Good day, everyone, and welcome to the EOG Resources 2012 First Quarter Results Conference Call. As a reminder, this call is being recorded. 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, and thanks for joining us. We hope everyone has seen press release announcing Q1 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 that appears at the bottom of our press release and Investor Relations page of our website. With me this morning are Bill Thomas, President Gary Thomas, COO Tim Driggers, Vice President and CFO and Moira Baldwin, Vice President, Investor Relations.
An updated IR presentation was posted to our website last night and we included Q2 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 Q1 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 Q1 12, EOG reported net income of $324,000,000 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 Q1 2012 adjusted net income was $317,500,000 or $1.17 per diluted share. For investors who follow the practice of industry analysts who focus on non GAAP discretionary I'll now address our operational results and key plays. During the Q1, all three of our production were up 48% year over year. Additionally, the midpoint were up 48% year over year. Additionally, the midpoint of our 2nd quarter total crude and condensate guidance projects 42% year over year growth and 5% sequential growth.
Our 1st 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% 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:one oil to gas price ratio. EOG's focus is on year over year increases in EPS, 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 Q1, 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 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 2000 to 3000 barrel oil per day range. Note that these are oil IPs if we included NGLs and natural gas, the Barrow 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 down spacing was successful and we'd increased the potential net recoverable reserve estimate from 900,000,000 to 1,600,000,000 BOEs. Now that we have an additional 90 days of production history, we're even more comfortable with these down spacing conclusions.
We're now testing space for 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 will likely have some results by year end. 2nd, 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 1500 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 2,005 100 to 3000 barrel oil per day rates are holding up and have averaged 30 day rates of 1500 barrel oil per day. We're also making these type of improvements in areas with lesser quality rock. With the success in down spacing, 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 Q1, 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. 3rd, 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. 4th, 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. 5th, 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 6th, 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 20 13.
To summarize the Eagle Ford, it's given us a lot of upside surprises so far and technically optimal pace. I'll now shift to the Bakken 3 Forks. Each of our 2011 quarterly calls had a business as usual tone for our Bakken 3 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: 1st, in the last quarter, we mentioned early success in our partial core area with 3 20 acre down spacing compared to our original 6 40 acre spacing.
Recently drilled 3 additional 320 acre down spaced wells and all are successful with IP rates ranging from 9.92 to 13.93 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 down spaced 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 down spacing throughout our core area and we'll also test 160 Acre Downspacing.
In our Fox and Light area, our original development plan was on 3 20 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 50,000,000 net barrels of oil we indicated on the February call. 2nd, 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 this acreage. We recently drilled a group of Clarks Creek wells.
Four wells were drilled into the Three Forks formation and hit IP rates of 926, 13 93, 1455 and 3415 barrels of oil per day, plus 1,000,000 to 3,000,000 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 percent working interest in all of these wells. These results are better than we expected. 3rd, in far Eastern Montana and Western North Dakota in our Diamond Point and Stateline areas, we recently completed 7 wells that IP ed at rates between 5.40 63% working interest in this area.
All 7 wells have higher rock quality than we expected, and this opens up a brand new development area for us where we have identified over 200 drilling locations. Additionally, in late April, we commenced 2 water flood pilots in our core partial oilfield 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 Bonken and Three Forks potential. Moving to our Wolfcamp and Leonard plays, our press release highlighted some individual rail 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: 1, is more than 1 interval productive? And 2, why are EOGs 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 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 is approximately 4.30 MBOE.
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 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 2nd largest liquids growth contributor in 2012 and we've highlighted typical wells in the press release. In the Q1, 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 timeframe. It will be touch and go for a month or so, 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 593,6001H, which tested at 412 barrels of oil per day with 2,200,000 cubic feet a day of rich gas and the RBLS 29-23H which tested at 208 barrels of oil per day with 1,600,000 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 sand 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 6,904 well produced 4 60 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 percent to 94% working interest in these wells. 2 nice 51% working interest Cleveland wells recently IP'd at 4.90-five sixty barrels of oil per day.
We're also continuing to look for new greenfield North American liquids place. 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 four oil resource plays. However, over the last several months, each of our big four oil plays 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 effort, 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 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 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 applies to all horizontal resource plays, both gas and oil. For 2 years, we've done only minor 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 Conway oil development with expected second half twenty thirteen production start up, production 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 flow stages after frac and looks strong. We've also drilled and cased a horizontal well and will 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 EOG begin capturing the current $15 Bakken to LOS 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 barrels a day by June, increasing to 70,000 barrels a day by year end. We provided guidance on our U. S. Oil differentials relative to WTI for the Q2 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 start up kinks, though likely the facility will run at intermittent capacity.
We will not have the St. James facility fully operational for the entire Q2 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 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 $300,000,000 per year. No other E and P company has both of these differentiators and only a very small minority has even wanted it to, which combined with our 1st 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. 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 $1,200,000,000 of assets this year. Through May 1, we've closed on $565,000,000 of sales and have approximately $600,000,000 of sales in progress. So once we close on pending sales, we've essentially met our $1,200,000,000 target. Over the past 3 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 4 wells during the Q1 and have 3 wells remaining to drill in the Q2. 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 spot gas prices.
Even though some of our gas hedges liquids growth, we expect only a small amount of 2013 North American revenues will emanate from unhedged gas. Simply put, we we think we're better situated than any other large cap E and 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 $11,900,000 For the Q1 In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $171,000,000 Total acquisitions for the quarter were $327,000 As mentioned, through May 1, proceeds from asset sales were $565,000,000 At the end of March 2012, total debt outstanding was $5,000,000,000 and the debt to total capitalization ratio was 28%. At March 31, we had $294,000,000 of cash on hand, giving us non GAAP net debt of $4,700,000,000 for net debt to total cap ratio of 27%. The effective tax rate for the Q1 was 38 6%. Yesterday, we included a guidance table with the earnings press release for the Q2 and full year 2012.
For the Q2 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 Q2 and for the full year. Regarding by $29,000,000 and cash flow was impacted by $43,000,000 For each $0.10 move in natural gas prices, net income is impacted by $10,000,000 and cash flow is impacted by $14,000,000 Now I'll turn it back to Mark.
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 either more show than substance or NGL plays. For the second half of twenty twelve,
For the second half of twenty
twelve, 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 were 45% hedged at $5.44 for the second half of the year. We think the current rise in gas prices is a hedge 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, 2011 and 2012. 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 are 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. 1st, 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 metrics. 2nd, 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 the full year of 2011 versus 2010.
Accordingly, we've raised our full year 2012 liquids growth target to 33% while keeping
CapEx flat. 3rd, we're
on track to sell 1.2 a 4th, what can I say about the Eagle Ford except that it's an 800 pound gorilla developing into a 1,000 pound gorilla? Gorilla. 5th, the Bakken 3 Forks is our upside surprise 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 netbacks, 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 and A.
Thank you. The question and answer session will be conducted electronically. 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 Q1 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?
Yes, that's been a focus for us. And as mentioned earlier by Mark, 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 in the 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'll be we believe we'll be able to stay within our CapEx guidance.
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 into your development program? And additionally, how much acreage you think left to be tested in the Bakken and sort of the light area that's kind of yet to be determined?
Yes, 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 and we kind of described four things there, the core area down spacing, the light area down spacing, actually it's 5 things and then the antelope area and the stuff out there in the state line area and then the water flood. I'd say that there's a 3 of those things are definitely working, core area downspacing, state line area, Antelope, the Bakken light area downspacing, we don't know for sure whether that's going to work and in the water flood. But probably the biggest things that could make a difference there are the core area down spacing, which we already checked the box on that and then this the water flow.
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 best how dense the 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 water flood to works, 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 are your extent you're planning to test at 40 acres versus what you've already tested at 65 to 90? And then beyond the spacing, where you think you are in optimizing completions in the Eagle Ford and whether you see room for further efficiencies?
Yes. I'll give Bill Thomas.
Yes, 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. So we're going to take that kind of slow 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 over large, large areas. So that will 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, we 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 to 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 and alternating the pump rates, 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 Martin mentioned, the rock quality in the Eagle Ford, it looks like we've definitely captured the sweet spot. And so the quality of rock that we have to deal with and work with in Eagle Ford is very, very, very good.
Great, great. Thanks. 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 4 fields is now leading you to pursue more outside partner funding for opportunities for exploration outside those Big 4 fields? And then can you just remind us how you're thinking about balancing growth with CapEx and cash flow beyond 2012?
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 the Eagle Ford at 900,000,000 barrels, now we're looking at 1,600,000,000. A year ago we were looking at the Bakken and based on this call, we're certainly more excited about the Bakken 3 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 would 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. 1 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.
Great. Thank you.
Okay.
We'll take our next question from Peter Salmon with Simmons and Company International.
Good morning. Morning.
Mark, impressive liquids growth during the quarter. And 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 in this tight oil revolution?
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 are 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 1,500,000 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.
And then thank you for that. And then 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 road map? You say you're going down to 65 rigs from year end and that was starting where? And then the majority of that is going to be gas rigs?
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.
And then what was the starting point on that going from how many rigs down to 65?
We peaked at 76 and we're now dropping to 65.
Thank you very much.
We'll take our next question from Joseph Uhlman with JPMorgan.
Mark, how much of the 9% decline in North America natural gas year over year that you experienced in the Q1, how much of that is natural declines and how much of that is asset sales?
Yes. We haven't worked that out exactly. I mean it's probably fair to make an assumption maybe half is due to asset sales and half is just natural declines, Joe. Probably won't be too far off if you make that as an assumption.
Okay. That's helpful, Mark. And then in the partial field, what were your previous assumptions about the recoveries you were getting? And then where can those recoveries go with the infill drilling?
Well, I mean in the partial 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 down spacing, 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 water flood work. I'm not going to quote your 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.
Good morning, David.
Hi, David. Good 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? Is it just didn't have the can you just give some color there?
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 projected.
So there were some profits of doom out there that said all these resource plays were going to overstated reserves, etcetera. And I just thought it'd be useful to you folks to hear some real world data.
All right. But yes, obviously a lot of players are saying that, so lot of guys report more gas than they thought.
Yes, sad, sad except for the gas market.
Yes, it's not good. As a follow-up, back to the Eagle Ford, you said you go into 21 rigs from 23.
You're actually 27 going to 23.
Okay, 27 going to 23. Is that just simply CapEx or is there I mean, why not if the play is working as well as you think and you're trying to test new concepts, why not just keep running at that 27, given the return you're probably seeing there right now?
Yes. We just had a target to drill 300 net wells this year. And what we're finding out is with our drilling efficiencies, we're drilling 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.
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. 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 wet 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 nudge up your type curve or your expectation for the play generally in terms of near term production outlook?
Yes, you're right. And 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 4.50 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 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, 3000, 4000 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 still kind of surprising to me,
on there.
As a follow-up, Mark, if I can use my follow-up. So as you've lowered your rig count for this year in the Eagle Ford, are you how 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.
Thanks. No, what's really driving us is more the acreage exploration exploration than trying to high grade it there. We can cover all the acreage exploration with 3 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 weaker wells 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 picked the best wells.
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.
We'll take our next question from Arun Jayaram with Credit Suisse.
Hi, Arun. Hi, good morning, Mark.
Mark, last quarter, you commented or gave you 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 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?
Yes, they were basically all on the same spacing. The 5H and the 12H are a little bit shorter than the other wells, but their IPs and 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.
Okay. But in general, those are all in that 65 acre spacing in terms of width?
Is that a fair comment?
Yes, that's correct. Yes.
Okay. And 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 6.4 to 320s. What exactly is going on there? And can you comment, was that a positive surprise for you?
It was a surprise. We didn't expect that. Our theory is that when we fracked those wells originally, which would have been 4 or 5 the 6 40 acre wells 4 or 5 years ago that looking back, we probably didn't get as efficient of stimulation as we might have liked and that we now are gave a bigger frac and we we gave a bigger frac and we probably stimulated some of that area even around the 6 40 acre original well. So that's kind of that's one theory that seems to make the most sense to me that we crack 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 down spacing there really.
And the other thing it tells us is that clearly the 648 for original spacing was too wide. So it makes it kind of a slam dunk case for the 3 20 acre spacing and then it just opens the question about is 320 still too wide and should we investigate and the Bakken, 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. And 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 have done it is we could have gone to ultra dense spacing to start and then say this is too dense and then work our way to wider spacing, but we're doing it the other way.
So we'll just see how it plays out, but we concluded that the initial spacing was too wide and we'll just work inwards until we conclude that now this is too close in terms of spacing. Okay. Thanks, Mark. Okay.
And we'll take our next question from Ray Deacon with BMC Capital.
Yes. Hey, Mark, I was wondering, so is 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. 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. Got it. And
would that be based on results of down spacing 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. Water flooding, 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 20 14 before we really see production results from a full scale waterflood. So that's still a couple of years away. Got it.
Thanks very much.
We'll take our next question from Irene Haas with Wonderland 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. And so I want to ask how you feel about the natural gas liquid market, specifically ethane? Are we kind of hitting a bottleneck or simply we have unusual amount of downtime during Q1?
Because in multiple basins, I want to get your take on the SA market.
Yes. I mean, we put some guidance in our 8 ks there for the first time, more of a guess than guidance as to 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. 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 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 Q2, our expectations are pretty bearish. Check with me in 6 months and I might have a different story.
Great. Thank you.
Okay.
We'll take our next question from Monroe Helm with Borrow Painley.
Thanks a lot. Congratulations on executing a great strategy. Actually my question had to do with the response that you're getting on the downspacing and you already answered that. So I'll leave it at that. Thanks.
Okay, Monroe.
We'll take our next question from Bob Brackett with Bernstein Research.
Hey, Bob. Good morning.
Good morning. A follow-up on Bakken rejuvenation. Are you recovering frac fluid from the new wells in those old mature offset wells?
Yes. We're recovering frac fluid from the offsets as well as the new well.
Okay. So you've connected it up and then
you've kind of done a mini waterflood test inadvertently?
That's correct. Yes. And the good thing about this is we've seen substantial increase in the offsets and there were about 7 of those wells and this production is holding up extremely well in those.
Yes. Some of our technical people that are optimistic about the waterflood have a theory that the reason we 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.
Thank you. Okay, Bob.
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 or closing remarks.
No, I have no further remarks. We'll talk to you next quarter. Thank you for listening.
And that does conclude today's conference. Again, thank you for your participation today.