Good day, everyone, and welcome to EOG Resources Fourth Quarter and Full Year 2010 Earnings Results Conference Call. At this time for opening remarks and introductions, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.
Good morning, and thanks for joining us. We hope everyone has seen the press release announcing fourth quarter and full year 2010 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 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.
Effective January 1, 2010, the SEC now 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 Wolfcamp, Marcellus and British Columbia Horn River Basin, may include estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary notes to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website.
With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Bill Thomas, Senior EVP, Exploitation; Tim Driggers Vice President and CFO; Maire Baldwin, Vice President, Investor Relations; and Jill Miller, Manager, Engineering and Reserves.
An updated IR presentation was posted to our website last night and we included first quarter and full year 2011 guidance in yesterday's press release. I'll discuss our business plans for 2011 in a minute when I review operations. I'll now review our fourth quarter and full year net income and discretionary cash flow, and then I'll review our year-end reserves and finding costs. I'll follow with recent operational highlights. Tim Driggers will then provide some financial details, and I'll have some concluding remarks.
As outlined in our press release, for the fourth quarter EOG reported net income of $53.7 million or $0.21 per share and $160.7 million or $0.63 per share for the full year 2010. For investors who follow the practice of industry analysts who focus on non-GAAP net income to eliminate marked-to-market impacts and certain one-time adjustments as outlined in the press release, EOG's fourth quarter adjusted net income was $92 million or $0.36 per share and $296.4 million or $1.16 per share for the full year.
For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the fourth quarter was $827 million and $3 billion for the full year.
Because we expect almost 70% of our 2011 and 73% of our 2012 North American wellhead revenues to emanate from liquids with current prices, we have shifted our reporting from natural gas unit measurements to crude oil unit measurements using the 6:1 conversion ratio.
I'll now address 2010 reserve replacement and finding costs. For the total company, we replaced 207% of our production at a $15.05 per BOE all-in costs net of reserve revisions. In the U.S., we replaced 339% of reserves at a $12.96 per BOE all-in costs net of revisions. For drilling alone in the U.S., our finding cost was $12.35 per BOE.
Total company proved reserves increased 8.5% to 1,950 million barrels of oil equivalent. Excluding the impact of producing asset sales, total company net proved developed reserves increased 9.6% overall and 12.6% in North America. Overall, 62% of the reserve adds were liquids. These are strong numbers, particularly given the rate of increase on the liquids side reflective of our 2010 drilling budget.
Overall, our natural gas reserves decreased due to producing property sales, a well that watered out in Trinidad and revisions in the Mid Continent area to reflect PUD reserves that are no longer part of our five-year drilling program.
For the 23rd consecutive year, DeGolyer and MacNaughton has done an engineering analysis of our reserves, and the overall number was within 5% of our internal estimate. Their analysis covers 77% of our proved reserves this year. Please see the schedule of accompanying earnings release for the calculation of reserve replacement and finding costs.
I'll now address our 2011 business plan, and then provide updates on several key plays. In 2010, we slightly overachieved regarding our revised production growth goal ending the year with 9.5% year-over-year overall growth compared to our 9% target articulated in November.
Our 2011 growth projection of 9.5% on an MMboe per day basis is identical to the goal that we presented in November. I'll also point out that this growth reflects all anticipated assets sales for 2011. Most importantly, the year-over-year liquids growth projection remains at 49%, although the mix between oil and NGL is slightly more oil dominated than presented in November. We expect 55% oil growth and 34% NGL growth in 2011.
Our North American natural gas production is expected to decrease by 5% reflecting property sales and only a limited amount of dry gas drilling. I'll note that our 2011 overall production growth will be lumpy depending on the timing of property sales and resource playbacks fracs, which bring a number of wells to sales at once and also including some February cold snap downtime.
I'd also like to interject a comment here regarding using production growth as a measurement parameter. At the current 22:1 crude oil natural gas price ratio, I believe that production growth yardstick had become somewhat meaningless. In today's world, the metrics of liquids production growth and product mix change will be the focus since cash flow, returns and earnings will follow liquids growth and that's how we defined EOG strategy over the past few years. I'll discuss multiple new operational developments in several of our key plays, and I'll start with our oil plays.
The Eagle Ford will be the biggest component of EOG's 2011 year-over-year oil growth, and we have positive results across our acreage, maintaining our 100% success rate. In our previously defined 120-mile oil area, we continue to achieve very consistent results. A sample of recent IPs from wells on the eastern half of our acreage are the Dullnig #3H and #4H and Hansen Kullin #2H and #4H, which IP-ed at 1,243, 1,244, 1,627 and 1,708 barrels of oil per day respectively with varying rates of rich natural gas in addition.
On the western side, the Naylor Jones 86 #1H IP-ed at 1,220 barrels of oil per day and 877 MCF per day of rich natural gas. We have 100% working interest in all of these wells.
Our total reserve estimates haven't changed from what we disclosed in November. Our current well cost in both areas of the Eagle Ford are roughly $6 million, and we expect to reduce these by $1 million by 2012 with total frac optimizations. At the current $6 million well costs, we were achieving 65% to 110% direct after-tax reinvestment rates return. We drilled 96 net Eagle Ford wells in 2010 and plan to drill approximately 250 net wells in 2011.
Also, you may have noted from previous presentations that in addition to our oil acreage, we have 26,000 net acres in the rich gas window in Webb County to the southwest of our oil position. Our first successful horizontal Eagle Ford well on this acreage, the Tully C. Garner #100 H has tested at a pipeline restraining rate of 2.8 million cubic feet a day of rich natural gas with 239 barrels of condensate per day, proving up this acreage. Therefore, we've extended the proven plays and now included our Webb gas acreage.
We now have another quarterly drilling under our belt. We've confirmed that our 26,000 rich gas net acres are also good, and we've continued to see consistent results within the oil fairway, and all that is excellent news. We also increased our sweet spot oil acreage from 505,000 to 520,000 net acreage. However, to be objective, I also need to mention two logistical pinch points in the Eagle Ford.
On our last call, I mentioned the tightness and availability of Eagle Ford frac equipment. This continues to be a problem, although in EOG's case, we've been able to alleviate almost all bottlenecks relating to completions in frac equipment except proppants availability.
The second pinch point is crude oil trucking. You may recall we signed up with Enterprise to have a new 350,000 barrels of oil per day oil pipeline built to our Eagle Ford acreage. However, the pipeline won't be in service until mid-2012. So essentially, all Eagle Ford oil, whether EOG or others, will have to move by truck throughout 2011, causing a crunch for crude truck availability. We have a plan to deal with both issues, but it will be a tight situation throughout this year.
I'll next discuss two oil plays where EOG was once again the first mover, the Wolfcamp and Niobrara. We drilled our first Wolfcamp horizontal well in early 2009, and after building up our acreage, we've now drilled eight horizontal wells and have completed four. Our second well was a short length lateral that proved the play concept, and the next two wells were longer length lateral wells. Of the two longer laterals, the University 40-1402 H had an initial 30 day average rate of 390 barrels of oil per day and 600 MCF of gas per day. The University 43-1000 H has averaged 560 barrels of oil per day with 250 MCF of gas per day in the first 12 days of production.
Our Wolfcamp product breakdown is approximately 55% oil, 23% NGLs and 22% residue gas. We have approximately 120,000 net acres in the play and we'll need additional drilling to test all portions of our acreage. But our initial reserve assessment from only one of the potential Wolfcamp target zones is at least 40 million barrels of oil equivalent, net after royalty, with possible upside from successful drilling.
This is typical of the EOG strategy. We were the first mover and kept it low profile until we've proven the play and established a good acreage position. The typical well cost here is $6.5 million and net after royalty reserves of 270,000 barrels of oil equivalent per well, yielding about a 25% direct after-tax reinvestment rate of return. We expect we can improve this ROR when we move into a program drilling mode.
In the Niobrara, recent completion results has increased our comfort factor regarding the play. As you know, this play has received a ton of press lately, and EOG, although first mover in the oil play, has been reticent to contribute to the hype, because the Niobrara was more highly fractured than other shales, and we had questions about longer-term productivity.
Relative to the industry, we drilled more wells than any other operator in the oil play, and we have the most data of any operator. We have recently found a way to convert the play from one dependent on fractures to more of a matrix-dominated play. This increases our confidence that the Niobrara can be developed as a true resource play.
So far we've tested 80,000 of our 300,000 likely perspective net acreage and have drilled wells such as the Critter Creek 13-17H and Elsie 7-34H, which recently tested at 731 and 820 barrels of oil per day, respectively.
During 2011, we plan to drill 40 wells, and we'll evaluate the remainder of our 300,000 acres. It's still too early to provide a total reserve estimate, but I can say that we're more optimistic about the play side than we were six months ago.
I'll also note that we expect both the Wolfcamp and Niobrara plays to be only minor contributors to our 2011 liquids growth because with our current infrastructure in the Niobrara and our Wolfcamp 2011 development will be at a modest pace with the three-rig program.
I'll now address our Bakken results. Some people seem to take EOG's Bakken position for granted and perhaps it's been overshadowed by some of our newer oil plays. However, I'll remind everyone that EOG is the biggest oil producer in North Dakota, which means we're also the biggest Bakken/Three Forks producer. We have one of the largest acreage positions in the play with 600,000 net acreage. The Bakken is our single largest oil production contributor, and we will remain so until the Eagle Ford passes it in 2012 or 2013.
Our recent drilling efforts have been to test areas outside the core, and we've had very good results. Typical results on our Round Prairie 10-1819H well near the Montana's South Dakota Stateline, which tested at 1,458 barrels of oil per day and 600 MCF of gas per day and the Bear Den 7-17H west of our core field, which IP-ed at 1,882 barrels of oil per day.
We have 85% and 90% working interest, respectively, in these wells. Our typical non-core well yields at 35% to 45% direct after-tax reinvestment rate of return, and we plan to run 10 rigs in the Bakken/Three Forks in 2011.
In our Barnett Combo play, Strickland drilling has again extended our core area from 160,000 to 175,000 net acres. The results have been consistent and because of drilling efficiency improvements, we've reduced our typical completed well costs to $3.0 million. Given the reserves we're achieving, our direct after-tax reinvestment rate of return is 50% to 60%.
Typical well results on the Weston A #1H and #3H and the Bahamas C Unit #3H, D Unit #4H and E Unit #5H were tested at oil rates of 635, 626, 376, 523 and 557 barrels of oil per day respectively with varying amounts of rich gas. We have 100% working interest in all of these wells. Because of our dominant acreage position, we have essentially no competition in this play. We drilled 231 net wells in 2010 and plan to drill about the same number in 2011. This play will be our second largest liquids growth contributor in 2011.
I'll also briefly mentioned our Permian Basin Leonard Shale play, where we've had only limited drilling activity because we were not faced with short-term lease expirations. The Endurance 36 #1H has a 30-day average part of 400 barrels of oil per day and 500,000 million cubic feet of gas a day. The Lomas Rojas #5H has a 30 average of 463 barrels of oil per day with 1.2 million cubic feet a day of rich gas. We have 100% working interest in both of these wells. Also, our Manitoba oil program continues to yield 90% after-tax reinvestment rates of return. We drilled 90 wells last year and plan to drill 86 wells this year.
Before we switch to the natural gas side of the ledger, I want to talk about reinvestment rates of return. The entire reason EOG has shifted from a gas to a liquids focus is based on our macro view. We can achieve much higher reinvestment rates of return with oil.
Now that we're a few years into this strategy shift, what can we conclude? First, oil RORs are clearly, much better than gas, which is obvious. Second, there's a differentiation between oil plays. A lot of our oil plays, the Bakken Lite, Niobrara, Barnett Combo, Wolfcamp and Leonard will yield a 30% to 60% direct ATROR. Each of these have different reserves and costs, but somewhat surprisingly, the RORs bunched together pretty closely.
Two other plays, the Bakken Core and the Eagle Ford will yield direct RORs between 65% and 110%. EOG is fortunate to have the dominant position in both of these ultra high return plays particularly the Eagle Ford. Because of its size, the Eagle Ford gives us an opportunity to invest a large amount of capital at very high direct reinvestment rates of return.
Now let me switch to the natural gas side of the ledger. As you know, our CapEx split in 2011 is 80% to liquids plays and 20% to dry gas. The only dry gas drilling we're doing is where it's required to hold acreage.
In 2011, we'll drill zero dry gas wells in the Barnett, the Permian Basin, the entire Rockies and in Canada Conventional. Our gas drilling will be primarily focused in the Haynesville, Marcellus and a little in the Horn River. I'll briefly discuss the three plays where we're committing 2011 capital.
In the Marcellus, we've had an interesting and positive turn of events. As you know in December, we mutually agreed to walk away from the sale of our 50,000 undeveloped net acres in Bradford County. We had drilled few wells there a few years ago using our old completion techniques and we got decent but not spectacular wells. After our sale fell through, we completed our first Bradford County well using our new high-rate frac completion techniques. The 96% working interest Hoppaugh #3H well has IP-ed at 14 million cubic feet a day with 1,200 psi flowing tubing pressure. This result is typical of results from offset operators, but we now think that the improved completion techniques has significantly upgraded this acreage. We plan on completing seven additional wells in Bradford County by midyear. If we can replicate these results, then we'll likely keep this acreage and not remarket it, since we estimate 1 trillion cubic feet of recoverable gas here.
We're also seeing similar unproved and proved results from high-rate completions in Clearfield County on our joint EOG/NFG acreage. In the last seven pump C [ph] wells we've completed here have averaged 8.1 million cubic feet per day with high drilling tubing pressures. We have 50% working interest in these wells.
As more data becomes available, our perception of the Marcellus has improved. Data to date had indicated two sweet spots, one in the Southwest near Pittsburgh and one in North Central Pennsylvania in the Bradford County area near the Pennsylvania-New York Stateline. It was thought that the area between these sweet spots was of lesser quality, but our Clearfield County results indicate at least a portion of the intervening acreage is excellent, and we're very pleased with our total 210,000 net acres.
In the Haynesville, we plan to run eight rigs this year compared to 11 last year. The activity level is the minimum required to hold all of our sweet spot acreage. Based on our analysis, the Haynesville can be divided into two regimes, the sweet and non-sweet spots.
Outside of the sweet spot, the chances of making an economic return are low. In the sweet spot, at today's gas prices, with average EURs of eight to 12 BCF per well, one can make an economic return. Fortunately, compared to others, EOG has a very high percentage of leases in the sweet spot versus total Haynesville leasehold. In fact, we believe we're the third biggest holder of sweet spot acreage, a fact that most people don't think of when they consider our Haynesville position.
Our recent well results are typical of what we reported in previous quarters. Hassell #1 and Oglesby #1 in Nacogdoches and San Augustine Counties, Texas had IPs of 24.7 million and 22.1 million cubic feet a day respectively from the Haynesville. The Lafitte #1 in Sabine Parish, Louisiana had an IP of 21 million cubic feet a day from the Bossier. Our working interest in these wells range from 72% to 96%. I'll also note that like several other companies, we've concluded that producing Haynesville wells at a restricted rate for the first several months is likely helpful to long term production and we have implemented that process.
In the British Columbia Horn River Basin, we've completed several wells from our early 2010 drilling program and obtained results consistent with past years. Meanwhile, the 100% working interest built E 55D [ph], tested with the peak rate of 22 million cubic feet per day and slow to the rate in excess of 18 million cubic feet a day for 15 days and appears to be the best well we drilled to date with estimated reserves of 17 BCF.
In conjunction with Apache, we've made good progress on the Kitimat LNG Export Facility project. We finalized an agreement with the Haisla First Nation regarding the sites for the LNG plant. We bought out the original owners of the Kitimat project, and with our partner, we've entered into an agreement to purchase full ownership of the proposed gas pipeline that will connect the existing pipeline network to Kitimat. We've also began discussions with potential customers on the off state contracts and our next step is to secure oil indexed LNG contracts. In my opinion, if any LNG export plants are built in North America, Kitimat is the most likely to happen. In my mind, our Horn River development is an oil project because we expect the gas to be sold at an oil index price.
Now I'll address our 2011 business plan. We expect our 2011 total CapEx to be between $6.4 billion and $6.6 billion, of which $1.1 billion will be devoted to facilities and midstream infrastructure. As previously noted, 80% of the CapEx will be focused on oil or liquids-rich plays and 20% is dedicated to holding natural gas acreage in the Haynesville, Marcellus and Horn River.
We intend to sell approximately $1 billion of assets in 2011. We are currently negotiating agreements to sell $550 million of acreage and natural gas assets that we expect to close in the first half of this year. We expect about $350 million of midstream sales and the remaining $100 million will come from the combination of acreage and gas-producing property sales.
As noted on the last call, our maximum net debt-to-cap tolerance level is 35% for year-end 2011, 2012 and later. Our game plan here is to hold on to 100% of our oil resource plays and also 100% of our top-tier Marcellus, Haynesville, Barnett and Rockies gas assets.
I've had a few investor questions recently about monetizing a portion of our 520,000 Eagle Ford oil position since it's now a hot commodity. My answer is that we can achieve 65% to 110% direct after tax rates of return by developing this acreage, but why would we want to water down a multibillion-dollar reinvestment opportunity given these kinds of returns. EOG seems to be almost the only independent ENP that isn't selling down its core resource play assets, and we think that's a positive discriminator.
I'll now turn it over to Tim Driggers to discuss financials and capital structures.
Capitalized interest for the quarter was $19.5 million and for the year was $76.3 million. For the fourth quarter of 2010, total cash exploration and development expenditures were $1.49 billion, excluding acquisitions and asset retirement obligations. In addition, expenditures for gathering systems, processing plants and other property plant and equipment expenditures were $148 million.
Total acquisitions for both the quarter and full year were $210 million, all of which represent the cost to acquire the rights to Kitimat LNG. For the full year 2010, total exploration and development expenditures were $5.37 billion, excluding acquisitions and asset retirement obligations. In addition, total gathering, processing plants and other property plant and equipment expenditures were $371 million.
For 2010, approximately 19% of the drilling program CapEx was exploration and 81% was development. Approximately 70% was directed toward oil and liquids-rich drilling programs with 30% to natural gas. We had proceeds from asset sales of $673 million in 2010.
At year-end 2010, total debt outstanding was $5.2 billion and the debt-to-total-cap ratio was 34%. At December 31, we had $789 million of cash, giving us non-GAAP net debt of $4.4 billion or net debt-to-total-cap ratio of 30%.
On a GAAP reporting basis, the effective tax rate for the fourth quarter was 62% and the deferred tax ratio was 27%. Similarly, on a GAAP basis, the effective tax rate for the year was 61% and the deferred tax ratio was 31%.
We have also announced another increase to the dividend on the common stock. This is the 12th increase in 12 years. Effective with the next dividend, our annual indicated rate is $0.64 per share.
On the natural gas side, from March 1 through December 31, 2011, EOG has 425,000 MMBtu per day of financial price swaps in place at an average price of $5.09 per MMBtu, excluding unexercised swaptions. This is roughly 1/3 of our expected 2011 North American gas production. For the full year 2012, EOG had 250,000 MMBtu per day of financial price swaps with an average price of $5.56 per MMBtu, excluding unexercised swaptions. And this is roughly 20% of our expected 2012 North American gas production.
On the crude side, from February through December 2011, EOG has 18,000 barrels of oil per day, financial price swaps in place at a weighted average price of $90.69 per barrel. For the full year 2012, we have financial price swaps for 2,000 barrels of oil per day at $100.50 per barrel.
Yesterday, we included the guidance table with the earnings press release for the fourth quarter and full year 2011. For the first quarter, the effective tax range is 35% to 50%. For the full year 2011, the effective tax rate range is 35% to 45%. We've also provided an estimated range of the dollar amounts of current taxes that we expect to record during the first quarter and the full year.
For each $1 per barrel change in wellhead crude oil and condensate price combined with the royalty change in NGL price, the sensitivity is approximately $26 million for net income and $39 million for operating cash flow. EOG's price sensitivities reached $0.10 per MCF change, and wellhead natural gas prices is approximately $19 million for net income and $28 million for operating cash flow.
Now I'll turn it back to Mark for his concluding remarks.
Thanks, Tim. Now let me summarize. In my opinion, there are six important points to take away from this call.
First, our shift from a natural gas to a liquids company is proceeding very well. At current prices, we expect almost 70% of our North American 2011 wellhead revenue to emanate from liquids as opposed to gas, with over half of that coming from crude oil. This ratio increases to 73% in 2012. Most importantly, our Eagle Ford results are matching expectations.
Second, all of our oil plays are in North America, with the vast majority in the U.S. Third, with the Wolfcamp and Niobrara, EOG has increased our oil inventory again on a first-mover basis. Our oil inventory is now so deep that we won't begin intensive development of the Wolfcamp, Leonard and Niobrara until the 2013 timeframe. This suggests that our strong liquids production growth will be sustained for many years.
Fourth, given our high ROR domestic oil inventory, combined with the fact that 80% of our CapEx is directed towards liquids, we expect to achieve above average reinvestment rates of return on our capital program in 2011 and later years. This will ultimately show up as above average ROE's and ROCEs versus the industry.
Fifth, we have a coherent plan to fund our capital program. And sixth, our Marcellus gas acreage currently appears to be more prolific than we had previously presented to the investment community. Thanks for listening and now we'll go to Q&A.
[Operator Instructions] And we will go to our first question from Scott Wilmoth with Simmons & Company.
Scott Wilmoth - Simmons
Just looking at your 2011 rate of liquids growth, it looks like up 49%, down a little bit from what you guys had previously said in November of 53%. Is that a function of maybe the oil pinch points you mentioned in the trucking in the Eagle Ford? Or is there an asset where you're getting maybe less liquids content than you initially thought?
Scott, your question is not quite correct. In November, we said 49% liquids growth and that's currently what we're saying. So there's no reduction in our liquids growth. In fact, for 2011, the mix has improved between NGLs and the crude oil, where now the crude oil was a slightly higher portion of the total liquids growth.
Scott Wilmoth - Simmons
I must have been misreading the November press release. Jumping to the Eagle Ford completion equipment, you mentioned that, that used to be a pinch point, but now you guys have secured your frac equipment you needed. What have you guys done to secure that equipment? And have you done anything to secure for your 2012 program?
What I'll say is we've got some proprietary activities going on relating to fracs. And nationwide, right now, I'd say that there's the fracs or pinch point for everybody in the industry. The work we've done in the Eagle Ford has removed the pinch point away from the pumping equipment back to getting proppant, primarily sand on there. So right now, industry-wide, we've got a shortage of sand. We've got a shortage of pumping equipment. And we got one of those two issues fixed for the Eagle Ford, but we really don't want to go into any details right now other than we will say, the same as we articulated on earlier calls, that we are moving in the direction of self-sourcing a higher percentage of our fracs in the company as we get particularly toward 2012.
And we'll go to our next question from Brian Lively with Tudor, Pickering, Holt.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
Mark, just on the asset sales, appreciate your remarks earlier especially with the Marcellus. But I just want to make sure I understand. What properties are you guys now planning to sell for 2011? And then what are the expected timing from a quarterly basis?
It kind of goes through. I mean, the biggest property we've sold in 2010 was a portion of our shallow gas acreage, producing acreage in Canada. And we're not looking at selling additional shallow gas production in Canada in 2011. The sales that we're looking at for 2011 are primarily from long, live natural gas assets in the U.S., and then some acreage positions that we have that are currently kind of hot commodities. And then on the midstream side, it's just some various midstream things, some of the midstream items pertaining to our North Dakota facilities out there. As far as on a quarter-to-quarter basis, I can't give you specifics other than what we laid out on the call that we expect in the first half of the year to have about $560 million worth of sales accomplished.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
On the Niobrara comments around matrix permeability in the Hereford Ranch area, what permeability range are you seeing there? And just given the data the you've seen so far, do you expect the Niobrara to really have a core in the Niobrara Lite region?
What we can say about this is as Mark noted earlier that the early wells in the Niobrara are generally dominated by high permeability open fracture system. And this typically leads to very wide spacing patterns and low in place oil recoveries. So what we're doing, we're developing the completion concept, and this allows us to connect more the oil and the matrix philosophy as opposed to only the oil and the fractures. So the results are encouraging, but they're early. And if we're successful in changing this, connecting more oil in the matrix, we may be able to drill wells on certainly much tighter spacing than we thought before and certainly increase the recovery factor of the oil in play. So it's going to take some time to determine this, and the ultimate impact on the play will just reveal itself over time.
And moving on, we'll take our next question from Leo Mariani with RBC Capital.
Leo Mariani - RBC Capital Markets, LLC
You're obviously more excited about the Marcellus based on some of your recent drilling results. Can you give us a sense of your well costs up at the Marcellus and the EURs and results?
In Bradford County, the typical well cost is about $5 million. The EURs, we're looking in the range of probably about minimum of close to four Bcfs. We just need to watch production from some of these wells. But if we can replicate the Bradford County results, as far as dry gas drilling, they're going to be reasonably economic dry gas wells to drill. So we really may have a situation here where we've got a series of wells that have been IP-ed at 14 million, 15 million a day in the Marcellus and Bradford County area. And then the stuff in Clearfield County kind of similar well costs, reserves might be a little bit less, maybe 3.25 Bcf, 3.5 Bcf on those. And those are a bit surprising because, as I said, it might incur that there's a trend of good gas productivity all the way from the New York Stateline down to Pittsburgh. So we just have to do some additional drilling to see if that really pans out in that manner. But there's no doubt that we're more sanguine regarding the Marcellus than we had been previously.
Leo Mariani - RBC Capital Markets, LLC
I guess, just touching base on the Eagle Ford here. I mean, it looks like in your latest update, you did have some improving IPs in the wells you guys have reported. You didn't talk about it for a better consistency across your position, but given the improving IPs, do you guys see potential upside in EURs during the course of the year as you refine your completion technique more?
I'd say if you model in the company, you're assessing the company's NAV. We'd still recommend you use your $900 million that we articulated last April. And we just have to -- as we get more data, we may come up with some different reserve estimates on there. But right now, I'd say the data that we've accumulated over the last three months just supports our $900 million Mboe net reserve estimate. The surprising thing to me about the Eagle Ford is just the remarkable consistency over such a long geographic area. So the next step, I think, for our Eagle Ford is really driving our costs down. We've got them pretty well tamed to the $6 million range now, and they're obviously generating, I'd say, stupendous reinvestment rates of return. I would say, in North America, whether oil or gas, I'm not sure there's any other large play that's generating any higher reinvestment rates of return than our Eagle Ford oil. And obviously, if we can knock that price down for 2012, and the well costs from $6 to $5 million with improved frac methodology, then we're going to have much, much even stronger reinvestment rates of return. And that's what this company is all about.
And we'll hear next from Bryan Singer with Goldman Sachs.
Brian Singer - Goldman Sachs Group Inc.
Going back to the Niobrara, can you speak more specifically to what you did differently in terms of the completion that gave you more confidence in matrix flow? And how, if at all, those changes may be applicable to other emerging liquids plays in your portfolio there where you're facing similar questions over natural fractures versus matrix?
Brian, again, for proprietary reasons, we really don't want to give a lot away relating to the Niobrara. There's probably 10 or 15 of our peer companies listening to this call that would like to hear what we've done in that manner, and we're not going to give it away. I would say, each of these resource play turns out to require a little different frac recipe, and the Niobrara has been maybe the most unique so far just because it's got such a high percentage of fractures. So whatever solution we come up with for the Niobrara, it's not obvious that, that's going to be immediately transferable to some of the other oil resource plays, because most of the others don't have a high degree of national fractures that we've seen in the Niobrara.
Brian Singer - Goldman Sachs Group Inc.
And then shifting to the Permian, can you put a plan to context when you look to the Wolf Camp, which really overlies a lot of play extending into the Delaware Basin, and based on what would you know now and the two counties you've tested? Can you talk to, I guess, a, whether you think the Wolfcamp can be drilled commercially beyond those two counties, whether it's the start of something wider within the play? And b, are there other zones beyond the Wolfcamp and the Leonard Shale that you think can provide a similar greater size resource for EOG?
Brian, on Wolfcamp specifically, we talked about Irion and Crockett counties, and we're not going to be going much beyond that today. But I would say that, at least within the areas that we've defined so far, where we've bought our leased, our 120,000 net acres, seeing some pretty positive things, very simple geology. We do have multiple targets in the fixed sections, and it's only very lightly structured, so not a big geo-steering issue of any kind. Gas and beryllium price in the overall Wolfcamp section, 20 million barrels of oil, 40 Bcf of gas in place per section, per zone. So there's a lot to work with in the Wolfcamp play. And also we're pretty encouraged by the early costs of EURs achieving 25% direct after-tax rates of return. In a program, though, we obviously hope to improve that pretty substantially. Right now we're only talking about a 40 million barrel of oil equivalent to net after royalty, but that's only from certain percentage of our acreage. It's risked pretty heavily for early recovery efficiencies, and as I said, it's only one of multiple targets net interval. And where it goes from here remains to be seen. It's a pretty competitive play right now, so we're not going to talk much about extensions beyond that. For the other play that we're involved in, near the Leonard or Avalon Shale play, we're also pretty happy with that, but it's a much more variable play geologically. Leonard, as we've said before, there's at least two target intervals, and below that in the Bone Spring, there's two, maybe three target intervals. Obviously, that play's also economic, incurring cost in EURs. But in program mode, we hope to get that up in the 40%, 50% range as well. I would say, on our 120,000 acres, we do have potential from additional zones, including the Bone Springs Sands. And maybe a little known fact is, that we've been active in the second Bone Springs sand for years. Since 2005, we've drilled about 27 horizontals and averaged about 300 Mboe per well NAR. And in the third sand, which may have even wider implications both in our acreage position and others, we just really haven't tested that in too many areas, but we do have an early discovery in that field, in fact, an oil discovery at a field called Red Hills, which -- we developed it vertically, because it was kind of pre-horizontal. But I guess we probably produced, what, maybe 15 million, 16 million barrels out of that field over the years. So we're pretty familiar with those objectives, and we'll be pursuing them in the future.
And moving on, we have a question from Irene Haas with Wunderlich Securities.
Irene Haas - Wunderlich Securities Inc.
This is really a macro question for Mark. I'm looking at everybody, this whole waiting, to us, oil in play is just great, its fantastic, all good. How do you feel about oil marketing, sort of localized oil-on-oil competition? And the reason why is because all these oil basins that have been sort of declining are coming back stronger and faster than expected. Do you see any sort of issue with really downstream infrastructure in the U.S., which is really, really sticky, and the ability to kind of catch up with upstream production growth in the oil area which is more dynamic?
The answer to your question, I believe, is that in multiple areas, on a macro view, we're going to see oil production, soon the existing oil transportation infrastructure. We clearly saw that in the Bakken play, and EOG put in a crude by rail to get our crude oil out of that North Dakota, which is kind of a depressed pricing area. And by the way, that project we put in is working like a charm, very profitable for us, and we've got a lot of requests to move other oil volumes on that line. The same thing is happening in the Eagle Ford in that the amount of oil that's generated is completely consuming the existing very limited compound infrastructure. And that will also happen in the Niobrara, if the Niobrara turns out to be a very, very large play. There's very little infrastructure there. So what I think is going to happen is you're going to see some significant differentials relative to some indices, whether it's LLS, whether it's Cushing, and you're going to see some companies who have proactive here, probably advantaged in their regional pricing, relative to some other companies in the play. I will say that there's a lot of talk right now on this LLS, Cushing big oil price differential, that if that differential persists, with time that we believe that our Eagle Ford oil is likely to get a price that is certainly better than Cushing, but not quite as good as LLS. Because most of our Eagle Ford oil by 2012 is going to end up in the Houston Ship Channel area. So that should be relatively advantage, certainly to Cushing. But short answer to your question is this infrastructure is a big deal.
And we'll take our next question from Joe Allman with JPMorgan.
Joseph Allman - JP Morgan Chase & Co
Mark, on the same note on the marketing, what precludes you from trucking your oil to LLS at this point, and what are the costs involved there?
The real issue we have right now, Joe, is just the physical time it would take to take a truck from the Eagle Ford to get it over to Louisiana. It would require that we need to sign up even more trucks to get our oil moved. And there's really, believe it or not, there's just not enough trucks out there to deal with that. So in the short-term, our issues with the Eagle Ford, we're going to be trucking to local areas where it can be put into a pipeline, but it's not going to be a situation that we're going to be able to get it to Louisiana anytime in the short run. I will say we're looking at some real issues that could get us even our Bakken crew to Louisiana. But it may take a year before we get those implemented and, as you know, the differential LLS to Cushing typically is only $2 or $3, and now it's blowing out. And I certainly can't predict whether it's going to stay at that blow out rate for years or weeks.
Joseph Allman - JP Morgan Chase & Co
And then on asset divestitures, just kind of three part question. One, do you think you'll need to sell additional assets in 2012? And two, do you still plan on selling Niobrara acreage, given kind of the update? And three, what actually went awry with that Marcellus Shale sale?
On the last question there, on the Marcellus Shale acreage, I mean, it was mutual agreement between us and the intended buyer to part ways on that. But what I can say about that Marcellus acreage is there is no title or environmental issues relating to that acreage. The fact that we're going to go ahead and develop that ourselves would indicate that there are no issues relating to those items. I think some of your question is -- as far as whether we need to sell the company in 2012, Niobrara acreage. Some of that, that kind of comes around to this funding gap question, which I'm surprised I haven't gotten so far. What I'd say on the funding gap issue is that philosophically the 35% net debt-to-cap ratio is a pretty hard line. It's not our intention to run this company at net debt levels higher than 35%. And that goes for 2011, '12, '13, '14, et cetera. And we've got a lot of levers at our disposal for 2012, '13, '14 that we can pull, some of that, obviously, going to depend on what are the hydrocarbon prices in those years and what will be our cash flow. And if I leave you with anything related to that, it's that we're not going up to lever up this company to what we view as unreasonably high debt levels. And we are going to pursue these reinvestment opportunities, and it is unlikely that we are going to do JVs certainly on any of the oil plays. And we'll keep open the concept of whether we would do any on our gas plays, but our inclination as of now is not to do any JVs on any of our gas plays. Although in the Horn River, potential buyers that we have talked to in the Far East for the LNG have expressed some interest in equity in the upstream, and we just have to see how that plays out in negotiations with potential buyers over this year. So we've got the Horn River kind of earmarked. We'll figure out what to do with it as the Kitimat LNG story plays out. But right now, the plan for the Horn River is to end up linking that large amount of gas to an LNG oil index contact. So as far as the other of your question was would we sell some Niobrara acreage, our answer is yes. I mean, we would consider but just depending on what price is offered on some situations like that.
And we'll take our next question from Monroe Helm with Barrow, Hanley.
H. Monroe Helm III
Just a little bit more on the Wolfcamp play, if you would. The 40 million barrels that you've indicated here you said just from one zone, can you identify within the Wolfcamp what sectors may be in season, if you talk about where you think the reserves are within that 40 million barrels relative to those three zones? And what other zones in the Wolfcamp do you think are perspective as we go down the road .
Monroe, we've said really about all we need to say on the amount of oil and gas in place in that overall Wolfcamp, and the fact that it is multiple zones. But that's a bit of a question yet in everybody's minds, which of the zones is going to be best? Or are they all going to be good? What areas are -- the A or the B or the C going to bring perspective into the overlay or not? And that's all kind of proprietary information from drilling that were not ready to give up yet.
H. Monroe Helm III
You did say from one zone it was 20 million barrels of oil in place and 40 Bcf. Is that what you said?
That's in place, per section, per zone.
H. Monroe Helm III
But you won't give any color on what you think the ultimate could be here on a per section basis or oil in place?
Well, I think I just did. Oil in place per section is that 20 million barrels of oil in place per zone per zone. That's really as far as we can take it today, Monroe. It's just too early in the play for us to talk much more about than what we've already said.
H. Monroe Helm III
The second question has to do with the Niobrara. Do you think that there'll be -- like we're seeing in East Texas -- do you think there's going to be some really sweet spots in this play? And do you think you've pretty much identified where the sweet spots are on your acreage?
Yes, all of these plays have sweet spots in them. We've learned from experiencing a vast amount of exposure that EOG has in all these resource plays. And we're still really working on that in determining that, and it's really early in the testing process of this new technique, but we're working on that. And I think there will be some sweet spots. And we'll just have to see how it plays out.
And we'll take our next question from Daniel Morrison with Global Hunter.
Daniel Morrison - Global Hunter Securities, LLC
I know you're keeping the information kind of skinny on the Wolfcamp play, but the 40 million barrels of your early assessment there, is that limited just to the area where you've been drilling in Irion and Crockett counties or is that across the basin?
No, Dan. It's limited to a portion of our acres in Irion and Crockett County. It's not our full 120,000 acreage position. It's only the part that we've actually put holes in so far. We've drilled, I think, eight horizontals and completed four. We're not ready to talk about the entire position yet.
Yes, I guess as an overview, there's too ways the oil product reserves in the Wolfcamp could grow. One way is if the one productive zone that we've pretty much proven by testing, if that extends over all our 120,000 acres. The second way is that if it turns out that these two other zones, which might be productive, if they turn out to be productive, if they extend just over the acreage we've tested or if they extend overall acreage. And obviously, the big home line is we have multiple zones that are productive over 120,000 acres. And I would say by year-end we ought to have a reasonable guess on do we have multiple zones and do they extend over all our acreage or part of our acreage. We're just as curious as you are to find out what the answer is.
And we'll take our next question from David Tameron with Wells Fargo.
David Tameron - Wells Fargo Securities, LLC
I'm just going back to what you said on trucking, Mark. If I think about the oil ramp or the oil volumes that are ramping predominately in the U.S. for EOG, but yet you said the trucking is tight. Can you reconcile that a little bit for me, how you're going to be able to grow with that rate with the tight trucking and just the tight infrastructure?
Well, you have to come up with some alternatives. I mean, for example, in the Bakken, when we had the high growth rate, if we had not come up with the crude by rail and implemented it within 12 months, we would have had significant production curtailments. But we came up with a plan. And the same thing, we have an interim plan. The window is a problem area relating to Eagle Ford is really today through mid-2012. Once the line gets put in by Enterprise, the oil pipeline, this problem pretty much just goes away. So we got 12 months kind of a timeframe, 12, 15 months, where we have to deal with it. And we're looking at some, I guess, the best thing to say is some unique and inventive ways to deal with it, and some of that's proprietary.
David Tameron - Wells Fargo Securities, LLC
Is it fair to say that if you didn't have that, or if you don't implement it, if you didn't have a system, that it would be hard to hit those numbers? I'm just trying to check out the overall tightness just coming out of the basin and the bigger picture oil macro.
I guess the way to put it is that I'd expect that as we go through the year, you may hear some stories about issues on tight trucking, particularly in the Eagle Ford, and we hope we get a fix on that. It's pretty much the same thing as when we articulated in November that the frac situation was tight, not only in the Eagle Ford but in other areas, and everybody said "Well, we're not hearing that from any other companies." And I think now, if you get other companies to fess up, I'd say 100% of the companies in the U.S. have problems with frac availability. So again, EOG is trying to be open to discuss these issues on the front end even though you may not be hearing them from other companies.
David Tameron - Wells Fargo Securities, LLC
If I think about bigger picture, you made a comment about supply consuming the infrastructure, there's always been the old axiom that oil is harder to grow than gas. But of course, that was before horizontal drilling. So how do you think about -- have you found that oil has been harder to grow than gas, or is it more infrastructure related, or is it just the initial ramp up that we're putting in these plays? It seems like across the industry, like you mentioned right? Frac-ing in November, everybody's bringing in production rates a little bit. Can you just talk about how you see that at EOG? Has it been hard to grow oil, et cetera?
Simple answer to your question is, yes, it's harder to grow oil than gas. And I think that as you see the whole industry moving towards liquid, you're going to see this played out among multiple companies that perhaps the initial estimates they give on liquids volume growth don't turn out to be what happens. The one reason, and a couple of reasons are, that we all report, whether it's Eagle Ford or Bakken oils or whatever, initial IP rates that look outstanding. But oil wells don't flow very long. They need artificial lifts in very short periods of time as opposed to a gas well that may go five or six years before it needs compression in some kind of cases. The second thing is the artificial lift that you put in oil wells has a higher downtime than you typically have with gas wells. With broad pumps, centrifugal pumps, they fail more frequently. So one of the issues that we've had to adjust to is that we've had to factor in for 2011 and '12 guidance just a higher downtime in our producing oil wells than we have been using a year ago. And I think you'll see that across the industry that the bottom line is it's just a lot harder to grow oil than it is gas.
And we have time for one final question from David Heikkinen with Tudor, Pickering, Holt & Co.
David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.
After tax rates of return for your Haynesville and Marcellus today, each region?
If you use the five-year gas strip, use the NYMEX on there, in the Marcellus, the stuff that we're doing in Bradford County, it's pretty darn high. You could build a case that it's 40% or so. In Clearfield County, it's a little bit lower than that. It's probably in the range of 30% or so. The Haynesville in a sweet spot, I would say, it's probably 20% to 30% in there.
David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.
And then Kitimat CapEx and export capacity in a go-forward case?
Well, it's going to be a bunch of money ultimately. I mean, the export capacity on a day [ph] basis is about 700 million cubic feet of gas a day. And conceptually, what we're looking at, and I believe this is in conjunction with Apache, I'm not sure what comments Apache may have made on Kitimat on their call, but we're really looking at this as Kitimat Plant 1, and then Kitimat Plant 2, which would be double that 700 million cubic feet a day. Ultimately, and the CapEx requirements, are clearly multibillion dollars. We're currently doing some engineering analysis on that. Of course, the big portion of that would be not required until 2013, 2014 kind of timeframe on there. So the biggest goal for Kitimat for 2011 is to secure an oil index contract in the Far East, and I expect it's going to take probably 12 months or so before we know if we can secure one. We have a lot of warm and fuzzy positive feelings now, but it's just going to take -- these things take a fairly long time to get it all done. So that's going to be the key point as you get toward late 2011.
And that concludes the question-and-answer session today. At this time, Mr. Papa, I will turn the conference back over to you for any additional or closing remarks.
Okay. Thank you very much for listening, and we'll talk to you again three months from now.
Again, that does conclude today's conference. We do thank you for your participation.
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