 exploration expertise and our understanding of the rocks. And so we really are only focused on opportunities where we see very sweet spot top acreage and either existing core areas or in emerging plays.

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've developed 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 to the table on any acquisition that we might pursue. Also, we have certainly are built in cost of reduction mechanisms like our self-source sand and other materials that we use in our fracs. So that gives us an advantage from an economic standpoint to be competitive on acquisitions.

Okay, great.

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

Okay.

As far as the number of wells that we are deferring, really the number is -- we had 200 wells at the start of 2015. And we are going to end the year with about 285 wells waiting on completion.

So about an additional 85 wells. And were we to complete that, that cost would be somewhere $450 million to $500 million. As far as the wells that we're drilling and not to be completed, that's a couple hundred million dollars additional cost that we're spending this year, 2015.

Great, thanks a lot.

Charles Meade, Johnson Rice

Yes, good morning, everyone, there. Bill, I wonder if I could get you to go back to some of the macro comments that you closed out 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 more of a V-shaped recovery in oil prices and maybe activity, as well.

I wonder if -- 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 2016?

Charles, I don't think that I've talked about a shape of the recovery. 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 US production growth on a month-over-month basis by the end of this year.

That's certainly going to slow down US production growth this year. As that slows down, there should be a price response. I'm not going to predict whether it's going to be V or U or W or 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. That's actually a 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?

The current forward curve has us at January crude is right around $60, January 2016 crude. Would that be -- would $60 crude be sufficient for you to start wanting to work that down, or perhaps that in combination with some other factors on completion costs or that sort of thing? Can you just elaborate a bit how you're thinking about it?

Certainly, because we're deferring these completions because we do believe that prices would be better in the future and even a $10 increase in oil price gives us a significant additional return on our investment and NPV upside.

Really our rate of return focus and our capital return focus is really what's driving the deferral. Let me kind of walk you through. There's two parts of this deferral.

One is as Gary said, we're starting out 2015 with about 200 uncompleted wells in our inventory. 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 into 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 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'll have about 285 wells in inventory to start the 2016 process.

That will give us a bit of an advantage as we go into 2016, and we'll be able to grow oil at very strong double-digit rates and be able to stay free cash flow neutral in a $65 oil price environment.

Hopefully that gives you a bit of more understanding of what we're thinking.

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

Leo Mariani, RBC Capital Markets.

Yes. I was just hoping you can speak a bit into how quickly once the price response is in place where you can start working down the backlog of completion. Is that just a matter of a month or two?

Additionally, just following up on what you had just mentioned there in terms of if we got to $60 oil by midsummer where we 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'll ramp up in the fourth quarter. And you're right. It would take us about one month since we have wells drilled waiting on 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've been encouraged with oil prices improving.

Yes, that is included in our guidance -- production guidance.

Okay.

Thanks.

Okay. No, that's helpful. I noticed that you did have a relatively healthy increase year in the dividend this quarter.

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

Yes. No, we didn't increase the rate of dividend in this quarter. So we did increase it twice last year by two healthy amounts. That's just to give back for the shareholders, share with them 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 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.

It's a very top priority for us. But we need a bit better business environment to work on that.

All right, thanks.

Pearce Hammond, 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?

Our drilling cost is roughly 25% to 30% of the cost of a well. There gives you the completion. Of course, I guess we could put facilities in there.

The facilities would be somewhere around 10%. So the balance being completion. The other part of the question was what, Pearce?

Was just 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 saying 5% to 10% cost reduction. Now, we're seeing 10% to 30% cost reduction.

That, of course, depends on the sector. Just to illustrate that, I might just mention in the Eagle Ford, you noticed in our Exhibit 18 we're showing our well cost at 6.1%. We're expecting -- we're setting our target -- we hope to see somewhere around 5.5%, or about a 10% reduction.

And on the Bakken, we've got 9.3%. Our target would be to further lower that. Well, 9.3% in 2014. We've got 8.2% is our plan number.

But we've got a target that's slightly less than that. Maybe 19%. So overall, we're expecting our costs to come down somewhere around 10% to 20% from 2013.

Thank you, Billy. And then what is the base decline for the Company?

Pearce, we haven't given that number out. The decline rate and the reason we haven't -- the decline rate is slowing over time. There's three reasons for that.

One is every year that goes by our well base gets more mature. And we've 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're applying in the Eagle Ford are not only increasing the initial rates but they're also decreasing the decline rates there.

We're very encouraged about that. And then number three, as we go forward, we are targeting plays that have better rocks with better permeability and better ability to flow oil.

And those rocks, such as the Sandstone plays and the Delaware Basin and in Wyoming have lower decline rates, also. So the mix of our decline rate in the Company is slowing over time due to a number of different reasons.

Thank you very much.

Joe Allman, JPMorgan.

Thank you, operator. Hi, everybody.

Good morning, Joe.

First question's on production. I heard what you said about the U-shaped production for 2015. And I just want to get a better understanding.

So the first part of the question is, why is the first quarter of 2015 production below fourth quarter, especially in the oil side? I know you sold Canada, so I'm factoring that in. And then could you just give us just a better understanding of the trajectory? So it sounds as if you're going to be down in the first quarter down, down in the second, down in third and then up in fourth.

Will the fourth quarter oil be flat with four quarter 2014 oil especially in the US? And I understand what's happening in the East Irish Sea; you're bringing on that field in the third quarter.

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

So we wanted to -- as the oil continued to drop, we wanted to drop CapEx quickly and not focus on growing oil when we had the lowest races 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'll ramp back up.

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

Okay. That's helpful, Bill. On the cash flow from operations, do you get the cash flow 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. The second part of your question was?

Are you assuming you can still generate the cash flow while you -- first, I'd love to get the WTI assumption, brand assumption and then the natural gas assumption, too. Are you assuming the midpoint of your guidance when you say you're going to cover the CapEx with cash from operations? For example, if you hit the low end of your guidance, maybe you'd be short of -- you'd be deficit spending somewhat.

That's the average midpoint of our production for 2015. Yes, Joe.

Okay. How about natural gas assumptions and brand oil if you got that?

On the gas, we use a five-year strip. We use a five-year strip on that. And then on the NGL's, it's -- the NGL's is basically a percent of oil price in our assumptions. Gas, again, is a five-year strip.

Okay, all right. Very good, thank you.

Bob Bracket, Bernstein Research.

Clarifications on some of the other questions. One, I've trying to do the math on you start the year with 200 uncompleted. You drill about 465 wells and then you end the year, was it 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 at 285. Here's the numbers 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 used, two definitional terms.

You contracted bolt-on versus large, large acquisitions. Is there a monetary value associated with those two numbers or those two adjectives?

No, there's not a monetary number. It's --we just want to distinguish that we're open certainly to any kind of acquisition that would be very highly beneficial to the Company, but most likely the type of acquisitions we do are not in the very large -- we're talking multi billion-dollar acquisitions.

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

You said core areas. That's Bakken, Eagle Ford, Permian?

Well, certainly those would be the first choices. But obviously, those are the most competitive.

We do from time to time consider those type of things and some of the emerging plays. But again, we're very discriminatory there in that we're only looking for acreage that will be additive to our inventory. And that means it has to be equal to or better than our Eagle Ford, Bakken and Permian plays.

Great, thank you.

Thank you.

Brian Singer, Goldman Sachs.

Thank you. Good morning.

Good morning, Brian.

You talked to 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 you think the 10% to 30% is merely cyclical or secular?

Let me let -- Well, I'm going to let Gary Thomas answer this question.

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

I guess the thing that'd be a little unique for EOG is we believe that we're going to be seeing maybe in the 10% to 15% reduction in some of our self-sourced areas. You know, EOG has three sand plants.

We also have at least a half a dozen other vendors. That combination of cost of sand and distance from well site, so we'll be able to use some of the lower cost sand with us having half the number of frac fleets running in 2015. That will benefit us as well.

As far as more granular, yes, in the tubing and casing area it may be lower, you know, in the 5% to 7% range. But we are seeing stock tanks, those discounts coming down as much as 25%.

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

No, not appreciably. I think the secular part, Brian, would be in the efficiency gains particularly in the technology side of it. Those will stay with us for years.

They keep improving. The service cost comes and goes obviously with the activity. It'll be a bit more short term.

We build in long-term, I think, a 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. That is mainly due to the efficiency gains we've been able to accomplish with our completion technology and the efficiency and cost reduction on the wells.

That's helpful.

Along those lines, you talked about the acquisition strategy. Let's say oil prices do quickly recover. The acquisition opportunities are not accretive as you're hoping for. What potential do you see from your higher rate of return legacy areas to further extend your inventory beyond the 15+ years you're at now? Where are we in that ballgame?

Brian, we see upside in really all of them. Just to start with the Eagle Ford, again we still believe we're in the sixth inning there in Eagle Ford.

We're still testing new zones like the upper Eagle Ford and we're working on downspacing. And again we've added acreage there in the last year, about 11,000 acres that is very high quality acreage. We think there's additional room there.

In the Bakken, we've not upgraded our Bakken well count or reserve potential after we started this downspacing process. We see upside there.

And in the Permian, we are diligently working on spacing and targeting and specifically in the Second Bone Springs sand, we're working on bringing the spacing patterns closer together and identifying maybe even two targets in that particular zone.

In the Leonard, we're working on spacing there. We haven't upgraded that well count in a long time. And then in the Wolfcamp, we have multiple pay zones and spacing that we're working on there and we haven't upgraded that in awhile. Really each one of our core areas we believe will continue to provide additional high quality inventory as we go forward.

Thank you.

Okay. 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 any 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've taken the short-term approach this year and just picked out the very best wells in the Company to drill and focus on those and cut our capital back to really only 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. That's our focus. As we said, we are going to not grow oil while oil prices are low. We're 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.

We appreciate everybody. Great questions and thank everybody for their support.

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