Diamondback Energy, Inc. (FANG) Q4 2010 Earnings Report, Transcript and Summary

Good afternoon. My name is Michelle and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2010 Earning Release and Operations Update for QEP Resources Conference Call. [Operator Instructions] Thank you. Mr. Richard Doleshek, you may begin your conference.

Thank you, Michelle. Good morning, everyone. This is Richard Doleshek, QEP Resources' Chief Financial Officer. I want to thank you for joining us today for QEP Resources' Fourth Quarter and Full Year 2010 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 Operations; and Scott Gutberlet, Director, Investor Relations. As you know, the fourth quarter was our second quarter as a standalone company. Having being spun off from Questar Corporation on June 30, and we feel pretty good about how the company has performed since its debut. In terms of our fourth quarter and full year 2010 results, we provided an operations update on Tuesday, and we issued our earnings release yesterday. In our operations update, we reported fourth quarter 2010 production of 62.1 Bcfe and full year production of 229 Bcfe, a 21% increase over 2009 volumes. We reported year-end proved reserves of just over three Tcf, a 10% increase over 2009 year-end reserves. We updated operating activities in our core areas and we reiterated 2011 production guidance to be in the range of 258 to 265 Bcfe. Yesterday, in our earnings release, we reported fourth quarter and full year 2010 results and affirmed our 2011 financial metrics guidance. Just to remind everybody, in conjunction with our spinoff from Questar, we distributed Wexpro Company to Questar. Accordingly, we have recast our historic results to treat Wexpro's results as discontinued operations. In addition, we have recast QEP Field Services results including revenues and volumes to reflect Questar Gas Company no longer being an affiliate gas company. Therefore, QEP’s reported period-to-period results are comparable to each other. We'll be happy to provide additional information about this during our Q&A session. In today’s conference call, we're using non-GAAP measure, EBITDA, which is defined and reconciled to net income in our 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. Turning to our financial results and comparing the third and fourth quarters of 2010, the story for the fourth quarter was flat production and a slightly higher net realized equivalent price at QEP Energy, our E&P business and better performance at QEP Field Services, our gathering and processing business. Our fourth quarter EBITDA was $298.5 million, which is $1 million higher than the third quarter of 2010 and down 8% in the fourth quarter of 2009. QEP Energy contributed $242 million or 81% of our aggregate fourth quarter EBITDA, and QEP Field Services contributed $52 million or about 18% of our total EBITDA with Field Services EBITDA up about 7% from the third quarter of the year. For the full year, excluding costs associated with the spinoff, which includes separation costs and early debt retirement expenses, our EBITDA was $1,140,500,000 which is down just $25 million from a year ago in spite of net realized natural gas prices that were 26% lower in 2010. QEP Energy's contribution was $926 million, which was $62 million or roughly 6% lower than 2009. However, QEP Field Services contributed $204 million, which was about $41 million or 25% higher than 2009. Factors driving our full year EBITDA included QEP Energy's daily production, which averaged 627 million cubic feet equivalent a day in 2010 and was 21% higher than the 519 million cubic feet equivalent average in 2009. QEP Energy's net realized equivalent price, which includes a settlement of all of our commodity derivatives, averaged $5.26 per Mcfe in 2010, which was 19% lower than the $6.53 per Mcfe realized in 2009. QEP Energy's commodity derivative portfolio contributed $223 million of EBITDA in 2010, compared to $575 million in 2009. The derivatives portfolio added $0.98 per Mcfe to QEP Energy's net realized price in 2010, compared to $3.04 per Mcfe in 2009. QEP Energy's combined operating production tax expenses were $205 million in 2010, compared to $186 million in 2009. LOE was essentially flat for the two years. Production taxes were $19 million higher in 2010, driven by higher production volumes and higher fuel level prices. With the respective lease operating business being flat, the per unit LOE metrics declined to $0.56 per Mcfe in 2010 from $0.67 per Mcfe in 2009. And finally, QEP Field Services EBITDA was 25% higher in 2010 than 2009. Gathering margins were up $28 million or 22% in 2010, driven by gas gathering volumes that averaged about 1.3 Bcf per day, up about 15% from 2009 levels. The increased throughput was driven by an increased production in Northwest Louisiana and Pinedale. Processing margins were up $19 million or 29% in 2010 due to an 8% increase in fee-based processing volumes and a $0.24 per gallon or 34% increase in NGL prices in 2010, offset somewhat by higher operating and shrinkage expenses that were 16% higher year-to-year. Net income from continuing operations for 2010 was $283 million, up 33% from 2009, influenced heavily by non-cash charges. In 2010, DD&A expenses were $84 million higher than in 2009, although sequentially lower on a per unit basis at the E&P company. Exploration, impairment and abandonment expenses in an aggregate were $24 million higher in 2010 and we incurred separation and early debt retirement costs associated with the spinoff of $27 million in the year. Offsetting the higher expenses in 2010 was an increase in gain on asset sales of $11 million. In addition, in 2009, net income was adversely impacted by unrealized losses on our basis-only swaps of $164 million compared to unrealized gains on our basis-only swaps of $122 million in 2010. For 2010, we reported capital expenditures on an accrual basis of $1,486,000,000, which includes $429 million of expenditures in the fourth quarter. Spending for E&P activities was $1,216,000,000 in 2010 including $339 million in the fourth quarter. Spending on leasehold acquisitions was $109 million for the year and spending in our Midstream business was $268 million in 2010, which included major projects in Northwest Louisiana, the completion of our Iron Horse plant in the Uinta Basin and continued spending in our Blacks Forks II plant, which is scheduled to be in service in the fourth quarter of this year. Our budget for 2011 is $1.2 billion, of which $1.05 billion is for the E&P business and $150 million is for the Midstream business, and Chuck will give you more details about our 2011 budget in his remarks. In terms of our balance sheet, we reported total assets of $6.8 billion, common shareholder equity of $3 billion and total debt of $1.5 billion. We ended the year with $400 million drawn under our $1 billion revolving credit facility and we should end this month with about $450 million drawn, which will include the funding of the $58.5 million senior notes that are maturing on March 1. With that quick overview, I'll take a breath and I'll hand it over to Chuck.

Thanks. Good morning, everyone. As Richard noted, on Tuesday and Wednesday we issued separate releases covering our operations and financial results. And I'll try to add some color to those releases, give you an update on our plans for 2011 and then move on to Q&A. First, some highlights from our operations. QEP Energy grew production 21% in 2010 to a record 229 Bcfe, driven by good results in all of our core areas, particularly in our midcontinent operations. Fourth quarter 2010 production was 62.1 Bcfe, a 12% year-over-year increase over the 2009 volumes. As we discussed in our third quarter call, we anticipated significant shut-ins in our Haynesville asset as we and other directly offsetting operators fracture stimulated and brought online new wells near our existing producing wells. The shut-ins had an impact on our Midcontinent and total company production volume growth. Fourth quarter 2010 production was only up 1% sequentially over the third quarter of 2010. Most of that impact happened in the month of October. Our production averaged a record 721 million cubic feet of gas equivalent per day during the month of December. I'd also point out the continued acceleration of our Midcontinent production growth for 2010. QEP grew Midcontinent production 37% from 2009 levels to a record 120.4 Bcfe. Western Midcontinent production driven primarily by the liquids-rich Cana and Granite Wash plays was 35.4 Bcfe for 2010 or up approximately 21% from a year ago. Eastern Midcontinent production dominated by our Haynesville Shale play in Northwest Louisiana totaled 85 Bcfe in 2010 and that's a 45% year-over-year increase. We've been getting a number of inquiries about the impact of the winter weather on our drilling and completion activities and on forecasted 2011 production volumes. Like all companies, we've experienced some delays in rig moves, frac base and other activities due to the freezing temperatures and poor road conditions, particularly in the Midcontinent region, where folks frankly are just ill-equipped to deal with snow and ice, but none of this we think will have any impact on our forecasted results for 2011. Interestingly, the number of well freeze-offs that we've experienced this year has been much less than we've experienced in some previous cold weather and so I think that's a direct tribute to the experience and focus of our production team, who have never missed a beat through the extreme cold weather both in the Midcontinent and in the Rocky Mountain region. We did experience some oil production curtailment up in the Williston Basin in North Dakota due to very poor road conditions that precluded trucks from accessing some of our wells, but again, this shouldn't be material to our 2011 results. That said, and I hate to sound like a broken record on this one, we always experience seasonal declines in our Rockies production volumes, in particular gas production volumes and particularly at Pinedale as a result of our decision not to attempt to complete wells during the coldest months of the winter, which are typically as you know from late November through some time in March. Let me draw your attention to our operations release and to the slides that we posted on our website at qepres.com that accompany that update. I'll refer to the slides as I sort of walk you through the operational details. Since our last call, we've turned 19 new company-operated Haynesville Shale Wells to sales. They're all very strong with initial rates in line with our previously announced results. Just a reminder, we continue to constrain or choke back our Haynesville wells during flow backs so initial production rates from these more recent wells may not be comparable to rates reported by other operators nor to our earlier results. We continue to see very strong evidence that constrained flow back is the right approach to manage the Haynesville reservoir, and we believe that the wells we're drilling, completing today continue to be every bit as good if not better than the wells that we reported last year with 20 million a day or higher initial rates. QEP-operated gross completed Haynesville well costs in 2010 averaged $9.3 million, while the last eight operated wells have averaged about $8.5 million gross completed well cost. Our lease saving activity in Haynesville is starting to wind down. We now have 11 QEP-operated sections left to drill to hold all of our operated leasehold by production. There's an additional 10 undrilled sections in which we have a working interest, representing less than 650 net acres that are operated by others that remain to be drilled. We currently have six QEP-operated rigs in the Haynesville play, or more precisely, as I'd like to say 5 1/2 rigs since one of the rigs isn’t capable of drilling to the full total depth; it’s only capable of drilling to about 12,000 feet, which is the intermediate casing point. Please refer to Slides 3 and 4 in the slide deck that we posted on our website for more detail. At Pinedale, we completed and turned to sales 103 new QEP-operated wells during 2010, including a dozen new wells since our third quarter operations update. 2010 QEP-operated gross completed well costs at Pinedale averaged $3.9 million. As you will remember, we go into winter mode at Pinedale starting in November. We have five rigs continuing to drill in cased wells and we'll get back to completion activities some time in March or early April depending on weather conditions. Please refer to Slides 5 and 6 in the slide deck for more details on our Pinedale play. At our Granite Wash, Atoka Wash play and the Texas Panhandle, since our last call, we've turned three new QEP-operated wells to sales. The Individual well results are described in detail in the operating release that we issued day before yesterday and in the accompanying slides so I'm not going to recite the actual volumes here. I will make a couple of observations. First, we continue to be quite pleased with the liquids content in the deeper Atoka Wash section. Our two most recent Atoka wells that we announced in our update confirmed the presence of significant liquids in the interval over a fairly large area now. Secondly, you may have noticed the somewhat weaker reported rate for the Barrett 10#1H well. That well targeted in the Atoka interval and it tested 5.7 million cubic feet of equivalent of gas a day. While we're still evaluating the results on that well, we think the weaker rate probably indicates that we're near the edge of this particular individual Atoka Wash interval. Keep in mind that there are multiple targets across our acreage. Slide 7 shows the location of the wells and recent results. We continue to have three rigs running in this Granite Wash play. Also note that in the slide deck, we've added a new slide that depicts our broader acreage position in the wash plays both in the Texas Panhandle and in Oklahoma. And as you can see on Slide 8, we have a total of almost 41,000 net acres in the play, including the 13,500 net acres in Oklahoma and yes, some of that Oklahoma acres may be perspective for the Hogshooter, just had to get that in. Turning to the Anadarko Basin, Woodford or Cana Shale play, we've completed and turned to sales two new QEP-operated wells since our last call. The results are in the release. Also noted on Slide 9, we've included some new information to show our acreage compared to the approximate distribution and relative value contribution of liquids to the total production stream across the Cana play. Note that less than 30% of QEP 68,000 net acres is in the dry gas window, and yes, if you're wondering, we have added a couple of thousands net acres to our acreage position here since our last operating release. We've added a rig as well. We now have three rigs operating in the Cana Shale play. Turning to the Williston Basin in North Dakota. Since our last call, we've completed and turned to sales two new QEP-operated middle Bakken wells. We've also doubled the rig count in the play from one rig to two. And if we see the recent improvements in the pace of permit issuance, we plan to add a third rig before mid-year. Slide 10 has additional details on the Bakken play. On the exploratory front our first Niobrara well on our 84,000 net acre leasehold in the Wyoming portion of the DJ Basin has now been tested. The Borie 16-4H horizontal well that was targeting chalk zones in the Niobrara on a very large anticlinal fold on the western edge of the basin was a disappointment. While we did have some drilling problems, in fact, we had to sidetrack the well once, and we didn't get away all of our planed 20 frac stages, in fact, we only got about a dozen, I think we had a dozen frac stages away, we believe that the well and the results from the well were a valid test of the Borie structure, and the well is a legitimate dry hole. Keep in mind, we have two distinct play concepts on our DJ leasehold. The first concept that was tested by the Borie well was a structural play with structurally enhanced natural fractures. The second concept, the more traditional, if there is such a thing as a traditional play in the DJ Niobrara, which is basically chasing the chalky intervals of the Niobrara formation in the oil window, remains untested on our acreage. And as you can see on Slide 11, there's a lot of running room on our acreage in the DJ Basin for the second play concept. Turning to the Powder River portion of the Eastern Rockies, there have been some very positive results in the Powder River Basin of Wyoming that may have important implications for QEP. In the Powder, several operators have recently drilled horizontal wells in the Sussex formation sands with reported initial rates of 700 to 1,000 barrels of oil per day. The Sussex and related sand plays in the Powder may be more predictable in terms of areal distribution and repeatability than the chalk plays in the DJ Basin Niobrara play. QEP has over 55,000 net acres in the Powder River basin, Niobrara, Sussex, Frontier play, including significant acreages directly offsetting some of the recent successful wells. A map of our acreage, the location of the Borie well, location of this recent successful Sussex wells up in the Powder River basin and other key data is included on Slide 11. We plan to drill five to seven Eastern Rockies oil wells in 2011 focused on the Sussex and Niobrara in both the Powder and DJ Basin. Now let me turn briefly to our 2010 estimated year-end reserves. QEP reported proved year-end reserves of 3.03 trillion cubic feet of gas equivalent, which was a 10% increase over our 2009 our estimated quantities. Excluding price-related positive revisions, we replaced 205% of our 2010 production. Our drilling and completion capital for 2010 was reported yesterday in our earnings release. It totaled about $1.1 billion. Note that crude oil and NGLs comprise 14% of our year end 2010 estimate proved reserves, and that's up from 8% of total proved reserves in 2009. The big jump was due to initial booking of a number of proved undeveloped locations in our Williston Basin Bakken asset. Also note that the overall percentage of proved undeveloped reserves declined at year end 2010 to 47%, compared to 51% in 2009, as we drilled up a number of proved undeveloped locations last year. As you can surmise from the increase in proved reserves that we reported, we didn't aggressively add new PUD locations at year end 2010. For example, in the Haynesville Shale, we still have a maximum of two proved locations per 640 acre unit booked as proved even though we've seen some good early results from pilot projects on increased density wells. Turning to our Midstream business, in late December QEP Field Services completed construction of the 150 million cubic feet a day Iron Horse deep-cut cryogenic processing plant that's adjacent to our existing Stagecoach hub in the Uinta Basin, and the plant was up and running in mid-January. The Iron Horse plant is underwritten by fee-based contracts with third-party producers in the Uinta Basin. Construction is now well underway on our Blacks Forks II cryo plant in Southwestern Wyoming. And when completed in the fourth quarter of this year, the Blacks Forks II plant will process gas volumes that are dedicated for the life of field from the Pinedale Anticline, the northern third of the biggest gas field in the Rocky Mountain region. The Blacks Forks II plant as you will recall has a capacity to recover an incremental 15,000 barrels per day of NGL net to QEP resources. When this plant comes on line later this year, QEP will own and operate gas processing facilities in the Rocky Mountain region with aggregate capacity of 1.37 billion cubic feet per day of gas. Field Services was also quite active in Northwest Louisiana in 2010, constructing major gas gathering trunk lines and CO2 treatment facilities for QEP and other operators last year. We completed the installation of our backbone Haynesville gathering system and a 1,000 gallon per minute amine treatment facility adjacent to our existing 300 gallon per minute facility at Hall Summit, Louisiana, bringing our aggregate carbon dioxide removal capacity to 530 million cubic feet per day of inlet gas. Let me briefly touch on our 2011 capital investment plans. Richard already gave you some numbers and we've obviously disclosed it before. Back in November, we released our board approved 2011 capital budget for QEP Resources of $1.2 billion. In our last call, I described our general philosophical approach to capital allocation for 2011 and let me just remind you those key elements: One, a CapEx program that lives in and around our forecasted 2011 EBITDA; two, an allocation of capital to the highest return plays, which are obviously oil and liquids-rich gas plays; three, maintenance of critical mass that we've established in our core dry gas plays in order to preserve our low-cost advantages; four, aggressively completing the Blacks Forks II gas processing plant to capitalize on recovery of additional liquids; and then five, delivering profitable growth. We've allocated to QEP Energy for 2011 $1.05 billion. Following our focus on returns, we pushed as much capital as we can to our high return of oil and liquids-rich gas plays with roughly 25% of the total going to Rockies oil plays, including the Bakken, Three Forks and Niobrara, Sussex plays and a handful of liquid-rich gas delineation wells that we plan to drill elsewhere in the Rockies. The next 25% of the $1,050,000,000 will go to the Midcontinent liquids-rich gas plays, the Cana Shale and Granite Wash, Atoka Wash plays. The remaining allocation is allocated roughly equally between Pinedale and Haynesville to preserve the critical mass and low-cost advantages in those two core gas plays. Note that our E&P business will see a significant increase in capital allocated to oil and liquids-rich plays in 2011 compared to last year, and we've reduced the capital allocated to our lowest return dry gas play, the Haynesville, by about 40%. As a result, we expect our year-end daily crude oil and NGL volumes to more than double in 2011 compared to last year. And because of our efficiencies, we should continue to see profitable growth from our dry gas assets. Field Services received the remaining $150 million of the $1.2 billion total capital budget to fund the completion of the Blacks Forks II plan and for other what I would describe as growth maintenance projects that are basically to connect new wells, add compression, increment our gathering systems in order to respond to growing production in our core areas. With this program, we anticipate that we can drive profitable mid-teens growth year after year and continue to grow our Midstream business all while living in and around EBITDA. In fact, when we look at our five-year planning horizon, we think we can deliver profitable mid-teens compound annual growth from our existing asset base while living within our means. In summary, despite some continued challenges in the natural gas markets, we believe that QEP through continued investment in our low-cost, high-quality E&P assets and our complementary Midstream business is well positioned to drive profitable long-term growth for our shareholders in 2011 and beyond. With that, Michelle, let’s open the lines for questions.

[Operator Instructions] And your first question comes from the line of David Heikkinen [Tudor, Pickering]. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: I just wanted to confirm your costs incurred and do you have a PV10 for your reserves as well that you can disclose?

David, this is Richard. What was your question about costs incurred? David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: 2010 costs incurred and then what your PV10 would be, your standardized measure?

The costs incurred, we'll have the complete breakdown of that in the K that we expect to file tomorrow. But basically, if you're looking for numbers like acquisitions, $109 million of acquisitions on the development side, and again the costs incurred include things like ARO and accrued capital since the costs incurred are going to look on the development side almost $990 million and then exploration is going to be about $146 million. So total, when you look at that supplemental disclosure, it's about $1.24 billion. And then the PV10, on a pretax basis, is about $3.6 billion. On a post-tax basis, the supplemental measure is going to be about $2.7 billion. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then, Chuck, you hit the ability to double oil and liquids by year end. Can you talk about a rough split of just in your guidance what your liquids gas split would be?

Liquids gas split? David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Yes, the 2011 guidance.

Well, last year, we were about 90:10 in the E&P business. It will go down to somewhere between 80% and 85% gas. And David, that doesn't include the incremental recovery that's net to QEP Resources forecasted from the Blacks Forks II plant. That's just the volumes that we would report in our E&P business. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: You have this additional $15,000 of NGLs that you'd recovered on the Blacks Forks as well.

It probably gives you another 5% so that gets you down to the 80:20 mix. That's on a 6:1 basis though obviously. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then in the Granite and Atoka Wash, and then you hit the Hogshooter bit. I'm just trying to get some thoughts around spacing assumptions or number of zones and trying to get an idea of how large your inventory could be as you start testing multiple zones and then multiple wells in the same areas.

Sure, as you know, there's a stack sequence of individual sand bodies. The shallower ones, we call them the Caldwell and Cherokee, which is a local name and those have been the topic of quite a bit of discussion over the past 24 to 48 hours. I think we've said this repeatedly that the shallower horizons tend to be very high quality. They’re borderline not even tight sands; there are some high porosity, high permeability zones present in the upper part of the section and we saw evidence of the high porosity and high permeability and interference from existing vertical wells in the first well we drilled, the Perrier well that we drilled back in -- over a year ago and reported back when we were part of Questar. In fact, we had trouble drilling out frac plugs and ended up getting stuck and left a bunch of junk the hole as a result of partial depletion. As you go deeper into the section, into what I call the alphabet soup of Granite Wash zones, A, B, C, D, E, F, and again those are local nomenclature and may not be transferable across from one company to another. Those zones get tighter and tighter. There's questions about lateral continuity because we just don't have a big enough network of vertical wells in our area to know for sure that they’re continuous over even a section. And then as you go down into the Atoka, the formations get tighter and tighter. The Atoka Washes tend to be the lowest porosity and lowest permeability. So with that backdrop, the shallower stuff, we've never thought about development on any more than a couple of wells a section in the Cherokee and in the Caldwell. Down in the alphabet soup washes of the Granite Wash, we just don't know because we don't have any experience with drilling wells in these things to know how continuous they are and really how variable the porosity and permeability is, although we can tell that they're much tighter than the Caldwell and Cherokee. So it’s maybe three or four wells per individual horizon and there are four or five alphabet soup targets that may be perspective and we've seen well results in other places like the Lower Cotton Valley and Northwest Louisiana and rock similar to that, that yield economic wells. Going down into the Atoka Washes, from the wells we've drilled today in the Atoka Wash, we've drilled quite a few now. These are probably four well per section targets, just based on the well performance and on our calculations of gas in place versus recovery. So that's sort of the rundown. So four or five obvious targets and then a bunch of discontinuous questionable targets that we'll get to. In our sort of summary sheet on plays in our IR slides, we enumerate I think a sort of mid-80 sort of target inventory and that's based on what we know today David, and that's with limited drilling.

And your next question comes from the line of David Tameron [Wells Fargo].

Can you talk about two things, first on the Sussex, can you talk about what your case is in Deep Powder, other well results, anything else around you? Can you just give us a little more color there?

Sure. The Sussex is a sandstone. It's a clastic interval unlike the chalks in the Niobrara or the Haynesville or any of the shale plays. And it's an interval that has been drilled through by numerous vertical wells and has been produced, although the production results from the vertical wells are pretty modest. And like every other sort of redevelopment or horizontal well driven play, the Sussex seems to be amenable to drilling a 4,000 or 5,000 foot lateral on multi-stage fracture stimulating and converting an interval that might have only given up 20 or 30 barrels a day and a vertical well to a well, a horizontal well that will deliver 700 to 1,000 barrels a day. We farmed out one section and we talked about in our last call that the far more drill day, 900-plus barrel a day well in the Sussex immediately adjacent to our block of acreage in the Powder. Since then, there have been three or four additional wells drilled very close to our acreage with similar results, so it's very encouraging from early offset well result perspective. These wells are probably 300,000 to 500,000-barrel wells and they're at reasonable drill depths and very economic. And the Sussex because it has been drilled through in a number of places, is probably a lot -- well, we would anticipate it to be a lot more predictable as far as areal extent, thickness and therefore a lot less risky in our mind at least at this point than the Niobrara chalk play. Are you still there, David?

You mentioned it, I think, but what are your plans again as far as going forward?

Well, we'll have one rig that will jump around and drill some Sussex wells and maybe test additional Niobrara targets in the second, the more traditional play concept down in the DJ Basin. But given the repeatability and the potential that we've seen from recent wells drilled in the Sussex, we may focus our efforts there first. Five to seven wells and we'll see, obviously it will be dependent on results of our drilling and the offset operator results.

And then staying in the Rockies, there has been some chatter that Devon and perhaps yourself are chasing liquids play in and around the Vermillion Baxter Shale type area. Can you comment on is that accurate and/or can you comment on that?

I can comment on it in general, not about Devon because obviously I don't work for them, but the shallow sandstone reservoirs in both the Vermillion Basin and the geological equivalent formations down in the Uinta Basin, they've been targeted for development for years, the Mesaverde equivalent section and it has different names in the Vermillion Basin, Canyon Creek and Trail Sands and other formation names, are well known gas producers, but they're also well known because they have a fairly high Btu content and free liquids production associated with them and our processor company, Questar and Wexpro developed the Canyon Creek and Trail and Hiawatha areas years ago, starting back in the 30s and the production history from those wells would indicate that they do have a substantial liquids component. We have drilled a handful of wells in the Uinta Basin, testing the same concept on our acreage, a large 110,000 to 120,000 acre block in the Unita Basin as a contiguous federal unit called Red Wash and we've seen encouraging results there. One of the things that we're focused on is making sure that we understand long-term well performance before we go forward because obviously when we start drilling a lot of wells, we're also going to have to increment processing capacity and that would be in both the Vermillion Basin and in the Uinta Basin.

Back last summer, you made a comment, I think at Enercom that you could grow 15% plus or minus within cash flow, but you'd wait to see if that's what the market really wanted. Can you just talk about how you think about production growth and CapEx and the slowdown? I’ll just leave it open-ended for you and let you answer that how you want.

I was hoping you'd tell me the answer, what you want and then I'll tell you what we're going to do. But I think the obvious overarching focus of this management team is on investing in profitable growth and so we're looking at deploying capital in plays where we can generate acceptable returns on invested capital to current commodity price and that will drive ultimately – we solve for capital allocation first and then see what the answer is as far as growth and it just happens to be in that sort of mid-teens spot, and we think that these assets that we control and our low-cost structure allow us to remain profitable in a fairly low commodity price environment and generate acceptable returns on invested capital. So our planning process starts with the sort of philosophical edicts that I mentioned to you earlier, living within cash flow and then a focus on returns and then we run it through the model and then that tells us what the production growth is going to be and that's what we tell you. It's not that we sit around trying to figure out what you want and then back-solve for how much money would need to do to get there.

And your next question comes from the line of William Butler [Stephens, Inc.].

Just had a follow-up question on the Midstream side of the business. With the capital that you're investing in the Blacks Forks, what kind of impact do you think that could have to EBITDA and how should we think of sort of -- and I don't know if you can bracket it, think of sort of a 2012 run rate EBITDA and sort of growth on the Midstream business going forward?

We reported $204 million of EBITDA for 2010 in the Midstream business and with Blacks Forks coming on, remember it's probably going to come on in the fourth quarter and so if you kind of annualize what the impact should be and the biggest challenge is trying to say what's your feedstock, your gas costs going to be versus your NGL price going to be. But you kind of use a normalized 10-year kind of average feedstock cost and the NGL price cost. Think of a number in the $50 million to $75 million a year range on an annual basis. And again, it's not going come on until the end of the year. So the most aggressive is going to be a quarter of that.

And the other thing just to remind you, we've had almost a $20 increase in crude oil prices over the past several weeks and as we saw in the past when crude oil moved above $100, the historical percentage relationships between ethane, butane and the NGL components versus NYMEX crude widens, so that the actual realizations don't track oil prices and that's a common misconception, I guess, that some people have that there's a one-for-one increase in NGL revenues for every dollar increase in NYMEX crude oil and that just is not true.

As you heard us say before, the plays are going to be full day one because right now that NGL stream is going down, the sales pipe is, it's gas BTUs versus liquid. So it's not like we've got to go out and hook up new wells, it's going to be full day one.

Sort of a housekeeping question. Looking at your fourth quarter cash flows, it looks like there was maybe some sort of deferred tax, sort of true-up at year end. Could you talk a little bit about that sort of deferred versus current?

The deferred tax calculations. Let's just kind of boil it all down, 2010 we're going show $14 million of cash taxes paid and that’s some timing issues. But really, we're going to have no real federal income tax liability in 2010. As you know, when we do the March market calculations for the derivatives portfolio, the impact of the value change runs through other comprehensive income; however, the tax impact does run through the income statement. So it's kind of a weird mismatch, and most of the things that go on with the deferred taxes versus current taxes, and it looks like credits and things are happening has to do with the geography of where the changes go, one being OCI, the other one being on the income statement. So that's probably what you're seeing. Assuming in 2011 that nothing changes in the federal tax code with the drilling activity we see, we don't really expect a lot of cash taxes in 2011.

And just finally, have you all looked at any of the Smackover potential underlying your Haynesville acreage? Is that something you're evaluating?

Everybody's evaluating it. I haven't seen any results. The Smackover is pretty deep under our acreage. We actually have a well that goes into the Smackover. It doesn't look very impressive to me. Keep in mind as you get deeper, the Haynesville is already in the gas window so anything underneath of it, under our acreage is going to be in the gas window. And the Smackover historically has been in the sour gas realm and the particularly nasty sour gas realm so it's been in actually a formation that we've tried to steer clear of in frac-ing our Haynesville wells and then where we land our laterals to make sure we don't get into that sour gas, which more likely than not to be present under our acreage, but we're not really focused on it.

And your next question comes from the line of Brian Singer [Goldman Sachs].

On the Niobrara and the Powder River Basin, but more on the Niobrabra. Just looking at the map on your Slide 11, does the well that you drilled, condemn that whole acreage block there in the south, I guess, the southwest portion of the play? And how should we think about within the DJ Basin, that's a more central north piece of the acreage? And I know you talked about your company prioritizing more towards the Powder, but I guess just give us here your thoughts, big picture on that acreage block versus the western acreage block.

So the Borie well was drilled on a big structure and we think it adequately tested that structure and condemned the structure, but there is a 10,000 to 12,000 acres downthrown or across the big fault that creates that structure, which would be in what I would consider the "traditional Niobrara play" and therefore untested. All the acreage running off to the northeast -- as far as I'm concerned, the Borie well had absolutely no impact on the prospectivity. The results of that well have absolutely no impact on the prospectivity of the acreage going off to the northeast. And we're just waiting to see other wells drilled out there because we've got quite a bit of term on our acreage and we're not in a big hurry to go out and be the first one to drill a well if we're going to see other operators drill all around us. Up in the Sussex, I've already sort of gone over that. There, there’s a lot more vertical well control. We've got a lot of better feel for the geology and these sands are just so much more predictable and lower risk, and we think we can get after that and get production volumes out of it more confidently than we can going out and drilling wildcat wells on our Niobrara chalk acreage.

Acquisitions, how interested and active are you in pursuing acquisition opportunities, and to what degree do you see attractive value out there?

We've talked about this a lot in meetings with investors. When we look at our inventory and the quality of our assets, when we go out and we look at acquisition targets, we have to run a comparison against the inventory that we've already captured, that already sits inside our company and determine whether or not an acquisition, especially when you layer on the acquisition premia that are being paid for, especially oily or wet gas assets if the returns are competitive with the existing inventory and everything that we've seen to-date, the opportunities have not been competitive. We've got enough captured inventory and enough plays either actively being developed or as we talked about in the case of the wet gas plays in the Rockies and the Vermillion Basin and Uinta in an evaluation phase that we think will result in another very economic play. We just don't see the need to go out and aggressively pursue acquisitions in order to continue to propel growth at least over our five-year time horizon that we model.

And your next question comes from the line of Sulan Ted [ph].

I was wondering if you can give us your current thoughts on taking on potential financial partners, your midstream assets and so maybe potential monetization. And if so, how would you plan to redeploy that capital within your E&P business?

It's Richard. We've talked about our midstream business and I think it's one of the sort of hidden assets in the company. We didn't talk a lot about it when we were at Questar because we couldn't get to it. But our number one priority with the midstream businesses is to control our density and making sure our molecules get from the wellhead to the point-of-sale and so control is the number one issue. You've heard Chuck say it's a competency of ours, not necessarily the core competency, but a necessary competency, but the short answer is we don't have to own it all to control it. And certainly there, we have a very visible inventory of gas-rich projects that we could spend a fair bit of capital on over the next three to five years. And so I think if you think about as a potential monetization, it’s certainly an asset we could sell. We're not sure that the market appreciates the value of it inside QEP. You're never going to see us sell the majority of it and in terms of what we would do with the cash, certainly, in a rising commodity and gas environment, we put it back in the ground, and in an environment what we see today we would take those proceeds and pay down debt. All that being said, we’re not signaling that we're doing anything with the midstream business. It's certainly an idea that we've talked about and continue to talk about.

Other point that I would make, Sulan, is that when you look at the sort of full cycle risk-adjusted returns in the E&P business and you compare them to the returns that we see in our investment in our Midstream business, they're not dissimilar. We like the investment opportunities we see in the business and we see it as a way to profitably grow QEP Resources.

And second question is just a quick follow-up on your drilling plan in Sussex oil play. What kind of CapEx -- what kind of well costs should we think about there and also what is the timing of your plan of to drill the first well there?

Sulan, they’re about $5 million gross completed well costs and I don't know when we have them on the schedule, Jay. When do you think we'll have a rig out there?

Probably mid-year.

Mid-year. We have to get permits and obviously get a rig out there so it will be mid-year.

So we probably won’t’ have anything to talk about it even in August.

So is that going to be an additional rig or is that -- or the rig will be moved from another...

We'll probably move a rig from one of our other plays into that play. Just relocate a rig to test those wells.

[Operator Instructions]

Well, it sounds like we don't have any other questions.

And there are no questions at this time.

Well, thank you. And in conclusion, we believe that QEP is well positioned to drive profitable long-term growth for our shareholders in 2011 and beyond. We'd like to thank you for calling in today. Thank you for your interest in our company. Goodbye.

And this concludes today’s conference call. You may now disconnect.