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QEP Resources (NYSE:QEP)

Q2 2013 Earnings Call

August 01, 2013 9:00 am ET

Executives

Greg Bensen - Director of Investor Relations

Richard J. Doleshek - Chief Financial Officer, Executive Vice President and Treasurer

Charles B. Stanley - Chairman, Chief Executive Officer and President

Analysts

Brian M. Corales - Howard Weil Incorporated, Research Division

Eli J. Kantor - Iberia Capital Partners, Research Division

Brian D. Gamble - Simmons & Company International, Research Division

Dan McSpirit - BMO Capital Markets U.S.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Subash Chandra - Jefferies LLC, Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Operator

Greetings, and welcome, to the QEP Resources second quarter earnings conference call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Greg Bensen, Director of Investor Relations for QEP Resources. Thank you, Mr. Bensen, you may begin.

Greg Bensen

Thank you, Brenda, and good morning, everyone. Thank you for joining us for the QEP Resources second quarter 2013 results conference call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer; Richard Doleshek, Executive Vice President and Chief Financial Officer; Jay Neese, Executive Vice President and Head of our E&P business; Perry Richards, Senior Vice President and Head of our Midstream business. If you have not done so already, please go to our website, www.qepres.com, to obtain copies of our earnings release, which contains tables with our estimated financial results and the slide presentation with maps and other supporting materials.

In today's conference call, we will use a non-GAAP measure of EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings, and is reconciled to net income in the earnings release and the SEC filings. In addition, we'll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control, and we refer everyone to our more robust forward-looking statements disclaimer and discussion of the risks facing our business in our earnings release and SEC filings.

With that, I'd like to turn the call over to Richard Doleshek.

Richard J. Doleshek

Thank you, Greg, and good morning, everyone. In terms of reporting our results, yesterday we issued a financial and operating results news release, in which we reported second quarter 2013 operating and financial results, we updated operating activities in our core areas and we updated our guidance for 2013. Chuck will provide more color on our operating activities and our updated guidance for 2013 in his prepared remarks.

Turning now to our financial results. We picked up a little momentum in the second quarter. While we continued to be challenged by weather, mainly rain and wet surface conditions in the Williston, and we continued to sell lower volumes of NGLs as a result of weak ethane prices, we generated $389.5 million of EBITDA in the second quarter, which was within spitting distance of our record EBITDA level.

In comparing the second quarter of 2013 to the first quarter of the year, our results were driven by strong financial performance at QEP Energy, our E&P business, and improvements at QEP Field Services, our gathering and processing business. QEP Energy reported equivalent production of 77.9 Bcfe, essentially flat from the first quarter, but higher net price realizations, about 2.5% higher than the first quarter. Field services second quarter results were higher than in previous quarters due to higher gathering and higher processing margins.

From an EBITDA standpoint, the $389.5 million generated in the second quarter was $14.5 million or 4% higher than the first quarter and $53 million or 16% higher than the second quarter of 2012. QEP Energy contributed $332 million or 85% of our aggregate second quarter EBITDA, and QEP Field Services contributed $58 million or about 15%.

QEP Energy's EBITDA was up $8.4 million or 3%, while Field Services' EBITDA was up $5 million or almost 10% in respective first quarter levels. There is a little bit of noise in the Field Services EBITDA but still an improvement from the first quarter. Of note, if you remove the impact of our derivative settlements from their respective quarters, we generated $35 million more in EBITDA in the second quarter than in the first quarter of this year.

Factors driving our second quarter EBITDA include QEP Energy's production, which was 77.9 Bcfe, 0.1 Bcfe lower than the 78 Bcfe recorded in the first quarter, and the quarter's production was 2% lower than the 79.6 Bcfe produced in the second quarter of 2012.

A year ago, natural gas comprised 80% of our net production compared to 73% in the current quarter. Oil volumes were 2.39 million barrels, up 11.5% in the first quarter of the year, and NGL volumes were 1.12 million barrels, up 1%. Natural gas volumes were down 3% from the first quarter of the year and down 11% from the second quarter of 2012, driven by declining production in our Southern Region. Oil volumes were up 82% or 1.08 million barrels from the second quarter of 2012, and NGL volumes were down 14% or 183,000 barrels from the second quarter.

QEP Energy's net realized equivalent price, which includes the settlement of our commodity derivatives, averaged $6.47 per Mcfe in the quarter, which was $0.16 higher than we realized in the first quarter and $1.34 higher than we realized in the second quarter of 2012. The higher equivalent price reflects field-level gas prices that were $3.83 per Mcfe or $0.45 higher, field-level NGL prices that were $41.36 a barrel or $4.32 a barrel lower, and field-level accrual prices that were $87.31 a barrel or $3.50 a barrel lower than the respective levels in the first quarter of the year. Field-level accrued oil revenues account for 44% of total field-level revenues, which was about the same as in the first quarter of the year, but up 37% from the second quarter of 2012.

QEP Energy's commodity derivatives portfolio contributed $31 million of EBITDA in the quarter compared to $50 million in the first quarter of the year, and $117 million in the second quarter of 2012. The derivatives portfolio added $0.40 per Mcfe to QEP Energy's net realized price in the quarter compared to $0.64 per Mcfe in the first quarter of the year and $1.47 per Mcfe in the second quarter of 2012.

QEP Energy's combined lease operating and transportation expenses were $105 million in the quarter, up from $97 million in the first quarter of the year, and up from $99 million in the second quarter of 2012. On a per unit basis, LOE was $0.59 per Mcfe, up $0.06 from the first quarter, transportation expense was $0.76 per Mcfe, which is up $0.04 from the first quarter. And just as a reminder, our LOE is typically lower the first quarter of the year as a result of how we manage our field activities in the winter in the Northern region.

Finally, QEP Field Services second quarter EBITDA was $58.3 million, which is about $5 million higher than the first quarter of the year. Processing margin is up $3.5 million or 13% from the first quarter of the year as a result of 108% higher NGL sales volume, which include additional volumes from the new Iron Horse II plant, but 21% lower realized NGL prices because we did recover some ethane in the quarter. The average margin was up $3.8 million or 10% in the quarter compared to the first quarter of the year, on marginally lower gas gathering volumes. But the increase in gathering margin is associated with other gathering revenues, which include water handling and condensate sales.

We reported net income attributable to QEP of $178 million in the quarter, driven by a net $100 million gain on asset sales and a $84 million gain in mark-to-market value of our derivatives portfolio. Sequential G&A expenses were down $5 million primarily as a result of reversing some bad debt expense we took in the first quarter, lower restructuring cost and negative swing in the mark-to-market value of stock-based compensation. We expect that G&A will tick back up somewhat in the third quarter. Sequentially, DDA expenses were down $4 million to $250 million.

For the first half of the year, we reported capital expenditures, including acquisitions on an accrual basis, of $740 million. Capital expenditures for E&P drilling and completion activities were $697 million, and capital expenditures in our Midstream business for the first 6 months were $30 million. In addition, we also reported $20 million of acquisitions. If you exclude the acquisitions, in total, we spent about $718 million in the first half of the year, which is about $47 million less than our 6 months' EBITDA.

With regard to our balance sheet, at the end of the quarter, total assets were $9.4 billion, shareholder equity was $3.4 billion and total debt was $3.4 billion, which was about a 1.2x multiple of midpoint of our 2013 EBITDA guidance.

Our debt at the end of the quarter consisted of $2.2 billion of senior notes, $300 million under our term loan due in 2017, and $888.5 million drawn under our $1.5 billion revolving credit facility.

In June, we closed the 2 asset sales that we mentioned in subsequent events in our first quarter 10-Q. We recorded a gain on sale of about $103 million and have about $140 million of cash proceeds from those transactions on the balance sheet at quarter end. If you assume we acquired all that cash to pay down debt, our net debt multiple of midpoint EBITDA guidance, would be just under 2x. In addition, yesterday, we reported that we entered into an agreement to sell several non-core properties in our Southern region for approximately $66 million and we expect to close that transaction before the end of third quarter.

Finally, in May, we filed a registration statement with the SEC for the initial public offering of LP units of our midstream MLP. We filed 3 amendments to that registration statement in July and we continue to push that project along.

With that, I'll now turn the call over to Chuck.

Charles B. Stanley

Good morning. Richard has already hit the financial highlights, so I will briefly touch on some operational results for the second quarter, and our plans for the remainder of 2013, before we move on to Q&A.

As Richard noted, we're making great progress driving the share of liquids as a percent of our total production volumes. Crude oil was up 12% from last quarter and 82% from the second quarter of 2012. Crude oil represented 18% of total QEP production in the second quarter, up from less than 10% a year ago, and combined crude oil and NGL volumes represented 27% of QEP Energy production in the second quarter, up from 25% in the first quarter and 20% of total production in the second quarter of 2012. We're now well underway with pad-base development on our Williston Basin oil assets, and we remain on track to achieve at least 70% year-over-year increase in crude oil production volumes in 2013.

I'd note that a lot of the growth in crude oil volumes is coming in the back half of the year, and in particular, in the fourth quarter, as the pace of well completions catches up with the number of rigs that we've added in the Williston Basin during the first half of the year. We can get into more detail on that in Q&A.

Clearly, our growing oil production is having a significant positive impact on our financial results. QEP Energy delivered adjusted EBITDA of $332.1 million in the second quarter. That was up 3% from the first quarter and 25% from a year ago. If we strip out the proceeds from the settlement of derivative contracts during the period, the higher margin crude oil production growth is even more obvious. QEP Energy EBITDA was up 10% for the first quarter of this year and 101% from the second quarter of 2012. We are clearly focused on profitable production growth.

Now let me give you a little more color on our operational results from the second quarter and our plans for the remainder of 2013. And as I do so, would you please refer to the slide presentation that the company released yesterday afternoon.

In North Dakota, we're making steady progress on development of our Bakken and Three Forks oil properties. Recall that last year we closed the acquisition of South Antelope property in late September. And toward the end of the year, we shifted away from single-well development to pad development on the property. We swapped out the 2 rigs that the previous owners were using for skid-capable rigs, and as each new rig arrived, it moved on to and started drilling on a multi-well pad. As a reminder, our development plans at South Antelope, the newly acquired property, called for an average of 8 long lateral wells per 1,280-acre spacing unit, with an average of 4 wells drilled in each of the 2 reservoirs, the Three Forks and the Middle Bakken reservoirs. We will develop most of the units with 4 well -- with 2 4-well pads. Pad drilling is helping us drive down well cost by reducing the time and associated cost of rig moves and mobilization and demobilization costs associated with completion crews and equipment. The pad development will also enable us to share some production facilities and gathering lines on the properties.

It's important to note that we're not able to complete any of the wells on a pad until all the wells -- all 4 wells have been drilled and cased by the drilling rig and then the drilling rig is moved out of the way. And that can take 4 to 5 months depending on the cycle time before you get first production from the spud of the first well. So pad development, obviously, will introduce some volatility in our production growth profile. We've tried to manage the arrival of each new rig to stagger the delivery of each new multi-well pad. So while there will be some volatility in the production growth going forward, we remain on track to grow crude oil at least 70% in 2013.

We're making good progress on drilling and completion efficiencies and are continuing to drive toward a targeted year end gross, all in. That includes pad construction all of the facilities, drilled, complete, equipped and turned to sales, all in well cost of $10 million or under.

We've been quite pleased with the well results of South Antelope back in early June. We released some results from a number of recent well completions, including the first 2 QEP-operated Middle Bakken wells that were drilled by us on our South Antelope property. These wells were important in that the previous owner had concentrated their development activity drilling one Three Forks well per spacing unit in order to save all the leases on the property. We knew the Bakken was present, we'd seen it on logs, we had core through it. But we didn't have a modern, state-of-the-art long lateral Bakken completion on our acreage. Our first 2 QEP-operated Bakken completions, with post-processing 24-hour IPs of over 4,500 Boe per day, confirm the Middle Bakken is every bit as good, and perhaps even better, than we had modeled in our acquisition evaluation. In total, we completed, and turned to sales, 6 new wells during the second quarter on South Antelope. There was 4 Bakken and 2 Three Forks wells. And if production performance of all of these wells, that we completed during the quarter and in prior quarters since assuming operations, continue to meet or exceed our forecast with an average first 30-day production rate of about 1,300 barrels of oil equivalent per day. We currently have 6 rigs working on South Antelope. You'll recall that we guided for 5 rigs. That's one more than last quarter. In response to some challenging pad construction conditions over to the east, on the Fort Berthold Reservation, caused by a very wet spring, we decided to temporarily move 1 of the 3 rigs that was working on the reservation over to South Antelope to give the ground some time to dry out. So as a result, we have 6 rigs running today at South Antelope. See Slide 6 for a reminder of the location of South Antelope in the Fort Berthold acreage, and Slide 7 for the location of the 6 wells that we completed and turned to sales during the quarter.

Turning to the Fort Berthold acreage, we completed and turned to sales 9 new wells during the quarter, 5 Middle Bakken and 4 Three Forks wells. Four of the new wells were on a pad that's located in the northwest corner of our Fort Berthold acreage block, and all 4 then came on with excellent rates with an average 24-hour IP of over 3,000 barrels of oil equivalent per day post processing. An additional 5 wells were completed on the second pod of the 10-well Independence pad, which is located about 4 miles to the east, and the average per-well initial 24-hour rate for this group of wells was a little over 2,100 barrels of oil equivalent per day post processing. You can see Slide 8 for the locations of these wells and for additional information on our Fort Berthold acreage.

On the infrastructure side, the third-party gathering system operator on the Fort Berthold Reservation continues to make progress, and their water gathering system is moving about 75% of our produced water. So we're significantly reducing LOE as a result. As a result, we're now saving about $5 a barrel moving that portion of the produced water by pipe versus trucking it. Additional gathering system upgrades are in progress and that should allow us to move the remainder of our produced water, the flowback volumes, by pipe, by the end of the summer or early fall.

We continue to make good progress on well cost on the reservation, as well. We're targeting a $10 million or lower gross completed well cost by year end. But I would remind you that, on the Fort Berthold Reservation, because of our acreage configuration under Lake Sakakawea, on average we're drilling a longer lateral than we do over on South Antelope. So we would expect that the completed well cost would remain slightly higher than that of South Antelope. As I stated earlier, we have 2 rigs running on the Fort Berthold Reservation.

Field-level crude oil prices for all of QEP Energy, dominated by our oil volumes in the Williston Basin, declined a bit from the first quarter, due in part to the narrowing BRENT, WTI and WTI LLS basis. Our company-wide average field-level crude oil prices during second quarter 2013 was $87.31 per barrel versus an average NYMEX price of $94.05 per barrel or about a 7% discount to WTI. For comparison, first quarter 2013 fuel level prices for crude oil were $90.81 a barrel, falling to 4% discount to WTI. And, of course, field-level prices are stronger than they were a year ago, in both absolute terms and as a percentage of WTI. For reference, in the second quarter of 2012, our average field-level price was $81.90 a barrel versus an average NYMEX price of $93.29 a barrel or about a 12% discount to WTI.

Turning to Pinedale. Due to favorable weather conditions, we got off to an early start completing wells at Pinedale. And at the end of the second quarter, we had a total of 57 new producing wells completed and turned to sales for the year, including 35 wells that were completed in the second quarter. QEP has an average 74% working interest in the new wells that have been completed to date. We're on track, today, to complete about 110 wells at Pinedale for the year, and that includes 29 wells that we operate for another operator that used to be affiliated with QEP, in which we only have an override. So there will be 29 wells that have a minimum volume impact on our production volumes in the second half. Note that due to continued low ethane prices and high natural gas prices, net to the well frac spreads for ethane remain negative and we continue to run all of our gas processing plants in the Rockies, with the exception of an intermittent operation of ethane recovery down in the Uinta Basin in ethane rejection mode. And we can get into more detail in the Q&A on that.

As we have told you previously, the ethane rejection results in a 7% to 8% reduction in the Mcfe or Bcfe production volumes at Pinedale. But because of lower ethane prices, the rejection has very little impact on our financial results.

We currently have 3 rigs running for QEP and another QEP-operated rig that's currently drilling wells for that other operator, in which we have only a small overriding royalty interest, i.e. no working interest in those wells. The fourth rig will begin drilling on QEP working interest locations toward the end of this month, and we plan to continue to run all 4 rigs at Pinedale through year end.

Slides 9 and 10 show details for Pinedale. In the Appendix of our current IR slide deck has a great slide that shows the details of the production volume impact of ethane rejection and recovery.

In the Uinta Basin, we continue to make good progress on the Red Wash Lower Mesaverde liquids-rich play -- liquids-rich gas play. At the end of the second quarter, we had one rig active in the Mesaverde drilling on a Pinedale-style multi-well pad. As is the case with all of our pad drilling operations, we have a number of wells that are drilled and cased and that we cannot access until the drilling rig is moved out of the way. We've completed and turned to sales 8 wells, 8 new wells in the first pod of wells on that pad, and we're continuing to evaluate the early production performance to help us determine the ultimate well density and drainage pattern in this Lower Mesaverde play.

As a reminder, we're rejecting ethane in the Uinta Basin, too, and it has a negative impact on reported gas equivalent volumes from the Mesaverde play of 7% to 8%. At the end of the quarter, we also had one rig running in the Uinta Basin actively drilling horizontal and vertical oil wells in the Green River formation. Slides 11 and 12 show more details on our Uinta Basin activities.

Turning to the Mid-continent. During the second quarter, we completed and turned to sales 8 new QEP-operated wells in the core of the liquids-rich portion of the Cana shale play. In addition to operated activity we also participated in a number of outside-operated wells that were in progress, drilling or waiting on completion during the quarter. We dropped our last QEP-operated rig in the Cana play for the time being as we continue to focus on allocating capital to higher return crude oil projects. See Slide 13 for the location of recently completed Cana wells and for other details on the play.

In the Granite Wash, we completed 2 new QEP-operated horizontal wells and we participated in 4 additional outside-operated horizontal wells that were completed during the second quarter, and all had solid results. These wells all targeted crude oil and liquids-rich gas horizons in the various washes in the Granite Wash section. Slide 14 gives additional details.

And then, finally, there were no new completions in the Haynesville, down in Northwest Louisiana, in the second quarter. But we are participating with a small working interest in 7 wells that are being drilled by other operators in the Haynesville play. Slide 15 gives the details.

At Field Services, we started up our new 150 million cubic foot a day Iron Horse II cryo plant in the Uinta Basin early in the first quarter of this year, and the play continued to run smoothly in the second quarter. We did, however, recover some ethane in the second quarter, and we can get into details on that because I want you to understand the impact of some performance testing that we did that distorts our second quarter numbers. So Richard can give you the details on that.

About half the capacity of this new Iron Horse plant is contracted to a third-party producer, under a fee-based processing arrangement, while the other half is available to process QEP Energy's gas volumes in the Red Wash Lower Mesaverde play. And that arrangement between QEP Field Services and QEP Energy is also fee-based.

Most of the gas volume currently going through the Iron Horse II plant was previously being processed in our refrigeration plant that we call Stagecoach. So while the net change in fee-based processing volumes was small, we did experience a 10% increase in average fee-based revenue in the second quarter compared to the prior year period.

Field Services also completed construction and started up its new 10,000-barrel a day NGL fractionation facility at the Blacks Fork complex in Western Wyoming. This facility will provide additional options for marketing purity propane, ISO and normal butane, and gasoline-range products to what are, oftentimes, premium value markets, both locally and regionally, via truck and then, of course, across the U.S. by our expanded rail loading facilities at the plant. The rail loading facilities are still under construction, should be finished up some time in the -- late in the third quarter or early fourth quarter of this year.

So now as we look forward, we view 2013 as a pivotal year for QEP, as we continue to dramatically shift the production mix of QEP Energy from one dominated by natural gas to one that's more balanced. We remain on track to increase crude oil production by at least 70% this year, compared to 2012 levels, and natural gas volumes are likely to decrease 10% or so in 2013, as we allocate capital to higher return oil projects. And most, if not all, of that gas production decline is being driven by declines in the Haynesville, absent new drilling and completions.

Despite the sale of over $200 million in producing properties and associated reserves that we announced yesterday, we reaffirmed our production guidance for the year. Our focus remains on growing high-margin crude oil production, and we're on track to grow QEP crude oil volumes by at least 70% over 2012 levels.

With that, I'll turn it back over to Greg.

Greg Bensen

Thanks, Chuck. Before moving on to the Q&A portion of the call, I want to remind you the status of our Field Services business. On January 7, we announced that, in addition to evaluating strategic alternatives with respect to certain of our midstream assets, we plan to form a master limited partnership, or MLP, and have filed a registration statement with the SEC in the second quarter of 2013. As we've initiated the registration process, our remarks about the MLP on this call will be limited and we will not provide any detail on the midstream business beyond what we have historically disclosed.

With that, Brenda, let's open the line for questions.

Question-and-Answer Session

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you talk about where your Bakken production is currently?

Charles B. Stanley

Current volume is a little over 20,000 barrels equivalent a day and it's heading up. I think, Brian, there were some -- we probably didn't do an adequate job communicating the shape of the growth in our production curve, in the Williston Basin, generally. As I said in my prepared remarks, we moved in a number of rigs in the first half of the year, but they had no impact on production volumes because they're all sitting on pads, drilling multiple wells and we see that production volume response really starting a little bit in the second quarter, but it's really back-end loaded. And so I would caution you guys as you model our production volumes into the third and fourth quarters, to not assume sort of a linear increase in production in the second half. It'll tend to be, as I said, back-end loaded, we forecast about an 18% growth in Q3 and a 31% growth in Q4. So I guess if I was a spin doctor, I'd say to you that, that means our exit rate's probably higher than most of you have modeled in your model going into '14. But it's not a linear -- just a linear extrapolation, it would be about a 24% increase across the second half. So it's kind of a bent hockey stick, if you will, between the third and fourth quarter.

Operator

[Technical Difficulty] And our next question comes from the line of Eli Kantor with IBERIA Capital Partners.

Eli J. Kantor - Iberia Capital Partners, Research Division

Can you talk about the Williston IP rates that you announced in June? Looks like 24-hour rates were significantly better than previous results. Just wondering what was the driver of improvement there.

Charles B. Stanley

Well, I think, in general, the strongest results are obviously on the South Antelope acreage. The big wells were the Middle Bakken wells that we announced, and obviously, it's a reflection and confirmation of what we recognized and analyzed when we made the South Antelope acquisition last year. It's good rock, it's overpressured, the quality of the production performance is directly related to that rock quality, in both the Middle Bakken but also in the Three Forks. Both reservoirs put up some of the best well results in the basin. And just as a reminder, we forecast EURs in the Middle Bakken on the South Antelope property, slightly over 1 million barrels of oil equivalent and slightly under 1 million barrels of oil equivalent for the underlying Three Forks. So they're just good wells and it's supporting our geological and engineering analysis of the South Antelope property. So maybe I should also -- just as I think about it, the completion techniques that we're using, just to remind everyone, we are using sliding sleeves. We average about 30 stages. The wells that we put up earlier in the middle of the year were generally smaller sand volumes or smaller profit volumes, somewhere around 2 million to 2.5 million pounds of sand. We're now experimenting with larger profit volumes in more recent wells. I think we've got some either slated or we've just recently pumped some as large as 5 million pounds of sand. We're looking for that point of diminishing results and diminishing returns as we increase the sand volume. We have not seen any material difference between the Three Forks wells that were drilled and completed by the previous owner on South Antelope, using a cemented liner and plug-and-perf completion design versus the recent wells that we have drilled very, very close by, in which we've employed sliding sleeves and similar-sized jobs, with 30-stage job sliding sleeves versus the cemented liner. The other observation that I'd make, Eli, is that we are using a hybrid proppant design dominated by sand, with a tail-in of either resin-coated sand or ceramic proppant. And we have a good family of wells in the Three Forks that we can compare performance. The previous owner not only designed their completions with cemented liner and plug-and-perf. But they also pumped a 100% ceramic proppant in each of those wells. So it's been a great natural laboratory to compare early well performance and longer-term well performance, and frankly, we struggle to see any significant difference. Now that doesn't mean that in certain parts of the basin, where rock quality may not be as good, where geology is different, that there may be a material difference between sliding sleeve and plug-and-perf cemented liner completions. We just don't see it in the area where we're operating.

Eli J. Kantor - Iberia Capital Partners, Research Division

One of your peers in the basin has reported a significant improvement in well productivity by using slick water-based fracs. Is that a design that you guys have looked at?

Charles B. Stanley

Yes. We, again, in addition to the proppant design, we use a hybrid completion fluid design, as well, with a combination of gel and slick water. As we get in to higher proppant concentrations, we tend to add a little gel towards the end of the jobs, to place the terminal portions of each frac stage. And it also sweeps the sleeves and keeps the sleeves from malfunctioning as well.

Eli J. Kantor - Iberia Capital Partners, Research Division

Moving over to the Uinta, it looks like you dropped 1 of your 2 Lower Mesaverde rigs. Are there plans to reallocate that capital elsewhere?

Charles B. Stanley

Yes. Generally, we're pulling capital away from the Lower Mesaverde for the time being, while we let these wells perform and watch the well performance to help us determine the ultimate -- not only well density spacing but also the pattern that we drill the wells in, to avoid frac interference. And, frankly, we need to see some history on these wells to make sure we understand the interference pattern and we can design a plan of development going forward. So, as we pull capital out, it's generally headed to the oil plays, and especially to the Williston.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay. Last one for me, just on the Cana, you guys had looked at potentially selling that asset earlier this year. It sounded like you had pulled it off the market. Any change in thoughts there?

Charles B. Stanley

Well, it's an asset that we've thought about selling, and obviously, if a buyer made an offer that was acceptable to us, we would divest of it. When we look at any of our properties, we look at the PV of developing the property ourselves and holding it in our portfolio versus the PV offered to us by a buyer and of course, the buyer's offer is risk-free with respect to execution and commodity prices, et cetera. So we take that into account. But to date, the offers that we've received have not met our threshold to consider transacting. Gas markets change. Perception of the property changes. So it might happen, it might not. I'm not going to predict what the future will hold for the Cana.

Operator

Our next question comes from the line of Brian Gamble with Simmons & Company.

Brian D. Gamble - Simmons & Company International, Research Division

I wanted to follow on, on your comment about what you're seeing currently in those Middle Bakken wells. You expected them to be good and they were. Is your expectation from what you've got as far as data across your new acreage there, is it consistent across? Would you expect to see those same sort of flow rates as you're moving forward?

Charles B. Stanley

Yes. The geology looks pretty well behaved from the wireline logs that we have across the Bakken, and we just have a handful, of course. There's been a few outside operator wells around the periphery of our acreage, and they, too, look very similar as far as well performance. And I guess, I would caution you that, as always, IP is not what we really look at. We look at 30-, 60-, 90-, 120-day performance, and obviously, as we get enough production history on the well forecast EUR, that's what really matters. The -- we're, in fact, internally struggling with maximization of the first day rate versus risk of flowing back a portion of the proppant that we've placed in the fractures. And from our experience in other plays like the Haynesville, we think not getting too aggressive on flowback on these wells may be advisable. So as we go forward, we may, in fact, choke back on these wells a little bit at the initial -- for initial flowback to avoid any long-term damage to the reservoir. So I think, it's pretty well established from us and for all the other operators that, in fact, I've got a plot here of IP versus EUR, and the R-squared is about 0.3. It starts to -- the cluster starts to tighten around -- the distribution starts to tighten, and by the time you get to 90 days, there's about a 75% or 80% correlation coefficient. So I think it's very dangerous to just look at IPs. And we're still very happy with the well performance, and it's pointing us toward the wells that we assumed when we made the acquisition about 1 million barrels -- a little over 1 million barrels, almost 1.1 million barrels of oil equivalent.

Brian D. Gamble - Simmons & Company International, Research Division

I would agree with that definitely, and then when you look at -- to that point, you raised your average EUR just based on the current or recent Three Forks wells. It looked like it was gone from 990,000 to right over 1 million. Does that speak to any sort of trend as you're moving in a certain direction through your Three Forks wells? Or was that just [indiscernible] just happen to fall above the type curve?

Charles B. Stanley

No, I mean, we're just -- we just do the math, right? We just -- we looked at our -- at the reserves that we have signed, and wells that had enough production history to feel comfortable, and the average is what we reported. So we -- I wouldn't read too much into the slight bump in EUR. It's just -- it's the statistics of the recent wells that we put on. There's some variability in the Three Forks across the acreage, but it's generally, again, as good as, if not, better than we had assumed in the acquisition model.

Brian D. Gamble - Simmons & Company International, Research Division

Great. And then one more for me. On the discussion about the Cana divestment, obviously, active before. Doesn't -- it seems like you're not as active now. Does the -- I guess, do the other packages that are out there on the market -- we've seen several announcements from different guys, not all Cana but seemed to be all Midcon properties over the last few months. Has that changed the landscape? Are there new people potentially looking that could come in? Or how has that changed your thinking just based on your assets in the area?

Charles B. Stanley

Well, I think there are a handful of new buyers who are emerging. Some of them are still working on their funding. There are -- obviously, the private equity-sponsored companies have a maybe a more constructive long-term view on gas properties versus oil properties, and that's typically what we've seen in the data rooms and in interest levels. So I think that this summer, the first quarter and the second quarter and into the summer, the market was pretty full of property divestitures. And the inventory seems to be coming down some as we move to the end of the summer, so we'll see. We've had several inbounds from new people that didn't originally participate in the data room and process. So you never know. One of them may get to our magic number.

Operator

Our next question comes from the line of Dan McSpirit with BMO Capital.

Dan McSpirit - BMO Capital Markets U.S.

Assuming the current pace of drilling and assuming current development spacing, in what period do you drill the last well on the South Antelope and Fort Berthold leasehold? In what period does production peak from these same areas?

Charles B. Stanley

So in aggregate, we finish everything by sort of the end of '15. Production peaks a little earlier on the South Antelope property. It peaks in sort of late '14. We've got more locations on the Fort Berthold Reservation than on South Antelope. But -- and of course, we're consuming the locations on South Antelope more rapidly because of the current rig count and rig allocation.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And at what price -- what gas price does the Haynesville begin to compete on returns with the Fort Berthold operation?

Charles B. Stanley

Let me think about that for a minute, Dan. It's got a 5 in it. Let me ask you this question. At what oil price should I compare? At current oil prices?

Dan McSpirit - BMO Capital Markets U.S.

Yes, please.

Charles B. Stanley

If I sort of take out the forward curve, we would need a 5 handle on gas to start to think -- even think about allocating capital away from the Fort Berthold Reservation and back toward the Haynesville. But keep in mind, the Haynesville is the driest, lowest return gas project in our portfolio. There are other places that we would allocate capital in our gas portfolio before we got to Haynesville, the Mesaverde and the Uinta Basin, additional drilling at Pinedale and some other properties that we have in the Midcontinent, including the Cana, which, as you know, has a significant liquids component that helps boost returns. So it's not just the dry gas play. The Haynesville is a tough one because as we learned when we were actively drilling with 6 rigs in the Haynesville, you really need to have a decent program there, multi-rig program, 5 or 6 rigs running in the play in order to get the kind of economies of scale that allow us to drive down or hold down completed well cost. And that's not an immaterial capital allocation decision. It's probably $400 million of capital that we would need to divert on an annual basis from some play to the Haynesville in order to fund that level of activity. So it's a major, major shift in capital allocation. And looking at the forward curves of oil and gas today, I struggle to see that happening in the next year or 2.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then one more if I may. If you could remind of the decline rate on the base natural gas production and how is that expected to change over time?

Charles B. Stanley

It's about -- we're forecasting about a 10% year-over-year decline this year in base natural gas production. And it's driven by an over 30% decline in the Haynesville, and that's not base. If I step back -- I'm sorry, that is our forecasted decline in gas production versus last year. And so that includes drilling activity because all of our gas-producing areas, Pinedale, Uinta, et cetera, are up year-over-year with the exception of Haynesville. So when I think about the Haynesville, Haynesville is the mid-30s first year decline with no drilling activity going on and no completion activity going on. And then, of course, we're growing gas production in the other areas. If we look at our corporate average -- and I can't -- I don't have the number in my head or on any of the paper in front of me for our -- just our gas wedge, but our corporate average first year PDP decline is in the high 20s, 27%, 28%. And I don't think it's dissimilar, Dan, between oil and gas. It might be a little steeper on the oil side because of all the new Bakken wells we're bringing on, but it's probably a reasonable proxy for both oil and gas.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then I will ask one more. Chuck, the stock price, the performance continues to lag the group, I guess, to put it politely. What do you think the market is missing here?

Charles B. Stanley

Well, the -- we ask ourselves the same question, Dan. I think the thing that I sense is that the market's waiting for execution on South Antelope, and obviously, it's toward the back-end of the year. We put another element of uncertainty into the equation with the announcement of the formation of an MLP. So the market's waiting for us to execute on that. There's been debate about the value of our midstream assets in an MLP. So I think that those 2 things are probably the 2 that we hear most from investors when we're on the road talking to our shareholders.

Operator

Your next question comes from the line of Duane Grubert with Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Yes, Chuck, kind of along the same lines of thinking, maybe 5-year planning-wise, you guys had made a pretty good commitment to the Uinta as sort of the next big project. And obviously, you're going to focus on the Bakken side, your term here [ph]. But what kind of science works and what kind of other work do you do on the Uinta in the meantime that doesn't necessarily involve drilling a lot of wells? And it looks like the Uinta still is going to be material after [indiscernible].

Charles B. Stanley

Yes. That's a great question, Duane. One of the things that we have focused on is taking some full whole cores and doing special core analysis on those cores because one of the things that we've learned is that the wireline log data from the Mesaverde section, Lower Mesaverde section, is being dramatically distorted by the presence of clays in some of the sands. And we had been under the false impression that the Mesaverde section in the Uinta Basin, unlike the Mesaverde section up at Pinedale, had some wet reservoirs interspersed through the sand packages. The core data that we've collected over the past 6 months and the analysis that we have done suggest that we've been leaving behind a large percentage of the section thinking it was wet when, in fact, it's gas bearing. We took oil-based cores. We've done -- we tagged the drilling fluid with markers so that we could differentiate between invasion of drilling fluid and native hydrocarbon. And all of that data points to some very exciting -- a very exciting change in our interpretation of the wireline log data that suggests that the whole section is gas. At least, the lower half of the section is gas charged, and we don't have to surgically complete these wells. We can pretty much look at the logs and pick the sands and not worry about free water production. That has significant ramifications because it could fundamentally change the EURs of these wells. The current pad -- or I'm sorry, pod of wells that we're drilling will be completed using this new data that we've derived from the cores. And that's -- I think that's an important data point to watch over the next couple of quarters because if that is true, then our whole sort of drilling plan and development of this asset changes dramatically. And just to put a final point on it, early on, we struggled, Duane, and I know you're reservoir engineer, so you'll get this. There was a very low correlation between net pay calculated on the logs and well performance. And we couldn't understand why. We'd have high EUR wells that had very little net pay and vice versa. And we originally rationalized that we were frac-ing away from the wellbore into sands that we couldn't see on the logs. It may be that what's going on is that we were seeing contribution from sands that we were counting as wet that were actually flowing into the well just because of frac height growth. So it's a very interesting data. We've got now several data points. We're going to -- I'm sure that I'm going to be bombarded by the technical team to take even more cores, so if they're listening in, I guess, you got me. So that's the story on the Uinta, Duane. So there's a lot of science we're doing there. Of course, on the production reservoir engineering side, watching these wells that we've completed to see if we see either direct or indirect interference between the wells of different spacing are -- is an important part of the strategy as well.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And I guess just one follow-up to that. Since you guys have a minority interest in a lot of that program, are you working with other owners out there? Is there sort of a consortium that's doing the same sort of work? Or are you guys trying to gain a competitive advantage [indiscernible]

Charles B. Stanley

So Duane, actually, in the Red Wash unit, we are 100% working interest owner. We operate all of the stuff that we're working on. Around the periphery to the south in the Natural -- the northern part of the Natural Buttes unit and the Chipeta Wells unit, we have a smattering of acreage. But our acreage is concentrated in a 100% working interest QEP-operated block. That being said, all the acreage out there is tightly held by Anadarko, EOG, us and a handful of other operators right in that neighborhood. And so there has been some cooperative sharing of core and core analysis and well data between the operators because we all benefit from sharing the science.

Operator

[Operator Instructions] Our next question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies LLC, Research Division

At the risk of making too much of IPs and I know how you feel about that, but just looking at the second quarter completion reports on the Bakken. Looked like there was a wider choke, but pressures looked pretty strong. At the risk of trying to sound like a reservoir engineer, I mean, is that a testament to an ability to actually produce these wells more flush? Or were you saying earlier that you still run the risk of pulling some proppant in?

Charles B. Stanley

Yes, I mean, the -- Subash, the wider chokes are a direct indication of the reservoir support. It's really a question of how much velocity you have down hole and whether or not we run the risk of pulling in proppant. We also worry a bit -- we developed a view in the Haynesville that hard flowback, if you will, higher initial flowbacks and of course, we could never go down there and observe it directly, but the higher initial flowbacks had a detrimental effect on long-term well performance and that it made -- and we speculated that maybe we were doing something to the near wellbore either compacting the prop fracture or not completely connecting the well up to the full length of the prop fracture by having preferential inflow from the -- either the new wellbore part of each of the frac stages or perhaps having preferential inflow from the best frac stages in the well and not cleaning up the rest of the well. So from that thought process, we have been debating internally, managing that early flowback. And so that's why I made the comment, I want to make sure that folks don't look at results in the third quarter or fourth quarter and say, "Oh, now their wells aren't as good." Because, first of all, I don't pay any attention to the IPs; and second, we may manage those IPs in order to avoid reservoir damage.

Subash Chandra - Jefferies LLC, Research Division

Secondly, so when you were talking about your internal forecast for South Antelope, I just want to get the numbers right, so you're thinking about Q4 slightly over 30,000 Boe per day?

Charles B. Stanley

Yes, hang on. I've got -- I think I've got that number here. If you'll just give me a second or actually, we could follow up with you with that number. I don't have it right in front of me, Subash. The 30,000 -- it's a little under 31,000 barrels a day. And to kind of put -- to kind of put it in context, we're planning on completing 70 wells this year, and we only had 27 completed by the end of the first half. So that should also help you with the shape of that production growth curve.

Subash Chandra - Jefferies LLC, Research Division

Okay. I'm sorry, Chuck, could you just repeat those last numbers?

Charles B. Stanley

So we're planning on 70 wells total for the year, 70 QEP-operated wells. Obviously, we have an interest in a number of outside-operated wells. We had, by the end of the second quarter, first half of the year, 27 completed. So [indiscernible] with geologist's math, that means we got 43 to go if I didn't slip a decimal.

Subash Chandra - Jefferies LLC, Research Division

Right. Okay. I think that's layman's math, too. KKR -- I mean, this is just, I guess, third-party evidence in the Haynesville. But KKR and EXCO, they're going to -- they're going back in their drilling. I don't think they're drilling core-core. EXCO had exhausted that. But just given your comments earlier on the Haynesville, have you given thought to that? I mean, I don't think KKR are dumb folks notwithstanding that they're a bunch of ex-Jefferies people.

Charles B. Stanley

I won't comment on the latter part of your statement. But the -- well, as far as the joint venture, you mean? Or are you talking about just that they're doing it and we're not?

Subash Chandra - Jefferies LLC, Research Division

Yes. I guess, they jumped into this with a 75% interest with EXCO on this new acquisition that EXCO made in the Haynesville. And I guess, they have some sort of -- they have a model, an internal model that suggests that they can, at current gas prices, get away with it and earn a good to exceptional return. Do you see that angle or...

Charles B. Stanley

Well, it's all about portfolio, right? So I -- the way we run our business is we look at all of the investment opportunities we have in our portfolio, and we allocate capital, at least we try to allocate capital to the highest-return projects in the portfolio. And clearly, when we force rank it, we run out of capital before we get to the Haynesville. Other companies might not be as fortunate to have as high a return projects as we do in front of the Haynesville. But I'd also say with respect to that company that they have done an excellent job of driving down well cost because unlike the rest of us, who pulled out of the play, they kept drilling, and they have continued to perfect their well design. And obviously, well costs are a huge driver in returns. It's very sensitive -- the Haynesville is very sensitive to completed well costs, and it's even more sensitive to the shape of the natural gas curve. I mean, if you look in the tendencies of our IRR deck, you can see how steep the return sensitivity is versus NYMEX gas price. And so some might take a view that, well, the gas price is wrong, it's going to be up $0.50 or $1 over the next 12 to 18 months. And with that kind of view, I could see how you could continue to allocate capital and aggressively develop the Haynesville. We have better places to put our capital.

Operator

And your next question comes from the line of Hsulin Peng with Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

My first question is regarding the drilling inventory that you talked about in South Antelope. So I was wondering, can you elaborate more how many -- what is your number of well per unit assumption because I think you guys are doing mostly 4 well per pad right now. Have you looked into the deeper ventures or down-spacing potential for South Antelope?

Charles B. Stanley

That's a great question, and I should have added that to my answer earlier. Thanks for reminding me. I mean this is -- the inventory and runway is based on the assumption, Hsulin, that we only drill 4 wells in each of the 2 reservoirs per 1,280 acre spacing unit, so 4 Middle Bakken wells and 4 first bench Three Forks wells. We're still working to evaluate the 2 additional opportunities, the first being increased density, and we're doing some increased density, both reservoir engineering work, as well as we'll do some piloting work. And then the second piece is evaluating other potential reservoirs in the sequence, and that work is ongoing as well. So it has the potential to materially impact that inventory, both in terms of infill and with respect to additional reservoirs.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, great. That's good color. And then secondly, on your -- the third asset sale agreement that you entered into, maybe I missed it but did you say what assets those were?

Charles B. Stanley

No, we did not, Hsulin, and I would prefer not to identify the asset until the transaction's closed. I mean, we gave you the dollar amount, and it's about $66 million, I recall, of proceeds. And we will give you more color around that asset once the deal is closed.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And how about in terms of the 3 combined asset sale, can you tell us what the associated production is with those assets, those sales?

Charles B. Stanley

Yes, for the first half, it's immaterial because the 2 that have closed really closed toward the end of the first half. If we look at it on a full -- for the remainder of this year run rate, a couple of Bcfe roughly of production. And I'm sitting here looking at Rich. I can't remember the ratio of gas to oil, but it's an oilier mix. They were oilier properties, so a couple of Bcfe of impact in the second half of the year.

Richard J. Doleshek

But Hsulin, you won't see it. We didn't change our guidance because of the 2 that we've closed and the 1 that we're going to close. So you can kind of calibrate if we had a 5 Bcf range, it's sort of in that zip code to still be inside guidance.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then in your -- in the Field Services, processing volume, I noticed that it went up meaningfully in the second quarter, and I think you alluded to some, maybe abnormality during the second quarter. Is that -- would that -- and I'm not quite sure what you guys were referring to but...

Charles B. Stanley

Well, let us help you with that. Richard can give you color because I -- what I don't want to have happen is folks start taking the second quarter number and multiplying it by 2 for the second half of the year because there are some anomalies in there. So Richard can give you some color on that.

Richard J. Doleshek

So with the Iron Horse plant being completed, we actually ran that plant in all phases of recovery. And -- but I would say the real increase associated with that processing activity is probably 150,000 barrels in the quarter. We produced about 100,000 barrels of ethane in conjunction with some things that we were doing that we really don't expect to be recovering. So we took the 709,000 barrels in the second quarter, backed up 110,000 barrels of ethane. We also had some just accrual changes that we were doing as a result of that plant coming on. So I think if you think about a sort of good run rate for the third quarter, it's going to be somewhere between 450,000 and 500,000 barrels, as you work the noise out of the system with bringing that new plant on and some of the things that we were doing to just test that plant, get it fully up and running and doing some other custom processing for other people.

Charles B. Stanley

So you do see an impact on volumes, and -- but it's going to be on the heavier part of the barrels going forward. It's just because of the increased recovery efficiency of the cryo plant, even when it's running in ethane rejection mode, it does a better job of extracting the propane and heavier liquids out of the gas stream than the old refrig plant did.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then, I guess, last question in the interest of time. It's regarding your CapEx. So you mentioned that you're trying to get the Bakken well cost to, I think, $10 million by year end. So I was wondering what is currently building your CapEx. And would you potentially increase -- if you have seen the same CapEx amount, would you consider increasing the number of well count? Or would you keep your well count and then reduce CapEx? And then also just a quick question about the $30 million CapEx decrease in your midstream, what is that attributed to?

Charles B. Stanley

Okay. So on the first question, Hsulin, we've got a declining -- a forecast to decline in the completed well cost in the second half of the year that drives the CapEx number. What really drives an increase in CapEx and an increase in well cost or well count in, particularly in the Middle Bakken, is just getting -- Middle Bakken and Three Forks is just getting better and better in the cycle time, both drilling and completion cycle time, which would increase the number of wells that we can deliver to production by year end. And it would also, by necessity, increase the CapEx if we're just completing more wells. So the guidance right now assumes that the number that I gave earlier, about 70 total wells completed for the full year and roughly 43 wells in the second half, and there's a lot of folks focused on doing better than that, and that might result in an uptick, a slight uptick in capital -- CapEx in the second half if we can just get more wells completed. On the $30 million reduction at Field Services, that's a reflection of pushing out the new processing plant that we had talked about, we've been talking about for several years down in the Uinta Basin into next year. And that's really a direct reflection of the desire to get some more production data on the Lower Mesaverde play and make sure that when we go in to start development, we understand exactly how to develop the reservoir. But that's the -- we had anticipated earlier when we set guidance -- well, this time last year, when we started thinking about guidance for 2013 that we would be ordering a lot of equipment and vessels for that plant during 2013 and has slipped into '14.

Operator

It seems there are no further questions at this time. I would like to turn the floor back over to Mr. Stanley for closing comments.

Charles B. Stanley

Thank you, Brenda. In summary, we're excited about QEP's future. We continue to make great progress in shifting our production mix toward higher return, crude oil and liquids-rich gas production from our existing asset base. And with our recently acquired Williston Basin assets, we're now poised to accelerate crude oil production volumes and drive profitable growth from our portfolio of high-quality assets in 2013 and beyond.

I'd like to thank you all for calling in today, and thank you for your interest in QEP. And we look forward to seeing you all soon. Have a good day.

Operator

Ladies and gentlemen, this concludes today's teleconference. You may disconnect your lines at this time, and thank you for your participation.

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