EOG Resources Inc (EOG) 2012 Q4 法說會逐字稿

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.

Good morning, and thanks for taking the time to join us. We hope 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 EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com.

The SEC permits oil and gas companies, in their filings with 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 incorporated 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; Billy 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 include first quarter and full year 2013 guidance in yesterday's press release.

This morning, we'll discuss topics in the following order. I will 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 will finish with concluding remarks.

As outlined in our press release, for the full year 2012, EOG reported net income of $570.3 million, or $2.11 per share, and a net loss of $505 million, or $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 nonrecurring 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 of 2012. Our investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's 2012 DCF was $5.7 billion for the full year and $1.4 billion for the fourth quarter.

I will now address our operational results and 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 midpoint of our guidance; our unit costs significantly beat 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, and Trinidad volumes increased 6%. Overall, total company production grew 10% in 2012 verses 2011. Over the past three years, our organic crude and condensate gross 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 these three important financial perimeters of all large-cap ENPs. We expect further growth in each of these three metrics in 2013 as well as improvements in ROE and ROCE.

I 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 uneconomic at current gas prices. However, the drilling we have done to date holds our remaining 127,000 net acres in the Horn River, with an estimated 7 Tcf reserve potential until 2020, providing optionality for us. The other major 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 asset, 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. I have previously used the analogy of 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 the Eagle Ford to date. The 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 one year ago, and we've 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 speak to Street expectations, I will provide back-up details without dragging you through the minutia.

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 acres 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've 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 we have previously provided because there was 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 have 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 have added an estimated 600 million Boe, net potential recoverable reserves, where the 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.

Thanks, Mark.

Our Bakken and Three Forks drilling results during fourth quarter were outstanding, and our 2013 program should be one of our strongest in many years. While most of the industry Bakken/Three Forks results are trending downward, EOG results were moving in the opposite direction. In other words, our wells were getting better. There are 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 used in 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 on a per foot of treated lateral basis. For example, the Wayzetta 156-3329, a 320-acre downspace well completed in 2012, has a cumulative production of 330 Mbo in the first 320 days and 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 that our drilling program is directed to the Parshall core and Antelope Extension areas, which are some of the best acreage [parks] in the play. Two Antelope Extension wells recently completed are the Hawkeye 102-2501H, a Three Forks well flowing 2,945 barrels of oil per day, and the Hawkeye 1-2501H, a Bakken well flowing 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 22-1509H and the Wayzetta 149-1509H tested at maximum rates of 1,185 barrels 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 areas 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 pay intervals, continue to improve frac efficiency, and to optimize the recovery factor of each play. If 160-acre downspacing proves successful, this will allow us to accelerate our development program in 2014 and beyond. The takeaway from our Bakken/Three Forks asset is the wells are getting better with continued success in downspacing, 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 56-1001H 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. And, the Harrison Ranch 56-1002H was completed in the middle Wolfcamp at 377 barrels of oil per day, with 602 barrels of NGO per day and 3.9 million cubic feet of gas per day. With estimated gross reserves of 900 MBoe per well and a target completed well cost of $6.5 million, these results yield a strong 60% direct ATAX rate of return.

Our Reeve County acreage has as much as 2,000 feet of gross Wolfcamp thickness in some places and an approximately 300 million barrels equivalent per section of resource potential. We have 220 subsurface well control points 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 high rate of return drilling inventory. As cautionary note, because we have such a large inventory of opportunities across the Company, significant production growth from 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 techniques, the wells are getting better and showing a higher percentage of oil production than previously reported. Successful downspacing and the identification of multiple pay 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 number 5H, with an initial production rate of 1,162 barrels of oil per day and 183 barrels of NGL per day and 1 million cubic feet of gas per day.

As a result, we are increasing our gross reserves from 430 MBoe per well to 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 Play potential reserves from 65 million barrels of oil equivalent to 550 million barrels of oil equivalent, net to EOG. Our direct ATAX rate of return for the 2012 Leonard program was 55%, and we see this improving in 2013.

In summary, our 114,000 net acres in the Delaware Basin has multiple pay-zone 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 continue to be on track.

The Barnett Combo remains a solid 30% direct ATAX rate of return drilling program. Cost efficiencies have reduced completed well costs to $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, ethane extraction is still economic and supports our drilling program, in spite of soft NGL processing. Recent wells include the Evans A Unit-1H, 2H; B Unit-1H, with initial production rates of 573, 677, and 685 barrels of oil per day, respectively; and the Collier 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 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.

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 affected our decision to exit the Kitimat LNG project. We believe Kitimat is a good project, and with Chevron involved, the project will likely get built. However, the projected Kitimat IRR didn't 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 would be best reinvested in US 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 US 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 a marketing price advantage.

I will now address 2012 reserve replacement and finding costs. Because of the extraordinarily low 2012 gas prices and the 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 tail gas reductions. The total write off, related to price, is 3.2 Tcfe.

However, excluding these price-related revisions, our reserve replacement and finding cost metrics are excellent. We replaced 268% of production at a $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 56% at year end 2012. Our domestic crude oil replacement rate 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 of our reserves, and their 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 likely 2013 WTI prices, which we expect to be in the mid-$90s range. 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. I will 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 differential at St. James and Houston continues to be very advantageous, as compared to Cushing, it is possible that the spread between Houston and WTI may narrow late this year, as additional pipelines from Cushing and 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 and 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 is 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 our Eagle Ford ethane in the gas stream, reducing our NGL production by 4,000 barrels per day, and we're projecting 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 will 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 billion and $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 an absolute Bopd basis is the same as last year, a tall order for a company our size. I 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 US, due to 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 metric that drives 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 our 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's quite an impressive outcome.

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

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 were $700,000.

For the year, proceeds from asset sales were $1.3 billion. At 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 a 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 recorded in [Chokken] 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 the 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 for current taxes that we expect to record during the first quarter and for the full year.

Now, I will turn it back to Mark.

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 premiere 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 an EOG and an industry scale. When you 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, 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 futures prices. Fourth, our 10% dividend increase is a tangible signal of our growing confidence in our 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. Now, we'll go to Q&A.

(Operator Instructions)

Doug Leggate, Bank of America Merrill Lynch.

Thanks for all the color, Mark, on the downspacing.

You have talked in the past about continued efforts to try 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? I am curious as to what else you might do in terms of trying to lift your recovery rates? I have a follow up, please.

Yes, Doug, there's -- no, we can't say that the 8% is the final answer at all. In terms of what we are still looking at doing there, there is the continued work on potential additional spacing, improvements from frac enhancements; 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 gas injection. And we have commenced our pilot gas injection project down there in the Eagle Ford, and the reason I didn't mention it on the script is that it may be as long as two years before we really have a read on the outcome of the pilot project. I just don't even want to give a timeline on it.

But it's worth our investors knowing that the pilot project is underway, but it's not anything that we're going to be able to provide a quarter-by-quarter feedback as to how is the pilot coming, or anything like that. 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.

Got it. Thank you for the answer.

My follow up is really going back to -- you have been very disciplined with, obviously, your balance sheet and so on; but when you take a write down, obviously, you're inflating your net debt to cap. It makes me wonder, given that you've 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 right limiter, in terms of pacing your development?

And, if you could share any updated thoughts on how you might look to monetize or bring forward some of those non-core assets -- not so much non-core, but outside Eagle Ford and the Bakken -- through a joint venture or something of that nature?

I'll leave it there, Mark, thank you.

Yes, the write down cost us -- I think I am right in saying -- about a 2% net-debt penalty, if you will, on there. We ended year at 29%, and absent the write down, we probably would have ended the year at about a 27% number on there. So, you can say we have a little tighter boundary if we stick with a 30%.

I think what we wanted to indicate -- if you look at the bigger picture, and we have a chart in our IR slides that we have released this morning that shows 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're seeing in the Leonard and the Delaware Basin Wolfcamp.

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

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

It does. Thanks very much, Mark.

Leo Mariani, RBC Capital.

Just a quick follow up on the Eagle Ford -- obviously, you increased your potential tremendously here. If I look at some of the numbers, do some quick math -- 569,000 net acres; 5,500 locations you've identified; it equates to about 103-acre spacing. You are talking more about 50-acre spacing. Is it fair to say that you have really high graded that 569,000 acres and are excluding some of the untested areas in that number? And, could that, potentially, if those were to work, drive the number higher?

No, it is not so much high-graded. Really, Leo, 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 lines that are in there, such as you can't drill wells across the lease lines and you have to 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 that's not in a geologic fault, or that just due to lease line issues or Railroad Commission limitation issues, you can really access.

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 550 million BOE is a pretty big jump. And, you are doing something similar in the Delaware with the 800 million BOE, and those are pretty big numbers. It seems like the results you reported, you've got, not a tremendous number of wells -- what gives you confidence in putting those pretty large numbers out there?

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. Then, in the Wolfcamp Shale, it is even richer and thicker; in some places, it's up to 300 million barrels of oil equivalent. So, they have a lot of resource in place and a lot to work with. Each play also has multiple targets. We are working with at least two targets in the Leonard on all our acreage, and in some places, we have three or four targets in the Leonard. In the Wolfcamp, we are looking at least three targets in some parts of our acreage, also.

So, there is a lot of potential pay zones. We are able to -- when we are complete the wells, we are able to isolate the each individual target, and we have also had really good success in the Leonard at continuing to downspace. We've tested patterns on 80-acre spacing per target, and we have not seen a lot of interference between the wells, and so that's very positive also. The other thing that's going on is, like in all of our plays, our frac technology is really increasing. Each well, the wells are getting better because of that. We have a pretty strong history. We have 47 wells we have completed so far in the Leonard, so we have a lot of history on actual production. Then, in the Wolfcamp in the Delaware Basin, as you know, there is a lot of deep penetrations by vertical wells for different plays and deeper targets over the years.

So, we have -- on our acreage, we have over 200 well penetrations that we've gotten logs on and subsurface control for both the Leonard and the Wolfcamp. So, we have a lot of confidence that the reserve potential is there, and we have been able to continue to reduce our costs on our drilling program, so we have got a lot of confidence that these plays are really very significant plays. And, we are excited about them. They're able to generate very high rates of return on the drilling that we've done so far right now.

That's really helpful. Thanks.

Evan Calio, Morgan Stanley.

Very helpful update. I'll just follow up on the downspacing comment one more time on the Eagle Ford.

I know you mentioned different lease-line issues or other issues that imply 45% of your Eagle Ford acreage works on that tighter spacing. But I also presume there is some risking element on the spacing. So any comments on how aggressive or conservative that assumption might be currently? Or, how that risking might progress, and when you might have more data to adjust us on that potential location increase, which is effectively what it is?

Yes. I know -- if you are saying, can you expect on the earnings call next quarter that we are going to again raise the reserves in Eagle Ford -- or the subsequent quarter -- I'd say, for the year 2013, you should not have any expectations that we're going to be giving another number and saying -- the number of locations is going up again in Eagle Ford. It's going to take some time to digest. There is certainly a possibility down the road, but for the next 12 months, I think the number that we've given you, the 2.2 billion, is probably where we're going to sit at.

Okay. That's helpful.

Then, maybe a commodity question -- thanks for sharing your view on the commodity. Any views on condensate pricing? I know we are beginning to see some price degradation as light sweet imports are backed out of the Gulf region. Do you expect any price degradation of this higher API hydrocarbon stream? Thanks.

Yes. I'll give you a comment regarding condensate vis-a-vis the Eagle Ford. We have a chart in the IR slides 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 the relative gravity of the oil or condensate production that the producers have, as compiled by IHS. And what you will see from that chart is that EOG is clearly the largest producer and EOG's production is well within the oil column, in terms of the gravity, but many of the rest of the producers there are actually producing condensate as opposed to oil.

What I will say is, there is definitely a difficulty in marketing the condensate in the Eagle Ford area, and you will just have to talk to the other producers as to see what kind of prices they're actually receiving for that condensate.

Helpful, thank you.

Bob Brackett, Bernstein Research.

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

The answer to that is, directionally, no, Bob. It's wells that are spaced 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 the lower Eagle Ford. That's where you get the issue of -- a question that logically would come up -- wait a minute, you were quoting 450 MBO per well, now you are quoting 400 MBOE per well. And, there is some inner-well drainage.

Bill, you may want to add something to that, here.

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, or the amount of surface area that we are connecting with each well. And we have also been able to contain the geometry in that complexity closer to the well. So we're not fracking really long, wing-length kind of fracs, we are really keeping that frac really close to the well and just increasing the amount of surface area close to the well. That really is a 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.

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

We have been more aggressive with our fracs -- more sand and more frac rates. One of the advantages that the Eagle Ford has over many of the shale plays -- it has very good upper and lower frac barriers. So, yes, you're right. The fracs are more contained close to the well, but they are fully contacting the pay -- the 200 feet or 300 feet of net pay -- in the Eagle Ford and creating a lot of complexity. So, the increased frac rate helps that connect all the pay.

Thanks. Then, a follow up -- in the past, really only two world class shale oil plays and resource plays in North America -- the Bakken and the Eagle Ford. As you have spent more time in the Permian, is that emerging as a credible number three? Or is it part of a long tail of number threes?

Yes, I think it's still certainly number three, and it's still a bit distant number three. Part of that is, many of the Permian plays are still a bit combo. They are not as rich in oil -- although we're making headway on that part of it, too.

Just the quality of the rock, the kind of matrix contribution you can get from the Eagle Ford and the Bakken is exceptional compared to the kind of matrix contribution you can get from the Permian plays. The Permian plays are very good plays -- don't get us wrong. We are not, certainly, down on those, but they are still, I think, a bit distant third.

Charles Meade, Johnson Rice.

I want to go back to the Bakken on a question. I think Bill Thomas said in his prepared remarks, those Hawkeye wells were Three Forks wells. And I am curious on two things -- one, are those the best Three Forks wells you have seen yet? And where in that Three Forks section are they placed? Do you see possibility for more than one bench in the Three Forks?

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. We have all four benches that have oil in them. That particular well, I believe, is drilled in the upper bench, and it is certainly a good well. I wouldn't say it's any more outstanding than some of the other wells we've completed.

We're working on that Three Forks development, and we'll be testing 160-acre spacing. And, we'll be testing multiple benches over the next year or so. So, the Three Forks, particularly in the Antelope area, has a lot of upside for us.

Got it. Thank you.

Also, going back to -- I think a point we maybe glanced on a few times here -- crude-by-rail marketing. I think, Mark, you made an allusion in your comments that you might be looking at taking crude from the Bakken to the East Coast by rail. Maybe you guys aren't 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?

Actually, we have made a few spot deliveries in the last couple months to the East Coast, just kind of as trial balloons. Where we are right now is, we are really just doing some strategic work with the plethora of new pipelines that will be installed during late 2013, specifically to the Gulf Coast. What does that really mean for likely crude differentials? Then, where would we want to place our Bakken and our Eagle Ford crude in 2014 and 2015? And then, what would we need to do to get in place to change our destination?

So, we're really not ready to talk about that specifically, other than to advise our investors that the system we have in place and the locations where we're selling our crude today, are not necessarily where we'll be selling our crude in 2014 and 2015.

Brian Singer, Goldman Sachs.

I'm just following up on the part question with regards to transporting crude to different destinations. 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? Is there anything baked into your 2013 guidance to the degree that you feel there is the need to get more crude elsewhere? Would you need to raise your capital budget for that?

No. 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. We have already got the tanker cars, which is a key thing, and the track access with railroads. The offloading terminal would be the issues at different destinations, and we're working on some deals there that would probably end up being joint ventures with other people.

At this stage, we don't think that there would be huge capital commitments, either in 2013 or 2014, for the offloading terminals. The main thing is just trying to figure out what is likely to happen with these differentials and as -- Goldman has their ideas; everybody's got their ideas. We're proceeding on the concept that, at any point in time, there will be somewhere in the US where there is an advantageous differential relative to other locations in the US, and our job is to see if we can make sure we can get our crude to that advantageously priced location.

That's helpful.

Then as a follow-up, going back to the Delaware Basin -- in the southern Delaware Basin, where you reported the Reeves well, is the production mix that you expect going forward consistent with the production mix from that well? And, I think Bill mentioned in a couple questions ago that you're making headway on production mix. I was wondering if you could add some color to what you can do to improve the oily production mix in the Delaware and the Permian?

I think it is. I think those two wells are representative of what we'll see in that particular acreage base going forward. The Wolfcamp does get more oily as you move to the north into New Mexico and some places; so hopefully -- 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 amount of rock that connects to the well, the surface area, is a big deal. We also have some production techniques we're working on. I think we're not really ready to talk about those right now, but we are making some headway on helping to increase the recovery of oil there. We feel really good. I think these whole combo plays are certainly more challenging as these NGL process have weakened. But I think going forward, I believe that we'll be able to technically improve those and make those plays better in the future.

Just to add a little bit of color to that, Brian -- for example, in the Leonard Play out there, where we previously had shown that the mix was about 41% oil, and now we are saying the mix is about 50% oil, a lot of it is in the design of the fracs. We typically keep closed mouth about most of this stuff because we don't want to 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 well bore more efficiently, as opposed to just having long fracs that increase surface area far from the well bore. What that does is, it really, likely, improves the ability for oil to flow in a radius around a well bore, and that's probably what we think is causing the increased oil yield. So, there's things you can do on frac designs that can modify things and help in these combo plays to get more oil out of them. I'm particularly impressed with this Leonard Play.

The reason we haven't -- couple reasons why we've upgraded the reserves. Number one -- that 65 million BOE, that's probably 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. We haven't had any urgent lease expiration, so we haven't been drilling frantically on it to hold leases.

That's one where we have been able to take our time, do our science, we purposely kept quiet, as EOG does on some of these plays, until we got our Ps and Qs right. When you take 550 million BOE at 50% oil, we've 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, particularly 2014, 2015 timeframe for capital.

That's very helpful. Thank you.

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

I have no additional remarks. Thank you for listening.

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