EOG Resources Inc (EOG) 2011 Q4 法說會逐字稿

Good day, everyone, and welcome to EOG Resources' fourth quarter and full year 2011 earnings 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 the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 2011 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. We incorporate those by reference for this call. This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found on our website, at www.EOGresources.com.

The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast, including those for the Eagle Ford, may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary note to US investors that appears at the bottom of our press release and Investor Relations page of our website.

With me this morning are Bill Thomas, President; Gary Thomas, COO; Tim Driggers, Vice President and CFO; Maire Baldwin, Vice President of Investor Relations; and Jill Miller, Manager of Engineering and Acquisitions. An updated IR presentation was posted to our website last night. We included first quarter and full year 2012 guidance in yesterday's press release.

This is our 50th quarterly earnings call since we became a fully public company. Fittingly, we have a lot of positives to discuss this morning, including exciting news from several Texas-based liquids resource plays. I'll discuss topics in the following order. I'll first review our 2011 fourth quarter and full year net income and discretionary cash flow. Then I'll provide operational results. Followed by reserve replacement and our 2012 business plan. Tim Driggers will then discuss financials and capital structure. I'll follow with our macro view, hedge position and finish with concluding remarks.

As outlined in our press release, for the fourth quarter EOG reported net income of $120.7 million or $0.45 per diluted share, and $1.091 billion or $4.10 per diluted share for the full year 2011. For investors who focus on non-GAAP net income to eliminate mark-to-market impacts in certain nonrecurring items, as outlined in the press release, EOG's fourth quarter adjusted net income was $309 million, or $1.15 per diluted share, and $1.0 billion or $3.79 per diluted share for the full year. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the fourth quarter was $1.3 billion, and $4.57 billion for the full year.

I'll now address our 2011 operational results and key plays. For both the fourth quarter and full year, our liquids and total Company production exceeded the midpoint of our guidance. For the full year 2011, we achieved 52% total Company crude oil growth, with a 61% increase in US crude oil production. Total Company liquids increased 48%, all organic. This is clearly best-in-class for a company our size. And is right on top of the 49% total liquids growth projection we provided you exactly a year ago on this same earnings call. Since 2007, EOG's crude and condensate growth and total liquids growth have each increased at a compounded annual growth rate of 38%.

Our 2011 North American gas production declined 7% versus 2010, from a combination of asset sales and lack of drilling. Total Company overall production growth was 9.4%. Again, very close to the 9.5% estimate we provided last February. Also, for the full year, our aggregate unit lease and well, transportation, and DD&A costs were lower than the aggregate midpoint guidance.

As I've said on multiple earnings calls, EOG's focus is on year-to-year, year-over-year increases in EPS, EBITDAX, and discretionary cash flow. Our path to achieve this goal is strong liquids growth. For 2011, compared to 2010, our GAAP EPS growth was 551%, non-GAAP EPS growth was 227%, adjusted EBITDAX growth was 55%, and discretionary cash flow growth was 52%. Based on current NYMEX prices, we expect continued growth in these metrics in 2012. In 2011, 67% of our total Company wellhead revenues came from liquids. In North America, 72% of wellhead revenues came from liquids. This strong liquids growth is generated by the first mover positions we captured in horizontal domestic oil plays. We presently have four of these, each of which we believe is world class.

I'll now discuss each of these four plays, starting with the Eagle Ford. The Eagle Ford was our biggest oil growth engine in 2011, and will again be the biggest component of our 2012 growth. A long-time oilfield axiom is that big fields tend to get bigger over time, and that's certainly the case here. This continues to be the hottest and highest reinvestment rate of return play in North America. EOG has the largest and best situated acreage position in the crude oil window. We continue to be the largest crude oil producer in the Eagle Ford, with net after royalty production of 66,000 barrels of oil equivalent per day at year-end, 88% of which was liquids. Our press release contains multiple well results, including the six outstanding wells on the Henkhaus lease which IP-ed at an average of approximately 3,100 barrels of oil per day, with 560 barrels per day of NGLs, and 2.8 million cubic feet a day of natural gas per well. This is the best package of wells we've drilled to date.

Rather than provide you a well by well recitation, I'll provide some content regarding the overall play. There are four key points. First, we now have up to 200 days of well performance from multiple down spacing tests. We've concluded that our original 130-acre spacing was too wide to maximize NPV and recovery factors. Based on reservoir modeling and pilot results, we now calculate that spacing of 65 to 90 acres is more appropriate, and will vary across the field, depending on a number of factors including lease configuration, geology and reservoir conditions. Using this new spacing, we have a total of 3,200 additional wells yet to drill, plus the 375 we've already drilled. For a total potential recoverable reserve estimate of 1.6 billion barrels of oil equivalent net after royalty. This is a 700 million barrel oil equivalent net after royalty or 78% increase from our previous estimate.

Just this net increase of 700 million barrels of oil equivalent is larger, we believe, than any net domestic discovery by any company in recent history. The total size of 1.6 billion recoverable barrels is the biggest US discovery net to any one company since Prudhoe Bay in the late 1960s, in our opinion, including the deepwater Gulf of Mexico. We tend to roll over some of these numbers and sometimes one gets lost in the numbers. But this is an extremely significant number and I want to quote it to you again. The total size of 1.6 billion barrels of oil equivalent net after royalty that we've captured in the Eagle Ford, we believe is the biggest US discovery, including the entire deepwater Gulf of Mexico, net to any one company, since Prudhoe Bay in the late 1960s.

This is not a pie in the sky number. Our 61% 2011 domestic oil growth was driven by this asset and proves this is the real deal. The number is substantiated by results from the 375 EOG horizontal oil wells drilled in the Eagle Ford. Plus hundreds of horizontal wells drilled by offset operators. The 3,200 additional wells were determined using our 572,000 net acres and derating that number to allow for subsurface faults or other drilling limitations related to varying lease ownerships.

Now, I know there are a lot of analytical people listening on this call. Your tendency will be to take our 572,000 net acres, divide by a mix of 65- to 90-acre spacing, and you'll come up with a much higher well count and an even larger reserve number. We would ask that you refrain from this calculation because, as with any play, a portion of our acreage is eliminated either because of subsurface faults or drilling limitations related to differing lease ownerships. In addition, we slightly raised our net after royalty per well reserve estimate to 450 MBOE based on recent well improvements that we've highlighted in the last several earnings releases. The outcome of our down spacing test is that we've taken the original 4% recovery factor and are now using 6%. Based on geologic analysis, logs and studies, we now estimate the net after royalty oil in place under our acreage, to be 27.9 billion barrels of oil equivalent.

The second point relating to the Eagle Ford is that our Wisconsin sand mine is now up and running. We currently expect our average 2012 Eagle Ford well cost will be $5.5 million, generating an 80% direct after-tax reinvestment rate of return. We believe these are the best economics in the entire industry for a large-scale hydrocarbon play. Our well costs are consistently $1 million to $2 million less than other operators drilling similar wells.

Third, we currently have 572,000 net acres in the Eagle Ford oil window. Now, that we drilled 375 net wells, we anticipate we'll be able to readily hold all this acreage. For example, for lease retention, we only need to drill 40 wells this year. Last year we drilled and completed 244 net wells. This year we expect to drill approximately 280 net wells to optimize development.

Fourth, during 2011 we encountered no major liquids or gas take-away issues relating to the Eagle Ford. We still are on the bubble regarding take-away capacity for the next five months until mid year when the new Enterprise gas plant and crude oil pipeline are in service. This will improve both our logistics and netbacks. To simply summarize the Eagle Ford, I can't think of a more substantial, profitable oil discovery in the entire industry in recent times. It's huge, located in Texas, has excellent economics, and it's not speculative.

I'll now shift to the Barnett Combo play, where our consistently good results have probably been overshadowed by the higher profile Eagle Ford and Bakken. EOG is the largest crude oil producer in the Barnett. The bottom line for the Barnett Combo is that we grew our liquids volumes by 107% in 2011, from 13.2 thousand barrels a day to 27.3 thousand barrels a day. We expect this to be our second largest liquids growth contributor in 2012 also. This play has become a consistent and profitable work horse for us. Roughly 85% of the revenue stream from these wells emanates from liquids, 41% of which is crude oil. Typical direct after-tax reinvestment rates of return, even with current low gas prices, are approximately 40%.

We have a cost advantage in the Combo because we use sand from one of our own sand mines. Last year we drilled 249 net Combo wells, and we expect to complete an additional 200 net wells in 2012. We added 25,000 core area acres during 2011 and now have a total of 200,000 net acres.

Now, I'll discuss results from our 240,000 net acres of Permian Basin, Wolfcamp, and Leonard assets, which we expect will be our third largest liquids contributor in 2012. We drilled 47 net wells in these plays last year, and plan to drill 112 net wells this year. Our overall results continue to be some of the best in the industry, as noted in our press release, with several wells with IP rates over 1,000 barrels of oil per day, plus NGLs and gas. We made good progress last quarter in reducing our well costs. After we begin using our self-sourced sand this year, we expect our typical Wolfcamp well will be about 280 MBOE net after royalty for $5.5 million completed well cost. A typical Leonard well will be 300 MBOE net after royalty for a $6 million well cost. Both of these plays have a combo product mix, roughly 40% oil, 30% NGLs and 30% dry gas.

Direct after-tax reinvestment rates of return are 55% for the Wolfcamp and 45% for the Leonard. Until recently, all our well results have been from the middle Wolfcamp interval. However, we just achieved our first success in the upper Wolfcamp. The University 9 # 2803H tested at 883 barrels of oil per day, with 68 barrels per day of NGLs and 400 Mcf a day of natural gas. We're currently evaluating whether this upper zone is a viable target across our acreage.

In the North Dakota Bakken we continue to achieve consistent results. The play contributed to the 13% total liquids growth realized in our overall Rocky Mountain operating area in 2011 over 2010. We're reducing our Bakken rig count in 2012 because a majority of our acreage is now vested and we, therefore, expect 2012 volumes to decline a bit. Some analysts have recently noted that Bakken economics may be less than stellar for many companies. Fortunately for EOG, we have the Crude-By-Rail system that gives us a netback advantage. We also started to self-source some of our sand needs giving us a cost advantage. In EOG's case, I'll also point you to a Bakken reserve chart in our IR Presentation posted on our website. An independent analysis of all 2,428 Bakken laterals completed in the basin by the industry to date shows that EOG has the highest per well reserves of any company.

During 2012, we'll be attempting to improve our Bakken recovery factor by testing down spacing in our core area, similar to what we've done in the Eagle Ford. You may recall that we drilled our core area with 640-acre spacing which is the widest spacing used in the Bakken by any operator. We have drilled multiple down space wells recently. A recent well, the Fertile 48-0905H, confirms our optimism with an IP rate of 1,324 barrels of oil a day. We believe that down spacing to 320 acres may increase reserves, but the magnitude of the potential reserve increase is much less than the Eagle Ford. It's about 50 million barrels net. We're also going to commence a Bakken water flood pilot this year to see if we can further improve the oil recovery in the field. We drilled 69 net Bakken and 10 net Three Forks wells in 2011 and plan to drill 60 total net wells in 2012.

Regarding other North American oil plays in the Niobrara we'll be completing a number of wells that we drilled last year. We'll continue to evaluate and optimize completion techniques. Our Mid-Continent Marmaton and Wyoming Powder River Basin plays exhibited good recent results. In Ellis county, Oklahoma, the Opal 31 # 2H was drilled as a horizontal oil producer in the Marmaton, and turned to sales at 870 barrels of oil per day with 1.3 million cubic feet a day of rich natural gas. The Glen 25 # 2H was completed at 502 barrels of oil per day with 1.2 million cubic feet a day of rich natural gas. EOG has 90% and 42% working interest, respectively, in these wells.

In the Wyoming Powder River Basin we have two rigs drilling in the Turner formation. The Arbalest 9-23H well was completed to sales at 390 barrels of oil per day, with 2.8 million cubic feet a day of rich gas. We have 52% working interest in this well. The Arbalest 42-14H was completed to sales at 391 barrels of oil per day, with 2.8 million cubic feet a day of rich gas and we have 83% working interest in this well. The Crossbow 20-06H and 52-18H wells were completed at 270 and 411 barrels of oil per day, respectively, both with 3.5 million cubic feet a day of rich natural gas. We have 69% and 100% working interest in these wells. The Niobrara, Marmaton and Powder River Basin will continue to be contributory but not game-breaking liquids plays for EOG.

In Canada we'll continue developing our Waskada area and we'll drill 126 net wells in 2012 compared to 94 wells last year. We don't expect large growth from this area in 2012 due to a slow ramp-up in operations, and minor dispositions. Two recent wells had production rates of 418 and 480 barrels of oil per day and are among the best wells in the play to date. In the British Columbia Horn River Basin we committed the minimum drilling capital required to hold leases in 2011, and will do so again in 2012. After our 2012 drilling program, all of our 160,000 acres will be converted to 10-year leases. The Kitimat LNG project continues to progress. Key items we need to establish before making a final investment decision are a detailed project cost estimate, and obtaining an oil indexed offtake contract. We expect final investment decision will be a second half 2012 event.

Outside North America, we have two areas of oil activity. In the East Irish Sea we expect to commission our Conway field and production facilities in early 2013. Production will likely peak at 20,000 barrels of oil a day net, sometime this year. In Argentina, we're currently drilling our first horizontal Vaca Muerta oil shale well and we expect results in the third quarter. Additionally, we expect our 2012 Trinidad natural gas production to be essentially flat with 2011 levels. We are devoting 10% of our 2012 capital to dry gas activities to perpetuate our acreage. The good news is that by year end our go-forward drilling requirements to hold acreage in the Haynesville, Marcellus and Horn River will be quite small. We'll expand the use of our self-sourced frac sand to our Marcellus activities during 2012.

I'll now address our 2011 reserve replacement and finding costs. For the total Company, we replaced 167% of our production at a $19.68 per BOE all-in cost including reserve revisions. Total Company proved reserves increased 5.3% to 2.054 billion barrels of oil equivalent. Excluding the impact of producing asset sales, total Company net proved developed reserves increased 9% overall, and 8% in North America. In the US, we replaced 216% of our production. From drilling alone in the US, our finding cost was $15.97. In both North America and the US, 72% of our reserve adds were liquids. Our overall reserves went from 28% liquids in 2010 to 36% in 2011 reflecting our liquids focus. Our total liquids replacement was 465%. Our total liquids reserve increased 39% year-over-year. Overall natural gas reserves decreased due to reduced drilling for dry gas, producing property sales, and adjustments due to both low gas prices and well performance. These are strong overall numbers and with our low finding costs are supportive of the high liquids margins we're currently generating.

For the 24th consecutive year DeGolyer and MacNaughton has done an engineering analysis of our reserves. Their overall number was within 5% of our internal estimate. Their analysis covered 85% 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'll address our 2012 business plan. We expect our 2012 total CapEx to be in the range of $7.4 billion to $7.6 billion, of which approximately $1.2 billion will be devoted to facilities, midstream and other infrastructure. We expect 90% of our CapEx will be focused on liquids-rich plays. We are increasing our previous 27% total Company 2012 liquids growth target to 30%. We are now targeting 30% total liquids growth consisting of 30% oil and 30% NGL growth year-over-year. I'll mention that this growth is back end loaded with the real liquids growth showing up in the third and fourth quarters. During the first quarter, we are adding frac spreads in a number of plays and we'll have pattern wells offline due to offset fracs. We'll also have some gas processing capacity down time in some of our Texas liquids-rich plays, and in addition, we expect some liquids dispositions in the first quarter. We've taken all this into account in the first quarter guidance. We have a very deep liquids drilling inventory. I previously mentioned an additional 3,200 drilling locations in the Eagle Ford.

We remain committed to managing a conservative financial structure. In addition to gas properties we are selling some working interest positions in non-operated oil and liquids-rich production this year to maintain our 30% limit on the net debt to cap ratio. We intend to divest $1.2 billion of acreage in producing properties, of which we've closed on $340 million of primarily gas properties year-to-date. We have an additional $50 million in progress. We expect most of the remaining 2012 sales will consist of either outside operated oil properties or non-core liquids-rich gas assets. We expect to sell over 3,000 barrels per day of liquids this year on an annualized basis and have taken this into consideration in the guidance for full year 2012 that we issued last night.

As previously stated, we have zero interest in growing North American gas volumes. We expect our North American natural gas volumes to decline 11% year-over-year in 2012 due to dispositions and severely limited natural gas capital investment. However, our game plan is to preserve our large dry gas core resource play positions, so we can exploit them several years down the road when gas prices improve. Our total aggregate production growth will be 5.5% this year. But because 200% of the growth emanates from liquids, and at the current 35 to 1 oil to gas price ratio, we expect to generate strong 2012 growth in EPS, EBITDAX and discretionary cash flow. Based on the current NYMEX strip we expect that our 2012 North American revenue ratio will be 84% liquids and 16% gas compared to only 29% from liquids just four years ago. When you consider that approximately half of our 2012 North American gas is hedged, that means that only about 8% of our North American total revenues are exposed to spot gas prices. Simply put, we think we're better situated than any other large cap E&P to deal with the current natural gas price environment.

I'll now turn it over to Tim Driggers to discuss financials and capital structure.

Good morning. Capitalized interest for the quarter was $13.5 million, and $57.7 million for the full year. For the fourth quarter 2011, total cash exploration and development expenditures were $1.66 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment, were $154 million. Total acquisitions for the quarter were $200,000, and $4.2 million for the year. For the full year 2011, total exploration and development expenditures were $6.47 billion, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property, plant and equipment were $656 million. For 2011, approximately 10% of the drilling program CapEx was exploration, and 90% was development. Approximately 20% of the CapEx was allocated to dry gas drilling.

For the full year 2011, proceeds from asset sales were $1.43 billion. At year-end 2011, total debt outstanding was $5.0 billion. The debt to total capitalization ratio was 28%. At December 31, we had $616 million of cash on hand, giving us non-GAAP net debt of $4.4 billion for a net debt to total cap ratio of 26%. The effective tax rate for the fourth quarter was 50%, and the deferred tax ratio was less than 1%. Similarly, the effective tax rate for the year was 43%, and the deferred tax ratio was 61%. We also announced another increase in the dividend on the common stock. This is the 13th increase in 13 years. Effective with the next dividend, the annual indicated rate is $0.68 per share, a 6.25% increase.

Yesterday we included a guidance table with the earnings press release for the first quarter and full year 2012. For the first quarter, the effective tax rate is estimated to be 35% to 50%. For the full year 2012, the expected effective tax rate is 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. Regarding price sensitivities, with our current hedge position in 2012, for each $1 move in crude oil prices net income is impacted $32 million, cash flow is impacted $47 million. For each $0.10 move in natural gas prices, net income is impacted $11 million, and cash flow is impacted by $16 million.

Now I'll turn it back to Mark.

Thanks, Tim. Now, I'll provide our views regarding macro hedging and concluding remarks. Regarding oil, we still think that the global supply/demand balance is tight and that fundamentals dictate the current $100 WTI price. The upside risks are mainly geopolitical. The downside risk is a second global recession. For that contingency we've recently increased our crude oil hedge position. For 2012, as a percent of North American oil production, we're approximately 23% hedged at $104.95. We're 33% hedged at $105.36 for February 1 to June 30, and 14% hedged at $104.26 for the second half of the year. I'll also note that we expect to commission our St. James crude unloading facility in April. Based on the current WTI LLS differential, we would plan to move up to 100,000 barrels a day from different areas to take advantage of the crude price uplift at St. James.

We continue to have a very cautious outlook regarding 2012 natural gas prices. Fortunately, as a percentage of North American gas, we're 45% hedged at $5.44 for the year. We've recently layered on 150 million cubic feet a day of hedges for 2013 and 2014 at $4.79. Please see the table that was included in our earnings press release for the details of our hedging contracts.

Now let me summarize. In my opinion, there are a lot of important points, eight in total, we would like you to take away from this call. First, the game plan we articulated several years ago is working. We've captured world-class, low-risk, liquids positions that are driving the strongest organic liquids growth, primarily oil, of any large cap independent. In parallel, our EPS, adjusted EBITDAX and discretionary cash flow are growing at high rates. We expect this to be a multi-year trend. Second, we're accomplishing this game plan with relatively low net debt which was 26% at year-end.

Third, our four liquids plays, the Eagle Ford, Barnett Combo, Bakken and Wolfcamp/Leonard constitute the most powerful horizontal liquids arsenal of any independent E&P. Each is world-class in size, is located in the on-shore, lower 48, in producer-friendly states, and generate strong reinvestment rates of return. Additionally, we believe that both public and sell side data indicate EOG is achieving the highest liquids reserves per well at the lowest cost in each play. I'll also note that our front-end leasehold costs were likely the lowest in industry for each play.

Fourth, with our expanded Eagle Ford reserve estimate, we feel even more confident that our estimated potential reserve recoverable of 1.6 billion barrels of oil equivalent, net after royalty, Eagle Ford asset is the largest net oil reserve accumulation found in the US in the past 40 years. Further, we believe that this play likely generates the highest reinvestment rate of return opportunity in the entire E&P industry for a large-scale play. Fifth, our Barnett Combo, North Dakota Bakken and Permian Basin plays are all performing as we expected. All of these have long-term growth upside.

Sixth, we have a plan to deal with our 2012 funding gap. Already we're nearly one-third of the way towards our 2012 property disposition target. Because of our liquids growth, our 2013 funding gap narrows considerably. Or, since a lot of our acreage will be vested by then, we could decelerate CapEx and achieve only robust instead of outstanding 2013 liquids growth.

Seventh, with two EOG sand mines now in operation and our Crude-By-Rail facilities in the Bakken, Eagle Ford, Cushing and St. James, we're comfortable that we can both reduce well costs and continue to obtain the highest oil netbacks. We have recently seen differentials at Clearbrook, Minnesota increase to $15 to $25 off of WTI, and as much as $42 below LLS for Bakken-related production. Using our own Crude-By-Rail facilities in North Dakota, we are currently transporting approximately half of our Bakken oil from Stanley to Cushing to capture the higher margins. During the second quarter, we'll have our St. James rail unloading facility in service, giving us the flexibility to quickly react to these types of market conditions. We can then avoid local market disconnects and sell our crude off of either WTI or LLS benchmarks.

There are a number of new crude-by-rail projects planned for this year. What's important for EOG is that we secured both the loading and off-loading facilities. We have origination facilities in Stanley, North Dakota and in the Eagle Ford. We have off-loading or destination facilities at both Cushing and St. James. Unit trains require tremendous amounts of real estate and a secure supply of crude oil. As part of our marketing strategy we put both pieces in place early on.

Finally, there are at least three significant discriminators that separate EOG from the pack. First, we have the four best domestic liquids resource plays in the industry, bar none. Second, our ownership in these four plays is 100%. We don't have any JVs. Our Eagle Ford acreage is an example of why we've shunned JVs on our major oil plays. If we had done a JV a year or two ago, we would effectively have given away a portion of the 700 million barrel Eagle Ford upside that we just announced. Lastly, we're unique in that we're the only Company that's reduced its North American gas production in 2009, 2010, 2011, and plan to do so again in 2012. We think that's a rational business response to chronically low gas prices and that's what our shareholders expect of us.

Thanks for listening. Now we'll go to Q&A.

(Operator Instructions) Doug Leggate with Bank of America-Merrill Lynch.

I've got a couple of questions. Actually, one specific question on the Eagle Ford, and one follow-up, if I may. You've clearly got a world-class asset here. And obviously congratulations on the results that you've come up with on this. My question's around the constraints on basically how your drilling plans have changed relative to your prior reserve estimate. And what I'm really getting at is -- a lot of value could potentially be accelerated if you accelerate the drilling program. But I'm just wondering what your thoughts are around that in the context of your balance sheet limitations and the number of wells that you plan to drill. And I've got a follow-up on that subject, please.

Yes, Doug. The real limitation on how much more we can ramp up the Eagle Ford activity level from current levels is personnel, and I'd say, learning curve knowledge. On the personnel side, for example, if we said -- wow, we just increased our reserves considerably, we're going to double activity in 2012 over expectations, we would flat be out of control in terms of being able to intelligently manage that increased investment. We just don't have enough qualified technical people to do that. So that's one issue.

The other issue is that it's obvious that we're learning quite a bit as we go on in this Eagle Ford play. You can tell that from the improved quality of our well results that we've reported each quarter. Obviously, the spacing is something we're learning more. So, we're going to take this at a moderate pace because we're going to be a lot smarter a year or two from now than we are today, relating to this asset.

So, it is possible that, with the relative size increase that we just announced, that in 2013 and later we may elect to accelerate development of this. But it's really not so much on the capital side. It's going to be more a function of -- have we got the people qualified to handle a further step-up. And have we got our learning optimization such that we could, say, dramatically increase activity even more on there. So it's a complicated picture. You can't really look at it on just advancing net present value without considering these other items, Doug.

What's your follow-up question?

My follow-up's really on -- you talked about upwards, 4% to 10% is a recovery range you ultimately think you could maybe move to at some point. Maybe I'm being a little optimistic there. You're currently at 6% on your assumptions. What would it take for you to take that number higher? I'll leave it there. Thanks.

Yes, I'm not going to commit to a number in terms of what's the highest percent we could think about. But it's probably in that range of 10% to 12%, really, in terms of what we see today with today's technology. There's two more steps here. We need to determine is this 65- to 90-acre spacing, is that the most dense we can drill, or should we be even looking at more dense.

The other possibility here is secondary recovery. And we mentioned on the call that we'll be initiating a pilot project in the Bakken to get more oil out of the ground using water injection. In the Eagle Ford, we probably would not try water injection, but we have some other things in mind there. So it's quite likely that within the next 12 to 18 months we'll have a pilot project going in the Eagle Ford of a secondary recovery nature that we hope would be successful. But we'll just have to play it out.

With 28 billion barrels of oil net, in place under our acreage, and improving recovery factors, this is clearly the single most important thing we can be doing here at EOG. And we're giving it appropriate focus.

Thanks a lot, Mark. I appreciate your answers.

Brian Lively with Tudor, Pickering, Holt.

Mark, on the Midland Wolfcamp results, it appears that, at least to me, the early rates versus the 280,000-barrel equivalent EURs, even on an after-royalty basis, it seems like those two don't jive. Can you just comment on what you're seeing from a curve standpoint as you get these update and higher rates?

Yes, Brian, we are making progress. We continue to increase the lateral length. We're also working on the frac designs to improve the wells and the recoveries. And we're working on the spacing patterns, too. So, we did update the reserve model last year, one time. The thing that we're really evaluating there is we test these various spacing patterns, and we down-space to tighter spacing, we're just trying to give us enough information and enough time to fully evaluate the effect on the ultimate EURs on the well. So, at this point, the 280 MBoe kind of wells on the model that we're using, and it could increase over time, but we're not ready to do that yet. But the play is going really well. We're focused primarily on developing the middle zone, and the numbers that we're using for the reserve per well are conservative.

Okay. That's helpful. My second question is just on the Q1 volumes. 2012 looks great. Q1 volumes are flattish sequentially. Can you guys go into some more detail on the drivers behind that? Thank you. I'll hang up.

Yes, Brian. Three different drivers on the Q1 volumes. We've always said on these resource plays -- you can't just take a straight line quarter to quarter to quarter to quarter and assume that our production growth is going to be that way. The biggest single component of the lumpiness in our production growth is what we call pattern drilling and fracking. If you notice in those Henkhaus wells, for example, in the Eagle Ford that we mentioned to you on the press release there, typically what we do there is we drill four or five of those wells. We don't frac any of them individually. And then we wait until we get all the wells drilled. Then we line them up and frac them, one, two, three, four, five, without producing any of them. And then when they're all fracked, we turn them all on at one time. So you get a big burst of production, but it's just a function of how many wells have you drilled in the pattern, what's your frac schedule and everything.

In the first quarter, we've got really I'd say an abnormal amount of wells that we're going to be pattern drilling and fracking. So, that's affecting it. We've also got some down time in some gas processing plants that we're anticipating that's going to hurt some of our NGL production, and oil production from some of our combo areas. And then the last thing is a little bit of property dispositions that, as we mentioned, because the gas market is so weak, the majority of our $1.2 billion worth of property dispositions this year are going to have some liquid component with them. And so we're trying to get those scheduled and timing.

So, you can expect that the first quarter and potentially the second quarter are not going to have strong year-over-year or quarter-over-quarter growth numbers. Excuse me, the year-over-year is going to be very strong in the first quarter. I believe it's a number like 40%, 40%-plus. But we just caution you -- don't just take a straight line on our quarter-to-quarter growth in 2011, and just extrapolate that in 2012.

Next question?

Leo Mariani of RBC.

Just on the Eagle Ford, wanted to see if you could comment on whether or not you're seeing any interference on your down-spaced wells, you are going to 65 to 90 acres. I know you don't have that much production history, but could you just comment on what you're seeing there? And whether or not you think you maybe need quite a bit more time before seeing that?

Yes, we think we've seen enough to feel pretty comfortable on the down-spacing in terms of evaluation. To be honest with you, on many of the down-spacing patterns, we found out that the down-space wells are better and stronger than the original widely spaced wells. And, of course, if we were having interference, it would be just the opposite of that.

And what we're seeing is the effects of two things. One, the original spacing that we had was just too wide to drain the areas. And the second thing is that those old wells may have been, say, one year, two years old. Now we're coming in between them and drilling, and our completion techniques have improved considerably during that time frame. The data from the down spacing, once we interpret it, I would classify as a slam dunk. That 130-acre spacing was too wide.

So, the data, when you analyze it, is pretty unambiguous really. And that's why I think a lot of people were expecting that sometime perhaps later in 2012 we would be announcing down spacing conclusions. But the data is pretty crystal clear.

Okay. In terms of your NGL growth guidance for 2012, you took it up pretty significantly. I just wanted to get a sense of what's driving that, whether or not maybe there was some higher than expected NGL cuts at any of your wells here.

Yes, actually, Leo, to be honest with you, the previous numbers that we had for liquids growth expectations 2012 were 30% oil and I believe the number was 16% NGLs. And now we've jumped the NGLs to 30%. Those previous numbers were about 18 months, maybe 24 months old. You'll remember when we had an analyst conference several years ago, we gave a three-year forecast for '10, '11 and '12. And we really never moved those '12 numbers. So, the 30% NGL number currently is, frankly, just simply updating a number that was stale even 12 months ago. It's not that we're seeing a huge influx of increased NGL mix or anything like that. It's really, we're just updating a stale number.

All right. That's great. And are you guys adding acreage still in some new North American plays as well? I know you've mentioned that in the past.

Yes. We've got three goals -- and we highlight that on one of the page in our IR book -- that are our goals for this year. The first goal is to find some new greenfield North American horizontal liquids plays. And we're working feverishly on that. The second goal was to improve recovery factors in some of our larger plays that we've already exposed. And today, you saw the results from the Eagle Ford on that. And we mentioned that in the Bakken we're looking at two things there. One is down spacing, and then the second is secondary recovery.

And then the third over-arching goal for this year is to find a large horizontal oil accumulation outside North America. And you heard us mention this Vaca Muerta shale that we'll give you more details on as the year progresses. So, in all three of those goals, those are still our targets for this year. And clearly we've nailed goal number two. And goals number one and three, hopefully we'll have good results by the end of the year.

All right. That's great. Thanks, guys.

Brian Singer of Goldman Sachs.

Going back to the Wolfcamp shale, a couple questions there. First, you highlighted in your comments that you would expect a combo, like Barnett Combo, mix of oil, gas and NGLs. The IP that you highlighted though, seemed to have a little bit more of an oilier mix, and I wondered if you expected that mix to change as the wells begin to climb? And then also whether you think you're planning for two horizontals, one middle and one upper, or whether you see additional zones that could be prospective?

Yes, Brian. On the Wolfcamp, it's really a combo type play. The GORs will gradually go up over time. The early rates on the oil are a bit higher than they will be later in the life of the well. Yes, we feel those mixes that we've given are accurate.

And then, we are working -- primarily, most of our drilling, maybe all of our drilling so far has been in the middle zone. And we're having really good results in the middle zone, really in every acreage block that we test. We tested the middle zone as being really good. We do have the one well that we have in the press release. It's the University 9 #2803 in Reagan County, and we IP'd that well at 883 barrels of oil a day. And that was a full lateral upper zone test. And that well looks very good to us, and is very encouraging.

Other than that, we have very limited tests in the lower zone and the upper zone. So, we have plans to do additional testing this year in those zones, and we'll see how it goes. But we're really optimistic. The middle looks very consistent. And so we're working on our development patterns out there, trying to establish what's the proper spacing. And we've implemented our self-sourced sand and new completion techniques. And so the play is going really well.

One of the great things about the play is that we significantly reduced the well cost over the last few quarters with the implementation of our sand. And our drilling efficiencies have gone up. We've recently drilled a well from spud to TD in 4.9 days. And so, our operational people in West Texas are doing an excellent job on reducing cost, as well as developing the play properly. So we're very encouraged about the play.

That's great. And then lastly, in the Eagle Ford, you highlight in your presentation some of the IPs exceeding 3,000 barrels a day. Is that a function of longer laterals and where your costs would exceed your $5.5 million objective? Is it a sweet spot around [seemingly] Karnes county? Or is there some other factor driving those results?

Yes, Brian. The best way to explain that is, is that we found that there's certain portions of this reservoir that are more prolific than other portions of the reservoir. The average well of 450 MBoe we quoted there is a mix. The kind of wells we quoted in our press release are more like 800 to maybe up to 1 million barrels of oil reserves per well. And we know that we have a tranche of those wells, quite a few of those, in that mix of 3,200 yet to drill. And if we wanted to, we could target and drill that tranche over the next couple years, and really shoot up our (inaudible).

But to be fair and objective, it's not so much that they're super long laterals, it's that they're located in a portion of the reservoir that we believe is definitely more prolific than in some other parts of the reservoir. So, we'll say -- you can expect we'll continue to be able to report wells of that similar type as we go throughout 2012. But we'd point you more to the average well and say -- the average well is quite strong, and gives the 80% return. So, hopefully that gives you an explanation.

That's great. Thank you.

Arun Jayaram, Credit Suisse.

Mark, you talked about some down-spacing opportunities in the Bakken. What does that do in terms of your inventory in the core part of the Bakken? And how many rigs do you plan to run in the core part versus the Bakken light in '12?

Yes, actually, I mentioned, in this call, focusing on the core. But we're really, it's fair to say that we're looking at the entire Bakken. The Bakken core is the sweet spot of the entire Bakken play. And then what we call the Bakken light is equivalent to pretty much every other company's Bakken. It's a lesser quality, but it's still good.

The spacing that we have initially drilled these on are in the core 640s and in the light 320s. We're testing down spacing in both the core and the light. In the core, we're testing 320 down spacing; in the light, we're testing 160 down spacing. If it was to work in both areas, and it looks good so far, the reserve uplift would be about the 50 million barrels. So we don't want to mislead you and mischaracterize it and say -- wow, we could double our reserves in the whole play under that circumstance there.

In terms of the rigs this year, we're running seven rigs. I would guess -- Gary, how many are in the core, how many in the light, would you guess?

We're still trying to retain acreage there, so we'll probably run somewhere around four in the light and three in the down spacing.

That's helpful. Just my quick follow-up. Mark, you did raise your NGL guidance for '12 quite a bit. And crude was more flattish, perhaps reflecting property sales. On a same-store sales basis, if you didn't have the asset sales, what would have been the growth guidance on the crude side?

I don't have the numbers. We quoted you numbers of a bit over 3,000 barrels a day of liquids on an annualized basis, is what our total liquids would have gone. And maybe that's two-thirds oil, one-third gas or NGLs. But I can't quote you an exact number on that, Arun.

Okay, that's fair. But just the mix shift is just moving a little bit more towards NGLs versus crude? Is that fair? As you get more experience in the play.

No, not really. What I'd say is, as I mentioned on one of the previous questions, the increase we showed in NGL growth from, I believe it was 16% previously, up to 30% in the update, is really that the old NGL number was probably about a two-year-old stale number that we just never bothered to change, and now we've updated it. So, we haven't really seen a mix change during '11 that says we're becoming more NGL mix versus oil. It was really just updating a stale NGL number.

Joe Allman with JPMorgan.

Mark, in terms of the assets that you sold already, could you just identify those for us? And what are some of the assets that you intend to sell? And then, along those lines, apart from asset sales, in terms of your organic gas production decline, what would you estimate the base decline to be, if you did nothing?

Yes, in terms of your first part of your question there, Joe, the sales that we've done to-date, and that we have in progress, which are roughly $400 million, those were predominantly gas, just a tiny bit of liquids and oil with those. But the remaining sales of roughly $800 million we have yet to do, we just anticipate that were we to offer just dry gas properties out there in the market, that they wouldn't fetch much of a price. And so, that's one change we've had to make over the last six months for this year is, originally we intended that most of our sales in 2012 would be just dry gas. But due to collapse of gas prices, we've had to change that.

And I'd say out of the $800 million remaining, essentially all of those are going to have a liquid component. Some of them are just going to be flat oil areas. We are looking at selling some outside operated stuff in the Bakken. And some of them are going to be gas with rich liquids component in there.

In terms of our gas production base decline and things like that, I don't want to offer up a specific number for you on that. The only thing I would offer up is that one of the things that I've noted on previous earnings calls is that it's been disturbing to me to see most of the independent group has strongly grown their North American gas volumes over the last three years, and have been, in my mind, active contributors to this gas bubble. Whereas EOG has done just the antithesis of that. As I mentioned earlier, this will be the fourth straight year where our North American gas volumes have declined, which we believe is a rational economic response to these chronic low gas prices.

That's helpful. And the Permian, in your Wolfcamp play, Midland Basin, what's the lateral length you're using right now, and what number of fracs? And then, could you comment on your prospectivity for the Cline shale?

Joe, in the Permian, in the Wolfcamp, our average lateral length is about 7,600 feet. We're experimenting on the number of stages, but they could be anywhere from 20 to 30-plus stages per well.

What was the name of that play?

Cline shale.

The Cline shale, no, not familiar with that.

Yes, I'm not either. It may have some other name out there in the Permian Basin. But it's fair to say that's not one of our stealth plays. We haven't even heard of it, hardly.

Pearce Hammond with Simmons.

I was curious what your outlook is for service cost, and what you might be assuming for service cost inflation or deflation in your 2012 CapEx guidance. And then I have a follow-up.

We've got so much of our services committed on the long-term. Of course, that's in our guidance and in our projections. We've got 42 rigs under long-term contract out of our 75. And we've got 11 of our frac fleets under long-term, out of 20. We are seeing quite a lot of services, more available with the slowdown in the true gas plays, most especially in the Permian Basin. We're starting to see some of that in the Eagle Ford.

So, we don't see much increase in our cost of services. We do have our own self-sourced sand, and we'll be servicing the majority of our wells with that. We've got self-sourced acid. We've got our own rental fleet. So, we're pretty well set here, not seeing much increase in 2012.

Thank you. And then a follow-up. To back into your 3,200 Eagle Ford locations, what spacing assumptions and prospectivity are you assuming across your entire acreage position in the Eagle Ford?

We've reduced the spacing assumption from the previous 130 acres to a mix of between 65 and 90 acres, depending on the different geologic areas of the play. Does that get to what --?

Is that all down space then?

The 3,200 incremental wells are what we call sticks on a map. And I guess the best way to describe those 3,200 wells yet to drill is that we have a map of the Eagle Ford play, and it's got all the subsurface geology with the faults, et cetera, on it. And it's also got all the lease boundaries that we have. And then our people have laid out actual specific locations for 3,200 wells on that map that will conform to the lease boundaries, conform to the subsurface geology, and so on. So, one way to describe the 3,200 wells is that we already have those 3,200 wells defined as to exactly where we would intend to drill them. Hopefully that's helpful to you.

Yes, it is. Thank you.

That does conclude today's question-and-answer session. I would like to turn the conference back over to Mr. Mark Papa for any additional or closing remarks.

I have no additional remarks. So thank you very much for staying with us on the call.

That does conclude today's conference, ladies and gentlemen. We appreciate everyone's participation today.