Diamondback Energy, Inc. (FANG) Q2 2012 Earnings Report, Transcript and Summary

Good morning. My name is Mary, and I'll be your conference operator today. At this time, I would like to welcome everyone to the QEP Resources Second Quarter Earnings Conference Call. [Operator Instructions] After the speakers' remarks, there will be a question-and-answer session and instructions will be given at that time. As a reminder, today's conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Richard Doleshek, Executive Vice President and Chief Financial Officer. Sir, you may begin your conference.

Thank you, Mary, and good morning, everyone. And thank you for joining us for our second quarter 2012 results conference call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer; Jay Neese, Executive Vice President and Head of our E&P Business; Perry Richards, Senior Vice President and Head of our Midstream Business; and Greg Bensen, Director of Investor Relations. Many of you have already met Greg. He joined QEP 3 months ago from Halliburton, where he was part of their highly regarded IR team. We're thrilled to have Greg and want to thank Scott Gutberlet for serving as QEP's IR Director since the spin. Scott has moved back to the operations side of the business and has been promoted to Vice President of Commercial and Technical Services. We think that Greg will continue to provide the same high level support to our various stakeholders in leading our Investor Relations team. If not, I'm sure you'll let us know about it. In today's conference call, we'll use a non-GAAP measure, EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings and is reconciled to net income in the earnings release and SEC filings. In addition, we'll be making numerous forward-looking statements. We remind everyone that our actual results could differ from our estimates for a variety of reasons, many of which are beyond our control, and we refer everyone to our more robust forward-looking statements disclaimer and the discussion of risks facing our business in our earnings release and our SEC filings. In terms of reporting of results, we filed our Form 10-Q with the SEC yesterday, and we issued a combined operations update and earnings release in which we reported second quarter and 6-month 2012 results, we reported second quarter 2012 production of 79.6 Bcfe, 20% of which was composed of crude oil and natural gas liquids. We updated operating activities in our core areas and we updated our guidance for 2012 as follows: we lowered the top end of our EBITDA guidance slightly to be in the range of $1.35 billion to $1.4 billion, reflecting weaker crude oil and NGL prices; we reaffirmed our production guidance to be in the range of 305 Bcfe to 310 Bcfe; and we raised the bottom end of our CapEx guidance to be in the range of $1.45 billion to $1.5 billion. In terms of reported financial results, recall that in the first quarter of 2012, we elected to discontinue hedge accounting. As a result, the entire change in the mark-to-market value of our derivative portfolio runs through our income statement instead of through other comprehensive income. In addition, the impact of settled derivatives is no longer included in the revenue section of the income statement but is now reported below the operating income line. We also rebucketed our revenue streams such that we now report NGL revenues from our midstream business together with the NGL revenues from our E&P business. And finally, recall that in the fourth quarter of 2011, we changed the presentation of transportation expenses. Historically, we netted transportation expenses against revenues. We are now reporting these expenses in a separate line item in the operating expense section of the income statement and have recast historical revenue in product price to reflect this change in presentation. We'll be happy to provide additional information about the changes in how we report our financial results during Q&A. Turning to our financial results. When comparing the second quarter of 2012 to the first quarter of 2012, the story was a slightly stronger financial performance at QEP Energy, our E&P business, and somewhat weaker financial performance at QEP Field Services, our gathering and processing business. QEP Energy reported 7% higher equivalent production, which included sequentially higher crude oil and NGL production. The production increase was offset by a 6% decrease in quarter-to-quarter net realized equivalent prices. Field services' second quarter results were lower than the previous quarter primarily due to lower NGL volumes and prices. Our second quarter EBITDA was $338.5 million, which was $7 million or 2% lower than the first quarter of 2012, but up $2 million from the second quarter of 2011. QEP Energy contributed $266 million or 79% of our aggregate second quarter EBITDA, and field services contributed $72 million or about 21%. QEP Energy's EBITDA was up about $5 million, while field services' EBITDA was $13 million lower than the respective first quarter 2012 levels. Factors driving our second quarter EBITDA include QEP Energy's production, which was 79.6 Bcfe in the quarter, 7% higher than the 74.2 Bcfe reported in the first quarter of 2012. And the quarter's production was 23% higher than the 64.7 Bcfe reported in the second quarter of 2011. Of note, oil volumes were 1.3 million barrels, up 7% from the first quarter, and NGL volumes were also 1.3 million barrels, up 6% from the first quarter of 2012. Combined oil and NGL volumes were 2.6 million barrels in the quarter, double the 1.3 million barrels of combined volumes in the second quarter of 2011. QEP Energy's net realized equivalent price, which includes the settlement of all of our commodity derivatives, averaged $5.13 per Mcfe in the quarter, which was 6% lower than the $5.47 per Mcfe realized in the first quarter of 2012 and $0.58 per Mcfe lower than the $5.71 realized in the second quarter of 2011. The lower equivalent price reflects field level gas prices that were $2.17 per Mcf or 20% lower than the first quarter of 2012. QEP Energy's commodity derivatives portfolio contributed $117 million of EBITDA in the quarter, compared to $83 million in the first quarter of 2012 and $37 million in the second quarter of 2011. The derivatives portfolio added $1.47 per Mcfe to QEP Energy's net realized price in the second quarter, compared to $1.13 per Mcfe in the first quarter of 2012 and $0.57 in the second quarter of 2011. QEP Energy's combined lease operating transportation and production tax expenses were $117 million in the quarter, up from $114 million in the first quarter of 2012 and up from $103 million in the second quarter of 2011. On a per unit basis, combined LOE, transportation and production tax expenses were $1.47 per Mcfe in the second quarter compared to $1.54 per Mcfe in the first quarter of 2012 and $1.58 per Mcfe in the second quarter of 2011. And finally, QEP Field Services' second quarter 2012 EBITDA was $72 million, which is up $13 million lower than the first quarter of 2012 and $15 million lower than the second quarter of 2011. Processing margin was down $12 million or 26% from the first quarter on 8% lower NGL sales volumes and 11% lower realized NGL prices, offset somewhat by shrinkage expense that was sequentially $2 million lower in the quarter. Fee-based processing volumes were up 8% from the first quarter of 2012 while processing fees were flat, and gathering margins was up $3 million or 7% in the quarter on 8% higher gas gathering volumes of 1.47 million MMBTUs per day and the average gathering fee was about $0.34 per MMBTU. We reported a net loss in the quarter of $1 million, driven by a $49 million impairment of proved properties and a $38 million loss on the mark-to-market value of our derivatives portfolio. The impaired properties were primarily mature, higher operating cost gas properties in the Western Midcontinent region that were impacted by lower crude oil, NGL and natural gas prices. And as I mentioned earlier, in the beginning of the year, we discontinued the use of hedge accounting. And as a result, the change in the mark-to-market value of the derivatives portfolio runs through the income statement as opposed to other comprehensive income. In spite of the $38 million unrealized loss in the quarter, the total unrealized gain for the derivatives portfolio for the first half of the year was $90 million. The unrealized gains and losses are noncash items and we adjust for them in our EBITDA calculation. Sequential DD&A expenses were up $15 million to $214 million in the quarter. And finally, interest expense was up $3.5 million in the second quarter compared to the first quarter as a result of the new senior notes that we issued on March 1. For the first 6 months of the year, we reported capital expenditures on an accrual basis of $731 million. Capital expenditures for E&P activities were $642 million, and capital expenditures in our midstream business were $86 million in the first half of the year. We continue to focus on directing as much capital as possible to a higher return in crude oil and liquids-rich natural gas plays, and Chuck will have more comments about our capital program in his prepared remarks. With regard to our balance sheet, at the end of the quarter, total assets were $7.6 billion and shareholder equity was $3.4 billion. Total debt at the end of the quarter was $1.87 billion, and we had $146 million of cash on the balance sheet, resulting in net debt of $1.72 billion, which is a 1.2x multiple of our trailing 12 months EBITDA. And you'll recall that in April, we entered into a $300 million, 5-year term loan agreement with a group of financial institutions, which has substantially the same pricing and covenants as our $1.5 billion revolving credit agreement. We drew the entire amount under the term loan, paid off the balance outstanding under the revolving credit and put cash on the balance sheet. We also entered into $300 million of interest rate swaps, which effectively fixes the interest rate under the term loan at 2.82% for the life of the term loan as long as applicable margin under the term loan stays at 1.75%. And with that, I'll turn the call over to Chuck.

Good morning. Richard has already hit the highlights of our second quarter results. I'll try to give you some color, give you an update on our plans for the remainder of 2012 and then move on to Q&A. First, some highlights. QEP Energy grew production to a record 79.6 Bcfe in the quarter, and that's a 23% year-over-year increase and a 7% increase over the first quarter of this year. We continue to make good progress on organic crude oil and NGL production growth at QEP Energy in the second quarter. Crude oil and NGL comprised 20% of total volumes. And at the field level, crude oil and NGL sales represented 52% of QEP Energy production revenues. QEP Energy crude oil and NGL production totaled 2.6 million barrels in the second quarter versus a little less than 1.3 million barrels a year ago, which was roughly 106% increase. Compared to the first quarter this year, crude oil and NGL production was up 7%. Crude oil comprised exactly 50% of the second quarter total liquids production. Northern Region total production was up 30% in the first quarter -- I'm sorry, in the second quarter compared to a year ago driven by a 33% increase in Pinedale gas and liquids production; a 30% increase in Legacy Division production, which was driven by an increase in oil production in the Williston Basin; and also by an 18% increase in Uinta Basin volumes. Northern Region crude oil and NGL production totaled 1.8 million barrels in the second quarter, and that's a 152% increase over the second quarter of last year and a 7% increase over the first quarter of 2012. The year-over-year increases were driven by a number of factors: first, a 93% increase in crude oil production in our Legacy Division primarily from the Williston Basin; second, from a growing volume of NGL at Pinedale, thanks to the startup of the Blacks Fork II cryogenic gas processing plant that came online in the middle of last year; and the third reason was driven by a 244% increase in NGL production associated with the new fee-based gas processing arrangement between QEP Energy and QEP Field Services or cryogenic gas processing of a portion of QEP Energy's growing Uinta basis volumes, and that contract was effective the 1st of May this year. Crude oil comprised 52% of the Northern Region total liquids production in the second quarter of the year. QEP Energy Southern Region production in the second quarter was up 18% from a year ago and 7% sequentially from the first quarter of this year. Midcontinent Division production, driven by increased liquids-rich gas production from the Cana shale and Wash plays and increased crude oil production in the Marmaton and Tonkawa plays was up 14% from a year ago. Production from the Haynesville/Cotton Valley Division was up 20% from a year ago and 10% sequentially from the first quarter of this year as we turn a few new wells to sales late last quarter on one of our 80-acre spaced pilot development units. Southern Region crude oil and NGL production totaled 777,000 barrels in the second quarter, and that was a 43% increase from a year ago and a 5% increase sequentially from the first quarter of this year. Crude oil comprised 47% of the Southern Region total liquids production during the second quarter of 2012. Turning to our midstream field services business. We had a good quarter. Clearly, the financial results at field services were hurt by the sharp decline in NGL prices, coupled with a slight increase in natural gas prices, which together negatively impacted keep-whole processing margins. The average realized NGL price for the second quarter was $0.96 a gallon, and then that compares to $1.26 -- $1.27 per gallon a year ago, and $1.07 per gallon in the first quarter of this year. The biggest component of the decline in the average realized NGL price has been the drop in the average price of ethane at Mont Belvieu, which was down 51% from the average price in the second quarter of 2011 and 31% from the first quarter of this year. The drop in the ethane price is magnified by the increase in the percentage of ethane in field services average NGL barrel as a result of the startup of the Blacks Fork II plant last summer. Ethane comprised roughly 55% of field services' unfractionated raw NGL or Y-grade mix in the second quarter of this year compared to about 48% in the second quarter of 2011. Field services' NGL volumes in the second quarter of 2012 were 41.4 million gallons, and that's a 14% increase over a year ago. Note that field services' NGL volumes were down about 8% sequentially from the first quarter of this year, and that's a result of this new fee-based processing arrangement that QEP entered into with -- QEP Field Services entered into with QEP Energy in the Uinta Basin, which effectively transferred about 3 million gallons of NGL from field services to Energy in the second quarter. While the decline in NGL prices certainly impacted field services, it's important to note that the unfractionated Y-grade NGL product from our plants here in the Rockies all ends up down in Mont Belvieu, which, as you all know, is a premium market for NGLs. And as a result, even with the recent pullback in prices, our processing margins remain positive. Though nearly -- they're not nearly as positive as they were 6 months ago. And we continue to run our cryo plants here in the Rockies in ethane recovery mode. Field services' gathering volumes were up 11% year-over-year, and that was driven primarily by increased volumes on the Blacks Fork and on the Cotton Valley/Hosston and Haynesville systems down in Northwest Louisiana. Now let's look forward -- let me give you a little color on our operations and plans for the remainder of 2012. As I do, I'd ask you to refer to the slides that accompany our release that we posted yesterday on our website at qepres.com. We continue to make changes in our capital allocation in QEP Energy in response to commodity prices and cost pressures. Those changes are summarized graphically on Slide 4. Note that we're now allocating 90% of our forecasted 2012 capital in QEP Energy to crude oil and liquids-rich natural gas plays. At Pinedale, we continue to refine our well design by optimizing the subsurface well placement to avoid fracture interference. We've been able to increase the number of fracture stimulation stages, the individual fracture stimulation size and the total interval that we're treating to maximize the recovery of reserves. The results from the handful of wells that we've completed with this latest optimization show better initial production rates, very similar to declined rates that the wells that we've drilled previously and hence, higher ultimate recoveries that have very attractive finding and development cost. Also note that we started to defer completion of a few wells at Pinedale into next year to take advantage of the contango and the forward natural gas curve. See Slide 5 in the slide deck for some details on Pinedale. In new innovation, we're making good progress on the Red Wash Lower Mesaverde wet gas play. We should get another 20 or so wells completed in this play during the second half of this year, including some additional 10- and 20-acre spaced pilot wells to help us figure out optimum well density and -- for our full field development. Based on our knowledge and experience from Pinedale, we placed these pilot wells adjacent to some of the older wells that had been online for several years in order to accelerate our understanding of potential drainage and frac stimulation interference issues. You can see the location of those pilot wells on Slide 6. And for those of you who are familiar with our Pinedale development story, Slide 7 should strike a familiar chord. We're now building our first of what will be many Pinedale-style, multi-well pads in the Uinta Basin. It's a big step as it signals the shift to our whole manufacturing mode for our talented team of well-delivery specialists in the Uinta basin. With all the focus on shale plays, I think it's important to note that tight sand plays like those at Red Wash and Pinedale offer excellent economics. And are in many ways superior to shale plays because the accumulations are far more concentrated. Pinedale is a world-class gas field in no small part because of the over 1 mile of fixed stack of discontinuous sands that comprise the gross pay interval, that translates into a massive amount of gas per square mile. And the Lower Mesaverde has all the markings of a world-class asset, too. It has stacked discontinuous sands and while the gross pay interval isn't as thick as it is at Pinedale, the interval is shallower. So the wells are cheaper to drill and complete. And because of the richness of the Mesaverde gas, the well economics are every bit as good and in fact even better than those at Pinedale. The concentration of gas in place in both of these assets means there is less wasted motion during drilling and completion operations due to more wells from each surface pad location, which means less investment in gathering systems, all of which translates into lower cost and higher margins. Also note that in addition to the Mesaverde-directed activity wells, we also have a drilling rig in the Uinta Basin that's focused on drilling horizontal and vertical oil wells, targeting various reservoirs in the Green River Formation. Moving to the Williston Basin, Bakken/Three Forks play, I must say I'm disappointed at our recent performance. We continue to fight high cost and permitting delays that are hampering our progress. We're suffering from high secondary service cost -- I call it secondary service cost there. There are things downstream at the completed well, primarily associated with water handling. We have already solved half of the problem by drilling our own water source wells to drive down the cost of obtaining and trucking the water that we use in our fracture stimulations. But on the flowback-produced water side, our wells on the west side of Lake Sakakawea are connected to a third-party gathering system that gathers the water, and that system isn't working properly. We're working diligently with the owner to get it fixed, but parts of it are undersized to handle the ever-increasing volume of water that's coming from QEP and other operated -- other operators' wells in the area. As a result, right now, we're paying to truck most of our flowback water and it's costing us over $1 million per well extra to do so. We will get this problem fixed, but it's a good example of the dangers of relying on third parties to provide gathering services. Permitting on the reservation has also remained a challenge. You'll note from our release yesterday that we dropped a drilling rig from our program mostly because of the cost associated with the water-handling issues but also because we’re struggling to get enough drilling permits on the reservation to keep ahead of our rigs. Despite statements from the Department of Interior that they've improved the process and reduced the permitting backlog, we just haven't seen it. Even with these challenges, we still anticipate completing about 14 new Bakken/Three Forks wells in the second half of this year. See Slide 8 for details, and I'll be happy to answer additional questions when we get to Q&A. Turning to the Powder River Basin in Eastern Wyoming. We're very pleased with the results of our first QEP-operated horizontal Sussex oil well which came online with a 24-hour peak rate of a little over 1,600 barrels equivalent a day. We have a couple of more wells in progress in the play targeting the Sussex. Slide 9 has details. In addition to the Sussex, we have permitting activities underway to permit additional wells to test other deeper targets, including the Shannon sand, which is a look-alike to the Sussex, as well as the Niobrara and Frontier Formations. We have a significant number of additional well locations in various stages of permitting in the play, but unfortunately, the majority of them require BLM approval. And today, we have yet to see our first permit on federal land. We provided details on our Midcontinent Division activities in yesterday's release. We have a number of wells in progress in the liquids-rich portion of the Cana shale play, where we are focused on drilling up our leasehold on 80-acre density. Most of these wells won't come online until late this year. See Slide 10 for details. In the Granite Wash, Marmaton and Tonkawa plays, we reported a number of operated and non-operated well results. All of these horizontal wells are targeting relatively shallow oil and liquids-rich gas horizons. Slide 11 gives some details on the recent activity in the Granite Wash. As I'm sure you'd all expected, we dropped our last rig in the Haynesville play during the second quarter. And to take advantage of the contango in the forward gas curve, we've elected to defer the remaining 5 drilling Haynesville Shale wells until next year. See Slide 12 for details. In a separate release yesterday, we provided you with an update on our estimate of probable and possible reserves and petroleum resource potential on QEP's extensive leasehold positions. The last time we reported estimated probable and possible reserves and resource potential was in our IR materials that we put out in conjunction with our spinoff in the summer of 2010. We strive to update these estimates every other year, and we try to do it outside of the normal year-end reserve reporting cycle just because of the amount of workload involved both for our folks and for Ryder Scott, our reserve evaluators. The key takeaways from the release, in addition to year-end 2011, in proved reserves are 3.6 Tcfe, we reported estimated probable reserves of 7.7 Tcfe, 9.5 Tcfe of estimated possible reserves and almost 20 Tcfe of petroleum resource potential. In short, there's a lot of very high-quality future drilling opportunities in our portfolio that are economic at prices under $4 for gas and $90 for oil. I would encourage you to take a look at the release, which contains much more detail by area and a summary of our methodology that we use to come up with these estimates. Slide 13 also provides a nice visual portrayal of the inventory by producing area, and the inset box in the lower left corner of the slide presents the comparison of the changes in our estimates by category since our last update back in 2010. Jay Neese is here with us today and he'd be happy to give you more color on QEP Energy. At field services, our plans call for investment of roughly $170 million in several major projects and obviously, we have a number of smaller ones. Construction is proceeding smoothly on the Iron Horse II plant, which is our next cryogenic gas processing plant in the Uinta Basin of Eastern Utah. The plant will have an inlet capacity of roughly 150 million cubic feet a day, and we expect it to be operational by early 2013. About half the capacity of this plant is contracted to a third-party producer under a fee-based processing arrangement. The other half will be available to process QEP Energy's growing liquids-rich gas volumes from the Red Wash Lower Mesaverde play. During the second quarter, we also commenced construction of a 10,000-barrel per day expansion of our existing 5,000-barrel per day NGL fractionation capacity at the Blacks Fork complex in Western Wyoming. The expanded facility is designed to provide additional options for marketing purity propane, iso and normal butane and gasoline range products to what are oftentimes premium value local, regional and national markets. And we can deliver these products by truck, obviously, in the close-by markets. But also, we are doubling our rail loading capacity of the plants so that we can deliver into more distant markets. We expect this new fractionator to be in service toward the end of the second quarter of next year. In addition to these projects, we, of course, have ongoing gathering system construction and well-connection activities, as well as we're continuing work on preliminary design, engineering and procurement activities related to additional new gas processing facilities in the Rockies. So in conclusion, we continue to make great progress on our organic growth of crude oil and NGL production at QEP Energy by allocating capital to highest return projects in our portfolio. And so 90% of our capital is being allocated to oil and natural gas liquids-rich plays. Yesterday, we affirmed our production guidance and we're still on track to deliver a production stream this year which will be comprised of at least 20% oil and NGLs. Our teams and very talented asset managers continue to look for ways to drive down cost and enhance the financial performance in both our upstream and midstream businesses. With that, Mary, let's open the lines for questions.

[Operator Instructions] Our first question comes from William Butler from Stephens.

I was wondering if you guys could provide some color now that we've gone to 0 rigs in the Haynesville on what the production profile could look like in the second half of the year.

Well, obviously, William, will go down. We would expect to start to see declines on the order of, maybe sequentially, 10% a quarter, starting in the third quarter. Remember, we did put some wells online earlier in this first quarter this year. And so those wells will continue to whole plateau, but obviously, we can't keep production flat forever with no drilling activity.

Right. And the deferrals of the completions, too. And so now that you all ceased all activity there and just sort of thinking maybe more broadly about the Haynesville, has it gone to the point like the Barnett, where it's sort of almost getting mature? And is that an asset that you all would actually consider selling at this point like Barnett play?

Everything's for sale for the right price. The -- although intuitively, it doesn't feel like the right time to sell our dry natural gas assets at the bottom of the cycle and it's far from mature. In fact, it has a huge amount of both proved reserve and future development potential, William. And we think it's a very high quality asset. And as gas prices a little north of $4, it becomes an attractive investment opportunity for us in our portfolio. So at this point, we don't have any plans to sell it.

And, William, it's got very low operating cost on an LOE and production tax basis it is about $0.40 per Mcfe. So on just a pure operating basis, it generates great cash flow. And we don't have really a lot of carrying cost in terms of lease maintenance, things like that. So we can just keep it in inventory.

Okay. Yes, I guess I used the word, mature. It's all on a relative basis. And then on the Lower Mesaverde, any idea in terms of 10-acre pilots, what the timing might be on that?

We'll get the wells drilled in the second half of this year, William. And from what we've seen, you get some, what I would call, instantaneous data as you drill. These wells, adjacent to wells that have been online, you will see or you have a good chance of seeing partially depleted sands as you drill. Or after we drill, we sometimes run RFTs to get pressure data. So that will give you some real-time data, but the real sort of proof in the pudding, if you will, is from production performance on the well after it's been online and you see whether or not you see impact from the adjacent closely spaced well. That takes 1 year or so. Frankly, that's the -- fully. And if you load -- I can't remember which slide it is -- now Slide 7 in our presentation, we show red and blue ovals there and you can see the 10-acre ovals are being held out. And we're basically laying the field development plan out on 10-acre spacing, but we'll start out by drilling the 20-acre spaced wells and we can come back in and infill with 10 acres as we get enough data to gain confidence on the effective drainage area of these wells. And it's just going to take a while. And it was -- it's basically the exact same process we went through at Pinedale, where, if you will recall, we started out basically with a grid of 40-acre wells and then just kept tightening the grid until now, we're 5 acres. We probably averaged about 8 acres at Pinedale. So the other thing that we look for and that we will refine as we drill more closely spaced wells is the exact azimuth of the frac wings off of these wells because at Pinedale now, we were able to predict within a very narrow aperture exactly where these fractures go. And so we avoid actually physically hitting the offset fracture, the offset frac ring and the offset well, by very carefully placing these wells in the subsurface. And that's data you can't model. You have to get it from real-time experience, and we'll be getting that data as well.

Okay. And one last question on the Sussex, certainly, it looks like an encouraging well. Kind of 2 questions there. Assuming by your comments, that was on private property? And then is there any visibility on the timing of BLM permits that you all can talk about?

Well, it's been frustrating for us that the BLM field office that handles permitting for that area is woefully understaffed. They have a large backlog. They don't even have some of the key people that they need in order to process permits to do on-site inspections and things like that. So it's a staffing issue. They're aware of it. We are not the only operator who is very actively campaigning to have them address this issue. We hope we'll be able to address it through maybe sharing some personnel from other field offices that aren't as busy, and they're focused on that, William. I can't give you an exact timeline. The good news is we still have some additional targets that we can access from private property, including deeper horizons underneath the Sussex that I mentioned in my prepared remarks, the Shannon, the Niobrara and Frontier. So we have some additional work we can do on private land while we wait for the permit backlog to clear.

Okay. What percentage of the acreage there is private versus BLM?

The vast majority of it is BLM. And I guess what I should point out is that if there is 1 acre of land in a 640-acre section, you need a BLM APD in order to drill anywhere in that section even if the actual physical location of the well, the surface location of the well or the subsurface trajectory of the well doesn't touch federal minerals. You're going to have to have an APD if there is 1 acre in a 640-acre unit.

Our next question comes from Andrew Coleman from Raymond James. Andrew Coleman - Raymond James & Associates, Inc., Research Division: I had a question -- I guess to delve more into the Haynesville data, I guess, how many wells or what percentage of your well count there is still on restricted rate?

Boy, that's a good question. I can't answer it. But let me answer it different way. We see a plateau -- all the wells are choked, okay. They're all on a -- they all started out on either 12 -- roughly a 12, 64 choke. And they all exhibit a plateau period, and that plateau period probably averages 6 months, some a little shorter, some have been plateau-ed for a year or so. And part of that just depends on exactly where the well was located in our acreage. And when they come off, we just -- we let them decline "normally." So we're not changing the choke size. And so what you'll see is that the decline, post plateau, is 55% or so averaged in the first year. So if you go back and sort of go quarter by quarter -- and I can't do this in my head. But if you go back quarter by quarter and just look at the well completions that we've made quarter-to-quarter and then assume that once those wells come on, if they all came on exactly in the middle of the quarter, they would stay on a plateau for, on average, 6 months. You'll get at the question that I think that you're trying to get me to answer, which I just can't in my head about how the families of wells in their plateau would start their decline. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. Yes, I'm just trying to get a sense of it. That you said 10% per quarter, and that might be a little -- or perhaps could be lower.

It's going to be hyperbolic, right? So you're going to see a higher initial -- a higher decline initially and then it's going to flatten quarter-to-quarter. I'm just thinking about the next couple of quarters. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Yes. And I guess, next question is, I guess, how much compression do you have in the field? And are you thinking about adding more compression? Or would you wait until next year to do that?

That's the interesting thing, and we talk about this quite a bit when we're on the road comparing and contrasting different shale plays. And I think this is an interesting point that is missed by a lot of people. There is 0 horsepower of compression in the Haynes field -- Haynesville field. And you compare that -- or rather contrast that with the Marcellus, where most of the wells there need compression after the first 60 days to 120 days, maybe even sooner depending on where you are in the play. Our wells probably -- average flooring pressure on our wells is probably 5,000 or 6,000 pounds. I mean, very few of the wells are even close to line pressure yet. So there's a heck of a lot of reservoir energy to help -- and as Richard commented earlier, that's what makes the cash costs so low in this play. And I think people miss that, but it's a very important point. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. So even then, when they're declining, you're still declining with 5,000 pounds on?

Yes. There's a great slide -- if you refer back to our Analyst Day presentation from November 14 last year, and I don't know if this page number is right. But in our Slide #123, if the book that I happen to have here is the correctly numbered 1. But there's a slide that shows Haynesville well ultimate recoveries in net present values are approved with restricted initial flow rates. And what it shows is a -- on the -- it's 2 graphs on the same slide. And the bottom one shows flowing pressure versus cumulative gas production. And what it does is it shows you that in a family of 4 wells that we put in here, 4 QEP wells that -- with almost 3.8 Bcf of cumulative production, those wells were flowing at about 5,000 pounds of pressure. So it -- yet at the -- at what is effectively the half life of the well, you still have flowing pressures of 5 times our gathering system, MAOP, roughly. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. So there's no risk then of the -- of wells getting backed out because of pressure?

No, the only wells that get backed out are non-Haynesville wells. Now when you move out of the sweet spot, when you move out of the core area, the wells exhibit a completely different behavior. They don't -- they -- the rates decline and flowing pressures decline very rapidly, and they hit line pressure very early in their lives. But this is the sort of hallmark of the core of the Haynesville play. And it's a relatively limited footprint when you think about it. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. I had a -- 2 other ones. Just, would you see the Pinedale declining as well, given deferred completion activity there? And then, I guess, lastly, if you could opine on perhaps what an exit mix might look like, say, you're going to be at least 20% liquids through the end of the year? How much above that could you get if the gas declines?

Okay. Pinedale doesn't decline other than we see that seasonal blip down in the wintertime when we intentionally shut down completion activities. And it's all weather-dependent, Andrew, but it starts sometime usually in late November, early December when we basically stopped completing wells during the coldest months of the winter and we start back up in March or April. This year, we're able to start really early because we didn't have a winter. So Pinedale production volumes will continue to grow. And as for mix, I think our exit mix will be higher than 20%. It'll probably be 23%, 24%, but I don't have an exact number for it -- for year-end.

Our next question comes from Brian Corales from Howard Weil.

And just getting back to the Bakken. And Chuck, I think you said in the past, it's -- running kind of 3 to 4 rigs isn't necessarily optimal in terms of efficiency standpoint. And now that you're dropping a rig, where -- I mean, where do you sit with the play? Is it one that -- is it time to get out? do you need to get bigger? Or where does that sit kind of over the next year or 2?

That's a good question. You're right, 3 rigs is suboptimal. 5 or 6 rigs is probably the right size so that you get some -- the economies of scale that we like to see and that would be -- if you think about our Haynesville program when we were running that at full scale, it was about 6 rigs, same at Pinedale. We continue to look for opportunities to get bigger there, and we've -- we continue to identify some areas where we think we may be able to do that. If we're unable to do that, it's a valid question, and we obviously look at our assets and constantly evaluate whether they're worth more to us and our shareholders or to somebody else. And the same answer basically applies. It applied to the question on Haynesville and that is the assets for sale, if for the right price, then it's simply a matter of looking at the value of the asset on a PV basis versus an offer that we would receive, which makes the most sense for us and for our shareholders.

And maybe to expand on that, I guess, if you look at your true oil assets, the Powder, which you've talked about, may -- your permitting may be tough. And then Western Oklahoma, I mean, could we see more capital -- continue to see more capital go to those areas? Or are you kind of -- are they at levels that you can expand today?

Well, there's certainly limitations right now in the Powder. I think those issues get fixed. There's a lot of operators who are all very exercised about the delays and inability to get permits in the Powder so that would -- that ultimately gets fixed. And there's the ability to accelerate there with additional permits because there are -- not only just -- it's not like the Bakken/Three Forks, where basically you have 2 reservoirs, there's a stack sequence that we can target. In the Midcontinent, it's going to be a struggle to drive a lot of additional activity there by allocating additional capital. Part of it is just the variability in results and not wanting to go faster than we can evaluate each well that we drill, so that we don't end up like we ended up earlier in the Granite Wash play, where we had our -- a series of wells being completed back-to-back, and the -- each well just confirmed the bad results from the previous one. So we need to be careful not to go too fast to sort of outrun the data. The other area that we haven't talked about where, I think, there is longer term in the next year or 2, a potential to accelerate oil production is in Uinta Basin. As we gather more data on the Green River formation, oil reservoirs and distribution of oil in that play, there's a ton of oil in place there that has not been touched by the existing wells that have been drilled in the field. And we know that oil is there, we just don't know where it is exactly. We know it's inside the limits of the field, and so we just need additional sub-surface control in order to develop a drilling program to get after it.

Our next question comes from Hsulin Peng from Robert W. Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: So my question, I want to talk about Bakken. I know you guys talked that -- you mentioned that you're drilling your own water wells. Can you talk about the timing of when you think the water issues will be resolved such that you can bring down the well cost?

Hsulin, there's a short-term solution. So the water supply wells are there, so that part of the equation has been solved. The challenge is moving the produced water, primarily the flowback water, which is the high-volume part of the life of the well. And we're trucking it right now. There are some intermediate or interim steps that we can do. And we're working with the owner of the water gathering system to do those. And that involves mainly adding additional pumps so that we can shove more water through the system. And that's going to take a quarter or so to get it done. And then the second step is we will need -- they will need -- and we are helping them with this because they didn't even have a hydraulic model on their water gathering system, so they don't even know how the flow works on it. We're building a hydraulic model on their system so that we can help them understand how a gathering system works, but we're going to have to -- they are going to have to loop or add additional pipe in parts of their system in order to handle the volumes of water that we are forecasting and the other operators are forecasting in the area. I mean that will take longer but we -- the intermediate step is 3 or 4 months away. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay, got it. And all that sounds good. And then second question is, can you just kind of give us your outlook on NGL prices for the next 12 to 18 months?

I'll give it to you, I'm not sure what it’s worth. But it's -- on a -- the 2 parts that matter, ethane and propane -- I'll start with propane. As you know, propane inventories skyrocketed last winter as a result of no heating demand. And so, we ended the winter season with a lot of propane in storage. That inventory level has come down in the second quarter and continues to come down. In addition, there are de-bottlenecking projects underway to move -- to increase the export capacity of propane from the Mont Belvieu area. So there are some incremental steps that are being done there. And then there are several new export projects under construction that come on next year, so the propane bottleneck and excess supply gets worked off. And you can see that propane prices have turned back up from a low -- in late May, early June, and are now up significantly from that bottom. And part of that's a result of -- and that -- this is in Mont Belvieu and then -- and that's as a result of the inventory being worked off. Ethane, we've seen ethane bottom and come back up as well. There were obviously some -- there were problems because of the propane storage inventory levels that drove ethane prices down, as well as problems with -- as a result of crackers being offline. Those crackers are back online now, and you're seeing ethane prices back up to around $0.40 or so a gallon at Mont Belvieu from a low, that it was a good $0.10 or so below that at the bottom back in May, early June. So for the rest of the year, I see some strengthening in propane. I think ethane prices will continue to recover some, but it's all about location. And as I mentioned in my prepared remarks, our NGL product all shows up in the Gulf Coast region at Mont Belvieu. And there, I think, the situation is fundamentally much better than it is at Conway where ethane prices are still negative, the frac spread's still negative. Ethane prices are roughly $0.07 or $0.08 at Conway today, and that's about $1.20 or so in MMBtu. So the frac spread's quite -- is negative. And as a result, most of the plants in the Midcontinent region are still running on ethane-rejection mode. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay, right. Okay. So that was -- that's helpful. And my last question -- I'll let someone else ask you some. Can you give us your current thoughts on M&A? Any desire to streamline your current portfolio, whether it's addition or a subtraction?

Streamline by addition. That's a good -- that's a sort of a double entendre. Look, we like our diversified portfolio because we've been able to demonstrate time and again that when we face problems, either permitting problems or well cost problems or commodity price challenges, that we've been able to allocate capital away from the area which is causing us challenges and move it to other parts of our portfolio and continue to deliver profitable growth, and I think that is one of the virtues of a diversified portfolio. And as a result, we continue to look at our core assets and look for opportunities to get bigger in those areas where we currently have activity because of the attractiveness of having multiple opportunities and multiple projects in which to invest capital. We tend to probably be more acquisitive than to be divesting of assets especially -- you've already heard my comments but I think the timing around divestitures of dry gas assets is absolutely a worse time to be selling, is in this market, and so it's unlikely you'll see us make any major divestitures. That being said, we're always looking at our portfolio and trimming things that we think are more valuable to other people than they are to us, and that effort continues. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay. How about additions potentially? Any area that will be -- that you'll get interested in?

Well we continue to work for opportunities to get oil here. We've continued to look at our property acquisitions, focused on the core oil areas where we are active, both in the Midcontinent and in the Rockies. And we've exposed a lot of bids and we've made unsolicited offers on a number of properties. We've been unsuccessful to date. We think we're pricing these offers reasonably, and we'll continue to do so. Ultimately, I think we'll be successful.

Our next question comes from Subash Chandra from Jefferies. Subash Chandra - Jefferies & Company, Inc., Research Division: A couple of working interest questions. First, in the Pinedale, I guess that the other dry gas Pinedale operators, probably one of the basins where they're showing very large sequential declines here in Q2, is your working interest going up materially from non-consents or anything else? And then in the Sussex as well, what do you think your working interest will be on wells in your development program if and when that occurs?

So at Pinedale, yes, our working interest has gone up because we've seen other operators who don't benefit -- our partners who don't benefit from the uplift associated with gas processing who clearly have different well economics, as a result, non-consent our wells. So -- and we've gone from a little over 60% average working interest to a little over 70% average working interest in the wells that we have drilled so far this year. Jay?

We anticipate it to be completed this year.

We anticipate it to be to completed this year. And that -- I think that's a good thing for our shareholders because in essence, we're acquiring reserves in a very low cost gas field from them, from -- as a result of those non-consents. And again, it shows the advantage of having a midstream business and being able to capitalize on the processing margin, which is still positive and still enhances the value of the production streams sufficiently that it makes the wells quite economic. Your second question on Powder River Basin, we probably average -- the Sussex play, we probably average 40% to 50% working interest across our acreage. I think we got about a little 120,000 net acres in the Sussex. And It's a fragmented -- it's a chunk of acreage but our interest is not 100% across it. So we typically, in a unit, we'll have anywhere from 40% to 50% interest. Subash Chandra - Jefferies & Company, Inc., Research Division: So it looks like from your non-op activity, and then even your op activity, that there's a lot of interest from other players to participate in these wells and/or explore on their own?

Right. Subash Chandra - Jefferies & Company, Inc., Research Division: Yes. Could you describe sort of who they are, privates or publics? And do you think that they have the pocketbooks to make it for a while?

Yes. Looking -- so, are you specifically focused, Subash, on the Powder? Subash Chandra - Jefferies & Company, Inc., Research Division: Yes. Specifically on the Sussex wells, I'm just curious about it.

Yes. The primary player -- one of the primary players is a private, and then the other players in the immediate vicinity are large publics, so there's a mixture. But some of the recent wells we've drilled, the largest non-op partner has been a private, it appears to be very well funded and very aggressive in the play. In fact, they've -- we borrowed a drilling rig from them to drill these 3 wells because they -- they're facing the same challenge that we are with permits. So we've been sharing a hot rig rather than moving one in the play just to drill the handful of wells ourselves. Subash Chandra - Jefferies & Company, Inc., Research Division: Good. In Red Wash, you've given us a lot of detail and maybe I missed this, but -- so what are your current thoughts on sort of continuity? I guess you're still working on the frac orientation question. And what do you think about variance of individual well EURs?

So we gave you a probit plot or probability distribution plot back in the Analyst Meeting last year. And I'll tell you at the outset that this is a statistical play. We see wide variability in EURs from 0.5 Bcf to over 4 Bcfe per well. It is -- as a -- it is the result of the geology. There are a series of sands that are stacked in each wellbore samples that sequence. And in some wellbores, you get a lot of sands, in other wellbores, you get a lower number of sands. The result though is a very robust and economic program that shows an average of about 2.3 Bcfe. Our CFO likes to just simplify and say 2, 2 and 2: 2 Bcfe, $2 million a well and 2 million cubic feet equivalent of initial production. And that's probably a simplistic but reasonable way to look at it, Subash. And the challenge for us, and the opportunity, is to set up on pads and start doing what I think is our core competence, which is whole manufacturing. I don't accept the $2 million well cost, I think we can drill these wells -- drill it completely for a lot less than that cost as we move into Pinedale-like development. And that's what excites me because we're at the cusp of doing that. We're building our first paths to start doing that today. Subash Chandra - Jefferies & Company, Inc., Research Division: In that variability, you would -- in contrast to the Pinedale, will be far greater in that the Pinedale just had a bigger vertical column of sands?

Yes, exactly. It's the -- sort of this power of numbers. So in Pinedale, you have basically 1,100 to 1,200 gross feed of -- I'm sorry, net feed of pay in a 5,000 -- 5,500-foot thick gross column. And so the geologic variability gets smooth because you just have so many more sands that you sample. But we see the same variability in other areas and -- in the Mesaverde and the Uinta basin, where other operators are developing in. And this looks very similar to us. And so again, I think you have to look at it as a statistical play. You have to think about it in terms of just multiple samples. And one of the reasons -- people asked us early on, "Why don't you have a bunch of rigs out there drilling?" We needed to gather the statistical data to be confident that we had the right mean, that we had the right distribution of results and that it makes sense from a development perspective. And the more data we get, the more confident we are that we have a very strong and very robust project economics. Subash Chandra - Jefferies & Company, Inc., Research Division: At what price for gas and NGL does -- do you think you're outside the comfort zone on wellhead IRRs?

In the Mesaverde play? Subash Chandra - Jefferies & Company, Inc., Research Division: Yes.

I think we have a slide in the back of our IR package that shows that -- but it's a sub -- it's around a $2 gas price. And we would be at probably sub-$2 gas price, and with a sort of $85 WTI and the current ratios of oil and NGL prices to WTI, so it withstands a very low gas price. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. I was just scared because I guess you had Devon out there talking about sub-30% ratio, NGL to TI. And if you had a view on the NGL component?

Devon is not an operator in Uinta Basin, so I'm a little confused. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. And then in the Bakken, do you think you'd get to sort of a 10,000 barrel exit rate this year? Or is that given what you discussed, too much to hope for?

I can't predict it at this point. It really depends on the timing of when was -- we get this water handling system problem is solved and how fast we can get wells completed.

Our next question comes from Brian Velie from Capital One.

Just a quick question in the Pinedale. With the improved completion procedures that you're using and the uptick that you're seeing in IPs, do you -- what would that take, kind of the average Bcfe EUR, from and to? I'm modeling it at about 4.5 Bcfe right now. Does that bump into close to 5? And if so, what does that turn your rate of returns into there for the play?

It's going to be variable, Brian. What we're seeing is that on the low end, we're getting a couple of just 0.2 or so of a Bcfe of improvement. And on the high end, it may be 0.7 to a Bcf of improvement in EURs. And we just don't have enough data yet to confidently put it across the whole field and say it's going to raise the average by x percent. It's just -- it's too early to do that. But there is a definite increase in initial rate, the shape of the type curve, the initial decline and term of decline seemed to be completely consistent with our earlier well results. So there just basically a bulk shift up in the type curve, which could result in a 10% or 12% increase in EURs across the field. We just don't -- we don't know yet.

Okay. All right. And then I guess, where are your rates of return right now in the Pinedale, maybe pre that improvement or being conservative enough in figuring that in right now?

Again, they vary from the flanks sort of low- to mid-teens up to well, north of 20% to 25% across the crest. And it depends on the well EUR. As you remember, there's a distribution of well results across Pinedale with the down dipped most or deepest wells on the flanks of the structure having the lowest EURs and the wells on the crest having the highest EURs. And some of the crest wells are probably north of 40% returns even at current prices because they're very strong wells.

Our next question comes from Andre Benjamin, Goldman Sachs.

First question is a follow up on one of the previous questions asked a little bit more directly. How are you thinking about the prospect, so the acreage and the amount of running room you have, in the Texas Panhandle and the various zones given your increased focus on the Marmaton and the Tonkawa versus less discussion at Granite Wash? I guess, how many locations do you think you have in those different zones? And I checked your prior comments that deals indicate you're kind of effectively writing off the Granite Wash? Or is it just being deprioritized?

Specifically with respect to the Granite Wash, the -- our focus here for the past year, maybe a little over a year now, has been on the shallowest zones. So on the Cherokee and shallower sands, and the -- for lack of a better term, Hogshooter or Missouri and/or whatever you want to call the shallowest most, very oily interval. The recent well results suggest that there are a couple of 3 shallow, very oily reservoirs there that appear to be quite economic. They're relatively limited in area like Stent [ph]. So the total inventory of those oil zone targets and oil zone locations is may be several dozen. And there's still an open question about exactly how many of those zones will be commercial, because there are various sands within the so-called Hogshooter or Missouri in interval, some of which are relatively thin and may or may not be commercial and we're watching other wells being drilled around us. And we'll have better ideas as we see some performance from those wells. The Marmaton and Tonkawa, we gave in our IRR materials back at our -- in November at our Analyst Day, sort of an overview of our inventory in those plays. And it's an evolving view of those reservoirs because we continue to get new wells drilled in the play and it changes our interpretation of the distribution of targets. So the key there is going to be just continuing to watch not only our own well results but that of offset operators as their drilling continues in the play. But the key point on all of these Midcontinent oil reservoirs is that they are not a typical resource play because they're not shales. They're sandstones and they're carbonates and they're deposited in a totally different environment. So there's a lot of lateral and vertical variability in the plays. We have not written off the Granite Wash. We have steered clear of the deeper intervals in the Granite Wash because they're dry gas. So in the current price environment, as we go through our capital allocation exercise, they don't get any capital. Those targets do not get drilling capital, but they're still there and they're still viable from a geologic and technical perspective, and they're economic at higher gas prices. But today, they're not getting drilled because they don't meet our -- well, they don't fall inside the window of where we're allocating capital.

All that's very helpful color. I guess on the Bakken, just want to understand the potential to get back the fourth rig. Was it the same rig that you just added, I believe, it was in June or so? Do you still have it on the contract? And would it be hard to get it back if say oil prices were to rise?

Let me answer in no particular order. It is a rig that we've had under contract for a very long time. And it was the poorest of the rigs that we had running in the Bakken. We would not want it back. We can pick up rigs in the Williston Basin. Interestingly today, there are rigs available in the play. And so we could pick up a rig tomorrow if we were comfortable that we could deal with the water issues. And I think the water issues right now are driving the cost and really is a rate-limiting step. Permitting is a concern. The issues with the permits are -- it kind of limits our flexibility and ability to move rigs to pads where we think we would have less issues with water handling. So in other words, we have permits but they're not in the right places to move the rigs today in order to avoid the water handling issues. So as we get additional permits and it gives us additional flexibility, we can add a rig and maybe even 2 rigs back to this program. But it's going to be -- it's going to take us about a quarter to work through these issues and make sure that if we do add a rig, that we can keep it running.

Okay, just one last big picture question. As you think about the liquids growth potential with your portfolio and balance sheet, what liquids growth rate do you think you'll target over the next couple of years, maybe a little color on the growth contribution from the key plays you're focused on, and then whether you would try to do that spending within cash flow, or whether you'd be more willing to outspend for the sake of some high return growth?

So looking at our existing portfolio that -- the sort of natural growth rate is probably -- will be 20% liquids this year, maybe 25% next year. It will cap out somewhere between 30% and 35% of our total volume, just because of the inventory and ability to really drive that growth. Would we outspend cash flow to drive liquids growth if the plays are economic? Yes. I mean, we're not going to -- we're probably not going outspend twofold or threefold to do it. But will do it within some reason without incurring a ton of additional leverage? Yes, we probably would, if the plays make economic sense and we're comfortable that they'll continue to make sense.

Our next question comes from Dan McSpirit from BMO Capital Markets.

Turning to the balance sheet and the ratio of debt-to-EBITDA, is that expected to change much here going forward -- from the sub 1.5x we calculate today? And then secondly, in the context of an acquisition where debt could be used to help permanently finance a transaction, how far would you stretch that ratio?

Dan, it's Richard. I don't think the ratio of debt-to-EBITD is going to change because we incurred more indebtedness. I think we're going to be at about that same level of debt that we ended the quarter with today at the end of the year, excluding an acquisition transaction. So the issue is going to be what the -- what does the denominator do? So that -- we won't increase, or increase that. We'll still be at about that $1.87 billion through the end of the year. And you just have it at the trailing 12 months quarter for roll-on versus roll-off. With regard to using what amount of debt as the level of permitting capital for acquisitions, we've worked very hard the first half this year to get liquid. We're sitting on $1.65 billion of cash and availability under the revolver. I think it's probably safe to assume that if we did do an acquisition, you'd see a short-term bump in that ratio. And if it goes north of 1.5x to 2x, you ought to expect that we would be very active in terms of delevering that, the balance sheet after a transaction.

Got it. And in recognizing that you do possess abundant liquidity today, just -- we're just returning to a statement made earlier about everything is for sale. I guess in the context of portfolio management here, if you were to monetize assets today, that is divest those assets today, how would you rank them as most likely to less likely to be divested?

Well one of the places that are most obvious sources of liquidity, Dan, would be something around our midstream business because of the inherent multiple advantage of that business. So a partial monetization through a strategic partnership or formation of an MLP, we've talked about and thought about. And I'm sure if you listened in on our previous calls, we've been asked about those. But one of the things that has basically made us pause and not do it is the -- was the -- is the obvious question about use of proceeds. If we found an acquisition and it was of sufficient size that we got outside of our leverage comfort zone that Richard mentioned, which is based on 1.5x -- 1.5, 1.6x. One obvious source of liquidity would be to proceed with a partial monetization of that business. But we clearly also like the business and we want to continue to control it because -- a good example is this water gathering system where owning and operating on your own assets between the wellhead and the point of sales and all of those sort of auxiliary assets that make production possible is absolutely critical to be in a successful E&P company. And we think that the model that we have is unique and it provides shareholders value that other companies just don't have.

Got it. And then looking at the probable and possible reserve table that you released in a separate press release yesterday after market close, the Haynesville and the Cotton Valley make up a significant percentage of both the probable and the possible reserve totals. What percentage of the 2.4 Tcfe of resource potential under that category is economic today, that strip pricing again, recognizing the low, low operating costs in the Haynesville?

So the Haynesville, the probable and possible stuff all falls inside that $4 and $90 window. And then the resource potential is basically everything outside of that. So a lot in the Haynesville/Cotton Valley division, a lot of the resource potential category is the upside and horizontal Cotton Valley wells. Additional, what I would call fringe Haynesville, so the stuff that's up in the extreme northeastern corner of our acreage where we don't have any reserves booked today. But the biggest piece of it is in the Cotton Valley where we have a -- we drilled a number of horizontal Cotton Valley wells back 2 years ago. And they're decent wells. They're just not economic at sub-$4 gas.

Okay, got it. And then just to clarify on the statements made earlier about delays and permitting wells on the reservation in the Williston Basin, can you provide some color and context on why that is? And again, just to confirm here that this is an issue not unique to QEP.

It is absolutely an issue not unique to QEP. It is a function of federal employees and the foot speed at which they process permit applications compared to the State of North Dakota. So everything on -- inside the reservation boundaries requires both BIA and BLM involvement to get a permit. And we've seen a growing backlog of permit applications for wells being drilled inside the reservation boundary. I think that, in part, it has been the result of a gross underestimation of the level of activity inside the reservation boundaries. So the office that issues the permits is understaffed, chronically so. There was an effort to bring in a group of people from outside of that office, a so-called strike team to help get caught up, and that did help some but they were only there for a finite period of time. And when they left, the backlog just came right back. And that has not been addressed by the Department of Interior yet, and it's something that -- again, we're not the only ones who are pounding on the table to try to get attention on it. One of the challenges is that the same people that we hire, engineers and specialists, that are necessary to issue these permits, we're competing for the same talent. And the federal government is -- it really struggles to, a, hire and then once they hire, retain the specialists that are needed because the industry ends up being our worst enemy and cannibalizing those staff. And it's extremely difficult, as you can imagine, to get people to live in North Dakota. The housing issues just are quite an impediment to hiring people and getting them up there. One of the approaches has been to -- in the past, in other areas has been for industry to pay for hosted workers or for consultants to come in to help the field offices process the permits. And that has met with deaf ears. That proposal has met with deaf ears so far. And that's an applicable concept not only for the Fort Berthold Reservation and for North Dakota but also for other areas where we're facing challenges like the Powder River Basin.

Our next question comes from Hubert Van der Heijden from Tudor, Pickering, Holt. Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just real quick also on the Bakken. Could you talk a little bit about how the wells are performing in terms of the learning curve there? And what are you seeing on the cost -- or on the drilling and completing cost side other than the increased cost for the water flowback handling?

So we provided type curves and sort of a range of well results from our previous communications and in our IR materials. The range, the short laterals are 300,000 to 350,000 barrels. And then if you look at the best wells in the play in our area, they approach 1 million barrels. And we've seen very strong Three Forks, as well as Middle Bakken wells. The learning curve, as far as drilling and completion -- on the drilling side, our drill times have come down. The drilling portion of the well construction costs have actually reduced over time, as we've gotten better at drilling our wells and running line there, et cetera. I'll remind you, we are drilling some extra long laterals. Some of our wells have measured depths that approach 23,000 feet, so we do have a relatively higher well cost as a result of that. On the completion side, we haven't seen any moderation in pumping services cost. And that has been an area that has continued to drive up the total completed well costs. We have made some progress on completion design and optimization around that, but it has not resulted in a reduction in the completion costs. The biggest single driver in the well cost inflation that we have seen and it is -- it has been this sort of what I call secondary service cost of handling water. We participate in a lot of wells that are operated by others. And with one glaring exception, one company that has a -- has been very good at holding the line on costs, our experience seems to mirror that of other operators that are operating both on the reservation and off the reservation, and that is that well costs have continued to escalate or spiral upward despite a flattening of rig count and therefore completion activities. So our experience hasn't been unique. We've seen other operators effective at higher well cost than ours as a result of inefficiencies and continued service cost escalation.

I would now like to turn the conference back to Mr. Stanley for closing remarks.

Thank you, Mary. Thanks, everyone, for calling in today, and thank you for your interest in QEP. We'll be on the road at various conferences over the next few weeks. We look forward to seeing you soon. And, of course, we would welcome you here to our hometown for our upcoming conference in a few weeks. With that, everyone, have a good day.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.