Diamondback Energy, Inc. (FANG) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the QEP Resources First Quarter Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to Mr. Richard Doleshek. Sir, you may begin your conference.

Well, thank you, Regina, and good morning, everyone. Thank you for joining us for our first quarter 2012 results conference call. With me today are Chuck Stanley, 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 Scott Gutberlet, Director, Investor Relations. In today's conference call, we'll use a non-GAAP measure, EBITDA, which is referred to as adjusted EBITDA in our earnings release, is reconciled to net income in the earnings release. 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 SEC filings. In terms of reported results, we issued a combined operations update in earnings release yesterday, in which we reported the first quarter 2012 financial results, reported first quarter 2012 production of 74.2 Bcfe, 20% of which was composed of crude oil and natural gas liquids. We updated operating activities in our core areas and updated our guidance for 2012. We reaffirmed our EBITDA guidance to be in the range of $1.35 billion to $1.45 billion. We reaffirmed our production guidance to be in the range of 305 to 310 Bcfe, and we modestly increased our CapEx guidance to be in a range of $1.35 billion to $1.45 billion, which is still in line with our projected EBITDA for the year. As you've heard us say in the past, the current year capital program generally has more impact from the following year's production than on the current year's production. From a financial reporting perspective, we continue to try to keep you on your toes. In the first quarter of 2012, we elected to discontinue hedge accounting. We believe that investors understand what is going on with the change in the mark-to-market valuations of our derivatives portfolio, and we don't believe that there's any real benefit derived from the effort required to maintain hedge accounting. As a result, the entire change of the mark-to-market value of our derivatives portfolio now runs through our income statement instead of through other comprehensive income. In addition, the impact of settled derivative contracts is no longer included in the revenue section of the income statement, but is now reported below the operating income line. Also, 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 and historical product price dated to reflect the change of presentation. We will be happy to provide additional information about the changes and how we report our financial results during Q&A. Turning to our financial results. In comparing the first quarter of 2012 to the fourth quarter of 2011, the story was weaker financial performance in QEP Energy, our E&P business, and slightly weaker financial performance in QEP Field Services, our gathering and processing business. QEP Energy reported marginally higher equivalent production, which included sequentially higher crude oil and NGL production but lower natural gas production, which is typical as we suspend completion activities in the winter in our Northern Region properties. The production increase was offset by a 10% decrease in quarter-to-quarter net realized equipment prices. Field Services' first quarter results were marginally lower than the previous quarter primarily due to lower FA prices. Our first quarter EBITDA was $345.7 million, which was $45 million or 11% lower than the fourth quarter of 2011, but up $40 million or 13% from the first quarter of 2011. QEP Energy contributed $261 million or 75% of our aggregate first quarter EBITDA, and QEP Field Services contributed $84 million or about 24%. QEP Energy's EBITDA was down about $40 million, while Field Services EBITDA was $3 million lower than the respective fourth quarter 2011 levels. Factors driving our first quarter EBITDA include QEP Energy's production, which was 74.2 Bcfe in the quarter, slightly higher than the 73.9 Bcfe reported in the fourth quarter of 2011. The quarter's production was 12% higher than the 65.9 Bcfe produced in the first quarter of 2011. Of note, while gas lines were down 1 Bcf, oil volumes were 1.2 million barrels, up 3% from the fourth quarter, and NGL volumes were also 1.2 million barrels, up 17% from the fourth quarter of 2011. Combined oil and NGL volumes were 2.4 million barrels in the quarter compared to 1.1 million barrels of combined volumes in the first quarter of 2011. QEP Energy's net realized equivalent price, which includes the settlement of all of our commodity derivatives, averaged $5.47 per Mcfe in the quarter, which was 10% lower than the $6.08 per Mcfe realized in the fourth quarter of '11 and $0.03 lower than the $5.50 per Mcfe realized in the first quarter of '11. The lower equivalent price reflects field level prices -- gas prices that were 26% lower than in the fourth quarter of 2011. QEP Energy's commodity derivatives portfolio contributed $83 million of EBITDA in the quarter compared to $66 million in the fourth quarter of '11, and $42 million in the first quarter of '11. The derivatives portfolio added $1.13 per Mcfe to QEP Energy's net realized price in the first quarter compared to $0.89 per Mcfe in the fourth quarter of '11 and $0.64 in the first quarter of '11. QEP Energy's combined lease operating transportation and production tax expenses were $114 million in the quarter, down from $122 million in the fourth quarter of '11 and up from $99 million in the first quarter of '11. LOE was down 2%, transportation was down 9%, and production taxes were down 9% in the quarter compared to the fourth quarter of 2011. And finally, QEP Field Services' first quarter 2012 EBITDA was $84 million, which is about $3 million lower than the fourth quarter of 2011 and 37% higher than the first quarter of 2011. Gathering margin was up $2.5 million, or 6%, in the quarter compared to the fourth quarter of '11 due to slightly higher other gathering revenues. Gas gathering volumes were about $1.36 million Mmbtu per day and the average gathering fee was $0.34 per Mcf. Processing margin was down $8.6 million from the record fourth quarter of 2011 dollars on 4% higher NGL sales volumes, but 22% lower NGL prices offset somewhat by shrinkage expense that was sequentially $5 million lower in the quarter. Fee-based processing volumes were up 1% from the fourth quarter of '11, while processing volume fees were flat. While EBITDA was $45 million lower in the first quarter of 2011 compared to the fourth quarter -- sorry, 2012 compared to the fourth quarter of 2011, net income from continuing operations was $155.5 million higher, driven in large part by $128 million gain in the value of the commodity derivatives portfolio. As I mentioned earlier, on January 1 the company discontinued the use of hedge accounting. As a result, the entire change in the value of derivatives portfolio runs through the income statement as opposed to other comprehensive income. The gain is a noncash item and we adjusted for it in our EBITDA calculation. Sequential DD&A expenses were essentially flat at $199 million, while exploration impairment and abandonment expense in aggregate were $9 million in the quarter compared to $205 million in the fourth quarter of 2011, which include a $195 million impairment of producing properties. Our provision for income taxes was $89 million in the quarter compared to a credit of $2 million in the fourth quarter of 2011. And finally, interest expense was up $1.7 million in the quarter compared to fourth quarter of 2011 as a result of new senior notes that we issued on March 1. Turning to capital expenditures. In the first quarter of the year, we reported capital expenditures on an accrual basis of $341 million. Capital expenditures for the E&P activities were $293 million, including $1.4 million on property acquisitions, and capital expenditures in our Midstream business were $47 million in the quarter. We continue to focus on directing as much capital as possible to our higher return 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 $7.5 billion and shareholder equity was $3.4 billion. Total debt at end of the quarter was $1.68 billion, which was a 1.18x multiple of trailing 12-months EBITDA. In March, we issued $500 million of senior notes due 2022, and proceeds of the offering were used to reduce indebtedness under a revolving credit facility. The notes are unsecured, carry a coupon of 5.375%, pay interest semi-annually in April and October, and we were pleased with the execution of the offering, which resulted in the lowest interest rate for a long-term debt issuance by the company in recent history. In addition, last week we entered into a $300 million 5-year term loan agreement with a group of financial institutions, which has substantially the same price unit covenants as our revolving credit agreement. As of today, we have no outstandings under the revolver and have $1.7 billion of borrowing capacity under our combined bank credit facilities. I'll now turn the call over to Chuck.

Thanks, and good morning. Richard's already hit the highlights of our first quarter results. I'll try to add some color. I'll give you an update on our plans for the remainder of 2012 and then move on to Q&A. First, QEP Energy grew production to 74.2 Bcfe in the first quarter of 2012. That was a 13% increase over a year ago. But that's not the big story. As I'm sure you saw on our release, we're making excellent progress on our organically growing QEP Energy crude oil and NGL production. In the first quarter, QEP crude oil and NGL production comprised 20% of total volumes. And at the field level, crude oil and NGL sales represented 50% of QEP Energy production revenues. Crude oil and NGL production at QEP totaled 2.4 million barrels in 2012 compared to 1.1 million barrels in the first quarter of 2011. That was a 113% year-over-year increase. And crude oil as a total -- out of total liquids production comprised a little over 50% of total volumes in the quarter. QEP Energy Southern region production in the first quarter was up 5% from 2011 levels. The Midcontinent production, basically the Anadarko Basin production, driven by increased liquids-rich production in the Cana shale and Wash plays in western Oklahoma and the Texas Panhandle, and increased crude oil production in the Marmaton and Tonkawa plays was up 20% from a year ago. Production from the Haynesville-Cotton Valley area in Northwest Louisiana was essentially flat from a year ago. Southern Region crude oil and NGL production increased 46% in the first quarter of 2012 over the first quarter of 2011 to a total of 737,000 barrels. Crude oil, as a percentage of total liquids production, was 40% in the Southern Region. Northern region production was up 24% in the first quarter of 2012 compared to a year ago, driven by a 37% increase in Pinedale gas and NGL production and a 51% increase in Rockies Legacy Production, which was driven primarily by increased crude oil production in the Williston Basin, Bakken/Three Forks play. This growth was slightly offset by a decline in Uinta Basin volumes. Please note that the Uinta Basin year-over-year comparison was distorted by a positive 1.6 Bcfe prior period adjustment back in the first quarter of last year that resulted from a change in QEP's ownership interest in the federal unit. Without that adjustment, Uinta Basin volumes were down only 4% from last year. Keep in mind that we restarted drilling activity in our new Uinta Mesaverde play late in the fourth quarter of last year, so it's going to take a while for us to arrest decline, the underlying base decline in the properties, and turn up the volume growth. Northern Region crude oil and NGL production totaled 1.7 million barrels in the first quarter of 2012. That's a 164% increase over the first quarter of 2011. That increase was driven by a 149% increase in crude oil production from our Rockies Legacy division, primarily from the Williston Basin, and from NGL production at Pinedale, thanks to the start-up in the middle of last year of our Blacks Fork II cryogenic gas processing plant. Crude oil production comprised 54% of Northern Region's total liquids production in the first quarter of 2012. Turning to our Midstream business. Fuel Services had a good quarter, both financially and operationally. The Blacks Fork II plant continues to operate quite well. And as a result, the Fuel Services' first quarter of 2012 NGL sales totaled 45.2 million gallons or approximately 12,000 barrels a day. And that was a 63% increase over the first quarter of last year. The average realized NGL price for the quarter was $1.07 a gallon. That's essentially flat with a year ago. But importantly, it's down significantly from the $1.38 per gallon average realized price that we had back in the fourth quarter of last year. The biggest driver in the recent decline in overall NGL prices has been the drop in the average price of ethane, which was down 36% from the average price in the fourth quarter. Also note that in the first quarter of 2012, we reported our first clean quarter of operational results from Blacks Fork 2. That is with no noise from line pack inventory in either QEP Energy or QEP Field Services that we experienced and talked to you about in the third and fourth quarters of last year. So for the first time this quarter, the percentage of ethane in our average NGL barrel has increased significantly relative to historic levels. And that should now be pretty stable going forward until we bring on our next cryo plant, Iron Horse II, which should start up in the first quarter of next year. From a macro perspective, we talked about this last quarter, the decline in ethane prices appears to be the result of a near balance in supply and demand in the ethane market, exacerbated by normal plant turnarounds in the ethylene complex, which generally occur during the winter and certainly occurred during the first quarter of 2012. And that's been exacerbated by an excess of propane due to the unusually warm winter of 2011, 2012 that we had. And of course, propane can be cracked and substituted for ethane and the ethylene complex. So that's added to the apparent oversupply. The good news is we have seen some recent strengthening in ethane prices as the ethylene crackers are returning to normal service. It's important to note that the raw NGL product from our plants here in the Rockies all ends up down in Mont Bellevue, Texas, which as you all know is the premium market for NGLs. As a result, even with the pullback in pricing, our processing margins remain well above historic levels. Fuel services gathering volumes were up 4% from a year ago driven primarily by increased volumes on systems connected to the Blacks Fork hub, which, of course, includes the Pinedale Anticline. Blacks Fork's hub volumes totaled $61.2 million Mmbtus during the first quarter of 2012. That's 6% higher from the first quarter of 2011. Cotton Valley-Haynesville volumes also increased about 6% to $20 million Mmbtus. And this increase was partially offset by a 6% decline in Uinta Basin gathering volumes. So looking forward to the remainder of this year, we gave you a lot of details on our current drilling activities and our results of recent wells in our release yesterday, so I'm not going to repeat that information. I'd also draw your attention to the slides that we put out on our website yesterday that accompanied our release. As you know, natural gas prices have continued to drop with the remainder of 2012 NYMEX price hovering around $2.38 in Mmbtu. In response, we've made and will continue to make changes through our capital allocation in QEP Energy. Those changes are summarized graphically on the slide, in the front of the deck Slide 4 that shows our capital allocation to each of our plays. You'll note that the radic [ph] decline in capital and allocated to the dry gas Haynesville play today were down to 1 rig operating in the Haynesville. And we'll drop that rig this summer when it finishes drilling 80 acre development wells in the section it currently occupies. Also note that we were anticipating a significant decrease in outside our operated activity in the Haynesville for the remainder of 2011. We're now allocating 89% of our forecasted capital in QEP Energy to crude oil and liquids-rich natural gas plays. Our focus will be on driving crude oil production in the Northern Region, in the Williston Basin, Three Forks, in the Powder River Basin, Sussex, Shannon, and in the Uinta Basin Green River plays, where you'll note we're picking up a third rig in the Uinta Basin focused solely on drilling Green River oil wells. In the Southern Region, we'll continue to focus on the Marmaton and Tonkawa plays, as well as the shallowest of the Wash plays, the Missouri play in the Texas Panhandle, where we plan to drill some oil wells in the remaining part of the year. We'll also allocate capital to liquids-rich gas plays including our emerging Uinta Basin, Mesaverde play and, of course, to Pinedale in the Northern Region, and to the up dip wet portion of the Cana shale play in the Southern Region. Our release gives you a lot of details on our current thinking on rig count in each of the plays and other details. Jay Neese is here with us today and he'll be happy to give you more color on our thoughts around individual plays and our evolving plans at QEP Energy during Q&A. At Fuel services, our plans call for an investment of roughly $170 million in several major projects and in a number of smaller ones. We recently broke ground on our next cryogenic gas processing plant, the 150 million cubic foot a day Iron Horse II plant, which is located in the Uinta Basin in eastern Utah. About half of the Iron Horse II plant capacity is contracted by a third-party producer under a fee-based processing arrangement, and the other half will be available to process QEP Energy's growing liquids-rich gas volumes from the Uinta Basin, the Red Wash-Mesaverde play. We've also announced sanction, construction of a 10,000 barrel a day NGL fractionator at our Blacks Fork complex in western Wyoming, combined with a 5,000 barrel a day fraction that already exists at Blacks Fork. This facility will be designed to provide additional options for marketing purity propane, normal and isobutane and gasoline range products to premium range, local, regional, national. And sometimes, we even send propane by rail into international markets, such as Mexico. We placed orders for major rotating equipment and vessels, and we'll begin fuel construction on this facility in a few months. We expect that the Blacks Fork fractionator will be in service by the end of the second quarter of 2013. Of course, an additional -- in addition to these major projects, we have a number of ongoing minor projects, including well connections and construction and expansion of our existing gathering systems, as well as we're starting work on preliminary design, engineering and procurement activities on additional gas processing capacity here in the Rockies. So at this macro level, we're finally seeing signs that gas-directed drilling is starting to slow down. And we've seen ourselves and other operators drop a number of rigs in dry gas plays, such as the Haynesville and other plays. Even so, we expect that the supply response will be sticky and will lag the downturn in the rig count, while the inventory of standing wells that have yet to be completed is worked through. It's too early to tell if this supply response in conjunction with increased demand driven primarily by increased gas burn in the electric power sector will allow the industry to avoid forced curtailments toward the end of the injection season in the shoulder season this fall. As a reminder, in response to our concern about this, we've been defensive on natural gas prices. And we now have about 74% of our forecasted gas production for the remainder of 2012 protected by derivative contracts, primarily fixed price swaps. We remain focused on allocating capital to the highest return plays in our portfolio, which means we will continue to drive profitable growth in our oil and liquids-rich gas plays, and in our Midstream business for the remainder of 2012 and beyond. And with that, Regina, let's open the lines for questions.

[Operator Instructions] Your first question will come from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Chuck, could you provide a little more color maybe on 2013 in the context of how the higher liquid spending impacts 2013, if not from an overall growth perspective, but maybe from a mix of liquids versus gas?

Well, Brian, it's pretty early in the year to talk about capital for 2013. And of course, as we've said repeatedly, the capital allocation decisions we're making today certainly by the end of the second quarter have far more impact on production volumes and mix in the next year than they do in the current year. We said that we're focused on growing organically our mix of oil and NGL as a percentage of our total production. And this year, we think we'll be about 20% for the year. You can see we're making good progress there organically. We would expect that looking at our year-over-year trend from 2011 to 2012, we were 14% for last year, 20% this year. Absent a major acquisition that would change that mix, we would expect a similar trajectory with the mix continuing to change maybe 5%, 25% or so, 27% in 2013. That being said, if we decide to radically change our allocation to gas in response to a further decline or a more structural decline in gas long-term, we could see our gas production drop. And that would, obviously, change the relative ratio going forward. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And is your expectation right now for year-end '12 and 2013 to drop the Haynesville rigs? So are you already dialing that in to your, I would say, your broad thoughts on what the mix looks like for 2013?

Yes. When I made that statement, we're assuming that we likely will not recommence drilling activity in the Haynesville until we see an improvement in gas prices to a zip code somewhere between 4 and 450, probably toward the high end of that range before we would commit the resources to restart development activities in the Haynesville. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And in the Pinedale, it looked like the working interest of around 70% was higher than it has been historically. What is sort of the normal working interest run rate for the Pinedale?

So low 60s working interest and we picked up interest from several of our working interest partners in some wells as they've elected to nonconsent because of the relative economics of our investment versus that of our working interest partners who don't benefit from the liquids volumes that we extract at Blacks Fork II. As we said before, it makes a substantial improvement in the relative economics. And of course, our working interest partners' gas is being processed by us, but is being processed on a keep-whole basis and we're enjoying the benefit of the liquids extracted there. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. Just the last question for me. On your commentary on the -- or for macro gas perspective, it taking longer to correct for the supply to correct. From your own portfolio, as you considered taking a rig out, your last rig out of the Haynesville, what is your expectation for your Haynesville volumes maybe over the second half and next year in terms of the decline? Meaning, do you think you guys with the restricted rate programs will be able to hold that relatively flat?

Well, certainly first of all, we're one of several operators that has decided, and we've convinced ourselves from the long-term well performance, that restricted flowback of these wells not only results in higher flowing pressures and higher cumulative production at any given point in the well history. It certainly appears that we're going to get higher recoveries overall from these wells. But it does, as you've observed, create a plateau period that lasts probably nominally 6 months or so from the time you first put a well on. That's observation #1. And sometimes it lasts even longer. We have some. I mean, it's a very subtle decline, but there is a plateau period that lasts close to a year before you really see the well starting to decline. And when the well does enter decline, it enters decline at a shallower rate than wells that have been flowed back hard and have not been -- we believe that have probably damaged the reservoirs. So as a result, we see initial declines, roughly half or in the 50%, 55% range as opposed to the 90 plus percent range for unconstrained wells. So our aggregate production portfolio will decline at a lower rate than most of the other operators in the Haynesville, and certainly a lot of the larger operators in the Haynesville who do not practice this constrained flowback. So we think we'll be roughly flat for the year on Haynesville production, and then we'll enter into decline next year absent additional capital investment. And the production will come off at some rate less than 50% because keep in mind, we've got a bunch of wells now that are 3 or 4 years old that are out of the steeper part of their decline. The industry in aggregate, I think, will still see a much higher decline than the 50% that I referenced. And so, there's a couple of other factors. One, is how many standing wells are left to be completed in aggregate in the Haynesville, the rig counts down to the high 60s this week, I think. So the number of wells that are being drilled encased is declining and the inventory is being worked off as completion activity has continued in the first quarter and into the second quarter of this year, pretty much at the same pace that it has in the past. So the inventory's down. I think Haynesville production has turned over, and I think that the decline will accelerate now that the rig count and the standing well inventory's coming off.

Your next question will come from the line of Brian Corales with Howard Weil.

A question on the Bakken. You're adding a fourth rig. Is there an optimal level you're trying to get to in the Bakken for a more efficient program?

Brian, yes, we're adding a fourth rig. We hope it will -- we're going to sequence it in with the 3 existing rigs there. And of course, as you know we're drilling from pads there and are sort of constrained. And when we add that fourth rig by making sure we put 2 rigs on the pad more or less simultaneously there so they accomplished drilling the wells in parallel so that we don't experience an unnecessary amount of delay in getting those wells online by having a staggered rig activity. The optimum number is probably 5 rigs and we're striving to get there. And we're anticipating adding a fifth rig sometime later this year. Again, we're looking at the sequencing of the rigs on the pads keeping in mind that some pads we can physically only fit 1 rig, some we can fit 2 rigs on. And so 5 rigs feels like sort of the sweet spot.

Okay. And do you have a guess right now if that -- what that would do on the cost side of the equation? Is that going to gain some -- allow costs to decline a little bit?

Well, we certainly hope so, Brian. We haven't seen enough pad drilling activity to really get a good handle on what sort of economies of scale we should see. But our experience at Pinedale and other places where we pad drill would indicate that -- it's some obvious things. It's not personal. You don't have to move the rig. You don't take the rig down and move it and rig back up, which should save a few hundred thousand dollars minimum. And then once we drill, encase a number of wells and we move the rigs out of the way, our ability to work on multiple wells back to back with the frac crews is also a savings. And then obviously, having all the facilities on one pad will reduce individual well connection costs. So in aggregate intuitively, you would think that we should save somewhere around $0.5 million or so a well. Whether we can actually realize that is still -- the jury is still out on that.

Okay. And then one question on the Uinta, you're adding the rig for the Green River. How was that developed? And you said horizontal, was that developed vertically prior? Or is that horizontally as well?

Well, Brian, the answer is both. The historic drilling out there, so if we sort of talk about 2 different areas, in the Red Wash field, which overlies our active Mesaverde gas development program, all of those wells are vertical. And there's a series of stacked sands out there. Geologically, it's quite reminiscent of the geology at Pinedale where you have in the case of the Red Wash field, in some wells, 40 or 50 separate sands that are perforated and have been produced. The average is probably 15 or 20. And so really for the most part, the development in the Red Wash area, lends itself to vertical wells because you really need to contact all of those separate sands. And so the focus there is on increasing the well density because most of the field was developed -- the tightest density was 40 acres. There's a lot of the field that only has 80 acre or 160 acre, and significant part of the field that only has 4 wells or 320 acre -- or, I'm sorry, 80 acre -- I'm sorry, Brian, 160 acre -- I'll get it right in a minute -- 160 acre spacing, 4 wells per section. So the opportunity there is to basically increase the well density and capture a lot of the oil that hasn't been produced from the old vertical wells. We have had in the past, and what we will be doing is continuing to drill a number of horizontal wells in the -- focused in the Green River formation for oil. I think up until maybe a few months ago, when the aggregate industry activity sort of outpaced us, we had the most horizontal wells in -- well, I think, we still have the most horizontal wells in the basin. And we probably had up until a couple of months ago, the more horizontal wells than the rest of the industry combined in the Uinta Basin. Our horizontal development has focused on thin sands and limestones that are a few feet thick, less than 10 feet thick generally. And they were ignored and not perforated in the original development of portions of the field that were developed with vertical wells. So what we find is that we can drill a horizontal well in these thin sands, find virgin reservoir pressure and find a reservoir that has never been produced either in primary mode or has been swept by the poorly designed and executed waterflood in portions of the field. So it's been a really neat sort of redevelopment activity. A lot of the horizontal wells are being drilled, have been drilled by cutting windows in the casing of existing vertical wells and then going horizontally. And we've actually done a number of them with multiple laterals, with one lateral in each compass, in 2 compass directions, so 2 horizontal legs off of the existing vertical well. And those have been quite successful. So we'll be doing a combination of horizontal wells and then drilling some additional vertical wells to get additional vertical well data and production around some of the areas of the Red Wash field, where we don't have high-density drilling.

Your next question will come from the line of William Butler with Stephens.

I had a question on the Bakken. You all had slightly higher well costs and you'd cited inflation there. Can you talk a little bit about the inflationary pressures you're seeing there? Is that something that's transitory? Or is that something you think is still solidly in the basin up there?

Well, it's interesting. Our well costs were below that or some of our offset and still are below that with some of the offset operators in the area that well costs are directly related to the depth, the amount of overpressure. We're in an area which has a significant amount of overpressure, so well -- drilling costs are a little higher and then treating costs are higher because we need more hydraulic horsepower. We've seen our well costs sort of inflate to be closer to that of our neighbors. And part of it's still inefficiency on our part, just in our inability to manage the completion activity to drive down costs and it's economies of scale that I think that we'll start to see when we add a fourth rig. Part of it is also we're giving you sort of a perspective view of what we think well costs will be for the remainder of the year, and we're hearing that some constituents of the completion fluid costs maybe going up in the future. And we're sort of trying to warn you that we anticipate some inflation on the completion fluid side. But obviously, we're focused on doing things -- everything we can to drive down costs. And I think pad drilling will help and then working on multiple wells will help as well. So we're hoping that that's transitory. And we hope that we can turn it the other way.

Okay. And on your well design, have you guys experimented with, given the depths and pressures where you are in some offset operators using ceramics? Is that something you all are contemplating more or less?

We've looked at the relative well performance of wells that have frac-ed and probably with ceramics versus sand. And we've seen -- we've participated in a lot of wells operated by others. And looking at that well performance versus ours, and looking at outside operators' well performance, ceramic profit versus non-ceramic profit, we have yet to be convinced that there's any material change in well performance related to the type of profit that's used. There's certainly a good argument for increased stages, and I think you've seen that as the understanding of the reservoir has improved over time. All the operators have gravitated to increased stage count and closer stage spacing, which is probably more to blame or is the reason why we're seeing better well performance overall out of the wells that are being drilled over the past 18 months versus the early wells that were drilled. And then the third point is long laterals. We're drilling all long laterals. So obviously, a long lateral exposes more of the wellbore to the reservoir and ultimately results in higher EURs per well.

Okay. And I noticed on your maps, you all spotted some more acreage in the Bakken now than you had previously? Is that just -- have you all acquired some smaller acreage blocks in Mackenzie, Williams? Or is that just stuff...

I think it was probably there before maybe we made the map bigger, so you could see it, but the acreage count hasn't really changed materially.

Okay. I appreciate it. And one last question on your Woodford Cana. Your EUR as you tighten in the range there, any comments around that?

Yes, we're -- the reason that we did that is the early -- I think we used to have a range of 4.5 Bs to 12 Bs. And that was our experience over the broader play. And now, we're focused in on drilling development wells in the sweet spot, in the core. And so we're taking into account A, the fact that we're drilling in the Cana where it's 275 to 350 feet thick. And 2, we're drilling on 80 acre density. So we're anticipating some interference between the wells on 80 acre density. But we're in an area now where there's just not as much variability in where we can predict pretty tightly what the results will be.

Okay. And is that an area -- it seemed pretty low down on the list of where you're allocating your capital. Is that an area that if you all had a use for funds that would be on sort of the divestiture block? Or is it an area that we should just continue to think is part of you guys going forward?

We think the core is very economic, especially in the -- as you move in our slide, Slide 8 there, in the light green to the dark green area, it's competitive with all the other liquids-rich shale plays around the country. We like that acreage and we don't have any plans to divest of it today.

Your next question will come from the line of David Tameron with Wells Fargo.

Can you -- Chuck, do you guys have a -- if you think about Blacks Fork and your -- you guys gave us some run rate numbers when you first came out with this and talked about what you expected. Obviously, ethane's moved that number. Can you talk about, one, is there any way to strip out what the actual earnings contribution was from Blacks Fork's on the quarter? And two, what the run rate is going forward? Or how we should think about that?

Well, we don't have -- I don't have the granularity to do it. We'd have to, obviously, Blacks Fork benefits not only fuel services, but also QEP Energy. In my prepared remarks, I did point out that this is the first -- the first quarter of 2012 was the first quarter where we didn't have all the noise going on. For instance, in the fourth quarter, we had 240,000 barrels of NGLs that went into line pack. Or -- and so that those barrels ended up going in being entered around the balance sheet and as basically is the inventory. And so of course, it sort of perturbs the reported production volumes in QEP Energy. And so one of the things that we've heard a lot of questions and a lot of commentary after we issued the release yesterday about the drop in realized NGL prices. And one of the things that I want to make sure everybody understands is that as a result of the first clean quarter of operation, the Blacks Fork in the first quarter, we saw a substantial increase in ethane as a percentage of our total NGL barrel. And so just to remind everybody, Blacks Fork is generating 15,000, 16,000 barrels a day of NGLs, of which 60% roughly, 59.8% to be exact, but 60% roughly is ethane. So that has substantially lightened the barrel and, therefore, driven down the average realized price of that barrel. So we had that going on just at a physical level with the lightening of the barrel. And then two, we saw a dramatic decline from what were just outrageously high ethane prices in the fourth quarter into the first quarter, which had the impact of driving down the realizations on that part of the barrel. So to get at the absolute impact just from Blacks Fork, it's probably somewhere in the $25 million to $30 million range of EBITDA and that would be total, right? That would be for both Fuel Services and for Energy. And obviously, your view of ethane. I mean, we believe that ethane prices -- we can see some strengthening. There was a lot of turnaround-related demand taken out of the market that those crackers are coming back on. It's taken longer than it did last year for the turnarounds, for whatever reason we're not sure. But that we have seen strengthening in the ethane price here in the past month or 2. And we would think that, that would continue.

Okay. No, that color's helpful. So I appreciate that. Let me jump a couple more. Haynesville or just, I guess, maybe gas in general, is there a price -- what price would you shut in gas? I mean you -- subcash costs, or what number are you talking?

So I mean, obviously, if we're not generating positive cash margins, there are other questions that drive that. And part of it’s reservoir related. Some of our highest cash cost gas production is in areas that are very low rate wells that are on plunge or lift. And we tried to shut those in a number of years ago and the results were not pretty. We never got the wells back on their original decline curve. And we're loathe to lose reserves as a result of a temporary shut in. There are some areas that clearly are amenable to shut-ins that we've done in the Pinedale in the past. Although Pinedale, arguably, on an economic basis, is our lowest lifting cost area and the one that would be the least likely to get shut in, just on a pure economic basis. Haynesville wells, they seem to be okay. Although, we only have short duration data on shut-ins of Haynesville wells. And in effect, we are managing production volumes in the Haynesville with our deliberate curtailment through the constraint flowback. We really can't choke the wells back in the Haynesville anymore without them freezing off. They're still flowing at such hard pressures that they tend to freeze off if we try to close the chokes anymore, just because of the significant pressure drop that the well head.

And David, this is a little bit of color, if you look at just the cash component lifting cost, whether it's production taxes, transportation and LOE. I mean, we -- they're -- none of our gassy regions that have cost in excess of $1 in the quarter. So if you just look at making money on a daily flowing Mcf, we can make money all the way down to $1 plus or minus.

Okay. No, that's helpful. A couple more questions. I mean, Chuck, what do you see -- from your experience or your crystal ball, what do you see for gas prices over the next 3 or 4 months given where storage is at? And you guys talked about lock-ins and hedges, I mean, what's your view on it?

Well, I know there's a group of folks that think that we could see forced withdrawals here as we're in a sort of the shoulder between withdrawal and injection to basically bring down inventories and storage -- forced inventory reduction that's driven by tariffs in some storage facilities. We haven't seen that effect yet. And I'm becoming more optimistic we won't see it in the spring. The real questions then become weather, right? How hot is it? How quickly does it get hot? And how fast does the cooling load pop up to help support gas burn in the power sector? Unfortunately, we do have a great pricing advantage over even Powder River basin coal at current gas prices. So I think we'll see continued high utilization of gas in the power sector, but it really becomes a weather issue. Just like gas demand in the winter. It's a weather issue ultimately. I'm more concerned about the end of the injection season and the risk that as a result of a cooler summer and less gas burned in the power sector and stickiness in the supply response that we end up north of 4.1 piece in storage. And I think that's still a risk. Although, the pundits that I read, and I'm as knowledgeable as the collective wisdom of everybody I read, is that we might squeak by. And then there's also this argument about maybe the real capacity is not 4.1 but 4.3. I kind of doubt that, but I do think that there's a chance that we squeak buy in the fall if we continue to see supply response head downward and we don't have a really cold summer.

Okay. No, I appreciate that. Final question for me and since nobody else will ask it, then I'll take the bullet. And you mentioned that during you opening response to Q&A, you said absent an acquisition, portfolio mix is going to be this next year. Can you -- that's obviously out there, a lot of chatter about that. Can you just talk about where you're currently on an acquisition? Are you still looking? I still have a -- I'll just leave it at that and let you answer it.

Well, we have a group who's charged with looking at opportunities to do bolt-ons. And obviously, all things being equal, we'd like to add more oil to the mix. Although, if you look at the prices of oil assets, they've been -- we've not been successful. We've made a number of unsolicited offers and we participated in some auctions, and we've not been the high bidder or the -- or unsolicited offers have not been accepted -- acceptable to sellers or owners of assets. We're continuing to buy leases in some of the oily plays and I think, honestly, from a value creation perspective, that's probably the -- well, certainly the lowest risk and probably the way you ultimately long-term create value is by looking for a new plays and then just bolting on through leasing, and we're still seeing forced pooling opportunities in places like western Oklahoma, where we're picking up incremental interest in wells that we're operating and drilling through farm outs or sales in the forced pooling process. But we continue to look. As Richard mentioned in his remarks, we've got a lot of dry power on our -- with our bank facility and revolving credit facility. And we'd like to be opportunistic. And we're agnostic, by the way. While we talk about oil, we certainly also understand that the best time to buy natural gas assets is probably when they're out of favor. And certainly, there's no one on the call that would argue that they're in favor right now. So we would also look for opportunities to buy at the right price natural gas assets to add to our portfolio.

Your next question will come from the line of Brian Singer with Goldman Sachs.

Chuck, it's been about 5 months or so since your Analyst Meeting where you laid out in great detail the excitement about your liquids plays. Can you assess with perhaps some greater color than in your slides how the wells that you've drilled since then are performing, particularly in the Powder River basin? But maybe you could also speak to the Green River basin, Marmaton and Tonkawa plays also how the percent crude oil in those wells is looking versus your expectations?

Okay. So the Powder River basin's an easy one. We haven't drilled any wells. We have been stymied as most of the industry has -- by our inability to get permits out of the BLM office in Wyoming. As you'll recall, we stated that's a goodly amount. Basically, all of our acreage in the Powder River basin has at least some federal acreage in each section which, with a 640 acre spacing unit, requires us to get a federal APD. We've got a handful of APDs, but we don't have enough APDs to date to support picking up a rig and moving it into the basin to drill wells. The good news is there's enough other operators in the area that are experiencing a similar problem that we may be able to win there out a rig and drill a handful of wells with the premise that we have, and then let the rig go back to the operator who currently has it under contract, and we're in discussions to do just that. But we've been very frustrated with the inability to get APDs out of the BLM office. Moving down to the Mesaverde, we have 2 rigs running in the Mesaverde play. The -- and by the way, before I leave Powder River basin, the wells that have been drilled up there by other operators, we participated in some of them with working interest around the periphery of our acreage have been quite encouraging. And we're seeing well results which would not change our view of the tight curve and potential EURs that we talked to you about. And as you know, the Powder River is a pretty oily basin, so it's Donnelly [ph] oil with some associated gas. And that play really does have an oil-type characteristic to it as opposed to some other liquids-rich gas place. Moving down to the Mesaverde, we have 2 rigs running in the play. And what we've seen there is basically the same results that we described to you from the handful of wells, the 20-plus wells that we drilled in the play earlier. It's a statistical play. There's a range of well results. And our average well, maybe a little higher than what we showed earlier driven by a couple of really strong wells that we've completed late last year, early this year. But it again -- there's no surprises there. In the Marmaton and Tonkawa, we see a range of outcomes as well, both not only from the wells that we're drilling, our QEP-operated wells, but from wells in which we have a working interest that are operated by other. But the well performance there has been within -- in line with our average sort of EURs that we're expecting. Mesaverde, by the way, it's a wet gas play. Although over 50% of the revenues at the well head come from condensate and from NGLs. The Marmaton, Tonkawa plays are really oil plays as well, and it's very similar to the Sussex and Shannon and other plays in the Powder River basin. And then one play that we did not talk about in the discussion at the Analyst Day was the shallowest of the Granite Wash reservoirs, Missourian Hogshooter, whatever name it goes by and whatever pass-through you happen to be in. But we posted in our slide deck some recent well results. We have 3 wells in which we are -- we have a working interest that are operated by others that are in the process of flowing back now. Those are oil wells. I mean, if you look at the ones that we drilled, that we reported last quarter that are also in that slide deck, a couple of very strong high-rate wells that came on at very high oil rates, the one over 5,000 barrels a day, one almost 3,000 barrels a day immediately offsetting our acreage. And we have plans to follow-up on that and drill wells on our operated acreage later this year.

Great, that's very helpful. And then -- and a follow-up to David's question earlier, in some of the areas where you have made bids, so whether they'd be solicited or unsolicited. Have these been in areas that are -- where you're currently producing or you currently have a meaningful position looking to meaningfully expand that position? Or have they been more in newer areas?

Our first priority is to increase ownership in areas that we have an operating presence and we have a local knowledge and arguably, expertise. And so our focus has been on trying to add to acreage positions in areas where we're currently active. We have a new ventures group by the way as well that's charged with coming up with new ideas and new geologic concepts. And those guys aren't -- and ladies are not constrained to just looking in the areas where we're currently active. But the bids have been in areas where -- and offers have been in areas where we're currently active.

Your next question will come from the line of Hsulin Peng with Robert Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: So a quick follow-up question onto the Marmaton and Tonkawa. I was wondering, can you talk about potential for adding -- so right now, you're running one rig there. What's the potential for adding another rig just like you are doing in the Bakken area?

Hsulin, the potential is there. What we need to do first, there's been quite a bit of industry activity in both of those plays, and we are, of course, participating in a number of wells drilled by others in sections where we have a lower working interest. For the most part, these had been sort of first well per section. And the results are variable. It's not a blanket reservoir, neither the Tonkawa nor the Marmaton. So the first thing we need to do is seek control over the area that sort of -- be able to more fully map and understand the potential. And where I think we add additional rigs is once we're confident that our acreage is within the range of economic well results, we'll come back in and infill those sections. And that's where we can add the additional well count or rig count, rather. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Got it. And second quick question is for Richard. Can you comment on the G&A trend for the rest of 2012, given that first quarter was slightly higher? Do you expect that to trend to the more historical norm?

I think, Hsulin, the first quarter we had a couple of unusual things happen. The first being, as you know, we consulted our Oklahoma offices into Tulsa, and we took a $2.7 million charge to the G&A. Then we've got another couple of million dollars that were recognized over the next 2 quarters. And the other piece of that is just sort of the trajectory of employees. And if you look at the first quarter of '11's employee count to the first quarter of '12 and think about, let's just pick a number, 50 open positions, we'll see an increase in G&A on an absolute dollar basis. On a per Mcf basis I think it stays pretty consistent with where it's been in sort of the mid-$0.30 per Mcfe range. So I don't know if that helps or not. But, and then there are other things that come whether that's litigation expense, or that's lumpy and hard to predict. And the other pieces, anything that's sort of share-based is going to move with where the stock price is. And so deferred comp piece moves around as well. So it -- I'll say, I think the trend ought to be consistent with where it has been with those comments in mind.

Your next question will come from the line of Craig Shere with Tuohy Brothers.

I just want to try to clarify, there's been a couple of questions around the comment of “all things being equal” in regards to M&A and the possibility for some altering transactions. Do you see your gas mix only declining through M&A because you're adding liquids through acquisitions? Or would you consider even though you said this might be the time to be a buyer in distressed markets, would you consider divesting some of your existing positions?

Let me try to answer, but I think I followed the question. Look, we don't have any plans to sell any assets and certainly selling gas and assets into the current market is sort of counterintuitive to the buy high or buy low, sell high sort of mantra. The shift in liquids as a percentage of total production that I mentioned, 14% last year, roughly 20% this year and probably about 25% next year, is based on our current run rate and doesn't assume any fundamental change in our property mix as a result of either an acquisition or a divestiture. We don't build into our forecast either when we give guidance or when we think about our plan. We'd like to be opportunistic. And if we see compelling valuations on either side, on either the buy or sell side, of course, we'd consider them. And we have always been pruners of our assets when we view the value of holding them to be less than the value that others are willing to pay for. There's no programmatic or built-in assumptions in our current thinking when we talk about our production mix and future forecast.

Understood. And second question, on Field Services, I noticed I believe a 10% sequential decline and unaffiliated customer gathering volumes. How exposed is Field Services to the ever growing exodus from gas EMP fields. And we're even hearing of people lightening up in attractive places maybe not the core like the Cana, when they've got alternatives, like the Permian. How exposed are you guys from the Midstream standpoint?

Well, Craig, it's Richard. And again, that there's the contract structure for the processing business in the gathering business in the Rockies is a little bit more different from the Midcontinent. And a lot of the contracts are structured as reservation charges versus throughput charges. And so when you look at declining volumes, that may not manifest itself at all in declining revenues or EBITDA just because of the -- it's a demand charge versus well, we'll just charge you for very molecule you put through the system. So I think your comment, on a macro basis, is right. If you look at what some of the operators are doing in the Rockies, they're reducing their gastric activities, which should have potentially an impact on gas flow through the system. It doesn't necessarily translate itself to reduced revenues in the systems.

And how far out are your contracts?

They're either life of lease or 10 years. So we've got a pretty good portfolio in terms of the tenure of that portfolio.

Craig, just to add to one of Richard's thoughts. The other underlying comment is the relative economic viability, if you will, of the producing assets that are connected to our systems. First of all, our gathering systems outside of the Haynesville were all in the Rockies. And a lot of the fields that we gather are low-decline fields, so they're older properties or they're fields like Pinedale, which I would submit to you that Pinedale's economics and given the well cost and low lifting costs, are competitive with any gas field in North America. So if I'm going to gather gas and have a big component of throughput coming from any field in the U.S., I like Pinedale as a field from it to -- from which that gathering volume to evolve.

[Operator Instructions] Your next question will come from the line of Brian Velie with Capital One Southcoast.

I have one quick question on the outside operated activity that you mentioned in the Haynesville. It's declined, as you mentioned. I know from '11 to '12 it dropped from about 29% to 22%. Is there any way you can kind of project what it might look like in '13 if gas prices stay about where they are?

Boy, that requires me to have an even clearer crystal ball to look inside the heads of our partners. I think that if we -- what I can do is just look at the current rig count and look at how people are pulling rigs out of the play and presume that at current gas prices and looking at the forward curve that we shouldn't see a substantial change in activity. And I would argue that we still have a ways to go in laying down rigs as an industry in the Haynesville, and it wouldn't surprise me by the sort of end of the summer to see rig count at half where it is today. I think some people are running rigs because they have a contract that's going to expire in the next few months and think they're going to lay them down. But we've just seen our outside operated activity as far as AFE is coming in, well proposals, it's just dried up. And that is what I would presume would continue to be the case into '13.

Okay. And then as a follow-up to that, with that money that you previously spent in the Haynesville field, if it is freed up or any significant portion of what's currently being spent there is freed up, how would you prioritize your more liquids-rich targets? And you mentioned the Bakken and I've seen some rate of return charts before, but with the way things stand right now, where would you go with that kind of money?

Well, the Bakken still makes sense. Obviously, we'd like to put capital into the Sussex and the other plays in the Powder River basin to the extent that we can gain some traction on permits. We're seeing some structural changes by the way in the processing capability of the BLM, which we hope will help turn that around. We're adding a rig. And so we're adding a rig in the Bakken as we speak. It will be there sometime before the end of next month. We're contemplating adding another rig in the Bakken later on. So that that's in response to that pricing. We hope we can get some permits and increase activity in the Sussex. And I'm kind of going geographically, which also happens to be sort of return as well. And then we're picking up a third rig in the Uinta Basin to develop Green River oil, and we'll keep that rig busy for the remainder of the year. And then we're down into the Midcontinent region. And the first and highest returns in that area would be these very shallow -- shallowest of the Missourian washes over in the Texas Panhandle with these very high rate 2,000, 3,000, 5,000 barrel a day oil wells, which pay out quite quickly. And so you could anticipate we'll put more capital there as we get permits. And as we watch these wells that are coming online that are currently flowing back.

Your final question will come from the line of James Spicer with Wells Fargo. Jim Spicer - Wells Fargo & Company: Just a couple of balance sheet-related questions. What was your revolver balance at the end of the quarter?

At the end of the quarter, it was $101 million. Jim Spicer - Wells Fargo & Company: Okay. And can you just comment a little bit more on that term loan you put in place, what the rationale behind that was? And was there any impact that has on the size of your revolver?

Yes. James, the term loan was our attempt to increase the size of the availability from banks without asking each one of the 19 banks to take a pro rata share increase and an accordion that we can exercise in the revolver. So the revolver's $1.5 billion. We can take it to $2 billion, but we didn't want to put a gun at the banks' heads and say, okay, each of you guys will take a pro rata share of the increase. So we said, we'll do a funded facility that will sit right next to the revolver, look just like the revolver in terms of covenants and pricing and the financial institutions that have an appetite for that kind of asset can play and the ones that don't, don't have to play. And so that was the rationale was trying to offer a piece of paper that gave us more availability through the bank market, but only required the banks that wanted to have a funded asset on their balance sheet to participate. So it was sort of a hybrid in terms of exercising the accordion versus doing another capital markets issue. Jim Spicer - Wells Fargo & Company: Okay. That makes sense. And then the size of your revolver is still $1.5 billion then in terms of...

Correct. And it still has the ability of $2 billion if we want to exercise the accordion down the road.

I will now turn the conference back over to management for any closing remarks.

Thank you, Regina, and thanks, everyone, for dialing in today. Thank you for your interest in QEP. And we look forward to seeing you over the next month or so as we're on the road at a variety of different conferences. So have a good day.

Ladies and gentlemen, this does conclude today's conference. Thank you all for joining and you may now disconnect.