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…

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…

[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…

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.