Everyone, and welcome to the EOG Resources Second Quarter 20 10 Earnings Results Conference Call. As a reminder, this call is being recorded. 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. Good morning and thank you for joining us. We hope everyone has seen the press release announcing Q2 of 2010 earnings and operational results.
This conference call includes forward looking statements. The risks associated with forward looking statements have 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 w 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 as well as possible reserves.
Some of the reserve disclosures on this conference call and webcast including those for the South Texas Eagle Ford Barnett Shale and New Mexico lettered plays may include potential reserves or estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary note to U. S. Investors that appears at the bottom of our press release and Investor Relations page of our website. With me this morning are Lauren Leiker, Senior EVP Exploration Gary Thomas, Senior EVP, Operations Jim Driggers, Vice President and CFO and Moira Baldwin, Vice President of Relations.
An updated IR presentation was posted to our website last night and we included Q3 and updated full year 20 10 guidance in yesterday's press release. We're still on track to deliver 13% total company organic production growth this year. Our shift to a higher liquids ratio is proceeding as planned and this was the Q1 in EOG's history where liquid revenues exceeded gas revenues. As we reported in our April analyst conference, production will increase every quarter this year giving us strong momentum going into 2011. I'll now review our Q2 net income and discretionary cash flow and then I'll provide operational highlights and discuss our capital structure.
Tim Driggers will provide some financial details and I'll close with comments regarding our macro hydrocarbon view in his concluding remarks. As outlined in our press release, for the Q2, EOG reported net income of $59,900,000 or $0.24 per share. For investors who follow the investors who follow the practice of industry analysts, focus on non GAAP net income to eliminate mark to market impacts and certain one time adjustments as outlined in the press release, EFG's 2nd quarter adjusted net income was $44,900,000 or 0.18 dollars per share. For investors who follow the practice of industry analysts who focus on non GAAP discretionary cash flow, EOG's DCF for the 2nd quarter was $656,200,000 I'll now address operational results and we have plenty of good news to report. Perhaps the 2 biggest new items are New Mexico Leonard Shale horizontal oil discovery and the results from some of the
best wells ever completed
in the Haynesville Shale. Completed in the Haynesville shale. In Southeast New Mexico, we've been working over a year on a Red Hills area at Leonard shale play and our first horizontal well has a 300 day production history. I note that the Leonard may also be called the Upper Bone Spring or Avalon Shale as there's some industry variance in terminology. We now feel we have reserve potential of 65,000,000 barrels of oil equivalent net after royalty reserves on 31,000 of the 120,000 net acres we have in
the play. We've completed 7 horizontal
and 4 vertical wells
and we believe typical for about 400 1,000 barrels of oil equivalent net after royalty for $6,500,000 well cost, which yields a 40 percent direct after tax reinvestment rate of return using NYMEX future prices. Typical wells are Loma Lomas Rojas 26, 1H and 2H which tested at 7 10 barrels of oil per day with 1 point 7,000,000 cubic feet of rich natural gas and 800 barrels of oil per day with 1,500,000 cubic feet and enriched natural gas respectively. We have 100% working interest in these wells. We're currently testing other portions of our 120 1,000 acres and we'll have results before year end. I'll note that the production stream from this accumulation is analogous to Barnett combo play since 1 third of the production is crude oil, 1 third is NGLs and 1 third is residue gas.
This play is just starting up. It will be late 2011 before we see a substantial production contribution from this asset. Moving to the Haynesville, during our April analyst conference, we advised that we delineated a new core area in Nacogdoches and San Alistin Counties in East Texas. Our most recent well results certainly confirm this. Our Murray 1H well averaged 25,000,000 cubic feet a day of natural gas for the 1st 30 days and the Crane 26 No.
1H well averaged 27,000,000 cubic feet a day from the same period. We have 96% working interest in both wells. Also in East Texas, our 49% working interest Walter's number 1H well IP ed at 21,000,000 cubic feet a day. We believe the Murray and Crane wells are 2 of the top 3 Haynesville wells completed anywhere in the Louisiana or Texas trend today. We continue to limit our flow rates in the Haynesville to manage pressure drawn out of the reservoir and these two wells were also limited by short term pipeline constraints.
Fortunately, a significant portion
of our
160,000 Haynesville and Bossier net acres are in this Texas sweet spot. In our April analyst meeting, we also noted that the Bossier shale was a separate target and our recent 100 percent working interest Red River 5 3H confirms our view testing at 15,200,000 cubic feet a day with 6750 PSI flowing tubing pressure. After several months of production, our Bossier wells appear to be as good as our Haynesville wells. Overall, we're extremely pleased with both our and activity level until we get all of our 3 d seismic shot and interpreted. Also, our activity in this area has been constrained by the lack of this quarter, some of which we've articulated in our press release, indicate a consistent 120 mile long accumulation with per well reserves similar to that outlined at the analyst conference.
Typical well completions are the Darling 2H, Kowalik 1H and Hach 7H wells, which IP ed at 1033, 1032, and 625 barrels of
oil per day respectively. We
recently completed the Borgfield 1H and 2H wells. These are our first wells in Wilson County for 707 and 8 36 barrels of oil per day respectively. We have 100 percent working interest in these wells. To date, we've drilled and completed 31 wells in the Eagle Ford. We currently have 25 wells waiting on completion, which will contribute to the second half oil growth this year.
We're currently running 5 rigs and we'll ramp up to 12 by year end. One major of the intensity of our future Eagle Ford development is that we plan to drill 2 45 gross wells in 2011 compared to 111 wells this year. The same story of consistent results holds true in our Bakken play. We have 12 rigs running there and our typical per well reserves for both the core and the light 30 seven-sevenH came online at 2,525 and 16.54 barrels of oil per day. We have 64% working interest in the Van Hook well, that's a correction for the 99% we noted in our press release and we have 81% working interest in the fertile well.
A few days ago, we also completed the Van Hook eight-thirty six well for 2,100 barrels oil per day, which will contribute to 3rd quarter volumes. Another note is that 3 recent wells on the western part of our acreage near the Montana State line, our Round Prairie, Carrot and Harts Scrabble wells recently tested at rates that are typical of our Bakken light wells giving us greater confidence in the western extent of our acreage spread. This year, we plan to drill 42 core wells, 57 light and 18 3 Forks wells. We'll also be drilling some longer reach laterals and we'll have results by year end. We are still early in drilling 12 80 Acres Space 12s.
A recent Eastern Edge 12 80 Space Lateral is Palomoe 2-eighteen which tested at 10 36 barrels of oil per day. In the Barnett combo play, we're operating 14 rigs and our typical horizontal results are characterized by the Bray 1H well which tested at 4 52 barrels of oil per day with 2,000,000 cubic feet of rich gas and the Bray 2H was tested at 5 28 barrels of oil per day with 2,000,000 cubic feet of rich gas. The King 1H and Olden 1H wells were outlined in the press release and tested at 344,000,000 with 2,500,000 cubic feet of gas and 3.20 barrels of oil per day with 1,700,000 cubic feet of gas. The Alamo B6H well is still cleaning up and is producing 500 barrels of oil per day. We've expanded our definition of the core combo from the previous 125,000 acres to 150,000 net acres based on recent drilling results.
In all areas of the combo except the East, our results are similar to our models. On last quarter's call, I noted outstanding results from the settled number 1H well, which was a horizontal drill in the 25,000 acre eastern portion of our play previously designated for vertical exploitation. After producing this well for 3 months, we estimate it will produce 260,000 barrels of oil, 412,000 barrels of NGLs and 3 Bcf net after royalty of residue gas or 1,100,000 barrels of oil equivalent net after royalty for a 4 $1,000,000 well cost and a greater than 100 percent direct after tax reinvestment rate of return. These reserves are considerably higher than our model well estimates. Additionally, results from our 2nd horizontal in this same area, the Richardson 3H, seem positive as a 3 25 barrel oil per day restricted rate while still cleaning up after frac.
Additionally or accordingly, we've changed our 2010 combo program toward more horizontals and less verticals in the Eastern area. Our original plan was 126 horizontal and 120 vertical wells. Now it's 200 horizontals and 34 vertical wells. This switch from verticals to horizontals with 100% rate of return will likely increase the overall ROR of the combo play. I'll also note that currently have several large multi well patterns on after frac flowback and we expect to see a significant increase in our combo production in the second half.
We also have some new data on our Colorado Niobrara plant. We've completed 2 additional wells, the Critter Creek 2-3H and 4-9H and they're producing at managed restricted rates of 570,600 barrels of oil per day respectively. We have 100% working interest here. We have 4 rigs running in this play, but as we previously stated, we want to observe production from these and earlier wells until year end before we make a reserve estimate because the reservoir is heavily fractured. In Southwest Kansas, we also recently completed 2 nice shallow vertical wells with 100% working interest.
The Cinthia thirty five-one IP at 1700 barrels of oil per day and the Brookover eight-two well IP at 2 60 barrels oil per day. Several offsets to these wells are planned for the second half of the year. Returning to our natural gas assets, we're continuing to have good results in the Barnett gas window. We're running 2 rigs in the Barnett gas area and recently completed 6 more unit Our all in total Barnett gas finding cost year to date is $1.48 per Mcf. In the Horn River Basin, we're completing 11 wells from our winter drilling program and anticipate having flow results on next quarter's call.
In conjunction with Apache, we're making steady progress with Kitimat LNG, although we are still early into our projects. The key to this project is securing an oil indexed LNG contract and we're in the preliminary stages of discussions with potential the eastern portion of the Barnett combo and the Texas Haynesville. Outside North America, our Trinidad asset is currently in a producing mode. We plan to begin development drilling in a Tucan field during the Q4. In China, we've completed a second horizontal gas well and it's performing okay, but not as good as our first well.
By year end, we'll have completed 2 more gas wells and 1 oil well and we can assess the overall program. Outside of operations, another part of our business plan this year involves the sale of some producing natural gas assets and some horizontal shale gas and oil acreage that we are looking to close by year end. This equivalents per day, which was put on the market 2 weeks ago. The second package will consist of 180,000 acres of domestic horizontal shale gas acreage in the Marcellus and Haynesville and some rich gas and crude oil acreage in the Eagle Ford. We considered the JV related to this acreage, but instead decided on an outright sale because it's cleaner and less complicated.
This acreage package is larger than when contemplated 3 months ago. We spent about $1,700,000,000 over the last few years accumulating 1st mover horizontal shale acreage and frankly we have more good acreage than we can say grace over given our manpower and capital structure plans. So we're going to monetize a bit of this acreage. Our intention is to close these sales by year end and maintain a year end net debt to cap ratio of 25% or less for 20 10 through 20 12. You'll note that our estimated CapEx for this year has increased $500,000,000 from prior estimates, primarily because of higher frac costs and the increased number of production facilities, particularly in the Eagle Ford.
All of this incremental CapEx is related to oil projects. Roughly $270,000,000 of the incremental $500,000,000 is due to EOG installing oil facilities that previously planned to have a 3rd party midstream company installed. We did this because of timing and cost issues. Even with this higher CapEx, we expect to maintain a year end net debt to cap ratio of 25% or less. I'll note that the potential sale of a small portion of our Eagle Ford acreage doesn't affect our 900,000,000 barrel oil equivalent net after royalty captured reserve estimate we previously provided.
I'll now turn it over to Tim Dragers to discuss financials and
capital structure. For the quarter, capitalized interest was $19,800,000 For the Q2 of 2010, total exploration and development expenditures were 1,300,000,000 dollars excluding asset retirement obligations. Total acquisitions for the quarter were $4,000,000 In addition, expenditures for gathering systems, processing plants and other property plant and equipment were $55,000,000 At quarter end, total debt, long term debt was $3,700,000,000 and the debt to total capitalization ratio was 20 7%. At June 30, we had $650,000,000 of cash, giving us non GAAP net debt of 3,100,000,000 or net debt to total cap ratio of 23%. Effective tax rate for the 2nd quarter
was 46% and the deferred
tax ratio was negative 24%.
The
for the Q3 and updated full year 2010. For the full year 2010, the effective tax range is 40% to 50%. This higher range is due to the impact of international operations. We've also provided an estimated range of the dollar amount of current taxes that we expect to record during the Q3 and for the full year. Transportation costs exceeded the 2nd quarter guidance that we have provided due to the impact of several firm transportation contracts and the North Dakota crude by rail project.
These marketing arrangements generally ensure more reliable markets and better prices for our products. During the Q2, we had better realizations for both U. S. Gas and U. S.
Crude oil. We sold our U. S. Gas at a premium to Henry Hub during the Q2. For the Bakken crude that is being shipped to Cushing by rail, we are realizing full WTI at Cushing.
Now I'll turn it back
to Mark. I'll now provide a few macro comments. Regarding oil, we continue to be what I'll call rationally bullish both short and long term. I'll note that 2010 global oil demand is currently expected to be 86,000,000 barrels a day, the same level as in 2,008. So oil demand has recovered from the global recession faster than almost anybody had predicted.
Demand mix of course has changed where China, India and the Middle East are bigger drivers than the OECD. Following a double dip recession, we like the outlook for future oil prices. We have a small amount of oil hedged in the 4th quarter and have 6,000 barrels of oil a day hedged at $93.18 for 20.11. North American gas however is more opaque. One hopeful sign is that recent U.
S. Storage has been filling at a net 2.6 Bcf a day lower rate than last year. Since May 1, we've injected 2 44 Bcf less over a 91 day period. Additionally, Canadian storage has swung 120 8 Bcf year over year or 1.4 Bcf per day during the same period. Combined, this is a 4 Bcf a day storage tightening over year since May 1.
This may be due to either hot weather, strengthening industrial demand or supply declines. We're also encouraged by the last 2 EIA-nine fourteen reports showing flat production, which matches our internal models. We continue to moderately bullish regarding short term gas prices. We currently have 150,000,000 MMBTU per day hedged for 2011 at an average $5.44 price and 100,000,000 Btu a day hedged for 20 12 at an average of $5.44 Now let me summarize. In my opinion, there are 2 points to take away from this call.
First, our conversion from natural gas weighted to an oil weighted North American company is proceeding very well. All of our oil plays are performing similarly to what was presented in our April analyst conference and we've now added a new Leonard Shale play. You'll recall that in our April conference, we specifically noted that our oil production growth would be lumpy and not in a straight line quarter to quarter and that's exactly what is occurring. This is the nature of the development of these horizontal assets for maximum reserve recovery, where by we drill and complete a group of 5 to 15 wells together before bringing any of them to sales. I'll also note that as other E and P companies have subsequently proclaimed themselves to be liquids rich, the distinction between crude oil and lower valued NGLs seems to have been blurred.
To recap, our acreage in Eagle Ford, Moncton crude oil and condensate and 25% to be NGLs. And then our second closing point is that our capital plan is on track and consistent with that articulated at our analyst conference. Our intention is to shift this company to an oil mix organically, while maintaining a low debt level. Thanks for listening. And now we'll go to Q and A.
Thank you.
Production ramp implied in second half twenty ten in order to meet the midpoint of guidance and that's largely attributed to the U. S. You guys mentioned the combo being an area that will ramp significantly in second half. Are there other areas on a regional basis that are infrastructure bottlenecks or completion backlogs that are going to be relieved in second half twenty ten or is this ramp mostly going to be from increased drilling?
Yes, It's not the other areas where we're going to see increased production are the Niobrara and Eagle Ford clearly and also in the Vaca some of our key plays. And I'd say that we don't have that much that's truly infrastructure related. The key point here is that we basically batch drill these wells, then we batch complete them before we bring any single well online. And so as we mentioned in our April conference, you can't project our production growth for either 2010, 2011, 2012 as a straight line quarter to quarter to quarter. If you try and do that, it's just flat not going to work.
And it so happens that our Q2 production happened to be a quarter where we were completing a lot of a lot of wells, but not bringing them to sales. And the 3rd and 4th quarters are ones where we're going to be kind of in the opposite of that cycle. We'll be bringing a lot more on sales relative to our operational activity.
And then moving on to well cost, can you talk about well cost in general? And can you identify what regions you've seen the most inflation?
Yes. Yes. We've seen most of the increase there in South Texas predominantly because of the Eagle Ford Shale and the Haynesville. And yes, those stimulation costs are up. And yes, we're working these essentially new plays and EOG will find ways to secure stimulation services and supplies in order to lower those costs.
Can you quantify any of those increases?
Yes. The drilling cost, it's gone up about 3 percent predominantly on the rigs. Our average rig rates run somewhere around 17.5% and is about 17% the first of the year. And stimulation costs have gone up anywhere from 10% to 40% just depending on the area. So yes, that kind of makes tender well cost going up maybe somewhere around 6%.
Okay, thanks. And then on your second sale package, you mentioned 180,000 acres. Can you give us the breakout the breakout between the
plays on acreage?
Yes, we can give you a breakout about 51,000 of that 180,000 are Marcellus Acres in Bradford County, which is kind of in the Swedish spot of the Marcellus about 117,000 acres are in the Eagle Ford and some of that is in the dry gas, some of that is in the wet gas and some of that is in the oil window. So kind of broken in all three and then a smaller amount about 15,000 acres is in the Haynesville play.
Okay. Thanks. And then lastly, this second sale package and your Canadian shallow gas package expect to close by year end, how far does that get you guys along your total divestiture process?
Yes, I mean that's where we think we will be for all of 2010 and all of 20112012. At this juncture, we don't plan any additional divestitures except for maybe some very small things beyond these two packages.
Okay, great. Thanks guys.
Next is Brian Singer with Goldman Sachs.
Thank you. Good morning.
Hey Brian.
Mark, in your comments you mentioned that you had created a proactive unique solution in the Barnett that you plan to apply to the Eagle Ford. Can you talk and add a little bit more color on that in terms of reducing some of the frac constraints, when you expect to have that in place and whether that would alleviate some of the reasons for perhaps why the Eagle Ford moved a little more slowly in
the quarter? Yes. Kind of for confidentiality purposes, Brian, I'll give you a bit of a circuitous answer on that. But there are 2 issues going on currently in the States and specifically in a place such as the Eagle Ford. One is just the availability of proppants whether that sand, resin coated sand or some kind of intermediate strength proppant.
There's a very, very tight market. And then the second thing is just the availability of pumps, pumping services, if you will. And although the service companies are expanding their unit of pumping services and it's probably going to lag the system a bit. And so we're going to address both those issues, the proppant and the pumping services in a way that believe is going to give us a long term cost advantage. But we don't want to go with a lot of specificity at this juncture.
But our view is did a similar thing in the Barnett because we have very significant gas and of course the combo liquids reserves And we're talking about close to a 1,000,000,000 barrels at Eagle Ford. And so we're gearing up for something very long term and very permanent kind of a solution.
And when do you expect to have that in place? Is that something that will be gradual or is that something that is on the cusp of being completed?
It's gradual. It's in place currently or just very early stages. Most of will take place in 2011.
Great. Thanks. And then lastly, I think in response to that previous question, you indicated that the asset sales, the 2 packages are really at for the next few years. Given that, how are you thinking about managing CapEx versus cash flow in 2011 or should we just look at the 25% net debt to total cap as your main source of what you're gearing for here?
Yes. I guess the bottom line on that Brian is that if we get the price that we think is a fair value for these 2 asset packages plus with our expectations of what hydrocarbon prices will be in 2011 and 2012. The 25% debt to cap level, we stay below that. So at this juncture, we don't look like we need to sell anything else. And so that's the way the plan works out.
I don't want to go specifically into what we expect in terms of a price for these packages, but I don't want to signal anything to prospective buyers, but that's the way we formulated our plan. We've accumulated so much acreage at such a cheap price over the last 3 years by being in a first mover position that it gives us flexibility that some other people maybe don't have. And then we've looked at the JV piece of this thing and to us the JV kind of complicates the issue. We end up using our manpower for something less than 100% working interest on there. And so, we thought it would be cleaner to kind of sever our position from with an outright sale with this acreage.
So I guess to conclude then, if you get the proceeds that you're looking for, you'll probably end below the 25% this year. And then I guess next year, maybe you do spend a little bit over cash flow to generate 19% growth or do you have plans to stay within cash flow next year to achieve that great rate of growth?
No, as we would see it now, it's pretty consistent with what we said at our April analyst conference. We are likely to outspend our cash flow into our operating cash flow in 20 102011 and then go positive on cash flow versus CapEx in 2012. And so what we need to do is get enough proceeds from these sales to cover us for the GAAP in both 20102011. That's what we believe.
Great. Thank you.
And next is Leo Mariani with RBC.
Yes. Good morning here guys. Mark, you talked about selling off assets to kind of cover 2011. What's your what are you thinking on gas prices next year in terms of what you're forecast kind of gets you there?
Yes, pretty similar to my $50 range. We're not counting on $7 gas prices next year. We take them if they come, but it's not a particularly aggressive gas price forecast, pretty similar to what the NYMEX is indicating for 11 currently.
Okay. Jumping over to the Leonard Shale, I guess you guys reported 2 well results, horizontal well results that is and you had 5 others. Were those 5 others that you had disclosed rates on reasonably consistent with the two rates you reported? Were those the latest rates? Have you seen kind of improvements?
Can you give us a little bit of chronology there?
Yes. The chronology is we drilled a short laterals and completed that well and brought it on production about 300 days ago. And we just observed production and kind of kept quiet about the play for 4 or 5 months to just see is the production going fall off sharply or what's it going to level out at. And during that interim, once we felt good about it, we began to accumulate a bit more acreage there. And so as we would see it, we've now spent enough time with this play and have enough production history and drilled enough wells over the 31,000 acre portion of our 120,000 acres that we feel pretty good about that portion and we feel pretty good about the production declines.
The 2 wells that we were reporting, those wells have been online anywhere from 30 to maybe 40, 50 days. And they are more the 5,000 foot lateral length wells with the optimized fracs. So they are more typical of what we would expect on a go forward basis. And then concurrently, we're drilling on some of the acreage outside the 31,000 acres. And at least for a portion of that we feel pretty good.
Some of it is we just have to see, but a portion of the additional acreage has really been confirmed by some other P and P companies drilling good wells kind of around us.
Okay. I guess just jumping back to your production guidance, you talked about sort of lumpy oil growth here, a lot of wells coming on in the second half of the year to boost volumes. I guess looking at your U. S. Gas production, you guys also have a pretty good increase in your forecast about $150,000,000 a day, I think, Q2 to Q3.
I guess you mentioned a bunch of oil plays ramping up. What's kind of happening on the gas side just to get your guidance there?
Yes. I meant to say, Leo, that the lumpiness is going to occur in both oil and gas for these horizontal plays. The 2 big drivers for the gas side in the 3rd and fourth quarter volumes relative to earlier quarters, the biggest single driver is the Haynesville. Another driver will be the Horn River in Canada, which will be we complete the wells in the summer and then bring them online about September or so. And then in our South Texas division, we expect to see some significant growth.
This division will be partly from horizontals and partly from some vertical wells in the Frio and Vicksburg
100,000 acres there. Is there any particular geologic reason you're focusing on that? Or is that more just sort of infrastructure related?
Yes, it's really infrastructure related. I mean, we drilled the first two wells in that area and they got a ton of publicity and then we just said, well, let's see whether we have enough sustained production here to justify putting in some infrastructure. And so we've been really drilling specifically in that area, not so much because the other areas are less perspective, but it's just we want to get a core area that can justify particularly some gas Haynesville wells in terms of
why they're so strong? Any sort of Haynesville wells in terms of why they're so strong? Any sort of geologic reasons? And what are your well costs there on the Haynesville in that area?
I think they're pretty typical geologically of that Texas sweet spot in Akadoshia, San Agustin counties and that they're slightly deeper than it is in Louisiana. The TBD depths are probably 13,000, 14000 seats as opposed to 11 or 12 in Louisiana. So, you have more pressure and rock quality is actually a little better as well. Some of the geologic characteristics, the amount of clay, the amount of total organic carbon are both very positive in that area. So it's pressure and raw quality together, we think it's indicative of that whole Texas sweet spot where most of our acreage is concentrated frankly.
Well costs, I'll turn it to Gary.
The well costs, are just a little bit higher in there, but we continue to make progress on drilling costs by just having program drilling going on now in the Haynesville our drilling cost is down really about 15%. But, yes, overall we're looking at 30 percent plus rate return all in on this HaynesvilleBossier play.
All right. Thanks
guys. And Rob Morris with Citi has our next question.
Good morning, Mark, Lauren, everybody. Three questions real quick here. You've addressed a lot of my questions on the $250,000,000 increase due to completion frac services, which per well, that's if I do my math right, whether you're counting the full year or just second half wells, it's about 500,000 dollars to $1,000,000 increase per well on those costs, which is that correct? That would sort of correspond to around the 30%, 40% increase in the completion costs in Eagle Ford and Haynesville, more toward the upper end of the range that was mentioned. Is that correct?
What it works out to is just looking at the stimulation portion, what portion that is of overall completion and then what portion that is of overall total well cost. We're looking at this percentage stimulation increasing our over all 20 10 drilling completion CapEx by about $230,000,000 Right,
which out to about $500,000 to $1,000,000 a well increase in cost versus what you baked in there before, right?
Yes, that's pretty close. Okay.
On the Barnett combo flow rates you highlighted today were a bit less than on the wells you highlighted in the Q1, but apparently you're restricting the flow rate there also like you're doing on gas in the Haynesville. Do you have any data or evidence that restricting that flow rate on the Barnett combo or any of the other oil plays that you have is actually improving the EURs or the economics there or how are you looking at that?
Yes. The reasons for restricting in the combo versus Haynesville are a little bit different there, Bob. In the combo play, we frac those primarily with 100 mesh sand and we noticed if we pull them too hard early on, you get a lot of frac sand flow back there and which could cut out your surface equipment and could damage your frac back. And so what we've decided to do is just say, let's just put a choke in there essentially and just flow them back at restricted rates early on, mainly just to keep the sand from cutting out things. In the Haynes Vale, I'd say the so the combo, it's almost become a mechanical necessity for us to do that.
So what you can expect the future earnings calls or maybe a little more modest production rates as we report and mainly which will arrest the declines a little bit. In terms of the overall reserves, we don't think we can't describe at this point that reduced flowbacks are going to increase or decrease the reserves one way or another. We just don't have enough data.
Okay. And then you didn't mention I don't think the well cost on the Niobrara wells, you gave the flow rate, but did you have how much it cost to drill those wells?
That was about $4,000,000
$4,000,000 And just last question very quickly. You mentioned a solution in the Eagle Ford similar to what you've done in the Barnett to sort of address the availability of proppant plumbing services. In the Barnett, you actually purchased your own sand mine. Looking down here in the Eagle Ford, can you utilize that sand here to offset some of those costs or might you look at acquiring proppant manufacturer or another sand mine in addressing that issue?
Yes, we don't want to go in too many specifics on that. But, I mean we need to kind of integrate upstream a little bit if you will to get our hands on some proppants. And there are several ways to do that. We're just we're very active in that. But confidentiality reasons, we really don't want to go any farther with the discussion on that right now, Bob.
Sure. I understand. Okay, great. Thank you.
And next we'll hear from Irene Haas with Canaccord.
Hello, everybody. I have questions on Niobrara. Firstly, where are the Critter Creek wells located in relation to the JAKE well and how long was the lateral legs and frac stage? Secondarily, on these Anything to do with the fracture complexity? And then also as compared with your other oil resource plays, what are the nuances in dealing with the Niobrara chalk?
And then sort of lastly, what is on the to do list? How much more work would it take EOG to get comfortable in assigning EUR and also a projection of what Niobrara could mean to EOG?
That's a long list Irene.
Let me kind of start with the first. The Credit Creek wells are south and west of our Jake and Elmer wells that we talked about previously and a little bit north of our Redpoll wells. So they're all bunched together in what we call the Hereford prospect that 100,000 acres of our total of 400,000 acres. So they're on 6 40 spacing currently. We're testing some closer spacing in there right now.
Regarding your second question about why we avoided silo, we as we said at the analyst conference, we had mapped that whole basin and tried to understand where the geologic sweet spots were. And actually silo mapped up as a geologic sweet spot, but we felt it was already fairly well developed. Although there are possible extensions to that build, downspaces to that build, but we did not focus our leasing efforts there because we felt like most of it was already HBP and we instead leased any other sweet spots that we had met. Relative to the other oil the big question we have here is, what is the contribution from the flow that we're getting from fractures versus matrix? And really we have not much to update you on from the analyst conference.
We still are looking at production. We're watching how fast pressure declines with production and try to understand are we seeing matrix kick in or not. We think we're seeing some positive indications on some and not on others and it's just too soon to tell. What we believe is it will take the rest of this year closely monitoring these wells and wells that we'll be drilling between and then to really understand is it going to be a very, very large play that includes Matrix contribution or is simply going to be a strong economic good rate of return play, but with less overall reserves because we have to space it at maybe 6.40s or 3.20s 80s. So that's the big question we're trying to deal with now.
We are testing a lot of different kinds of completions, proppants and spacing and trying to understand what we can do to enhance Matrix contribution. But it really is too soon to tell.
Okay. The 2 wells, are they how long are the lateral lengths?
They're 5,500 to 5,500 foot in length, Irene. And as Lauren was saying, there's a whole lot of experimenting going on with our stimulation treatments to try to determine how we best stimulate the matrix in order to determine individual well EURs to make an estimate of potential here.
Okay, great. Thanks.
Joe Allman with JPMorgan has a question.
Thank you. Good morning, everybody.
Hi,
Joe. Just a follow-up on the 2 Critter Creek wells. So just to confirm, so you stimulated both those wells?
Yes, yes, they were stage fracked. And the exact methodology of the stage frac is kind of what we're experimenting with. Since Niobrara seems to be of some interest to everybody, I mean, we'll give you a little more color on the Jake and Elmer wells appear to
be kind of stabilizing
each at about pretty
significant production, I think,
50,000 barrels or so in the first pretty significant production, I think 50,000 barrels or so in the 1st 6 months or whatever. So, I would say overall, if we are still cautious, we don't want to proclaim victory, but we are getting a little more positive feeling than we had 3 months ago, particularly in observation of the Jake and Elmer wells since those wells have a little longer life. But we're it's almost an issue of, okay, is this going to be, as Lauren said a very large oil reserve accumulation or is this going to be a more moderate size oil reserve accumulation? That's kind of where we stand today on the overall play.
Got you. That's helpful. And Mark, are you selling any of your acreage there in the Niobrara?
Yes. We've got some acreage that again, we just flat can't get to all the acreage that we've accumulated. And so we have some acreage there that we're in the process of disposing of. What we really did, we made kind of a choice in the company and we said, okay, we've got a plethora of acreage and whether it's on these shale gas plays or the oil plays. And for us to properly address all that acreage, we would have to be running in 2011 and 2012 well over 100 drilling rigs.
And we would be, I would say, as a company, a little bit out of control in terms of optimally managing those 100 drilling rigs. And we could dilute it and they would be great, but it's a bit of an 11, 2012 and go forward. And 11, 2012 and go forward? And do we really want to try and be in a little more controlled environment as far as our operational environment and maybe monetize the business acreage. So that's a little bit of the philosophy that's taken us to this asset or acreage monetization strategy.
We're going to be going 2011 and 2012. And we really don't want to go past that limit just because we have acreage that needs to be serviced, if you will.
Thanks. And then of the so how much acreage are you selling there in Niobrara?
It's probably somewhere around 200,000, 3000 acres. Yes, out of 4 100,000. So it's again,
it's not half our acreage or anything like that, close to it.
Okay, got On LNG, how are the discussions going related to the oil index contract?
Yes, still early days. I'd say we've got positive signs and I'm sure if you asked Apache who we're working with very closely, you'd get the same feedback that discussions are in the very early stages. The way I gauge this whole project is it's about the whole LNG project is probably a 10 step project. And right now, we are probably at step 2. We've got step 1 done, step 2 is looking pretty good.
But it's just I'd say all the elements are there to make this project come together. But it would be the first LNG project built by a non major company and also would be the 1st LNG project built in North America as an export project except one that's in Alaska that was built 20 or so years ago. So we have to realize that it's what we're taking on there is pretty big scope, but the price also is very big. So it's not going to move on just a rapid timeline in terms of we don't want to set any expectations that on the next slowly than that. All right.
Very helpful. Thank you. Thank you. Thank you. Slowly than that.
All right. Very helpful. Thank you.
David Heikkinen, Tudor, Pickering, Holt is next.
Good morning, Mark. Just to follow-up on Kitimat, thinking about the project and when you would start actually investing capital and then if we think about project financing as well, would that impact your 25% net to debt to total cap threshold if you project finance? And then when would you actually start investing capital?
Yes. I mean, the online date as we would see it now for this plant would be probably 2015. So, the big several of these several of these shale gas acreage plays, the one area that you have not heard me mention at all is the Horn River. And we have enough acreage up there where we believe we had 9.5 or so net TCF. And one option we have there is to bring someone in who might be an offtaker into the acreage position and use that to get some of our net funding for the LNG plant.
So we've got several kind of tools there. I mean, one is project financing. So I would say overall, our view is the 25% net debt to cap is going to be our target for throughout this LNG project also.
Okay. And then the asset monetization strategy, you've given some good operational explanations for selling versus joint ventures. Can you give us some thoughts around rate of return or cost of capital difference for joint ventures versus asset
sales? Yes. We haven't really gone down that road on there. In terms of that, it's just we've only got a certain staffing level here and we can expand it a bit, but we can expand it double it in a couple of year period. And the question really boils down to do we want to devote some of our scarce staffing level to basically educating someone else on a shale play and we do 100% of the technical work for perhaps a 50% net interest in the production or so.
And we would just prefer to do 100% of technical work for 100% of the production. And so it's almost a philosophical issue more than a calculated financial issue and comparative rates of return. And we can do that because we are so long on acreage relative to what we can logically develop during a reasonable period of time. So that's why we're looking at going that route.
Okay. And then a little more technically speaking the Eagle Ford, you had relatively low GORs, really interested in your thoughts around drive mechanism and recovery factors as compared to some of your gassier plays that you're experts in?
Yes. We're still looking at a limited drive mechanism and a recovery factor there, perhaps 3%, maybe 4% of the oil in as we'd see it there. And it's not a water dry reservoir. It's basically going to be just an expansion drive reservoir there. But again, it's early days in terms of Eagle Ford.
I tell our staff that if one of the big integrated companies had essentially a 1,000,000,000 barrel oil discovery somewhere, they would probably have 200 technical people assigned to only that project. And we certainly don't have 200 technical people assigned to essentially a 1,000,000,000 barrel project. And so, I'd say, we've got it identified as far as length, width pretty darn well. But there's a lot of other things that we're going to be working on and just kind of trying to optimize what is the right spacing here. Where is the right location that we can drill a well in this.
In some portions, you have 2 targets perhaps upper and lower Eagle Ford. In other portions, you only have one target. And then there's also the potential, you have the Austin Chonk and the Buddha that are very near the Eagle Ford there that some of our explorationists are clamoring to drill some wells in because they feel there is significant potential in those that we certainly haven't added in So what I'd offer to you is this year as we mentioned in our April conference, this is just a very slow start up year for the Eagle Ford. And we'll probably shift from low gear to 2nd gear in 2011 in Eagle Ford and then 3rd gear in 2012 and maybe high gear in 2013 or so. It's just it's not one where we're going to be able to just turn on and have these rapid volumes and we'll be learning the whole time.
That's why we're going a bit more slowly here with only 5 rigs. If we're making any errors, I think technically, we don't want to multiply it times 14 or 15 rigs at this time. So that's more of an answer than you want to get David.
Helpful, no. And then just on the Montana Bakken, your well results and just kind of the differences. Can you give us any thoughts around types of completions or any differences in how you think about completing how you have completed those wells and how you might complete them going forward? That's it. Thanks
guys. Yes. Basically, we're using primarily external packers on a lot of those things. In terms of the reserve levels that we're seeing, we're seeing situations where it appears like the reserves are very similar to our Bakken light reserves that we articulated in April conference and we'll probably be going to longer laterals out there, perhaps 7,500 foot laterals in that area. So the reason we kind of pointed it out is that there wasn't all that much drilling in the kind of Western North Dakota, Eastern Montana portion of the acreage we had.
And we always had a little bit of a question mark, is it going to be good that far out? And we feel that it's been answered in a positive manner now.
Guys. And we'll take our final question today from Biju Perincheril with Jefferies and Company.
Hey, Biju.
Hi, good morning. Thanks for taking the question. A couple of quick questions. When we look at 20 11 activity levels and to the extent that you can talk about those, I mean, are there any areas where you would see activity slowing down? I'm thinking Niobrara, Buen, Eagle Ford, those activity levels are going to be rising to offset that?
Yes. I'd say that our Rocky Mount gas development, we're not planning on doing much of anything there and might even slow it down a bit year to year mainly because that acreage is all held by
Okay. Yes. So would it be fair to say net net you would be looking at a higher rig count in 20 11 slightly? Probably. Okay.
We haven't finalized any plans yet, but slightly. And higher rig count, 100% of the incremental rig count will
be floated toward oil projects.
Fair enough. And then in the Niobrara, I think one of the wells that you talked about at the analyst meeting was unstimulated completion, I think was the Red Pul. How is that production holding up versus the other 2 that you mentioned that are stabilizing around 150 barrels a day?
Yes. We that was tried unstimulated and so they're kind of an open hole completion. And then what we ended up doing post the analyst meeting is, we went in and cleaned it out and did more of a case oil completion. And that well appears to be stabilizing at about 400 barrels of oil a day. So it's really right now and that's what we call the Hereford Ranch area, we've got 5 good wells.
Pretty good. So we like I say, we're warming up to the play cautiously.
Very good. And then lastly on the Lena shale, you said it's the production characteristics sort of similar to the Barnett combo. But when you look at the Rockies that would you say is it sort of more similar to the Eagle Ford in terms of lithology and rock properties?
No, I think the Upper Bone Spring or Vineyard as we call it is probably more similar to the Marcellus or Barnett or something like that, not to the Haynesville. It's more of a silicon based systems. It's got plenty of oil in place per section. It is a common type of tree. Probably a pretty good sized flake.
It has a large air lift, it gives a lot of stratigraphic variation in it, both in part itself and in the kind of barriers that you and saturation. So, lots to be learned by industry that is part of play right now.
Okay. Thanks.
Okay. Thank you everyone for listening and we'll talk to you again in 3 months.