Good day, everyone, 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.
Good morning, 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 of EOG's SEC filings, 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, 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. I'll provide operational results and our 2012 business plan.
Tim Driggers will discuss financials and capital structure, 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 non-recurring 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 three 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 our total company production growth target from the previous 5.5%- 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. 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 four 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 lbs gorilla in terms of crude oil growth. 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 the 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 bbls- 3,000 bbls 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 six key points regarding the Eagle Ford. First, last quarter, we advised you that 65 to 90 acre downspacing was successful. 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 spacing tighter than the current 65-90 acres, i.e., 40 acres, to determine if further densifying will be viable to increase the recovery factor and will 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 bpd IP rates, and today in those same areas, the IPs are 2,500 bpd-3,000 bpd . These 2,500-3,000 bpd rates are holding up and have averaged 30-day rates of 1,500 bpd .
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? 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 26-23 rigs. Third, I continue to be impressed with the consistency of this play across the trend. We don't get a lot of geological 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. 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 continued to be the largest Bakken oil producer in North Dakota. We've recently generated exciting and very significant results in three different parts of the play, indicating we have more potential upside and growth opportunities than we've previously indicated. The three focus areas are, first, in the last quarter, we mentioned early success in our Parshall core area with 320-acre downspacing compared to our original 640-acre spacing. We recently drilled three additional 320-acre down-spaced wells, and all are successful with IP rates ranging from 992 bpd-1,393 bpd . Working interest in these wells vary from 51%-61%. Production from the offsetting original 640-acre wells has doubled after the down-spaced ones have the completions.
The typical 640-acre well that had been online four to five years was producing 100 bpd-200 bpd before the down-spaced well was drilled, and is currently making 200 bpd-400 bpd . 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 down-spacings throughout our core area, and we'll also test 160-acre down-spacing. In our Pocket Light area, our original development plan was on 320 acres, and by next quarter, we'll have some 160-acre down-spacing results. In summary, the down-spacing is working, and the reserve impact will likely be larger than the $50 million net barrels of oil we indicated on the February call. We continue to achieve excellent results in our Antelope Extension area, which is 25 mi southwest of our core area.
Both the Bakken and Three Forks are productive this acreage. We recently drilled a group of Clarks Creek wells. Four wells were drilled in the Three Forks formation and had IP rates of 926, 1,393, 1,455, and 3,415 bpd , plus 1-3 million per day of rich gas. A Bakken well we recently drilled in the same area had an IP rate of 2,300 bpd with similarly associated rich gas. We have 100% working interest in all these wells. These results are better than we expected. In far eastern Montana and western North Dakota, in our Diamond Point and State Line areas, we recently completed seven wells that IP'd at rates between 540 bpd-1,100 bpd . We have an average 63% working interest in this area.
All seven wells have higher rock quality than we expected, and this opens up a brand-new large development area for us where we have identified over 200 drilling locations. In late April, we commenced two water flood 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. 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 two most asked investor questions we've received regarding the Wolfcamp are, one, is more than one interval productive? And two, why are EOG's indicated 280 MBOE per well NAR reserve estimates smaller than those quoted by offset operators? To date, most of our success has been in the Middle Wolfcamp interval, but we do have two 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 basis, our typical Wolfcamp per well EUR is approximately 430 MBOE.
I'll also note that although our university wells noted in the IR slides 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 two 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 timeframe. 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 Arboles 5936-01H, which tested at 412 bpd with 2.2 million cubic feet a day of rich gas, and the Arboles 29-23H, which tested at 208 bpd 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 contain 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 well produced 460 bpd 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 IP'd at 470 bpd-770 bpd each. We have 61%-94% working interest in these wells. Two nice 51% working interest Cleveland wells recently IP'd at 490 and 560 bpd . We're also continuing to look for new greenfield North American liquids plays.
We have captured a number of these, as you know, we only disclose these plays when they are 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 do not hype unproved potential. We think investors are happy with our actual oil results at the end of the day. Recently, the trade press has highlighted an EOG transaction in the Tuscaloosa. We continue to have zero interest in a JV in any of our big four oil resource plays. Over the last several months, each of our big four oil plays has gotten bigger, and we are accreting acreage in other areas. This will likely add to our CapEx opportunities over time.
We decided to work with an outside partner in our exploration effort for the Louisiana Tuscaloosa Marine Shale Oil Play, where we have teamed with Mitsubishi. We do not intend to provide specific funding details. We hope it is a win-win for both parties. To reiterate, any possible oil resource play JVs will be the exception rather than the rule and will definitely not be implemented in the Eagle Ford, Bakken, Combo, or Permian. We previously disclosed that approximately 10% of our 2012 CapEx will be devoted to dry gas drilling in the Haynesville, Marcellus, and Horn River to hold acreage. Nothing has changed. We expect the percent of CapEx allocated to dry gas in 2013 will be approximately 5%. I will make one interesting observation regarding our Barnett Shale gas production, which I believe applies to all horizontal resource plays, both gas and oil.
For two years, we have done only minor drilling in our Johnson County Barnett gas field. We have been able to observe production declines without interference from new wells. Over the past two 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 are continuing to work on our East Irish Sea Conwy Oil development with an expected second half 2013 production startup. Production commencement has slipped six months because of a delay in drilling rig arrival. Production will likely peak at 20,000 bpd late in 2013. We own 100% of this project. In Argentina, our first Vaca Muerta vertical well has been completed. The well is currently in the early flowback stages after frack and looks strong.
We have also drilled and cased a horizontal well and will frack it in June. In Trinidad, we continue to project that 2012 gas sales will be flat with 2011. We do not have much new to report regarding our Kitimat project. We still expect FID no sooner than year-end. I will now address two 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 15th, allowing us to begin capturing the current $15 Bakken to 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 oil in the Houston and Corpus Christi markets.
We expect our St. James facility to handle 50,000 bpd by June, increasing to 70,000 bpd by year-end. We provided guidance on our U.S. oil differentials relative to WTI for the second quarter in yesterday's press release. For those modeling this netback benefit, remember that May will be a debugging month while we iron out the startup kinks, though likely the 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 at 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 both of these differentiators, and only a very small minority has even one of the two, which, combined with our first-mover resource play advantage, gives us a big competitive advantage. I'll discuss our 2012 business plan. We value consistency, I'm happy to report that there are no changes to the strategy that we articulated in February. The 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 1st, we've closed on $565 million of sales and have approximately $600 million of sales in progress. Once we close on pending sales, we've essentially met our $1.2 billion target. Over the past three years, we've concentrated our assets by selling over 8,000 wells. Part of our plan is to preserve our 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 four wells during the first quarter and have three 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.
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, for a 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 the 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 move 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. I'll turn it back to Mark.
Thanks, Tim. I'll provide some views regarding macro hedging and concluding remarks. Regarding oil, we still think the global supply-demand balance is tight. The fundamentals dictate an average $105 WTI price in 2012. The upside pressures are mainly geopolitical. The downside risk is a second global recession. 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 either more show than substance or 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. 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 because the storage overhang is just too massive. As you know, we've been a big North American gas bearer the last several years. We adjusted our gas investments accordingly in 2010, 2011, and 2012. Last year, our North American natural gas production declined 7%. This year we project a 10% decline. This is likely the largest two-year gas production decline of the peer group. 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. Let me summarize. In my opinion, there are six 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 flow 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 of the quarter, and we're considerably more optimistic about the next 10 years of this play than we were a year ago. Finally, EOG has two very significant logistical advantages that put us in a class by itself, crude by rail and self-source 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.
Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touchtone telephone. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We'll take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star two. We'll pause for just a moment to give everyone an opportunity to signal for questions. We'll take our first question from Leo Mariani with RBC.
Hey, guys, 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 four 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?
Yeah, that's been a focus for us. As is mentioned earlier by Mark, we started off the year, we 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. With that, running 65 rigs, we believe we'll be able to stay within our CapEx guidance.
Okay, great. 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 come into your development program, and additionally how much acreage you think left to be tested in the Bakken in sort of the light area that's kind of yet to be determined.
Yeah, Leo, it's not so much additional acreage. Pretty much all the acreage we have we think is acreage that's going to turn out to be productive. Out of all the things we described, we kind of described four things there, the core area down-spacing, the light area down-spacing. Actually, it's five things. The Antelope area, then the stuff out there in the State Line area, the Waterflood. I'd say that three of those things are definitely working. Core area down-spacing, State Line area, Antelope. The Bakken light area down-spacing, we don't know for sure whether that's going to work, the Waterflood. Probably the biggest things that could make a difference there are the core area down-spacing, which we already checked the box on that, 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 now 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? That's the way I'd look at it. If we can get 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.
Thanks a lot.
Okay.
We'll take our next question from Brian Singer with Goldman Sachs.
Hey, Brian.
Good morning. 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- 90? And then beyond the down spacing, where you think you are in optimizing completions in the Eagle Ford, and whether you see room for further efficiencies?
Yeah, I'll get Bill Thomas.
Yeah, Brian, that's a good question. We have several patterns that we're currently drilling and fracking and just starting to test that are on the lower spacing, below 65 acres per well. We're going to take that kind of slow because that's pushing it pretty hard. We really would like to get a couple of those patterns fully tested and developed before we expand that over large areas. That'll just take a little bit of time, and we'll just see how that goes as we progress. On the frack side, as you know, industry-wide, we are very aggressive on trying new techniques and new styles of frack technology, and using microseismic, and trying to increase the amount of rock that we are connecting to each one of these horizontal wells. We're making 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 frack styles in terms of sand. We're using different kinds of frack fluids and even different kinds of sand sizes, and alternating the pump rates, as well as alternating the way we distribute the frack along the laterals. 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 frack technology than we had a year ago. We're just very pleased. We're also, as Mark mentioned, the rock quality in the Eagle Ford, it looks like we've definitely captured the sweet spot, the quality of rock that we have to deal with and work with in the Eagle Ford is very good.
Great. Thanks. 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 opportunities for exploration outside those big four fields? Can you just remind us how you're thinking about balancing growth with CapEx and cash flow beyond 2012?
Yeah, 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, you know this, a year ago, we were looking at the Eagle Ford at 900 million barrels. Now we're looking at it at 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. 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. They've all gotten bigger. Some of them considerably bigger, some of them just a bit bigger.
Then we continue to have an increasing list of greenfield new play ideas. We just decided that this 30% net debt to cap is a hard line for us, and we would just avail ourselves of some external financing on at least one selected oil play. I think on a go forward basis, two things come out of that you ought to conclude. One is, the 30% net debt to cap is not a number we take lightly. 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. On some of our greenfield ideas for new plays, we may elect from time to time to consider using outside financing.
Great. Thank you.
Okay.
We'll take our next question from Pearce Hammond with Simmons & Company International.
Good morning.
Morning.
Mark, impressive liquids growth during the quarter. As we wrap up the earnings season, a number of the producers have delivered some pretty stunning liquids growth. I was wondering if you could 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 and this tight oil revolution .
Yeah. I'm not sure as the quarter ends that I've seen that impressive of liquids growth for most of the companies. 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. There are some theories out there by some sell-siders that there ultimately will be a huge plethora of liquids growth. There are a lot of liquids plays that are being talked about, but they're yet unproven liquids plays. 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.
If you look at our analysis in what we put out there on our website last night, we're projecting by 2015, about 1,500,000 bpd of increase in total U.S. oil production, due to this horizontal revolution, which is quite substantial. We don't think that's going to be enough to change the global supply/demand picture.
Thank you for that. As a follow-up to Leo's question on the CapEx and how we stay within 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, and where, is the majority of that going to be gas rigs?
The ones we dropped, We dropped four there in the Eagle Ford, the rest of them are principally gas or liquids-rich gas well drilling.
What was the starting point on that? Going from how many rigs down to 65?
We peaked at 76, we're now dropping to 65.
Thank you very much.
We'll take our next question from Joseph Allman with JPMorgan.
Hey, Joe.
Hey, 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?
We haven't worked that out exactly. It's probably fair to make an assumption, maybe half is due to asset sales and half is just the natural declines, Joe. You probably won't be too far off if you make that as an assumption.
Okay. That's helpful, Mark. 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?
In the Parshall Field, the latest model we've done, we keep updating it. Previously, I'd quoted that our Bakken recovery factors in that area were 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 from 8% to in range of about, what is it? 12?
12%.
12% or so, further boost it farther than that if we're lucky enough to have the water flood work. I'm not going to quote you a number on a water flood. We'll give you that one if it actually works on there.
All right. Very helpful. Thank you.
Okay.
We'll take our next question from David Tameron with Wells Fargo.
Morning, David.
Morning. 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? Can you just give some color there?
Yeah. 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. There had been some talk out there, that all these resource plays were going to fall on their face once you quit drilling. The intent of my comment was to say, this is the first time where we've had two years without a lot of interruptions from a lot of new drilling wells. The data basically shows that we have two years, that with no precipitous declines other than what we had projected, and actually a little stronger well performance than what we'd projected. There were some prophets of doom out there that said all these resource plays were going to overstated reserves, et cetera, and I just thought it'd be useful to you folks to hear some real-world data.
All right. Yeah, no, obviously a lot of players are saying that, so a lot of guys report more gas than they thought.
Yeah. Sad for the gas market.
Yeah. It's not good. As a follow-up, back to the Eagle Ford. You said you're going to 21 rigs from 23.
Actually-
27, going to 23.
Okay. 27, going to 23. Is that just simply CapEx? Why not? If the play's working as well as 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.
Yeah. We just had a target to drill 300 net wells this year. What we're finding out is with our drilling efficiencies, it's taking us less time per well to drill. We're able to drill the 300 net wells for the rest of the year just with 23 rigs. That's what drove us to release rigs.
All right. Thanks. Appreciate it.
Okay.
We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.
Thank you. Good morning, Mark. I wanted to jump back to the Eagle Ford. The well results that you've disclosed are obviously pretty impressive, looking at your presentation on the website this morning, it looks like those wells are fairly consistently close to the transition window, I guess, into the wet gas area. I guess my question is, how repeatable do you think those results are going to be across your acreage? Are you prepared to nudge up your type curve or your expectation for the play generally in terms of near-term production outlook?
Yeah, you're right, in that what we've found is the wells that are nearer to the transition, closer to the rich gas area, generally have the better quality. 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. Again, overall, it's the average well that 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 bpd, 3,000 bpd, 4,000 bpd wells.
There appears to be a big differential between the wells we're making and what other companies are making, which is still surprising to me on there.
As a follow-up, Mark, if I can use my follow-up. As you've lowered your rig count for this year in the Eagle Ford, are you 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. Thanks.
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. In a perfect world for NPV optimization, you'd drill all your best wells in the early years. It's not a case where we're targeting our best wells in the early years and then saving all the weaker wells later. It's really just we drill some of the better wells and some of the less good wells, driven by the acreage side. You can't really project that the well quality will go down in later years because we cherry-picked the best wells.
Yeah, I was thinking more about front-end loading the better wells so that we actually end up with much, as you say, faster NPV realization. Okay, that's very clear, Mark. I'll leave it there. Thanks very much.
Okay.
We'll take our next question from Arun Jayaram with Credit Suisse.
Hey, Arun.
Hey, good morning, Mark. Mark, last quarter, you commented or gave us some data on the Henkhaus unit where you're testing down to 65 acres in the Eagle Ford, and obviously, the results from the 4H well were 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?
Yeah, they were basically all on the same spacing. The 5H and the-
I believe the 12
The 12H are a little bit shorter than the other wells. Their IPs and the way that they're responding, per foot of lateral, are very comparable to the other wells. The surprising thing on that is that we have significant production from the other wells on the unit before we completed these wells. That's 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. Things are going well.
Okay. In general, those are all in that 65-acre spacing, in terms of width? Is that a fair comment?
Yeah, that's correct. Yes.
Okay. My follow-up question, Mark, you talked about the offset wells in the Bakken increasing in the core part of the field as you've gone down from 640 to 320. What exactly is going on there, and can you comment, was that a positive surprise for you?
It was a surprise. Yeah. We didn't expect that. Our theory is that when we fracked those wells originally, the 640-acre wells four or five years ago, that looking back, we probably didn't get as efficient of a stimulation as we might've liked, and that we now are going to bigger fracs today than what we did back then. That in the downspace well, we gave a bigger frac, and we probably stimulated some of that area, even around the 640-acre original well. That's one theory that seems to make the most sense to me, that we cracked new rock around even the older well. It's kind of an extra bonus, really, on there, which kind of cinches the case for the downspacing there, really. The other thing it tells us is that clearly, the 640-acre original spacing was too wide.
It makes it kind of a slam dunk case for the 320-acre spacing. Then it just opens the question about, well, is 320 still too wide, and should we investigate 160? That'll be the next step we'll 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 a 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." Maybe in the Eagle, for example, maybe 65 acres is as dense as we want to go. Maybe 40 acres is. We don't know. But we, I guess, you live and you learn.
The other way we could've done it is we could've gone to ultra-dense spacing to start, and then said this is too dense, and then worked our way to wider spacing. We're doing it the other way, so we'll just see how it plays out. We 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 the spacing.
Okay. Thanks, Mark.
Okay.
We'll take our next question from Ray Deacon with BMC Capital.
Yeah. Hey, Mark. I was wondering, I think previously you were saying Bakken production would be in decline in 2012. Is that still the case, or not?
I think previously what we said is Bakken production would be flat in 2012.
Okay.
It's probably fair to say that in 2012, Bakken production will be flat, or maybe we'd say maybe just very slightly up. 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.
Got it.
Okay.
Would that be based on results of downspacing in Bakken Light and water flooding, or based on what you see today?
Probably just on what we see today, not even counting the water flooding results. The water flooding, all we're doing right now is a pilot, and we'll know something about that by the end of the year. We'd have to go to a full-scale water flood. Frankly, it would be 2014 before we'd really see production results from a full-scale water flood. That's still a couple years away.
Got it. Thanks very much.
We'll take our next question from Irene Haas with Wunderlich Securities.
Hey, Irene.
Hey, 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. I want to ask how you feel about the natural gas liquid market, specifically, ethane. Are we hitting a bottleneck, or simply we have unusual amount of downtime during first quarter? Because you're in multiple basins. I want to get your take on the ethane market.
Yeah. We put some guidance in our 8-K there for the first time, more of a guess than guidance as a function of crude, what our total NGL price expectations are. 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. The reason first and second quarters were weak, are weak, is that there were a lot of plant turnarounds, ethylene plant turnarounds. Beginning in the second half of the year, we expect those prices to strengthen in a relative sense. We're a little more bullish than a lot of people that ethane prices will remain decent, probably in the 40%-50% range of crude oil long term.
Right now, we're not writing off those prices and saying they're going to just degrade to nothingness. That's based on the long term that the cheapest place to make ethylene is probably going to be in the United States as opposed to anywhere else in the world. Second quarter, our expectations are pretty bearish. Check with me in six months, and I might have a different story.
Great. Thank you.
Okay.
We'll take our next question from Monroe Helm with Barrow, Hanley.
Thanks a lot. Congratulations on executing a great strategy. Actually, my question had to do with the response that you were getting on the down spacing, and you already answered that. I'll leave it at that. Thanks.
Hey, Monroe.
We'll take our next question from Bob Brackett with Bernstein Research.
Hey, Bob. Good morning.
Good morning. A follow-up on that Bakken rejuvenation. Are you recovering frack fluid from the new wells in those old mature offset wells?
Yes, we're recovering frack fluid from the offsets as well as the new well.
Okay, you've connected it up, and you've kind of done a mini water flood test inadvertently.
That's correct. Yes. The good thing about this is, we've seen substantial increase in the offsets, and there were about seven of those wells, and this production is holding up extremely well in those.
Yeah.
Great.
Some of our technical people that are optimistic about the water flood have a theory that the reason we've doubled the production in the older wells is that we've in fact, done a mini water flood with the frack.
Yeah
that's one theory anyway.
Thank you.
Okay, Bob.
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 or closing remarks.
No, I have no further remarks. We'll talk to you next quarter. Thank you for listening.
That does conclude today's conference. Again, thank you for your participation today.