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EOG Resources, Inc. (NYSE:EOG)

Q42012 Earnings Call

February 14, 2013 9:00 am ET

Executives

Mark Papa - Chairman of the Board, Chief Executive Officer

William Thomas - President

Timothy Driggers - Chief Financial Officer, Vice President

Analysts

Doug Leggate - Bank of America Merrill Lynch

Leo Mariani - RBC Capital

Evan Calio - Morgan Stanley

Bob Brackett - Bernstein Research

Charles Meade - Johnson Rice

Brian Singer - Goldman Sachs

Operator

Good day, everyone, and welcome to the EOG Resources 2012 fourth quarter and full-year results conference call. As a reminder, this call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Mark Papa

Good morning, and thanks for taking the time to join us. I hope that everyone has seen the press release announcing fourth quarter and full year 2012 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 the 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 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, including those for the Eagle Ford, Wolfcamp and Leonard 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 investors that appears at the bottom of our press release and Investor Relations page of our website.

With me this morning are Bill Thomas, President, Gary Thomas, COO, Llyod Helms, EVP, Operations, Tim Driggers, Vice President and CFO, Maire Baldwin, VP of IR and Jill Miller, Manager of Engineering and Acquisitions

An updated IR Presentation was posted to our website last night and we included first quarter and full-year 2013 guidance in yesterday's press release.

This morning, we'll discuss topics in the following order. I'll first review our 2012 fourth quarter and full-year net income and discretionary cash flow. Then Bill Thomas and I will provide operational results followed by reserve replacement, our macro view and hedge position, and our 2013 business plan. Tim Driggers will then discuss financials and capital structure, and I'll finish with concluding remarks.

As outlined in our press release, for the full year 2012, EOG reported net income $570.3 million, or $2.11 per share and a net loss of $505 million, or dollar $1.88 per share for the fourth quarter.

For investors who focus on non-GAAP net income to eliminate mark-to-market impacts and certain non-recurring items as outlined in the press release, EOG's full-year adjusted net income was $1.54 billion, or $5.67 per share and $437 million or $1.61 per share for the fourth quarter 2012.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's 2012 Bcf was $5.7 billion for the full year and $1.4 billion for the fourth quarter.

I will now address our operational results in key plays. We had a good fourth quarter providing a capstone to a very strong full year 2012. Our fourth quarter oil volumes essentially hit the mid-point of our guidance. Our unit costs significantly weak guidance and partially due to our crude by rail system, our domestic crude netback was at a significant premium over WTI.

For the full year, our crude and condensate volumes were up 39% year-over-year, NGL volumes were up 32% and total liquids increased 37%. North American natural gas volumes were down 9% year-over-year in line with expectations. In Trinidad volumes increased 6%. Overall total company production grew 10% in 2012 versus 2011. Over the past three years, our organic crude and condensate growth rates have been 35%, 52% and 39%, respectively.

More importantly, EOG's full-year non-GAAP EPS adjusted EBITDAX and discretionary cash flow grew 50%, 26% and 26%, respectively, above 2011. We believe, we have the highest two-year growth rate in the three important financial parameters of all large cap E&Ps. We expect further growth in each of these three metrics in 2013, as well as improvements in our ROE and ROCE.

I'll note that in the fourth quarter, we incurred a significant financial and natural gas reserve write-down, which is very unusual for EOG. Approximately 98% of the total financial write-down occurred in Canada as a result of low gas prices. We have written off the remaining book value of our entire Horn River acreage along with all PDP and PUD reserves, because they are on economic at current gas prices. However, the drilling we have done today holds our remaining 127,000 net acres in the Horn River with an estimated seven Tcf reserve potential until 2020, providing optionality for us.

The other major main issue of the component involved our Canadian shallow gas assets. Even with these write-downs affecting our capital account, we accomplished our goal of keeping our net debt to total cap below 30%.

I will now discuss our key oil plays, starting with Eagle Ford. The Eagle Ford continues to be our flagship oil assets and we have several important points to share with you today regarding this asset. First, as predicted on our previous call, our fourth quarter Eagle Ford production declined relative to the third quarter since we slowed down our capital spend rate to stay within budget targets of previously used the analogy of a coin-operated machine and we simply didn't insert as many coins in the fourth quarter. The good news is, we are ramping up in the first quarter and in January we completed our highest IP well in Eagle Ford to-date. 100% working interest Burrow Unit #2H tested at 6,330 barrels of oil per day with 5.7 million cubic feet a day of rich natural gas. The Eagle Ford will be the biggest driver of EOG's targeted 28% 2013 oil growth.

Second, we expect the aggregate industry wide Eagle Ford oil production to surpass the Bakken within the next two years. Remember that EOG's 569,000 net oil acres constitute the largest and highest quality oil position in the entire play.

Third, through year-end 2012, we drilled and completed 630 net wells and conducted multiple spacing studies, and reservoir computer simulations. Simply put, we understand the reservoir much better than we did a year ago and we reached several important conclusions. The bottom line answer is that we are increasing our net potential recoverable reserve estimate by 600 million Boe and the development economics are still excellent. However, since some of the data supporting this conclusion may be counterintuitive to street expectations, I will provide some backup details without dragging you through the (inaudible) here.

Conclusion one is that downspacing across all of our acreage has been successful and the optimum spacing is 40 acres in the Eastern half of our acreage and 65 acres in the West. Previously our spacing was 65 to 90 acres.

Conclusion two is that with the new spacing, we have a total of 5,500 net drilling locations on our acreage. Since we have completed 630 net wells to-date, there are approximately 4,900 wells yet to drill or a 12 year inventory based on our 2013 program of 400 net wells.

Conclusion three, is that per well reserves will average 400 MBoe net after royalty. This is lower than the 450 MBoe which previously provided because there is an inner well drainage component associated with this closer spacing. A minimal amount of drainage is optimal in developing a resource play and maximizing present value. Multiplying 5,500 net wells times 400 MBoe net after royalty equals 2.2 billion Boe net to EOG which is our new potential reserve estimate. This translates to an approximate 8% recovery factor of the estimated 26.4 net billion Boe in place under our acreage.

Conclusion four, is that we plan to drill longer laterals than previously assumed. 5,500 feet versus 4,000 feet previously. So the average well cost is now $6 million. Adjusted for lateral length this is equivalent to the $5.5 million cost target we previously reported.

The final conclusion is that using the new well cost and reserves and current oil and NGL prices the direct unlevered after-tax reinvestment rate of return per well is 100%. The bottom line is that we had an estimated 600 million Boe net potential recoverable reserves with a direct ATROR is 100% and the incremental infrastructure cost is rather low.

I will now turn it over to Bill Thomas to discuss other domestic oil plays.

William Thomas

Thanks, Mark. Our Bakken/Three Forks drilling results during the fourth quarter were outstanding and our 2013 program should be one of our strongest in many years. While most of industry Bakken/Three Forks results are trending downward, EOG results are moving in the opposite direction. In other words, our wells are getting better. There two reasons our well performance is trending higher and why we expect our 2013 results to be strong.

First new frac technology is improving our wells in every area of the Bakken/Three Forks. In some cases the new frac technology using our 320 acre downspacing wells in the Parshall Core has resulted in a 30% to 70% improvement in cumulative production over the original offset wells are per foot of treated lateral basis. For example, the Wayzetta 156-3329, a 320-acre down spaced well completed in 2012 has a cumulative production of 330 Mboe in the first 340 days in is still producing at a rate of over 800 barrels of oil per day. Please see our updated IR slides for an illustrative chart.

The second reason to expect strong results in 2013 is our drilling program is directed to the Parshall Core and Antelope Extension areas, which are some of the best acreage blocks in the play. Two Antelope Extension wells recently completed at our Hawkeye 01-2501H Three Forks well following 2,945 barrels of oil per day and the Hawkeye 01-2501H, a Bakken well following 2,444 barrels of oil per day. EOG has 75% working interest in these wells.

In addition to improving well results, we have completed our first two wells on 160 acre downspacing in the Parshall field. The Wayzetta 022-1509H and the Wayzetta 149-1509H tested at maximum rates of 1,185 and 1,265 barrels of oil per day, respectively. EOG has 68% working interest in these wells.

In 2012, we completed 28 net wells in the Parshall field and Antelope area with a successful 320 acre downspacing program.

In 2013, we plan to complete 46 net wells in these same two areas. Our focus this year will be to further downspace to 160 acres in both, the Bakken and Three Forks play intervals continue to improve frac efficiency and to optimize the recovery factor of each play.

If 160-acre down spacing proves successful, this will allow us to accelerate our development program in 2014 and beyond. The takeaway from our Bakken/Three Forks asset is that wells were getting better with continued success in down spacing. The number of potential locations is growing and this provides us many years of high ROR investment opportunity in the play.

In the Delaware Basin, we have completed our first two horizontal Wolfcamp wells, in Reeves County, Texas, and we have significant results to announce. The Harrison Ranch #56-1002H tested in the upper Wolfcamp at 635 barrels of oil per day with 480 barrels of NGL per day and 3.1 million cubic feet of gas per day

In the Harrison Ranch #56-1002H was completed in the middle Wolfcamp at 377 barrels of oil per day with 602 barrels of NGL per day and 3.9 million cubic feet of gas per day. With estimated gross reserves of 900 MMBoe per well and a target completed well cost of $6.5 million. These results yield a strong 60% direct a-tax rate of return. Our Reeves County acreage has as much has 2,000 feet of gross Wolfcamp thickness in some places and approximately 300 million barrels equivalent per section of resource potential.

We have 220 subsurface faults total cost on our 114,000 net acres and we estimate the reserve potential to be 800 million barrels of oil equivalent, net to EOG. This is another substantial addition to our growing opportunities of higher rate of return drilling inventory. As a cautionary note, because we have such a large inventory of opportunities across the company, significant production growth on the Delaware Basin Wolfcamp should not be expected until the 2015 timeframe. As noticed in previous earnings calls, the results from our Leonard Shale play also in the Delaware Basin keep improving. With improved frac technique, the wells are getting better and showing a higher percentage of oil production than previously reported.

Successful downspacing and the identification of multiple play targets have substantially increased the number of potential drilling locations. Recent wells include the Vaca 14 Fed #6H with an initial production rate of 1,290 barrels of oil per day with 255 barrels of NGL per day and 1.4 million cubic feet of gas per day, and the Diamond 8 FC #5H with initial production rate of 1,162 barrels of oil per day and 183 barrels of NGL per day and one million cubic feet of gas per day. As a result, we are increasing our gross reserves from 430 in MBoe per well two 500 MBoe per well and increasing the percentage of estimated oil from 41% to 50% of total well reserves. In addition, we are increasing EOG's estimated Leonard pipe potential reserves from 65 million barrels of oil equivalent to 550 million barrels of oil equivalent net to EOG. Our direct a-tax rate of return for the 2012 Leonard total was 55% and we see this improving in 2013.

In summary, our 114,000 net acres in the Delaware basin has multiple pay zones targets in the Leonard and Wolfcamp shale plays with a combined estimated reserve potential of approximately 1.35 billion barrels of oil equivalent net to EOG. Additionally, our results from the Midland Basin Wolfcamp program continues to be on track. The Barnett combo will make a solid with our 30% direct a-tax rate of return drilling program. Cost efficiencies have reduced completed well cost of 3.1 million and new techniques are helping to improve oil recovery. In 2013, we plan to drill 130 wells versus 190 in 2012.

Because we have an EOG owned processing plant, methane extraction is still economic and supports our drilling program in spite of soft NGL prices. Recent wells include the Evans Unit #1H, #2H, B Unit #1H with initial production rates of 573, 677 and 685 barrels of oil per day respectively and recall A Unit #1H and #2H with initial production rates of 371 and 447 barrels of oil per day respectively. EOG has 100% working interest in all of these wells. Remaining drilling potential continues to grow for EOG in the play.

In addition to these plays we have a smaller levels of horizontal oil activity in the midcontinent, Powder River basin and Southern Manitoba. Also we continue to test new Greenfield horizontal oil ideas in North America.

Now I will turn it back to Mark.

Mark Papa

Thanks, Bill. As you can see with our Eagle Ford reserve estimate upgrade and our success in the Delaware basin, we are very long on domestic oil and combo reinvestment opportunities for many years and this affects our decision to exit the Kitimat LNG project. We believe Kitimat is good project and with Chevron involved the project will likely get built. However the projected Kitimat ROR did not compare favorably with returns from our domestic shale oil projects, especially in light of our Eagle Ford reserve upgrade. We weren’t desperate to monetize our Kitimat position. We simply believe that the substantial go forward capital required by Kitimat will be best reinvested in U.S. oil shale plays. We hope this explains to shareholders our logic regarding the exit of this project.

In Trinidad, our fourth quarter gas sales were lower than previous quarters due to downtime from planned maintenance and construction work on our offshore facilities. We are currently in the middle of a drilling program which includes four wells off of our Osprey platform. These wells are expected to be completed in the first half of 2013. In Trinidad, we expect natural gas production to decrease by 4% this year. This is a function of the timing of first production from our current drilling program.

In the East Irish sea, we expect our Conwy oil project to start production early in the fourth quarter.

I will now address two other EOG differentiators, frac sand and oil margins. Frac sand is easy to explain. Our sand plants ran at essentially 100% during the fourth quarter and met our completion needs. In the fourth quarter our U.S. crude oil price realization was $10.52 over WTI, up from $5.45 in the third quarter. During the fourth quarter and currently our Eagle Ford crude is priced off an LLS index and essentially all of our Bakken and part of our Wolfcamp crude is being railed to our St. James terminal. To a large degree, our domestic crude price is linked more closely to LLS than WTI. We expect that the recent Seaway Pipeline delays will continue to provide us with marketing prices advantage.

I will now address 2012 reserve replacement and finding costs. Because of the extraordinarily low 2012 gas prices and current SEC rules, all companies with gas reserves will likely incur reserve write-downs and EOG is no exception. This will make it very hard for analysts to compare overall 2012 reserve metrics with past years. Because of low natural gas prices, EOG has written off essentially all of our dry gas PUDs in the Horn River, Marcellus, Haynesville and Barnett.

Additionally, our existing gas PDPs have been significantly reduced because of shale gas reductions. The total write-off related to price you 3.2 Tcfe. However, excluding these price-related reasons, our reserve replacement and finding cost metrics are excellent. We replaced 268% of production at $12.60 Boe total finding cost. This compares to last year's number of $18.74 per Boe. Our ratio of liquids in our total reserves, increased from 28% in 2010 to 36% in 2011 to 256% at year-end 2012.

Our domestic crude oil replacement rates from drilling was 442%. Overall, I believe EOG had an outstanding highly economic reserve replacement year, and I think the removal of gas reserves from our books properly reflects the new low gas price reality. Our reserve books are now more reflective of an oil company.

For the 25th consecutive year, DeGolyer and MacNaughton has done their own independent engineering analysis with the high reserves and that overall number was within 5% of our internal estimate. Their analysis covered 87% of our proved reserves this year. Please see the schedules accompanying the earnings release for the calculation of reserve replacement and finding costs.

Now I will provide our views regarding macro, hedging and crude by rail. Regarding oil, we think the NYMEX correctly reflects slightly 2013 WTI prices, which we expect to be in the mid-90s. We think the dangers of a global recession are slowly abating, so we continue to be cautiously optimistic regarding oil.

For 2013, as a percent of total company oil production, we are approximately 49% hedged at an average price of $98.85. Now, also note that we have some options that could be exercised further increasing our hedge position. Please see the table that was included in our earnings press release for the details of our hedging contracts.

As you know, our crude-by-rail system has been a profitable venture for us and is one reason why our average domestic oil price was $10.52 over WTI during the fourth quarter, likely the highest in the industry for any company with similarly situated crude. Although currently the price differentials at St. James in Houston continues to be very advantageous as compared to Cushing, it's possible that the spread between Houston and WTI may narrow late this year as additional pipeline from Cushing in the Permian come online.

We are already working on plans to use our rail system to maximize crude margins in 2014 and 2015 possibly by delivering to different destinations. Regarding North American natural gas, we continue to have a negative outlook and our drilling plans reflect this bias. We believe that those that are counting on the low gas directed rig count to balance the market will be disappointed because of the large associated gas volumes with drilling in combo-type plays. We have 150 million cubic feet per day hedged at $4.79 per MMBtu this year.

We are also bearish regarding 2013 ethane prices. We think it's unlikely that ethane will rebound much this year. It's likely that most producers including EOG will be on the cusp of ethane rejection throughout the year. For example, in January and February, EOG for the first time chose to keep out of Eagle Ford ethane in the gas stream reducing our NGL production by 4,000 barrels per day and we are projecting the Eagle Ford ethane rejection throughout the year. We have taken this into account in our lower NGL production growth estimates for the year.

Now I'll address our 2013 business plan, which is congruent with what we reported in our November call. We expect our 2013 CapEx to be between $7.0 billion to $7.2 billion, a reduction of approximately $400 million from 2012. Approximately $1.2 billion of this will be devoted to facilities, gathering systems and other infrastructure. We expect to spend very little, approximately $25 million, on North American dry gas drilling to hold acreage. We have already invested the drilling capital in previous years to hold the remainder of our dry gas acreage that we want to retain. Because of low NGL pricing, we shift some funds away from the Barnett combo to the Eagle Ford and Bakken. We are targeting 28% oil growth which on and absolute the OPD basis is the same as last year. A tall order for a company our size.

I will note that only a very small portion of this is condensate. Essentially all of our oil production is exactly that, crude oil. We are not particularly interested in growing the ethane portion of NGLs and expect 10% NGL growth, primarily because we are assuming full year Eagle Ford ethane rejection. It will be purely an economic decision as the year progresses. We are not driven by NGL production growth.

Since North American gas continues to be a money loser, we have zero interest in growing gas volumes and expect decreasing production for the fifth consecutive year regarding gas. We forecast EOG natural gas production to decline 14% in the U.S. due the past property sales and lack of gas drilling, but this also could be affected by ethane rejection.

In Canada, we also expect natural gas production to decrease by 24%. In Trinidad, we expect natural gas production to decrease by 4%. This is more a function of our well downtime due to our planned regional program. Overall, we expect total company production growth of plus 4%.

However the only metrics that drive financial performance is our crude oil growth. Additionally, we plan to sell approximately $550 million worth of assets of which 85% has already closed this year so far. The biggest component of this is our already closed Kitimat sale. We still plan to maintain a strong balance sheet keeping the net debt to total cap ratio below 30%.

Based on the current NYMEX strip we expect this plan to generate a reduction in the net debt ratio and year-over-year growth in DCF, GAAP and non-GAAP EPS and adjusted EBITDAX per share as well as healthy year-over-year improvement in ROE and ROCE. Given that we are bearish regarding pricing for two out of three of our hydrocarbon products, we think that is quite an impressive outcome.

Now I will turn it over to Tim Driggers to discuss financials and capital structure.

Timothy Driggers

Thanks, Mark. Capitalized interest for the quarter was $13 million and $49.7 million for the full year. For the fourth quarter 2012, total cash exploration and development expenditures were $1.5 billion, excluding asset retirement obligations. In addition, cash expenditures for gathering systems, processing plants and other property, plant and equipment were $143 million. For the full year 2012, total cash exploration and development expenditures were $6.9 billion, excluding asset retirement obligations. Cash expenditures for gathering systems, processing plants and other property, plant and equipment were $620 million.

Acquisitions for the year was $700,000. For the year, proceeds from asset sales were $1.3 billion. It December 31, 2012, total debt outstanding was $6.3 billion and the debt to total capitalization ratio was 32%. At December 31, we had $0.9 billion of cash on hand, giving us non-GAAP net debt of $5.4 billion or net debt to total cap ratio of 29%.

On a GAAP basis, the effective tax rate for the fourth quarter was negative 13% caused principally by impairments reported in Canada. The deferred tax ratio was negative 157%. The current tax provision for the fourth quarter was $152 million. EOG's board increased the dividend on EOG's common stock for the 14th time in 14 years by 10% to an indicated annual rate of $0.75 per share.

Yesterday, we included a guidance table with earnings press release for the first quarter and full year 2013. For the first quarter and full year, the effective tax rate is estimated to be 35% to 45%. We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the first quarter and for the full year.

Now I'll turn it back to Mark.

Mark Papa

Now, let me summarize. In my opinion, there are five important points to take away from this call. First, our Eagle Ford potential reserve increase gives EOG a domestic shale oil inventory unsurpassed in the industry. As I stated earlier in the call, we expect industry-wide Eagle Ford oil production to surpass the Bakken over the next two years and EOG indisputably has a premier Eagle Ford oil position in addition to our strong Bakken position.

Our 2.2 billion Boe net Eagle Ford position is not theoretical. The production results are visible on both, in EOG and industry scale. When add in our Permian and Barnett Combo assets, we have an unsurpassed inventory of proven reinvestment opportunities. Second, we have added a new Greenfield project to our portfolio with the Permian Basin and Delaware Wolfcamp, plus a significant Leonard Shale upgrade. Additionally, we are excited about additional future Greenfield shale projects. Third, as predicted, this is the year when we expect to reduce our net debt ratio based on current future prices. Fourth, our 10% dividend increase is a tangible signal of our growing confidence and cash flow stream. Finally, and most importantly, we expect our key financial metrics such as EPS, adjusted EBITDAX, DCF, ROE and ROCE to show positive year-over-year improvement in 2013.

Thanks for listening, and now we will go to Q&A.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). We will take our first question from Doug Leggate of Bank of America Merrill Lynch

Doug Leggate - Bank of America Merrill Lynch

Thanks. Good morning, everybody, and thanks for all the color, Mark, on the down spacing. You talked in the past about continued adverse supply and increase your recovery rates there obviously you've done a good job on that.

Would you now say that 8% is that pretty much target achieved or do you think there is still more running room there and just curious as to what else you might do in terms of trying to look at your recovery rates and I have a follow-up please.

Mark Papa

Yes, Doug. There is, no, we can't say that the 8% is the final, final, final answer at all. In terms of what we are still looking at doing on there, there is the continued work on non-potential additional spacing seeing improvements from frac enhancement and then the one that I think is the big hitter potential hitter out there is secondary recovery.

In the case of the Eagle Ford, it would be through the gas injection and we have commenced our pilot gas injection project down there in the Eagle Ford, and the reason I mentioned it on the script is that it may be as long as two years before we really have a read on the outcome of a pilot project. I just only want to give a timeline on it, but its worse our investors knowing that the pilot project is underway but it's not anything that we are going to be able to provide quarter-by-quarter feedback as to how is the pilot coming or anything like that. But it is fair to say that we are cautiously optimistic that we will come up with a method of significantly enhancing the recovery above the 8% number.

Doug Leggate - Bank of America Merrill Lynch

Got it. Thank you for the answer. my follow-up is really, you have been very disciplined in the focus of your balance sheet and so on but when you take a right turn, obviously you are inflating your net debt to cap. It makes me wonder, given you have got so much resource opportunity, particularly the upgrade in the Leonard, is that still the right metric, the 30% net debt to cap? Is that still the label in terms of pacing your development and if you could maybe share any updated thoughts on how might try to monetize or bring forward some of those non-core assets, not much non-core, as that Eagle Ford and Bakken, through a joint venture or something? So I will now leave it there, Mark. Thank you.

Mark Papa

The write-down cost, I think I might have said, about 2% net debt penalty, if you will. We ended the year at 29% in asset to write down. We thought we would have ended the year about a 27% number on there. So you can say we have a little tighter boundary if we stick with the 30%. I think what we wanted to indicate, if you look at the bigger picture and we have the chart in our IR slide that we released this morning, that showed years of our inventory, if we assume that we turf up zero additional Greenfield plays and we have already advised you we are working on additional Greenfield plays, that two things show up.

One is the locus of future investments is likely to shift to the Permian basin more heavily than you would have expected before this earnings call just due to what we are seeing in the Leonard and the Delaware basin Wolfcamp.

The second thing is that as we develop into a potential free cash flow situation starting in 2014, in other words there were questions as to what we are going to do with the free cash flow. I think that the picture is becoming clearer that where that free cash flow is likely to go is into reinvestments into both Eagle Ford and into the Permian basin area likely, which will generate additional production growth, high rates of production growth in the out years than we would have expected otherwise.

So we are still at the camp and I know that disagrees with your thinking. We are still not leaning towards JVs in any of the plays that the our key plays, however. Hopefully that gives you an answer.

Doug Leggate - Bank of America Merrill Lynch

Yes, it does. Thanks very much, Mark.

Operator

We will go next to Leo Mariani with RBC Capital.

Leo Mariani - RBC Capital

Hey, guys, just a quick follow-up on the Eagle Ford. Obviously you guys increased your potential tremendously here. I just kind of look at some of the numbers, do some quick math, 569,000 net acres, 5,500 locations you have identified. That equates to about 103 acre spacing. You guys are talking more about 50 acres spacing. So it is fair to say that you guys have really high graded that 569,000 acres and are excluding maybe some of the untested areas in that number. So potentially if those were to work, it will drive the number higher?

Mark Papa

No, it's not so much high graded. All the acreage is good but by the time you eliminate all the subsurface areas such as faults and everything, and then by the time you honor the lease line that are in there, such as you can't drill wells across the lease lines, then you stay certain boundaries away from lease lines. The amount of effective acreage you can drill on is considerably less than that 569,000. So, that's really the difference between the 100 acres if that's what you were quoting there and effectively the, roughly 50 acres. It's really how much of that acreage can you really access, it's not in a geologic fault or. That's just due to lease line issues Railroad Commission limitation issues you can really access.

Leo Mariani - RBC Capital

All right. That's helpful. I guess, just switching gears over to the Permian, you are obviously taking your Leonard Shale estimate up tremendously 65 million Boe to 500 is a pretty big job, and you are kind of doing something similar in the Delaware with 800 million Boe. Those are pretty big numbers. It seems like the results reported, you got not a tremendous number of wells. I mean, what gives you confidence in sort of putting those pretty large numbers out there?

Mark Papa

Yes. Now, that's a good question, Leo. Both of those shales are extremely rich, the Leonard is in most places up to 200 million barrels of oil equivalent per section. And then in the Wolfcamp Shale, is even richer and thicker in some places just up to 300 million barrels of oil equivalent, so they have a lot of resource in place and a lot to work with and each play also has multiple targets and we are working with at least two targets in the Leonard on all of our acreage and in some places we have three or four targets in the Leonard.

In the Wolfcamp, we are looking at lease three targets and in some parts of our acreage also, so there is a lot of potential plays zone. When we complete the wells, we're able to isolate the each individual target and we've also had really good success in the Leonard at continuing to down space. We've tested pattern from 80 acre spacing per target and we've not seen a lot of between the wells and so that's very positive also.

Of the other things going on in all of our plays are frac technology is really increasing. With each wells, the wells are getting better because of that and we have a pretty strong history. We have 47 wells we've completed before the Leonard, so we have a lot of history on the actual production.

Then in the Wolfcamp in Delaware Basin, as you know, there is a lot of deep penetrations by vertical wells for different plays and deeper targets of years, and so on our acreage, we have over 200 well penetrations that we have gotten valves on and subsurface control for both, the Leonard and Wolfcamp, so we have a lot of confidence that the reserve potential is there and then we've been able to continue to reduce our cost on our drilling program, so we've got a lot of confidence that these plays are really very significant plays and we are excited about. They are able to generate very high rates of return on the drilling that we've done so far right now.

Leo Mariani - RBC Capital

That's really helpful. Thanks.

Operator

Operator

We'll go next to Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley

Good morning, guys. Pretty helpful update. Just follow-up on the downspacing comment one more time on Eagle Ford, I know you different lease line issues or other issues that imply 45% of your operated [resource]. On that tighter spacing, but I also presume there's some risking element on the spacing, so any comments maybe on how aggressive or conservative assumption might be currently or how the risking might progress and when you might have more data to adjustments on that potential location increases, which is effectively.

William Thomas

Yes. If you are kind of saying can you expect on the earnings call next quarter that we are going to again raise reserve in Eagle Ford for the subsequent quarter, I would say for the year 2013, you should not have any expectations that we are going to be given another number in Sand with a number locations is going up again in the Eagle Ford, so now it's going to take some time to digest.

So, there is certainly a possibility down the road, but for the next 12 months. I think the number that we have given you, the $2.2 billion is probably where we are going to sit at.

Evan Calio - Morgan Stanley

Okay, that’s helpful. Maybe a commodity question. Thanks for sharing your view on the commodity but any views on condensate pricing? I know we are beginning to see some price degradation as likely those imports are backed out of the Gulf region. Do you expect any price degradation of this higher API hydrocarbon stream? Thanks.

Mark Papa

Yes, I will give you a comment regarding condensate vis-à-vis the Eagle Ford. We have a chart in the IR slide we rolled out this morning specifically relating to the Eagle Ford. A point that we will make is that all of our Eagle Ford production is indeed crude oil and the chart that we have shows the major producers there and relative gravity of the oil or condensate production that the producers have as compiled by IETF. What you will see from that chart is that EOG is clearly the largest producer, that EOG's production is well within the oil column, in terms of gravity but many be of the rest of the producers there are actually producing condensate as opposed to oil.

But I will say is there is definitely a difficulty in marketing the condensate in the Eagle Ford area. You just have to talk to the other producers to see what kind of prices they are actually receiving for that condensate.

Evan Calio - Morgan Stanley

Very helpful. Thank you.

Operator

We will go next to Bob Brackett with Bernstein Research.

Bob Brackett - Bernstein Research

Hi, good morning. I hate to harp on the Eagle Ford downspacing but I can't resist. If I think about 40 acre spacing, you are basically picking 16 one mile laterals into a square-mile. In the past, you kind of targeted a key zone in the Eagle Ford. Is the go forward plan more of a staggered development with one offsetting in the upper and one in the lower?

Mark Papa

The answer to that is directionally no, Bob. Its wells that are spaced the quite closely together, generally in the same stratigraphic interval in the Eagle Ford as opposed to one in, say the upper Eagle Ford and one in lower Eagle Ford. That’s where you get the issue of a question that logically it would come up, wait a minute, you were quoting 450 MBoe per well and now you are quoting 400 MBoe per well. There is some inner well drainage. Bill, you may add something to that here?

William Thomas

Yes, one of the things, Bob, that we have been able to accomplish is, on our frac geometry, we have been able to increase the complexity of the surplus area that were connecting with each well and we have also been able to contain the geometry on that complexity closer to the well. So we are not fracing really long wing link kind of frac. We are really keeping that frac really close to the well and just increasing the amount of surface close to the well. That really is the big driver in harvesting more and more reserves. If you can do that, keep it close to the well and then you can drill more wells without significant interference.

Bob Brackett - Bernstein Research

And what do you think about the vertical height of these fractures? Are we looking at things that are kind of tall but skinny?

William Thomas

Well, we have them more aggressive with our fracs. More sand and more frac rates and one of the advantages that the Eagle Ford has over many of the shale plays, it has a very good upper and lower fracs barriers. So, yes, you are right. I mean the fracs are more contained close to the well but they are fully contacting the play, the 200 or 300 feet of that play in the Eagle Ford and it is creating a lot of complexity. So the increased frac rate does help that. You could connect all the play.

Bob Brackett - Bernstein Research

Thanks, and then a follow-up. In the past, really only two world-class shale oil plays and/or plays in North America, the Bakken in the Eagle Ford. As you spend more time in the Permian, is that emerging as a credible number three or is it part of a long tail of number three?

William Thomas

Yes. I think it's still certainly number three, and it's still a bit different number three. Part of that is, many of the Permian plays are still a bit comb. They are not as rich in oil. Although we are making headway on that part of it too, but just the quality of the rock the kind of metrics contribution you can get them, the Eagle Ford and the Bakken is exceptional compared to the kind of metrics contribution you can get from the Permian plays. The Permian plays are very good plays, and don't get us wrong. We are not certainly down on those, but they are still I think a bit distant PUD.

Operator

We'll go next to Charles Meade with Johnson Rice.

Charles Meade - Johnson Rice

Good morning, everyone. I want to go back to the Bakken on the question. I think Bill Thomas said in his prepared remarks was Hawkeye wells were Three Forks wells and I am curious of two things. One are those the best Three Forks wells you've seen yet and where in that Three Forks section are the place and do you see possibility for more than one bench in Three Forks?

William Thomas

Yes. Those Three Forks wells are in our Antelope area. And in the Antelope area, we do have a significant column hydrocarbon column in the Three Forks, and we have all four benches that have oil in them. That's just the well believe was drilled in the upper bench and it's certainly a good well. I wouldn't say it's any more outstanding than some of the other wells we have completed and we are working on that three forks development and we'll be testing 160-acre spacing and we will be testing multiple benches over the next over year or so, so the Three Forks, particularly in Antelope, where it has a lot of upside for us.

Charles Meade - Johnson Rice

Got it. Thank you. And also going back to, I think point maybe you glanced on a few times here. crude-by-rail marketing. I think, Mark you've kind of made illusion in your comments that you might be looking at taking crude from the Bakken to the East Coast by rail, and maybe you guys are not ready to talk about that, but if you were to start that now, when should we expect that crude might be delivered to the East Coast?

William Thomas

Well, actually we made a few spot deliveries in the last couple months to the East Coast just kind of, (Inaudible) and where we are right now is we are really just kind of doing some strategic work as to the with a plateau of new pipelines that will be the installed during late 2013, specifically to the Gulf Coast. What does that really mean life in crude differentials and then where would we want place or Bakken and our Eagle Ford crude in 2014 and 2015, and then what would we need to do to get in place change our destination, so we are really not ready to talk about that specifically other than to provide our investors that the system we have in place and the locations, where we are selling our crude today are not necessarily where we will be selling our crude in 2014 and 2015.

Operator

We'll go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Thanks. Good morning. Just following up on prior question with regards to transporting crude to different destination, what if any capital commitment would be required to shift the focus of your crude going from where you have it largely going now to the Gulf Coast, and is it baked into your 2013 guidance or to the degree that you feel that there is the need to get more crude elsewhere, would you need to raise your capital budget for that?

William Thomas

I mean, the one thing about the crude-by-rail is, it's pretty flexible. We don't think there is any capital requirement over and above what's already included in our guidance guidance. We have already got the tanker cars which is a key thing in the track access with railroads. The offloading terminal would be the issues at a different destinations. We are working on some deals there that would probably end up being joint ventures with other people. So at this stage, we don’t think that there will be huge capital commitments either in 2013 or 2014 for the offloading terminals.

So the main thing is just trying to figure out what is likely to happen with these differentials. You know, Goldman has their ideas, everybody has got their ideas, but we are proceeding on the concept that at any point in time that we will be somewhere in the U.S. where there is an advantageous differentials relative to other locations in the U.S. and our job is to see if we can make sure we can get our crude to that advantageously priced location.

Brian Singer - Goldman Sachs

That’s helpful. Then as a follow-up, going back to the Delaware basin. In the Southern Delaware basin where you reported the recent well, is that production mix that you expect going forward consistent with the production mix from that well? I think Bill until mentioned just in a couple questions ago that you are making headway on production mix and I was wondering if you could add some color to what you can do to improve the oil production mix in the Delaware and the Permian?

William Thomas

No, I think it is. I think those two wells are representative of what we will see in that particular acreage based going forward. The Wolfcamp does get more oily as you move to the north in the New Mexico in some places. We have not drilled a Wolfcamp well up there yet but hopefully that will be a bit more oily. The main thing on increasing the oil out of these combo plays is certainly the narrow rocking connected to the well's surface area is a big deal.

We also have some production techniques we are working on. I think we are not really ready to talk about those right now but we are making some headway on helping to increase the recovery of oil there but we feel really good. I think these whole combo plays are certainly more challenging as these NGL prices have weakened but going forward I believe that we will be able to technically improve those and make those plays better in the future.

Mark Papa

Yes, just to add a little bit color to that, Brian. For example, in the in the Leonard play out there, where we previously had shown that the mix was about 41%, although now we are saying the mix is about 50% oil, a lot of it is in the design of the fracs. We typically keep trying to close mouth about most of this stuff because we don’t want share our secrets but the concept of designing the fracs to not have fracs that are necessarily long fracs but have fracs that really increase the surface area near the wellbore more efficiently as opposed to just having long fracs that increases surface area far from the wellbore.

What that does is it really likely improves the ability for oil to flow in a radius around the wellbore and that is probably what we think is causing the increased oil yield. So there is things you can do on frac designs that can modify things and help in these combo plays to get more oil out of them. So I am particularly impressed with this Leonard play.

A couple reasons why they are upgraded reserves. Number one, that 55 million Boe, that’s probably have a two to three year-old reserve estimate. So it’s a very stale reserve estimate. Number two, all that acreage has been held by production. So we haven’t had any urgent lease expirations. So we haven’t been drilling frantically on it to hold leases. That’s one where even though we take our time, do our science, we purposely kept quiet, as EOG does on some of these plays until we get our Ps and Qs right, but when you take 550 million Boe at 50% oil, we have got something pretty good there and that's going to turn into a pretty significant oil play for us. And that's obviously moved up considerably on our priority list for the particularly 2014-2015 kind of timeframe for capital.

Operator

This does conclude today's question-and-answer session. Mr. Papa, at this time, I will turn the conference back to you for additional or closing remarks.

Mark Papa

I have no additional remarks. Thank you for listening.

Operator

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

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