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Executives

Mark G. Papa - Chairman and Chief Executive Officer

Timothy K. Driggers - Chief Financial Officer and Vice President

William R. Thomas - President

Analysts

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

H. Monroe Helm - Barrow, Hanley, Mewhinney & Strauss, Inc.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

EOG Resources (EOG) Q1 2012 Earnings Call May 9, 2012 9:00 AM ET

Operator

Good day, everyone, and welcome to the EOG Resources 2012 First Quarter Results Conference Call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I'd like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Mark G. Papa

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing first quarter 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 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 and Bakken, 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 U.S. investors that appears at the bottom of our press release in Investor Relations page of our website.

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

This morning, I'll discuss topics in the following order: I'll initially review our first quarter 2012 net income and discretionary cash flow, then I'll provide operational results and our 2012 business plan. Tim Driggers will then discuss financials and capital structure and I'll follow with our macro view and hedge position, and finish with concluding remarks.

As outlined in the press release, for the first quarter 2012, EOG reported net income of $324 million or $1.20 per diluted share. 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 first quarter 2012 adjusted net income was $317.5 million or $1.17 per diluted share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the first quarter was $1.3 billion.

I'll now address our operational results and key plays. During the first quarter, all 3 of our production categories exceeded the midpoint of our guidance. Our total crude and condensate production was up 49% year-over-year and total liquids were up 48% year-over-year. Additionally, the midpoint of our second quarter total crude and condensate guidance projects 42% year-over-year growth and 5% sequential growth. Our first quarter North American natural gas volumes declined 9% year-over-year, which is consistent with our projections.

Total company first quarter production from all sources was up 10% year-over-year. Our aggregate unit costs were in line with projections. For the full year 2012, we have increased our total company liquids growth target from 30% to 33%, consisting of 33% crude and condensate growth and 32% NGL growth. The higher liquids growth is a result of stronger Eagle Ford and Bakken production. This increases are our total company production growth target from the previous 5.5% to 7%. We have not changed our full year CapEx estimate.

As you know by now, we believe that total company production per debt adjusted share is a useless metric, given the current 42:1 oil to gas price ratio. EOG's focus is on year-over-year increases in EPS, EBITDAX and DCF, and our path to achieve this goal is strong crude oil growth. In the first quarter 2012, our year-over-year increase in GAAP EPS was 131%, non-GAAP EPS increased 72%, adjusted EBITDAX growth was 39% and DCF increased 39%. This is on top of the peer leading growth that we posted in these same metrics for the full year 2011 versus 2010 that I articulated on our year-end earnings call.

For the first quarter, 80% of our total company wellhead revenues emanated from liquids. In North America, 85% of wellhead revenues came from liquids. Of these liquids revenues, 87% are from crude and condensate and only 13% from NGLs.

This strong liquids revenue and volume growth is primarily generated by our 4 large horizontal domestic oil and liquids plays, which I'll now discuss starting with the Eagle Ford. The Eagle Ford continues to be our 800-pound gorilla in terms of crude oil growth, and we still believe our position is the largest domestic net oil discovery in 40 years and generates the highest direct ATROR of any current large hydrocarbon play. We continue to be largest crude oil producer in the play, with 77,000 Boe per day average net production for March, 90% of which was liquids.

Our press release again contains multiple new well results with IPs for individual wells in the 2,000 to 3,000 barrel oil per day range. Note that these are oil IPs, and if we included NGLs and natural gas, the barrel oil equivalent per day rates would be even higher because our oil IPs are much higher than those reported by offset operators. I've received several investor questions asking whether we're testing our wells on wide open chokes to generate artificially high oil rates. The simple answer is no. These are flow tests into our normal production equipment with a normal choke in the wellhead. We think the high initial rates are simply indicative of better wells as attested by our 49% year-over-year organic crude oil and condensate growth rate.

I'll now discuss 6 key points regarding the Eagle Ford. First, last quarter, we advised you that 65 to 90 acre downspacing was successful, and we'd increased the potential net recoverable reserve estimate from 900 million to 1.6 billion Boes.

Now that we have an additional 90 days of production history, we're even more comfortable with these downspacing conclusions. We're now testing space or tighting -- tighter than the current 65 to 90 acres, i.e. 40 acres, to determine if further densifying will be viable to increase the recovery factor and we'll likely have some results by year end.

Second, we continue to see an improvement in well performance from recent wells compared to wells completed just a year ago. This is likely due to better fracs and better placement of our laterals. This is occurring across essentially all our acreage. We've certainly seen this in our more prolific acreage where a year ago, we were highlighting wells with 1,500 barrel oil per day IP rates. And today, in those same areas, the IPs are 2,500 to 3,000 barrels of oil per day. These 2,500 to 3,000 barrel oil per day rates are holding up and have averaged 30-day rates of 1,500 barrel oil per day. We're also making these type of improvements in areas with lesser quality rock.

With the success in downspacing, we have identified at least 3,200 additional locations to drill. Based on the 300 net wells we plan to drill this year, this gives us an 11-year inventory. The reason we're not accelerating the drilling of this unusually large well inventory is the technological improvements we're making. If we're making better wells than we were a year ago, who's to say we may not make even better wells a year from now? So why rush to drill wells that may not be technically optimum? We're closely focused on balancing the present value of this asset versus this technical well improvement. And you'll hear more about this in subsequent quarters.

We've reduced the number of drilling days per well due to learning curve efficiencies and now need fewer rigs to drill the targeted 300 wells. Relative to the first quarter, our Eagle Ford drilling activity will be less frenetic for the remainder of the year as we reduce our rig count from the current 26 to 23 rigs.

Third, I continue to be impressed with the consistency of this play across the trend. We don't get a lot of geologic or reservoir surprises, and the few surprises we do get are generally more upside than downside.

Fourth. Now that our Wisconsin sand plant is operational, we're currently using 100% self-sourced sand in this play and saving about $500,000 a well. Because our sand is cheaper, our engineers are experimenting with bigger fracs to see the effect on initial flow rate and long-term reserves.

Fifth. During the past year, I've highlighted the possibility of product takeaway restrictions, but so far, we've been able to dodge these bottleneck bullets. We expect Enterprise to commission their new oil pipeline and gas processing plant next month. So we think the go-forward risk of takeaway curtailments has been considerably reduced.

And sixth. In early 2013, we expect to commence a dry gas injection pilot to determine whether this enhanced oil recovery technique will improve our current estimated 6% recovery factor. We expect to have preliminary results in late 2013.

To summarize the Eagle Ford, it's given us a lot of upside surprises so far, and we'll continue to develop it at a technically optimal pace.

I'll now shift to the Bakken Three Forks. Each of our 2011 quarterly calls had a business-as-usual tone for our Bakken Three Forks asset, even though we continue to be the largest Bakken oil producer in North Dakota. However, we've recently generated exciting and very significant results in 3 different parts of the play, indicating we have more potential upside and growth opportunities than we've previously indicated. The 3 focus areas are: First, in the last quarter, we mentioned early success in our partial core area with 320-acre downspacing compared to our original 640-acre spacing. We recently drilled 3 additional 320-acre downspaced wells, and all are successful with IP rates ranging from 992 to 1,393 barrels of oil per day. Working interest in these wells vary from 51% to 61%.

Additionally, production from the offsetting original 640-acre wells has doubled after the downspaced won [ph] after completions. The typical 640 acre well that had been online 4 to 5 years was producing 100 to 200 barrels of oil per day before the downspaced well was drilled, and is currently making 200 to 400 barrels of oil per day. This gives us production gain from both the new infill wells and the older producing wells. Based on these results, we'll implement 320 acre downspacing throughout our core area, and we'll also test 160 acre downspacing.

In our Bakken Lite area, our original development plan was on 320 acres. And by next quarter, we'll have some 160 acre downspacing results.

In summary, the downspacing is working and the reserve impact will likely be larger than the 50 million net barrels of oil we indicated on the February call.

Second, we continue to achieve excellent results in our Antelope Extension area, which is 25 miles southwest of our core area. Both the Bakken and Three Forks are productive in this acreage. We've recently drilled a group of Clarks Creek wells. 4 wells were drilled in the Three Forks formation and had IP rates of 926, 1,393, 1,455 and 3,415 barrels of oil per day, plus 1 million to 3 million per day of rich gas. A Bakken well we recently drilled in this same area had an IP rate of 2,300 barrels of oil per day with similarly associated rich gas. We have 100% working interest in all these wells. These results are better than we expected.

Third, in Far Eastern Montana and Western North Dakota in our Diamond Point and Stateline areas, we've recently completed 7 wells that IPed at rates between 540 and 1,100 barrels of oil per day. We have an average 63% working interest in this area. All 7 wells have high rock quality that we expected, and this opens up a brand new large development area for us where we have identified over 200 drilling locations.

Additionally, in late April, we commenced 2 waterflood pilots in our Core Parshall Field to try to improve our current approximately 8% recovery factor and we expect to have preliminary results by year-end 2012.

In summary, we're much more excited than we were a year ago about our remaining Bakken and Three Forks potential.

Moving to our Wolfcamp and Leonard plays. Our press release highlighted some individual well results, which are consistent with previous quarters. Because of the timing of our pattern drilling, we expect our 2012 production from these plays to be back-end loaded. We're still experimenting with the optimum well spacing, and expect we'll have more specific detail regarding these plays later in the year. The 2 most asked investor questions we've received regarding the Wolfcamp are, one, is more than one interval productive? And 2, why are EOG's indicated 280 Mboe per well NAR reserve estimate smaller than those quoted by offset operators? To-date, most of our success has been in the middle Wolfcamp interval, but we do have 2 positive results from the upper interval. Regarding per well reserves, in our February IR presentation, we used an example of a well with a low net revenue interest to EOG that was not comparable to peers who report gross reserves. On a gross 8 8 [ph] spaces, our typical Wolfcamp per well EUR is approximately 430 Mboe.

I'll also note that although university wells noted in the IR slide we posted last night, have lower initial production rates than in past quarters. That's because these wells tested against -- flowing against high line pressures. We consider that these wells are typical and have typical reserves to wells that we've reported in previous quarters, even though the IP rates are lower because of the higher back pressure.

Shifting to our Barnett Combo play. We continue to expect this to be our second largest liquids growth contributor in 2012, and we've highlighted typical wells in the press release. In the first quarter, we expanded the combo play with successful step out wells in 2 different directions. This play continues to slowly expand year after year. We plan to complete 200 net combo wells this year. And year-to-date well results are on track with expectations. I will note that we might have a possible gas processing pinch point in the June time frame. It will be touch and go for a month or so to see if we can add processing capacity quickly enough to handle our increasing rich gas volumes from this particular area.

In the Wyoming Powder River basin, we continue to have success with our horizontal drilling program in the Turner sandstone. Two recent wells are the Arbalest 59-3601H, which tested at 412 barrels of oil per day with 2.2 million cubic feet a day of rich gas. And the Arbalest 29-23H, which tested at 208 barrels of oil per day with 1.6 million cubic feet a day of rich gas. We have approximately 93% working interest in these wells.

We continue to be bullish regarding our 240,000 net acres in the Powder River basin. The basin has multiple stack pays similar to the Permian Basin, all of which contained oil rich gas. We've had great results in the Turner sands, and we'll be testing other zones in addition to the Turner before year end.

Regarding other North American oil plays, we recently completed a nice Niobrara well in Laramie County, Wyoming. The Jubilee 6904 [ph] well produced 460 barrels of oil per day. After a few weeks online, we have 100% working interest.

In the mid-continent, we continue to generate consistent results from our Marmaton and Cleveland plays. Four recent Marmaton wells IPed at 470 to 770 barrels of oil a day each. We have 61% to 94% working interest in these wells. Two nice 51% working interest Cleveland wells recently IPed at 490 and 560 barrels of oil per day.

We're also continuing to look for a new greenfield North American liquids plays. We have captured a number of these, but as you know, we only disclose these plays when they’re proven successful and we have all the acreage tied up. This same disclosure strategy worked for us in the Eagle Ford, Bakken, Barnett Combo and Permian. It may frustrate investors on the front end because we don't hype unproved potential, but we think investors are happy with our actual order results at the end of the day.

Recently, the trade press has highlighted an EOG transaction in the Tuscaloosa. We continue to have 0 interest in a JV in any of our Big 4 oil resource plays. However, over the last several months, each of our Big 4 oil place has gotten bigger, and we're accreting acreage in other areas. This will likely add to our CapEx opportunities over time. Therefore, we decided to work with an outside partner in our exploration efforts for the Louisiana Tuscaloosa marine shale oil play where we've teamed with Mitsubishi. We don't intend to provide specific funding details, but we hope it's win-win for both parties. To reiterate, any possible oil resource play JVs will be the exception rather than rule, and will definitely not be implemented in the Eagle Ford, Bakken, Combo or Permian.

We've previously disclosed that approximately 10% of our 2012 CapEx will be devoted to dry gas drilling in Haynesville, Marcellus and Horn River to hold acreage, and nothing has changed. We expect the percent of CapEx allocated to dry gas in 2013 will be approximately 5%.

I'll make one interesting observation regarding our Barnett Shale gas production, which I believe apprized all horizontal resource plays both gas and oil. For 2 years, we've not only monitored drilling in our Johnson County Barnett gas field, and we've been able to observe production declines without interference from new wells. Over the past 2 years, the aggregate decline of wells has been slightly less than our forecast. This data should ameliorate concerns among investors regarding longer term declines from horizontal gas and oil resource plays.

Outside North America, we're continuing to work on our East Irish Sea Conwy oil development with an expected second half 2013 production start up. Production's commencement has slipped 6 months because of a delay in drilling rig arrival. Production will likely peak at 20,000 barrels of oil per day late in 2013. We own 100% of this project.

In Argentina, our first Vaca Muerta vertical well has been completed. The well was currently in the early flowback stages after frac and looks strong. We've also drilled and cased a horizontal well, and we'll frac it in June. In Trinidad, we continue to project that 2012 gas sales will be flat with 2011. We don't have much news to report regarding our Kitimat project. We still expect FID no sooner than year end.

I'll now address 2 other EOG key differentiators: Crude-by-rail and sand plants. Our St. James crude-by-rail facility received its first Bakken crude oil shipment on April 15, allowing us to begin capturing the current $15 Bakken in LLS price uplift. We now have the capability to move our Bakken, Eagle Ford and Wolfcamp crude to either Cushing or St. James. Based on current differentials, the best NPV for our rail tanker fleet is to move our EOG Bakken oil to St. James and sell our Eagle Ford in the Houston and Corpus Christi markets. We expect our St. James facility to handle 50,000 barrels a day by June, increasing to 70,000 barrels a day by year end. We've provided guidance on our U.S. oil differentials relative to WTI for the second quarter in yesterday's press release.

For those modeling this net back benefit, remember that May will be a debugging month while we iron out the startup kinks, though likely to facility will run at intermittent capacity. We will not have the St. James facility fully operational for the entire second quarter, and not all of EOG's oil production will be sold to St. James. As market conditions and differentials change, we have great flexibility and can rapidly revise where we sell our production and how we get our production to market.

Regarding frac sand, our new Wisconsin sand plant started up in January. And this plant, in addition to our other sand facilities gives us the capacity to now self source the majority of our 2012 domestic fracs. A rough approximation of the annual savings is $500,000 per well times 600 wells or $300 million per year.

No other E&P company has boasted these differentiators, and only a very small minority has even one of the 2, which, combined with our first mover resource play advantage, gives us a big competitive advantage.

Now I'll discuss our 2012 business plan. Because we value consistency, I'm happy to report that there are no changes to the strategy that we articulated in February. This strategy is obviously working because we increased our full year liquids growth target from 30% to 33%. We continue to adhere to a low debt ratio and intend to limit our max net debt to cap to 30% and sell $1.2 billion of assets this year. Through May 1, we've closed on $565 million of sales and have approximately $600 million of sales in progress. So once we close on pending sales, we've essentially met our $1.2 billion target. Over the past 3 years, we've concentrated our assets by selling over 8,000 wells.

Part of our plan is to preserve a large dry gas resource play positions, and we're achieving that by devoting a small portion of our CapEx to Marcellus, Haynesville and Horn River lease retention drilling. In the Horn River Basin, we drilled 4 wells during the first quarter and have 3 wells remaining to drill in the second quarter. Once these are drilled, our leases will be held for 10 years. Our liquids plays are generating very strong results as evidenced by our outstanding organic liquids growth. This business plan will generate strong year-over-year EPS, EBITDAX and discretionary cash flow growth even with low gas prices. Remember, only 8% of this year's North American revenue is subject to spot gas prices. Even though some of our gas hedges roll off in 2013, because of our strong liquids growth, we expect only a small amount of 2013 North American revenues will emanate from unhedged gas. 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.

Timothy K. Driggers

Good morning. Capitalized interest for the quarter was $11.9 million. For the first quarter 2012, total cash, exploration and development expenditures were $1.9 billion excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $171 million.

Total acquisitions for the quarter were $327,000. As mentioned, through May 1, proceeds from asset sales were $565 million. At the end of March 2012, total debt outstanding was $5.0 billion and the debt to total capitalization ratio was 28%.

At March 31, we had $294 million of cash on hand, giving us non-GAAP net debt of $4.7 billion or net debt to total cap ratio of 27%. The effective tax rate for the first quarter was 38% and the deferred tax ratio was 56%. Yesterday, we included a guidance table with earnings press release for the second quarter and full year 2012. For the second quarter and full year, the effective tax rate is estimated to be 35% to 45%.

We have also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. Regarding price sensitivities, with our current hedged position in 2012, for each $1 moved in crude oil prices, net income is impacted by $29 million and cash flow is impacted by $43 million. For each $0.10 move in natural gas prices, net income is impacted by $10 million and cash flow is impacted by $14 million.

Now I'll turn it back to Mark.

Mark G. Papa

Thanks, Tim. Now I'll provide some views regarding macro hedging and concluding remarks. Regarding oil, we still think the global supply-demand balance is tight and the fundamentals dictate an average $105 WTI price in 2012. The upside pressures are mainly geopolitical. The downside risk is a second global recession. And for that contingency, we've recently increased our crude oil hedge position. We don't subscribe to the theory that North American oil growth will create a global surplus. We think a lot of the advertised but untested new North American liquids plays are even more show than subsequence or our NGL plays.

For the second half of 2012, we're approximately 24% hedged at $106.74 price. We continue to have a very cautious outlook regarding 2012 natural gas prices. And fortunately, as a percent of North American gas, we're 45% hedged at $5.44 for the second half of the year. We think the current rise in gas prices is a head fake but the storage overhang is just too massive.

As you know, we've been a big North American gas bear the last several years, and we adjusted our gas investments accordingly in 2010, '11 and '12. Last year, our North American natural gas production declined 7%, and this year we project a 10% decline. This is likely the largest 2-year gas production decline of the peer group, so we're doing our part to balance the market. 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 6 points to take away from this call. First, the game plan we articulated several years ago is working. In the first quarter, our year-over-year GAAP EPS increased 131%, non-GAAP EPS increased 72%, adjusted EBITDAX was up 39% and discretionary cash flows increased 39%. This is on top of our peer leading full year 2011 versus 2010 growth in these same metrics.

Second, we continue to exhibit extremely strong oil and NGL growth for a company our size. First quarter crude and condensate growth was 49% year-over-year and total liquids were up 48%. This is on top of 52% crude and condensate growth and 48% total liquids organic growth for the full year of 2011 versus 2010. Accordingly, we've raised our full year 2012 liquids growth target to 33% while keeping CapEx flat. Third, we're on track to sell $1.2 billion of properties and keep our net debt to total cap below 30%.

Fourth, what can I say about the Eagle Ford except that it's an 800-pound gorilla developing into a 1,000-pound gorilla.

Fifth, the Bakken Three Forks is our upside surprise to the quarter, and we're considerably more optimistic about the next 10 years of this play than we were a year ago.

And finally, EOG has 2 very significant logistical advantages that put us in a class by itself, crude-by-rail and self-sourced frac sand. Together, these provide the opportunity for higher net backs, market flexibility and cost advantages far above what we estimated when we committed to these projects.

Thanks for listening. And now, we'll go to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just a quick question on CapEx. Looked like it is kind of trending a little bit higher in the first quarter on a run-rate basis, if I sort of multiply it by 4 for the year. Can you just talk through how CapEx may change sequentially in the following quarters to kind of keep you guys within your guidance?

William R. Thomas

Yes, that's been a focus for us. And as is mentioned earlier by Mark, yes, we started off the year. We've got to a peak of 76 rigs, and we did that because we had dropped back to 65 end of 2011, and we wanted to go ahead and get quite a number of these patterns drilled to bring on our production. We're reducing that to 65 rigs total. That's dropping rigs even out of the Eagle Ford as well as some of our gas well drilling. And with that running 65 rigs, we believe we'll be able to stay within our CapEx guidance.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, great. And I guess in the Bakken, clearly you guys seem pretty excited about it. Just trying to get a sense of how much additional acreage has kind of come in to your development program. And additionally, how much acreage you think left to be tested in the Bakken in sort of the Lite area that's kind of yet to be determined?

Mark G. Papa

Yes, Leo. It's not so much additional acreage. Pretty much all of the acreage we have, we think is acreage that's going to turn out to be productive. Out of all the things we described, and we kind of described 4 things there, the core area downspacing, the light area downspacing, actually it's 5 things. And then the Antelope area and the stuff out there in the state line area and then the Waterflood. I'd say that there's a -- 3 of those things are definitely working, core area downspacing, state line area, Antelope. The Bakken Lite area downspacing, we don't know for sure whether that's going to work, and then the Waterflood. But probably the biggest things that could make a difference there are the core area downspacing, which we already checked the box on that, and then the Waterflood. Those are the ones that are going to be the big difference. It's not so much are we going to be trying to prove up incremental acreage somewhere. It's really, really now, how best -- how dense a spacing can we drill on the acreage that we have, and then can we make a secondary recovery project work on that. So that's the way I'd look at it, but there's -- if we can get the -- particularly the Waterflood to work, then we've got, I think, a significant upgrade in the likely reserves that we’ve got captured and the likely production we'll be generating out of the Bakken for the next decade, really.

Operator

We'll take night our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the Eagle Ford, can you talk to, by year end, what areal extent you're planning to test at 40 acres versus what you've already tested at 65 to 90? And then beyond the downspacing, where do you think you are in optimizing completions in the Eagle Ford and whether you see room for further efficiencies?

Mark G. Papa

Yes, I'll give it to Bill Thomas.

William R. Thomas

Brian, that's a good question. We have several patterns that we're currently drilling and frac-ing and just starting to test that are on the lower spacing, below 65 acres per well. So we're going to take that kind of flow because that's pushing it pretty hard, and we really would like to get a couple of those patterns fully tested and developed before we expand that to -- over large, large areas. So that'll just take a little bit of time and we'll just kind of see how that goes as we progress. On the frac side, as you know, industry-wide, we are very aggressive on trying new techniques and new styles of frac technology and using microseismic and trying to increase the amount of rock that we are connecting each one of these horizontal wells. And so we're making very, very substantial and steady progress in the Eagle Ford. As Mark mentioned earlier, we are being more aggressive in some of the areas on our frac styles. In terms of sand, we're using different kinds of frac fluids and even different kinds of sand sizes in alternating the pump rates, as well as alternating the way we distribute the frac along the laterals and we're making really good progress. I would say much of the increases in the IPs that you see on the wells are due to just better frac technology than we had a year ago. So we're just very pleased. We're also, as Mark mentioned, the rock quality in the Eagle Ford, it looks like we definitely captured the sweet spot. And so the quality of rock that we have to deal with and work with in the Eagle Ford is very, very, very good.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great, great. And then as a follow up, is the takeaway from your comments on CapEx going forward that your call on development opportunities in your Big Four fields is now leading you to pursue more outside partner funding for opportunity for exploration outside those Big Four fields? And then can just remind us how you're thinking about balancing growth with CapEx and cash flow beyond 2012?

Mark G. Papa

Yes. It's fair to say that if you looked at our Big Four fields, and this is our internal assessment in terms of the size of them relative to a year ago, and you know this, a year ago we were looking at Eagle Ford at 900 million barrels, now we're looking at it 1.6 billion. A year ago, we were looking at the Bakken. And based on this call, we're certainly more excited about the Bakken Three Forks than we were a year ago. And as we also said on the call, we continue to expand in the combo play, although nothing that's discernibly exciting, but just gradual expansion and the same in the Wolfcamp Leonard area. So they've all gotten bigger, some of them -- considerably bigger, some of them just a bit bigger. And then we continue to have an increasing list of greenfield new play ideas. And so we just decided that this 30% net debt to cap is a hard line for us. And we will just avail ourselves of some external financing on at least one selected oil play. And so I think on a go-forward basis, 2 things come out of -- that you ought to conclude. One is the 30% net debt to cap is not a number we take lightly. And the second thing is that the comment about not using external funding in the Big Four plays is just totally inflexible. We're not going to change that at all. But on some of our greenfield ideas for new plays, we may elect from time to time to consider using outside financing

Operator

We'll take our next question from Pearce Hammond with Simmons & Company International.

Pearce W. Hammond - Simmons & Company International, Research Division

Mark, impressive liquids growth during the quarter. And as we ramp up the earnings season, a number of the producers have delivered some pretty stunning liquids growth. I was wondering if you can elaborate a little bit more on your comments at the end of your prepared remarks that you're not worried about there being a glut of oil developing here in the U.S. given this impressive oil growth in this tight oil [ph] revolution?

Mark G. Papa

Yes. I mean, I'm not sure, as the quarter ends that I've seen that impressive of liquids growth for most of the companies. So I might disagree a little bit from your first comment there. I think there's a lot of intent to have impressive liquids growth, but I haven't seen the numbers put on the board. But there are some theories out there by some sell siders that there ultimately will be a huge plethora of liquids growth. But I just -- and there are a lot of liquids plays that are being talked about, but they're yet unproven liquids plays. And I would just say that our analysis is that we just don't think that there's going to be the growth out there that some people are projecting. And if you look at our analysis in what we put out there on our website last night, we're projecting, by 2015, about 1.5 million barrels a day of increase in total U.S. oil production due to this horizontal revolution, which is quite substantial. But we don't think that's going to be enough to change the global supply-demand picture.

Pearce W. Hammond - Simmons & Company International, Research Division

And then as a follow-up to Leo's question on the CapEx and how we stay with the guidance for the full year, can you provide us with that roadmap? You say you're going down to 65 rigs from year end and that was starting at where? And then is the majority of that going to be gas rigs?

William R. Thomas

The ones we dropped were -- we dropped 4 there in the Eagle Ford, but the rest of them are principally gas or liquids-rich gas well drilling.

Pearce W. Hammond - Simmons & Company International, Research Division

And then what was the starting point on that? Going from how many rigs down to 65.

William R. Thomas

We peaked at 76 and we're now dropping to 65.

Operator

We'll take our next question from Joseph Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Mark, how much of the 9% decline in North American natural gas year-over-year that you experienced in the first quarter, how much of that is natural declines and how much of that is asset sales?

Mark G. Papa

We haven't worked that out exactly. I mean, it's probably fair to make an assumption, maybe half. Half is due to asset sales and half is just natural declines, Joe. It probably won't be too far off if you make that as an assumption.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. That's helpful, Mark. And then in the Parshall field, what were your previous assumptions about the recoveries you were getting, and then where can those recoveries go with the infill drilling?

Mark G. Papa

Well, I mean, in the Parshall field, the latest model we've done, we keep on updating it. Previously, I'd quoted that our Bakken recovery factors in that area we're about 10%. But now the latest model we've done shows that the recovery factor is about 8%. And then it shows, with the downspacing, hopefully we can take that up to -- from 8% to in the range of about 12% or so, and then further boost it farther than that, if we're lucky enough to have the Waterflood work. I'm not going to quote you a number on the Waterflood. We'll give you that one if it actually works.

Operator

We'll take our next question from David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Back to the gas comments. What do you think is going on in the Barnett as far as why those wells are holding up better? Is it just didn't have the -- can you just give us some color there?

Mark G. Papa

Yes. I mean, what I meant to convey there is they're holding up just a little bit better than what we had projected on our decline curves. So there had been some talk out there that all these resource plays were going to fall on their face once you quit drilling. And the intent of my comment was to say this is the first time where we've had kind of 2 years without a lot of interruptions from a lot of new drilling wells. And the data basically shows that we have 2 years, that with no precipitous declines other than what we had projected, and actually, a little stronger well performance than what we've projected. So there were some profits of doom out there that said always all these resource plays we're going to -- overstated reserves, et cetera. And I just thought it'd be useful to you folks to hear some real work data.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. But, yes, obviously a lot of plays are seeing that so a lot of guys report more gas than they thought.

Mark G. Papa

Yes, sad for the gas market.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Yes it’s not good. As a follow up, back to Eagle Ford, you said you're going to 21 rigs from 23 at year end…

Mark G. Papa

Actually, 27 going to 23.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. 27 going to 23. Is that just simply CapEx or is there -- I mean, why not, if the play's working as well you think and you're trying to test some new concepts, why not just keep running at that 27 given the return you're probably seeing there right now.

Mark G. Papa

Yes. We just had a target to drill up 300 net wells this year. And what we're finding out is with our drilling efficiencies, we're -- it's taking us less time per well to drill. And so we’re able to drill the 300 net wells for the rest of the year just with 23 rigs. So that's kind of what drove us to release rigs.

Operator

We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I wanted to jump back to the Eagle Ford. The well results that you discussed are obviously pretty impressive. And looking at your presentation on the website this morning, it looks like those wells are fairly consistently -- fairly close to the transition window, I guess, into the white gas area. I guess my question is how repeatable do you think those results are going to be across your acreage? And are you prepared to not chop your type curve or your expectation for the play generally in terms of near-term production outlook?

Mark G. Papa

Yes, you're right, in that what we found is the wells that are nearer to the transition, closer to the rich gas area, generally have the better quality. And so when you blend them all together, the wells that are farther back from that you end up with that 450 Mboe per well. A lot of these wells that we’re quoting, of course, are our best wells. And so many of them are 800, 900 Mboe per well, kind of wells on there. So again, we're -- overall, it's kind of the average well it turns out to be. The surprising thing to me is that other people, all of which I'm sure are quoting their best wells to you. Have yet to quote 2,000, 3,000, 4,000 barrel a day wells. So there appears to be a big differential between the wells we're making and what other companies are making, which is still kind of surprising to me on there.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

As a follow up, Mark, if I can use my follow up. So as you lower your rig count for this year in the Eagle Ford, are you -- how are you -- are you kind of high grading where you're focusing the near-term drilling program towards that sort of transition region. In other words, should we be looking at higher early production results, maybe transitioning to lower production over a longer period of time? In other words, your 2012 production guidance could actually have some upside risk? I'm just trying to understand how you're allocating the rigs in that play? And I'll leave it at that.

Mark G. Papa

No, what's really driving us is more the acreage exploration than trying to high grade it there. We can cover all the acreage exploration with 300 wells this year, but that's what's driving us, so we're not in a perfect world for NPV optimization, you drill all your best wells in the early years. But it's not a case where we're targeting our best wells in the early years, and then saving all the weaker well later. It's really just -- we drilled some of the better wells and some of the less good wells driven by the acreage side. So you can't really project that the well quality will go down in later years because we cherry-pick the best wells.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I think about -- more about front end loading the better wells so that we actually end up with much shaft [ph]. As you say, faster NPV realization. Okay, that's very clear, Mark. I'll leave it there.

Operator

We'll take our next question from Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Mark, last quarter you commented or gave some data on the Henkhaus unit where you're testing down the 65 acres in the Eagle Ford. And obviously, the results from the 4H well were very, very strong. I just wanted to see if you could give us a sense for the 5H and the 12H wells. How tightly spaced were those laterals relative to that unit?

William R. Thomas

Yes, they were basically all in the same spacing. The 5H and the 12H are a little bit shorter than the other wells, but their IPs and the way that they're responding for total lateral are very comparable to the other wells. And the surprising thing on that is, is that we have significant production from the other wells on the unit before we completed these wells. And so that's very, very, very encouraging to us. The matrix contribution on the Eagle Ford, I think, has been remarkable, and it's been a very big pleasant surprise for us. So things are going well.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. But in general, those are all in that 65 acre spacing in terms of width? Is that a fair comment?

William R. Thomas

Yes, that's correct. Yes.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And my follow-up question. Mark, you talked about the offset wells in Bakken increasing in the core part of the field as you've gone down from 640 to 320s. What exactly is going on there? And can you comment, was that a positive surprise for you?

Mark G. Papa

It was a surprise, yes. We didn't expect that. Our theory is that when we frac those wells originally, which would've been the 640-acre wells 4, 5 years ago that looking back, we probably didn't get as efficient of a stimulation as we might have liked and that we now are going to bigger fracs today than what we did back then, and that in the downspaced well, we gave a bigger frac and we probably stimulated some of that area even around the 640-acre original well. So that's kind of -- that's one theory that seems to make the most sense to me, that we would frac new rock around even the older well. So it's kind of an extra bonus, really, on there, which kind of cinches the case for the downspacing there, really. And the other thing it tells us is that clearly the 640-acre original spacing was too wide. So it makes it kind of a slam dunk case for the 320-acre spacing, and then it just opens the question about well is 320 still too wide? And should we investigate 160? So that'll be the next step we're look at too. On the spacing on both the Eagle Ford and the Bakken, clearly, what we did in retrospect is we started out with too wide of spacing and in both of them now, we're densifying the spacing, and we’ll densify it until we conclude okay, this is too dense of a spacing. And maybe in the Eagle Ford example maybe 65 acres is as dense as we want to go, maybe 40 acres is, we don't know. But I guess you live and you learn. The other way we could've done it is we could have gone to ultra-dense spacing to start, and then said this is too dense and then work the way to wider spacing, but we're doing it the other way. So we'll just see how it plays out, but we're concluded that the initial spacing was too wide, and we'll just work inwards until we conclude that now okay this is too close in terms of spacing.

Operator

And we'll take our next question from Ray Deacon with BBMC Capital.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

I was wondering, so I think is -- I think previously you were saying Bakken production will be in decline in 2012. Is that still the case or not?

Mark G. Papa

I think previously what we said is Bakken production would be flat in 2012. And it's probably fair to say that in 2012, Bakken production will be flat or maybe we'd say maybe just very slightly up. But based on what we're seeing, I'd say that 2013 and forward, there's a pretty decent chance Bakken production will have a good chance to be on the incline.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Got it. And would that be based on results of downspacing in Bakken Lite and Waterflooding or based on what you see today?

Mark G. Papa

Probably just on what we see today, not even counting the Waterflooding results. The Waterflooding, all we're doing right now is a pilot. And we'll know something about that by the end of the year and then we'd have to go to a full-scale Waterflood. And so frankly, it would be 2014 before we really see production results from a full-scale waterflood. So that's still a couple years away.

Operator

We'll take our next question from Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Mark I just want to catch back up with one of your beginning comments. You said that a lot of your growth is really coming from oil and condensate. And so I want to ask, how do you feel about the natural gas liquid markets, specifically ethane? Are we kind of hitting a bottleneck or simply we have unusual amount of downtime during first quarter. In multiple basins, I wanted to get your take on the ethane market.

Mark G. Papa

Yes. I mean, we've put some guidance in our 8-K there. For the first time, more of a gas than guidance as to -- as a function of crude, what our total NGL price expectations are. We don't guarantee the accuracy, but we decided we'd put some guidance in there anyway. Our read on the NGL market is that the second quarter will -- and specifically ethane. Second quarter will continue to be relatively weak. But the second -- and the reason first and second quarters were weak, are weak is that there were a lot of plant turnarounds, ethylene plant turnarounds. But beginning in the second half of the year, we expect those prices to strengthen in a relative sense, and that we're a little more bullish than a lot of people that ethane prices will remain decent, probably in the 40% to 50% range of crude oil long term. So right now, we're not writing off those prices and saying they're going to just degrade to nothingness. And that's based on the long term that the ethylene -- the cheapest place to make ethylene is probably going to be in the United States as opposed to anywhere else in the world. But second quarter, our expectations are pretty bearish. Check with me in 6 months and I might have a different story.

Operator

We'll take our next question from Monroe Helm with Barrow, Hanley.

H. Monroe Helm - Barrow, Hanley, Mewhinney & Strauss, Inc.

Actually, my question had to do with the response that you were getting on the downspacing and you already answered that. So I'll leave it at that.

Operator

We'll take our next question from Bob Brackett with Bernstein Research.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

A follow-up on that Bakken rejuvenation. Are you recovering frac fluid from the new wells in those old mature offset wells?

William R. Thomas

Yes, we're recovering frac fluid from the offset as well as the new well.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Okay. So you've connected it up and you've kind of done a mini waterflood test inadvertent, Mike.

William R. Thomas

That's correct, yes. And the good thing about this is you're always seeing substantial increase in the offsets. And there were about 7 of those wells, and this production is holding up extremely well in those.

Mark G. Papa

Some of our technical people that are optimistic about the Waterflood have a theory that the reason we've doubled the production in the older wells is that we've in fact done a mini Waterflood with the frac. So that's one theory anyway.

Operator

And at this time, due to time constraints, we're going to conclude the question-and-answer session. I'd like to turn the conference back over to Mr. Papa for any additional closing remarks.

Mark G. Papa

No, I have no further remarks. We'll talk to you next quarter. Thank you for listening.

Operator

And that does conclude today's conference. Again, thank you for your participation today.

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