Diamondback Energy, Inc. (FANG) Q3 2011 Earnings Report, Transcript and Summary

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

Well, thank you, David, and good morning, everyone. This is Richard Doleshek, QEP Resources' Chief Financial Officer. Thank you for joining us for our thirds quarter 2011 results conference call. With me today are the usual suspects: 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. The third quarter marked the beginning of our second year of operations as an independent company since the spun off from Questar Corporation on June 30, 2010. We had a number of important accomplishments in the third quarter, including starting up our Blacks Fork II gas processing facility, producing over 3 quarters of $1 billion cubic feet equivalent per day in our E&P company and putting a new 5-year $1.5 billion revolving credit facility in place. In terms of reporting our third quarter results, we issued a combined operations updated and earnings release yesterday, in which we reported third quarter and 9 months 2011 results, reported third quarter 2011 production of 70.7 Bcfe, 55% of which came from properties in our southern region, and 15% of our equipment production was crude oil and natural gas liquids. We updated operating activities in our core areas. We increased 2011 EBITDA guidance to be in the range of $1.315 billion to $1.35 billion. We increased production guidance to be in the range of 270 Bcfe to 274 Bcfe and modestly increased our capital guidance to about $1.35 billion, still in line with projected EBITDA. As a reminder, in conjunction with our spin off from Questar last year, we distributed Wexpro Company to Questar. Accordingly, we have recast our historical results and treat Wexpro's results as discontinued operations. In addition, we have recast QEP Field Services results, including revenues, volumes to reflect Questar Gas as an unaffiliated company. Therefore, QEP's reported period-to-period results are comparable to each other. We would be happy to provide additional information about this during Q&A. In today's conference call, we'll use non-GAAP measure EBITDA, which is defined as reconciled to net income and earnings release. In addition, we'll be making numerous forward-looking statements. And 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 in our earnings release. Turning to our financial results, in comparing the third quarter of 2011 to the second quarter of the year, we started with stronger performance at QEP Energy, our E&P business, and slightly weaker performance at QEP Field Services, our gathering and processing business. QEP Energy reported sequentially higher natural gas, crude oil and NGL production. We reported net realized equivalent prices that were slightly lower quarter to quarter. Field Services results were marginally lower than the previous quarter due to a variety of factors: Startup, shakedown, NGL line pack, et cetera, related to the operations at the Blacks Fork II plant. Our third quarter EBITDA was $353.7 million, which was $17 million higher than in the second quarter and up 19% from the third quarter 2010. QEP Energy contributed $267 million or 76% of our aggregate third quarter EBITDA, and QEP Field Services contributed $85 million or about 24%. QEP Energy's EBITDA was up $20 million, while Field Services EBITDA was $2 million lower than the respective second quarter levels. For the first 9 months of the year, our EBITDA was just shy of $1 billion, which was $154 million higher than a year ago in spite of net realized gas prices that were 16% lower than 2010. QEP Energy's contribution was $757 million, which was $73 million or roughly 11% higher than the first 9 months of 2010, and QEP Field Services contributed $233 million, which is about $82 million or 54% higher than first 9 months of 2010 and $29 million more advantaged full year EBITDA in 2010. Factors driving our third quarter EBITDA include QEP Energy's production, which was 70.7 Bcfe in the quarter or 9% higher than the 64.7 Bcfe reported in the second quarter of 2011. The quarter's production was 15% higher than the 61.7 Bcfe produced in the third quarter of 2010. Of note, NGL volumes were 894,000 barrels, up 127% in the second quarter of the year, benefiting from the start up of the Blacks Fork II plan. QEP Energy's net realized equivalent price, which includes a settlement of all of our commodity derivatives average $4.94 per Mcfe in the quarter, which was 2% lower than the $5.05 per Mcfe realized in the second quarter of 2011 and 3% lower than the $5.10 per Mcfe realized in the third quarter of '10. QEP Energy's commodity derivatives portfolio contributed $45 million of EBITDA in the quarter compared to $37 million in the second quarter of 2011 and $68 million in the third quarter of 2010. The derivatives portfolio added $0.63 per Mcfe to QEP Energy's net realized price in the third quarter compared to $0.57 per Mcfe in the second quarter 2011 and $1.11 per Mcfe in the third quarter of 2010. QEP Energy's combined lease operating and production tax expenses were $64 million in the quarter, up from $60 million in the second quarter of '11, and up from $52 million in the third quarter of 2010. LOE is up 9% and production taxes were up 4% in the third quarter of 2011 compared to the second quarter. Per unit LOE metrics were flat quarter to quarter at $0.54 per Mcfe, and were flat with the third quarter of 2010 at $0.54 per Mcfe as well. Finally, QEP Field Services third quarter 2011 EBITDA was $85 million, which was 2% lower than the second quarter of 2011 but 74% higher than in the third quarter of 2010. Gathering margin was down $4 million or 8% in the quarter compared to the second quarter of 2011 due to reduced volumes associated with the short-term third-party gathering processing arrangement. Gathering volumes were up about 4% to 1.38 trillion BTUs per day. Processing margin was flat to the second quarter of 2011 on 0.5% higher fee-based processing volumes, 14% higher average processing fees, 7% lower NGL sales volumes and marginally lower NGL sales prices and shrinkage expense that was sequentially $1.1 million higher. Net income from continuing operations for the quarter was $101.5 million at 9% from the second quarter of 2011, influenced primarily by sequential EBITDA growth. Changes in noncash charges were roughly smaller between the 2 quarters. DD&A expenses were up $2 million in the quarter compared to the second quarter of 2011. Exploration, impairment and abandonment expenses in aggregate were flat in the quarter compared to the second quarter of 2011. Our provision for income taxes is $5 million higher in the quarter compared to the second quarter 2011 due to higher pre-tax income, although we continue to expect that we will not be a cash income taxpayer in 2011. For the 9 months of the year, we reported Capital expenditures on accrual basis of just over $1 billion. Capital expenditures for E&P activities were $939 million including $41 million on property acquisitions, and capital expenditures in our Midstream business were $68 million in the first 9 months of the year. We are increasing our capital budgets slightly for 2011 to about $1.35 billion, and Chuck will have more comments about our capital program in his prepared remarks. Our balance sheet has grown about $0.5 billion since year end. We reported total assets of $7.3 billion, net PP&E of $6.3 billion, and common shareholder equity of $3.3 billion and total debt of $1.6 billion. We ended the quarter with $510 million drawn under our $1.5 billion revolving credit facility, which is up $10 million from the amount I've seen at the end of the second quarter. And regarding our new credit facility, in August, we entered into a new 5-year $1.5 billion revolving credit agreement with a group of 19 financial institutions. Conditions of the bank market had improved significantly since December of 2010 when we amended our previous facility. In our new facility, we have fewer restrictions, and we've lowered our borrowing cost by 75 basis points and reduced our commitment fee by 17.5 basis points. The credit agreement contains an accordion feature which will allow us to increase the size of facilities $2 billion and also to continue to provision to extend maturity by 2 one year periods. We appreciate the support of the banks and believe we timed the market pretty well. I'll now turn the call to over Chuck.

Good morning. Richard has already reviewed the key financial results for the quarter, so I'll try to ad some color to the release, give you an update on our plans for the remainder of this year and then briefly touch in our plans for 2012 and move on to Q&A. Let me draw your attention to the slides that we've posted on our website at qepres.com that the company released yesterday. I'll refer to the slides as I walk through the operational details. Since our last call, QEP has completed, in terms of sales, 13 new company-operated Haynesville Shale wells. All are very strong with initial rates in line with our previously announced results. QEP-operated gross completed Haynesville well costs have averaged $9.1 million in 2011, down from an average of $9.3 million last year. Other than one section where we recently acquired operatorship, our lease-saving activity is now complete on QEP-operated land. And we've commenced drilling 80-acre density pilot well programs in several areas on our acreage. We currently have 6 rigs running in the Haynesville play. But now that our leases are saved, you shouldn't be surprised to see us dial back activity going forward. Slides 3 and 4 will give you additional details on our Haynesville acreage and on drill times. At Pinedale, we've completed and turn to sale 89 new wells so far this year, and our completion in drilling team has continued to deliver industry-leading completed well cost. Our average gross completed well cost this year are under $3.8 million. We're on track to deliver a total of 100 to 105 completed wells during 2011 at Pinedale. As we noted in our release, QEP Energy Pinedale production volumes and revenues benefited significantly from the start up of Field Services Blacks Fork II processing plant in the new fee-based process arrangement that was effective on the 1st of August. Results from the first 2 quarters of operations, as Richard mentioned, under this new agreement, will be impacted by partial periods of -- for, obviously, for the 1st of August, as well as allocation of liquids volumes both in Field Services and in Energy for line pack and a period of time where we received Conway pricing for NGLs, we're now receiving our Mt. Belvieu pricing. The -- also note the significant economic impact on recovering liquids from Pinedale gas. In QEP Energy, we've been able to book additional reserves. As we noted in our release, 47.2 million barrels of liquids, minus the 93 Bcf of national gas reserves associated with the shrink that's lost in the processing of the gas. So this had the impact of reducing fuel level DD&A at Pinedale by about $0.21 per Mcfe. We currently have 4 rigs running at Pinedale. You can refer to Slides 5 and 6 for more detail. In the Anadarko Basin, Woodford or Cana Shale Play, we've completed and turned to sale 4 new wells since our last call, all with good results. Cana well costs, as we've described in previous conversation with you, vary widely across the play. Now gross completed well costs in the deepest gas prone portions of the play have ranged from $8.9 million to $9.5 million, while recent wells drilled in the shallower liquids-rich portion of the play have ranged from $7.5 million to $8.5 million. We currently have 2 rigs running in the play, and we're concentrating our activity in the liquids-rich portion. That's the area that's shown in green on the map on Slide 7. We'll soon be turning our attention to an in-infill development drilling program, most likely on an 80-acre density in this core area. Turning to Williston Basin in North Dakota, as you no doubt saw yesterday in our release, we've developed a substantial backlog of standing wells that are waiting on completion. Some of the delay was caused by the drilling of a number of recent wells from 2 and 4 well pads, which meant we couldn't complete any of the wells on an individual patent until we move the drilling rig off. This exacerbated the scheduling problems in our already tight pumping service environment. We are now working through that backlog. We recently completed 3 wells that have just started flowing back, and we have 10 more wells that are either currently being completed or waiting on completion. We should work off this backlog as we move through the fourth quarter. It is important to note, I think, that in spite of these delays, QEP's third quarter Williston Basin production was up 55% versus the second quarter of this year. Last quarter, we've described plans to ramp up our activity in the Williston to 5 rigs late this year or early next year by placing 2 additional drilling rigs on our first 10-well Bakken Three Forks pad. We have decided to delay that ramp up for now. First, pressure pumping service issues that caused a significant completion delays have also driven a continuous upward spiral in completed well costs. Despite significant improvements by our team in driving down drill times, we've seen recent gross completed well costs for QEP-operated long laterals in both the Bakken and Three Forks wells come in at an average gross completed cost of $9.7 million. That's up over $1 million from what it was earlier this year. We don't like this cost trend, frankly, and we especially don't like it in the phase of softer crude oil prices. Second, we need much better visibility on the timing of well completions. There's nothing more frustrating than seeing a growing inventory of drilling case wells that are standing, waiting on completion due to delay of the rescheduled frac dates. We have hoped this problem would be resolved by now, but it isn't. And we're willing to add more rigs until we're certain that it will result in a proportionate increase in completed wells. Finally, we're really encouraged by the strong results from our first 2 Three Forks wells that we've completed on a 90,000-acre leasehold, but we had expected to have a couple more key Three Forks wells completed in producing before we commence drilling from our first 10 well pad, especially wells targeting the Three Forks. We're just now getting those wells completed, and we would really like to see them produce for a while before we commence pad drilling and basically committing ourselves to drilling 5 wells in a row from that first 10 well pad. I'd refer you to Slide 8 for more details on our Bakken Three Forks play. Our Granite Wash Atoka play in the Texas Panhandle, since our last call, we've turn 3 new QEP-operated wells to sales, all with strong results. The first well was Puryear 8-27H was completed in the deeper, dryer Atoka Wash in early August, and it produced at a peak rate after processing of 231 barrels a day of oil and NGL plus 8.7 million cubic feet a day of dry gas. The second well, the Puryear 13-7H also targeted the Atoka. It was completed in mid-September and had produced at a peak rate of 284 barrels of oil and NGLs plus a 9.5 million cubic feet a day of dry gas. The third well, the Huff 7-24H was completed in the shallowest of the Granite Wash zones at Caldwell, and that's the liquid -- one of the most liquid-rich zones, and it came online in early October. It produced at the peak rate of 1,234 barrels a day of oil and NGLs plus 2.9 million cubic feet a day of dry gas. In addition to these results, we currently have 2 QEP-operated horizontal wells, one of each in the liquids-rich Caldwell zone and Cherokee zone that are waiting on completion. Well costs in this play have averaged $6.5 million to $8.5 million depending on the debt and the relative location on our acreage position. Refer to Slide 9 for more details. On exploratory front, we've recently completed our first Marmaton formation exploratory horizontal well in Oklahoma. The initial results from this well looks strong. The well came on at a little over 1,000 barrels a day of oil, and is in the early stages of clean up. From the early results, it appears to be as good as, or better than, the best wells that have been drilled in the play by offset operators. Our second Marmaton well was down and cased and will be completed this week or some time this weekend. We'll have more data on these wells and more color on the play in our analyst day presentations that we'll be making on November 14. In that meeting, we'll also update you on our plans for horizontal oil directed to drilling in the Powder River basin in Wyoming, where you'll recall, we're targeting a number of tight sands, and were planning on drilling our first operated Sussex horizontal well early next year. And, of course, we'll also review with you our early stages development plans for our liquids-rich Mesaverde formation play in the Red Wash in the Uinta Basin and also the associated processing Midstream opportunities around that emerging play. Let me turn to Field Services. QEP Field Services had a great third quarter. The successful start-up commissioning and loading of our Blacks Fork II plant, obviously, had a significant impact on the results of the quarter. It should also continue to do so in the future. The plant’s really performing quite well, better than designed, and we couldn't be happier with the superb execution of both our contractors in our Field Services teams who'd brought this plant online early and got it up and running without any issues. In case you missed it, we issued on September 29 a release in a set of slides that detailed the operating and financial impacts of the new Blacks Fork II plant and the Blacks Fork Complex on both Field Services and QEP Energy. I'd encourage you to take a look at those slides. They provide a lot of detail. You can also find the release and slides on our website, and it should be right there on the Home page. On a macro front, NGL prices remain strong. I think prices, in particular, is surprisingly strong. And as we reported yesterday, we've taken advantage of that strength to hedge an additional portion of our forecasted NGL production stream for the remainder of this year and also for 2012. We continue to monitor that market, and we may take additional risk off the table as we deem appropriate. As Richard noted, with better visibility, we've raised our full year 2011 EBITDA production guidance. We now expect our production to range between 270 and 274 Bcfe, up from our prior guidance of 265 to 269 Bcfe. And with Blacks Fork II coming on and our continued focus on allocation of capital to oil and liquids-rich plays, we believe QEP Energy should exit 2011 with oil and NGL comprising about 20% of net production volumes, up from about 11% for the full year 2010. With the increased production and continued strong performance in Field Services, we now forecast our EBITDA could range from $1.3 billion to $1.35 billion. That's up from our previous guidance of $1.275 billion to 1.325 billion. We gave you the main drivers in the release yesterday on what's driving that, and Rich had already commented on it. As we continue to notch efficiency gains in our core areas except, of course, in the Bakken, we've seen an increase in the number of completed wells. And obviously, the completed well costs are coming down, but then the well count is going up, both in the Haynesville and in the Pinedale play. We're still struggling with well costs in the Bakken, but that's driven a $1.35 billion capital budget, slight increase over our previous budget. Most of that increase is due to the increase in the number of Pinedale wells. As I mentioned, the Haynesville wells are waiting on completion, as well as higher operated well cost in the Haynesville play. We've also accelerated capital deployed in the Williston Basin to build a water gathering system to reduce the operating costs for our wells producing from the Bakken and Three Forks. I know many of you turned in today to get some color on our plans for next year. Unfortunately, as was the case last year, this call precedes our annual fall board meeting where we discuss our plans for 2012. As a result, we didn't give any 2012 capital investment production or EBITDA guidance in our release yesterday. I can't run the board's decision-making process, so I can't give you any details on our plan here today other than to make some general philosophical comments about our planning process, which if you'd listen to us in previous calls, it should sound very familiar to you, as well as to the folks in our organization. Number one, we plan to live in and around our forecasted EBITDAX for next year. We continue to focus on allocating capital to the highest return projects in our portfolio. Giving you some hints about the way we're doing that, we're pushing more of our capital to liquids-rich plays and dialing down capital allocated dry gas plays. We're focused on maintaining operational efficiencies, not only in our drilling and completion operations, but also in our production operations. And as we've described focusing on allocating capital to build out liquids gathering infrastructure, and other infrastructure to continue to drive down, at least, operating expense. We believe we can , through this capital allocation process, continue to deliver profitable production growth. So what does this mean? Our base case plan for the next year fits in with all of these criteria. Even with these prices, we think that we can still perform mid-teens growth in production and EBITDA over our 5-year planning horizon. I can also tell you that from our pre-board planning meeting, when we get the management team of QEP together, both our management team and our team of talented asset managers are excited about the future potential of your company and about our ability to drive profitable growth from our portfolio of high-quality assets. In the current commodity environment, we think there are very few companies in as good a position as QEP to continue to deliver significant growth while living in and around EBITDA. With that, David, let's open the lines for questions.

[Operator Instructions] Your first question comes from line of Brian Corales with Howard Weil.

On the Bakken, you've talked -- you've seen cost increase, I guess, for everybody. Do you have any signs that, that's going to slow down in the coming quarters?

It's Chuck. We have not seen any signs of plateauing or decline in cost so far. Intuitively, you would think that as a service industry response to the rig count that there would be a decline in costs as the infrastructure catches up with growth. The rig count has continued to increase. And frankly, I think that the pumping service sector has lagged the rig count, and that's what's led to we, and a lot of other operators seeing increase in the completion cost. And we're watching and hoping for that, but we haven't seen it yet and, hence, our reaction in not adding a couple of additional rigs to the drilling fleet out there only to build a larger inventory of standing wells. As we see the service companies respond, we can make appropriate adjustments real time. One of the comments that the folks who work for me have said is that they think that there's enough horsepower in the basin, but that is being poorly utilized due to logistical problems of getting profit into the field, crew moves, and then operator inefficiencies and scheduling frac dates. And all of which is contributing to tightness in supply, pumping services and, hence, the spiraling well cost. We can manage our own activity, but we can't manage the activity of the other operators in the basin that are contributing to it, obviously.

All right, okay. And maybe just switching to the Haynesville. I mean, you kind of made some comments. It sounds like activity may decline next year. I mean, you're currently at 6 rigs. I mean, is this a place that you'd stop altogether? Or what is an ideal in a low commodity price environment -- an ideal level of rig count?

We haven't finalized our decision. As I said, I want to front run our discussion with our board. I can tell you that it's highly unlikely we'll run 6 rigs next year. I think it's reasonably likely that we won't go to 0. But I think we can dial down substantially there. There are some things that we really want to answer, and the primary question is, what is the appropriate well density to develop our Haynesville Reservoir? And to do that, we need several sections, multiple sections of pilot wells that we drill and complete and put online so that we can watch the production behavior over an extended period of time. And it's our intention to drill those wells. We're already drilling one pilot section right now. We have several others planned across our acreage. So we think there's enough variability even in the small footprint of QEP-operated acreage that we need to sample a couple of different areas in order to get a good feeling. So with that said, I would expect a substantial pulldown. We'll give you all those details when we do our analyst day after we've had a conversation with our board. But a substantial pulldown in the rig count, one of the things we're unable to forecast, we've had conversations with our partners, but we yet don't have a very clear understanding of what our direct offset partners are going to do with their activity in the play. And that's a wild card in forecasting outside the operated capital. We would likely want to participate in wells drilled in and around the periphery of our acreage because even at current prices, the economics are attractive.

Okay. And then one final question. Just in -- how much acreage do you have kind of in that Western Oklahoma, in the Marmaton and some of the other zones?

Well, it varies by zone. We've got 30,000-plus acres in the Marmaton. We've got other zones that are prospective in which we were still assembling acreage. I'd rather not give a lot of details on it. We'll put some maps up in our analyst day presentation, which should give you a general feel for the inventory at each of the separate plays. As you know, there are multiple liquids-rich gas and oil plays in the play, in the region, that we are pursuing. So, some of them are stacked. Some of them are sort of offset. So by giving you an acreage number, I really need to do it on a play-by-play basis. But I'm just not ready to do that right now.

And your next question comes the line of Brian Singer with Goldman Sachs.

Chuck, as you shift towards liquids, do you expect that you could still generate, I think, as you said, mid-teens production growth? Or is there a sacrifice that of absolute production growth rate in exchange for higher-valued production mix, I guess. Can you have your cake and eat it, too?

Well, as we model it out, obviously, a big component of our production volume is 80% if its dry gas. But the growing liquids volume helps mitigate some of the decline in dry gas production as we shift capital to the liquids-rich plays. If you look over the 5-year planning horizon, and we -- I look at it over a 5-year horizon because quarter-to-quarter, you'll see variability as we have delays in well completions and things like that. We think we can continue to drive mid-teens production and EBITDA growth. Will it be a perfect linear trajectory? No. It will be a bit lumpy. But obviously, the benefit of new processing that's coming on, our focus on liquids-rich gas in the Uinta and in other plays should help drive that growth and allow us to continue to deliver in the teens production and EBITDA growth over the 5-year planning horizon.

And where would that liquids percentage of the total get you 5 years out when you think about that horizon?

It moves into the -- from 20% this year out – next year, it doesn't move dramatically because when you think about it, we'll exit at 20% this year. Next year, we'll average a little over 20%. In 5 years, I don't have the number on the top of my head, but it increases significantly over that time period.

And just another big picture question here. We've seen a number of split ups in Midstream assets from E&P assets, really going back to the QEP spin off. Now that Blacks Fork II is online, can you talk to the strategic importance of the Midstream business and adding liquid exposure and a sustained base EBITDA versus the potential benefits of more independent structures?

Well, it's the same question from last quarter. We were looking at our Midstream business and thinking about, obviously, the valuation of that business inside QEP Resources versus -- and some other structures. We continue to discuss it internally and with our directors. We haven't made any decision on a forward approach. Obviously, the benefit of the ability to control the infrastructure, pre-build infrastructure to connect wells timely, maximize the diameter of gathering pipes to avoid high line pressures on new wells as they come on in places like the Haynesville are attributes that argue for at least maintaining control of the Midstream infrastructure. Now does that mean we have to own it 100%, or is there some other vehicle that we can use? Obviously, those are questions that we're continuing to ponder and discuss with our board. But as I said, we haven't made a definitive decision on what's right at this juncture.

Last little question and potentially, a bit of repeat from the last one, but there is there a gas price threshold below which you would dial down the rig count in the Haynesville, or the other way to say it would be, there's some price read that you'd be comfortable with the rig count that you have now that acreage is held?

At 450, the Haynesville wells that we're drilling generate very good returns. And I think everybody focuses on the prompt gas price. If you look at the forward strip, our wells generate quite good returns. Obviously, we can manage some of that commodity exposure by hedging out on the forward strip to protect the activity. That being said, I mean, we're opportunity-rich and capital constrained. So as stewards of capital, we'll tend to move capital around in the higher return place in our portfolio which are the more liquids-rich plays in the Rockies and in the Mid-Continent. Do I anticipate running 6 rigs at the current price out there? No. If gas prices went up to $5, would I reconsider that? Maybe. But it really depends on the other opportunities and how they stack up on a return basis. I think it is important to realize that the activity level out there has obviously driven our efficiencies significantly. And we're focused on doing everything we can to maintain those efficiencies and maintain the expertise and the skill set, some of which we can move around from one play to another and preserve. But it takes a while to ramp back up from one rig or no rigs to 8 rigs or 10 rigs in a play. So you lose some of the efficiencies that you've embedded in the organization right now on the ground in the drilling completion shop. And it takes a while to get those back. And that's part of what's driving our decision-making forecast on allocation to the Haynesville and all of our other plays.

Your next question comes from the line of Subash Chandra of Jefferies. Subash Chandra - Jefferies & Company, Inc., Research Division: So on Pinedale, Blacks Forks, trying to get an understanding of how much of the growth sequentially was Blacks Forks related? How much of that was so-called organic?

Well, I mean, Blacks Fork II is organic liquids production growth. I mean, it was liquids that we were producing from an asset -- QEP Energy was producing from an asset that we were selling as methane molecules because of our inability to extract the liquids. So, Subash, as far as the way I think about it, we're now capturing value from that gas stream that arguably we should have been capturing several years ago. So that was part of the driver.

And Subash, almost 490,000 barrels of NGLs came out of Pinedale in the quarter that was directly related to Blacks Fork II. Subash Chandra - Jefferies & Company, Inc., Research Division: Got you, so was -- so there shouldn't have been any dry gas benefit, right? You should have been almost a dry gas negative, but the dry gas volume growth was fairly strong. So I'm trying to get an understanding of what that looks like in Q4.

Yes. Actually, Pinedale had about almost 3 -- almost 4 Bcf increase second quarter and the third quarter. So increase in activity. So, yes, there was probably some shrinkage that you didn't see. But again, we report Mcf, not BTU volumes. So there wasn't a lot of that, that you'd see quarter-to-quarter. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. In the Cana, the slide sort of Q3 versus Q2, has the Tier 1 acreage reduced, sort of what was the thought process behind that and what that might mean for drilling activity if anything? And secondly, was the winter sequential decline, was that sort of onetime item, or what was going on there?

So on the Cana, you're correct if you compared the outline of the Tier 1 from the previous IR slides to the one we released yesterday. You'll see this contracted zone. And what we've done is just tighten the area around the thick part of the Cana Shale. It's the area where we've see the most consistent well results and where we're focusing our current drilling activity. The Tier 2 area is still viable, but I will tell you that the results have been less consistent. When you move into the area where the Cana is less than 100 feet thick, you've seen some very good wells completed in terms of sales [ph] and some not-so-good wells completed in terms of sales [ph]. So from predictability standpoint and therefore a risk standpoint, we've tightened our view of that we think is core Tier 1 acreage. And that's what's showing in that revised number. Second... Subash Chandra - Jefferies & Company, Inc., Research Division: Chuck, just to follow-up on the Tier 1 then. So if you are focusing Tier 1, and if it's, I guess, I don't have it right here in front of me I think something like 20,000 -- 30,000, 31,500 acres now. So you see, I think you can sustain. I guess, the math would be to sustain the 2 rig program there for quite some time with 30,000 acres. Is that pretty fair?

Absolutely. And you could arguably sustain even a higher rig count. That area, and in particular, the green area inside the Tier 1, is an area where returns are still quite good even if current gas prices and it stacks up quite well on our portfolio of investment opportunities. We're at the point now where we are ready to start development. Most of the activity to date has been one well per section to save leases and to develop some control across the acreage especially as you move up dip into the oilier portion of the play. There are enough wells drilled, and you can see it from that slide, Slide 7. Across that core area now that I think everyone feels very comfortable with the geology and the reservoir and predictability of well results, so now it's time to set up in individual sections and start developing the reservoir in an orderly fashion. Because just like the Haynesville, we're trying to avoid creating a bunch of pressure things in the reservoir that would cause long-term completion problems where we have wells interfering -- older wells being either damaged or interfering with the efficiency of frac-ing new wells. So we're moving beyond the acreage saving activity in the quarter now into the development mode. Second question on the Uinta's sequential development, we don't have any rigs running in the U.S. basin right now. So what you're seeing, basically, is the organic PDP decline in that asset. And you have been seeing it for the better part of the year. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. And I'll ask, I guess, 2012 question again because as we look sort of at the base here of the growth assets, and Pinedale is going to sustain growth, I would imagine. But then some of the other growing assets, Cana, Haynesville and Bakken, I mean, 2 of the 3, I think, you signaled today wouldn't sort of be in growth mode. So back to the 20 -- the mid-teens growth rate question, it sounded to me like you thought that it's very achievable on a 5-year basis as you sort of kickstart new plays to make up for plays that you're differing from or eliminating. But the lumpiness, you said there was lumpiness. I just wasn't quite sure if that's lumpiness on an annual basis or a quarterly basis?

Well, it will be both. I mean, you'll see lumpiness on a quarterly basis. We still have lumpiness in the Rocky Mountains, in particular, in Pinedale because as you remember from our previous calls, we slowed down -- we stop that completion activity at Pinedale some time about now. In fact, it's snowing in Pinedale as we speak. And as soon as the weather gets too cold to operate efficiently, we shut down frac-ing out there, and we'll do that some time late November and into December just depending on when the cold weather hits. So that will introduce quarter-to-quarter lumpiness, although we hopefully will be able to make up for that through the spring and the rest of the year or next year. I don't want you to misread what I said. In particular, the comment you made about the Bakken and the Cana, we think we can continue to grow production in the Bakken and the Cana and do so quite significantly. The Bakken -- don't focus on rig counts so much as number of wells that we can complete and turn to sales. Our drilling efficiencies and drill times have come down substantially in the Bakken. And so our well delivery system shouldn't be simply focused on rig -- on absolute rig count but on the number of wells that we can drill and complete and turn to sales. The same in the Cana, we're able to get the wells down quicker, and we'll be able to deliver production growth there through efficiency and drill times. In the Uinta Basin, you'd noticed that the sequential decline there and that's because we haven't been allocating capital to that area. But we -- I did mention that we will be talking about an increase in activity in Uinta Basin focused on liquids-rich gas. And I'd also point out that in drilling to that Mesaverde target which is a stack series of liquids-rich gas-bearing sands in the Mesaverde formation, we're also drilling through the old Red Wash oilfield where there's over 600 million barrels of oil in plays, a loosely spaced grid of oil-producing wells and with our in-fill drilling that we're going to do out there, we will see that reservoir over and over again. And it's like many other complex stacks and reservoirs that we think there's opportunity to find additional oil reserves and increase oil production there as well. So there's lots of opportunities and lots of levers to pull. I'm not concerned about growth next year into future years. And I only warn on lumpiness because we don't forecast quarter to quarter. We don't give quarter-to-quarter guidance because we do have seasonally impacted operations, particularly in the Rockies. And when we give production guidance for the year, we've had a pretty good track record of being able to meet that guidance or exceed it. Subash Chandra - Jefferies & Company, Inc., Research Division: And the final follow-up for me, Chuck. You mentioned Bakken, Cana. Would you throw the Haynesville in that category, too, better efficiency, production growth on lower CapEx?

Yes. I mean, it will be somewhat better. A lot of the production response to drilling dollars in the Haynesville is directly related to the working interest we have in this section so -- that we're drilling. And so this year and previous quarters, we've had 6 rigs running in the play. And sometimes, those rigs have been drilling on sections in which we would have a very small working interest. We actually did a deal with one of our partners in which we went out and drilled some wells with remarkably low working interest in order to keep our efficiencies up, because we were able to drill and complete the wells for over $1 million less than their completed well cost. And we still have an interest in it. We thought it was a mutually beneficial thing to do. Whether or not we're able to continue to do that next year is still an open question. I would focus more on total capital. We will reduce our capital in Haynesville, and we won't see the dramatic growth in production that we've seen out of the Haynesville this year in 2012. But again, I'm not concerned about being able to put up significant growth next year.

Your next question comes the line of William Butler, Stevens.

Just not to beat a dead horse here, but just thinking -- talking broadly again on the 5-year sort of growth buoys. That is within -- spending within cash flow right around there, correct?

Yes, within EBITDAX. We think about EBITDAX as sort of our available cash to invest. And over that time period, when we model it out, we see the company continue to delever over time. And that's, I think, a pretty unusual result.

Yes, delever on a debt multiple EBITDAX.

Right. You're absolutely right.

Okay, great. And in the Pinedale, in the amount of completions that you had this quarter, was that sort of held back awaiting the Blacks Forks just for both the capacity and for the ability to get the NGL uplift? Or, I mean, that's pretty onetime step change, correct? And why was that? I guess, one more detail.

Well, no. I don't -- it's sort of a normal pace of completions. Basically, William, we have one frac crude dedicated to us, and it's a conveyor belt from whenever they're able to start up in the spring. And I think, this year, we were able to get with May -- I'm sorry, March.

Early March.

Early March. So from early March onward, we have been utilizing one frac crew. We -- as you'll recall, we're drilling from pads at Pinedale. We work on multiple wells at the same time while we're frac-ing. And so we're able to drive well delivery basically with that frac crew. They run 24 hours a day, 7 days a week. And they just moved from well to well or pad to pad. So there's nothing unusual about the pace of completion. So you shouldn't read anything into it just this quarter.

Okay. But like you've indicated, probably more of a seasonal thing, I mean, it just gets stronger for the summer?

Yes, right. And we've already mentioned that we're planning on picking up some additional rigs at Pinedale later on this year that continue to drive growth in that production volume to load not only the brand-new Blacks Fork II plant, but the Blacks Fork I plant which is part of the processing complex and continue to drive liquids production growth through our Midstream business.

And lastly, going back to the Bakken, with sort of the deferral of adding the rigs, can you give a little more detail on the timing of these other 2 and 4-well pad completions you've got? And I think you've previously said on that 10-well pad, you're anticipating bringing it on mid-next year? And so where does that slide to now?

Well, it depends on when we give some visibility around the availability of pumping services. We have -- I don't get hung up on just a 10-well pad. We have a number of other pads from which we can drill. We likely won't put 2 rigs on that 10-well pad with our existing 3-rig active drilling plan because that basically sticks 2 of the 3 rigs on one pad for 6 months. So we'll leave that pad, the 10-well pad, for 2 additional rigs to occupy. We have a number of other pads that we can drill from that will allow us to continue to drive growth. And obviously, since there are not 10-well pads, we'll get those wells online quicker, assuming some breakthrough in the pressure pumping services sector that allows us to more efficiently complete the wells. So I'm not concerned about delivering growth there. In fact, I would think we might actually be able to do a little better than we would having 2 rigs stranded on a 10-well pad going forward.

Okay. And what do you think it takes to get either time or critical mass to get the efficiencies you're used to in places like the Pinedale and Haynesville to sort of get that level of economy to scale going into Bakken?

Well, I think, first, it takes the service sector, the pumping service sector, in particular, catching up with the rig count. And you've watched the rig count in the Bakken continue to climb over time. And there's just been a dramatic lag in the service -- in the pumping service side catching up with it. Once it does, then it will take some time for the service sector to get more efficient in delivering those services and operators to become more efficient in utilizing the services. And how long does that take? It probably took a year in the Haynesville. Once we sort of saw the rig count peak before we saw the service sector sort of level out and be able to reliably provide services. So it's a hard question to answer not knowing where the rig count is going in the Bakken. Now from our own perspective, we think we can be pretty efficient to the extent that we can get the services on the ground on our locations. We know how to complete these wells, and we can do it efficiently as soon as we have services available to do it with, if that answers your question.

Your next question comes from the line of David Heikkinen of Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just thinking about the Bakken and the Haynesville and your focus on returns. Can you talk about what well cost you'd target before you'd start ramping activities at current oil price? Or in conjunction, is there an oil price at the current $9.7 million Bakken cost that you'd slow activity?

Well, I think, when we saw oil prices in the $85 range, we were becoming concerned about the margins, basically at $9.5 million, $9.7 million and $85 oil. There wasn't a lot of cushion left in our returns. If you look at a typical Bakken well at $9.5 million at $80 oil, it's generating a low 20% IRR. At that doesn't give you a lot of cushion, especially for delays, mechanical offset, things like that. That's assuming you can drill the well, get the rig off of it and timely complete it and turn to sales, and you start trapping capital as we have this past quarter. It really does ding the return. So that's been our concern, is the volatility of NYMEX crude oil prices, concerns about widening basis differential in the Williston and also just our inability to get wells timely completed and turned to sales. At current prices, we're comfortable continuing to invest in the program, assuming we can work off the inventory and keep the inventory of standing wells at a more normal level. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: That's kind of one well in front of each rig, it would be a normal type level?

Probably one or 2. It depends on some pads. On some pads, we will have a couple of rig -- of wells stranded under the rig while we drill and case the last well. But, yes, one or 2 wells is -we're comfortable than where we are today. At one point, we had 13 or 14 in front of 2.5 rigs, basically. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then in the Haynesville, the non-operated Haynesville well costs are considerably more than your operated costs. Can you answer the same question of gas price or well cost, where you'd either non-consent or not participate? Could you just talk about that in the Haynesville?

Well, we have, in the past, nonconsented wells in the Haynesville where we've seen well costs in excess of $11.5 million. And under any reasonable gas price scenario, it just doesn't make sense. There is some strange things in the Haynesville shale play that most people are not aware of. And one of them is in Louisiana. Even if you nonconsent a well, you're still liable to pay the royalties on the gas production stream from that well, which makes us more likely than not to participate in a well even if it's marginally economic because we're still on the hook to pay the royalty even if we're not participating in the well we're working interest. So we have to pay the lease owner our share of the royalty on a unit basis. So that is a vulgarity that I don't think many people are focused on in the Haynesville is, to my knowledge, unique to Louisiana. I don't think there's any other state that has that issue, something that, obviously, we would like to see fixed. But until it's fixed, we're sort of along for the ride in some of these wells. I will say that the majority of the wells, the offset wells are being drilled by other operators or one operator that is pretty efficient and has told us that they're focused on driving down their costs. And we think there's some things they can do to do that should make the economics more palatable to us.

And your next question is from the line of Hsulin Peng of Robert Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Just a quick follow-up on the Bakken. You have mentioned the 4,100 flow rate in the third quarter. I was wondering if you have a -- given backlog of 10 wells, do you have a targeted 2011 exit rate for the Bakken?

Hsulin, I don't have that number at my fingertips. But we've sort of guided to a 20% liquids versus gas production rate. I don't have an exact exit rate for the oil production from the Bakken for the year. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay. And also, the 20% liquids mix for 2012, do you -- is that predicated on not adding additional rigs in the Bakken as well? Can you get there without adding additional rigs in the Bakken?

Yes, we can. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay, sounds good. And then the second question is on the Haynesville. Given that you are restricting your flow rates there to improve the EUR, I was wondering if you can give us an update as to what you're seeing for the EUR trends currently?

Well, Hsulin, we've given you some data in our past IRR materials and in last quarter's operations release slide deck, where we showed you the relative performance both in flowing pressures in and estimated EURs for a family of 4 wells at QEP-operated that we drilled and completed compared to the performance of what I would call more unconstrained wells by 2 other operators. And what we see is -- I'll make some general observations. I think, first of all, we believe that constrained flow backs will ultimately result in higher EURs and better long time well performance, and that data shows it I think in 2 ways. The most dramatic is that it shows in our family of 4 wells that even after they produced 3.5 Bcf of gas, they were flowing at an average rate -- or average pressure rather of about 4,000 pounds compared to the other offset operator's wells that were at half that pressure or less. And flowing pressure is ultimately going to correlate to ultimate recovery because at any given cumulative production rate, to have a well that is flowing at double the pressure of an offset well is telling you that you're still remaining in contact with more of the reservoir and effectively draining more of the reservoir than the wells that were flowed back hard. The biggest thing that will drive ultimate recovery and EUR forecasting in the Haynesville is the assignment of a B factor. And the B factor is the hyperbolic exponent that we assigned to the -- when we forecast the production from these wells. In one of the slides, I have the distinct advantage that listeners don't have of seeing some of the slides that we're putting together for the analyst day. But one of the slides will show in the analyst day is the sensitivity of the hyperbolic -- of ultimate recoverable reserves for a well in the Haynesville to the assignment of hyperbolic exponent in the decline curve. And one of the things you'll see from this slide that I happen to be looking at right now is that there's a broad range of hyperbolic exponents that you can assign to a well with even a couple of years of production history that drives a wide range of EUR results. We're currently using 1.3, right, for hyperbolic exponent. Some other operators have used hyperbolic exponents of closer to 1 at 0.8, 0.9. So if you take our typical 0.3 hyperbolic exponent on a typical well in our core area, that gives us the 6 to 6.1 Bcf EUR. If we take that same data, the same production date and we assume a 0.9 hyperbolic exponent, the EUR of that well or forecasted EUR of that well jumps to over 10 Bcfe, 10.7 Bcfe. Both assumptions or both reserve assignments don't violate any of the existing production data. And it kind of gives you a feel for the range of possible outcomes. And, by the way, they also -- the 10.7 or 10.5 Bcf high in EUR doesn't violate the gas in plays assumptions and recovery factors. You still get reasonable recovery factors of gas in plays in the section with 8 wells drilled in the Haynesville. So there's still a lot we don't know about the Haynesville Reservoir and its long-term performance. The constrained wells are showing us that we're continuing to stay in contact with a lot more reservoir. We've seen wells now that have cumed over 50% of our signed EUR of 6-plus or minus Bcfe which makes us very comfortable that we probably won't be negatively revising the reserves assigned to our PDP. There is upside and we'll show you that graphically in our analyst day presentations.

[Operator Instructions] Your next question is from the line of Drew Venker of Lazard Capital Markets.

What's the potential level of activity in the Marmaton going forward if you continue to have success? Could you run a couple of rigs there next year?

We have a couple of rigs running there right now between the Marmaton and the Takawa. And yes, if we see the results that we've seen from our first well and the second well that shows we're good although shows don't make money. But just looking what offset operators have been putting up for results and knowing our inventory a couple of rigs next year is reasonable.

Okay. When do you plan to start drilling again in Red Wash? Is that next year?

It will be late this year, early next year.

[Operator Instructions] And the next question is from the line of Jay Yannello of Skyden Capital.

There has been some real extreme volatility in your stock price with the help of double leverage, triple leverage DTS and high-frequency in trading and all that stuff. And while I realize you can't front run the board meeting, does those daily moves affect the choice that the board may consider? In other words, I realize that you want to unlock the most value for the long term, but there is also some -- what could argue as pretty amazing short-term opportunities and, basically, are all things on the table for this meeting?

I think we have a pretty open-minded board, and we try to have -- and a great board with a lot of industry experience that haven't added up their cumulative experience. But it's got to be without making them sound old, over several hundred years of experience, it sits around the table. I think our board and certainly, our management team are all about creating value for shareholders, short term and long term. And so with that comment, I guess everything is on the table. We think about things carefully though and don't -- and try not to make instantaneous decisions in reaction to one day vol chart of -- I happen to be -- I've looked at the volatility just in the independent E&P space, and it's amazing to me how volatile everybody's stock is, not just QEP's, but you see why trading ranges through intraday and over one month or one week period, a lot of times, without any rational explanation. I mean, commodity prices haven't moved dramatically. Certainly, during the day or doing a week, we don't see any dramatic changes in our view of the world or our activity or results. Yet, we see wild swings in stock price and in volumes. And it very well -- it could be driven by the high-frequency trading and leverage. But it -- we have to run the company, mindful that we have long-term assets. We have what we think is a great inventory to drive growth in our upstream business, a great Midstream business. And we'll focus on creating value for shareholders and not overreacting to instantaneous changes in stock price.

[Operator Instructions]

Well, David, it sounds like we don't have any more callers waiting in the queue.

Sir, there are no additional questions in queue at this time.

Okay. Well thank you all for calling in today. We look forward to seeing you at our analyst day in New York on November 14. And always, as always, feel free to call Scott Gutberlet if you have follow-up questions. And thank you all for your interest in QEP.

Ladies and gentlemen, this does conclude today's conference. Thank you for your participation. You may now disconnect.