QEP Resources (QEP) Q2 2018 Results - Earnings Call Transcript

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About: QEP Resources, Inc. (QEP)
by: SA Transcripts

QEP Resources, Inc. (NYSE:QEP) Q2 2018 Earnings Call July 26, 2018 9:00 AM ET

Executives

William I. Kent - QEP Resources, Inc.

Richard J. Doleshek - QEP Resources, Inc.

Charles B. Stanley - QEP Resources, Inc.

Analysts

Gabriel J. Daoud - JPMorgan Chase & Co.

Brian Corales - Johnson Rice & Co. LLC

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

John Nelson - Goldman Sachs & Co. LLC

Kashy Harrison - Simmons / Piper Jaffray

Gail Nicholson - KLR Group LLC

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

Operator

Greetings, ladies and gentlemen, and welcome to QEP Resources Second Quarter 2018 Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.

It is now my pleasure to introduce your host, Mr. William Kent. Thank you, sir. You may begin.

William I. Kent - QEP Resources, Inc.

Thank you, Jen, and good morning, everyone. Thank you for joining us for the QEP Resources second quarter 2018 results conference call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer; Richard Doleshek, Executive Vice President and Chief Financial Officer; and Jim Torgerson, Executive Vice President and Head of our E&P business.

If you've not done so already, please go to our website, qepres.com, to obtain copies of our earnings release, which contains tables with our financial results, along with the slide presentation with maps and other supporting materials.

In today's conference call, we'll use a non-GAAP measure, 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 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. We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks facing our business in our earnings release and SEC filings.

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

Richard J. Doleshek - QEP Resources, Inc.

Hey. Good morning, everyone. Yesterday, we reported our operating and financial results for the second quarter of 2018. Adjusted EBITDA in the second quarter was $283 million, which compares to $172 million in the first quarter of 2018 and $177 million in the second quarter of 2017. From an adjusted EBITDA standpoint, this is our best quarter since the fourth quarter of 2014.

Production in the second quarter was 14.1 million barrels of oil equivalent, 2.4 million Boes higher than the 11.7 million Boes we reported in the first quarter of the year. Oil volumes were a record 6.57 million barrels, up 1.6 million barrels or 32% from the first quarter levels. Permian Basin oil volumes were 3.2 million barrels, up about 1,048,000 barrels. The Williston Basin oil volumes were also 3.2 million barrels, up about 555,000 barrels.

Natural gas volumes were 38.3 Bcf, up 3.2 Bcf from the first quarter. Haynesville volumes were up about 2.8 Bcf from the first quarter. NGL volumes were 1.15 million barrels, up about 248,000 barrels from the first quarter. Crude oil comprised 47% of our total equivalent production in the second quarter, which is about 5% higher than the first quarter of the year and about 12% higher than the second quarter of 2017. Chuck will provide more color about the second quarter production results in a few minutes.

Reflective of the strong second quarter oil volumes, we have revised our guidance for full-year 2018 production such that the midpoint for oil production is 23.5 million barrels, a 1.25 million barrel increase. Midpoint for gas production is unchanged at 140 Bcf. We have increased the midpoint of NGL guidance to 4.25 million barrels, a decrease of 250,000 barrels. Overall, the midpoint of our oil equivalent production guidance increased 1 million barrels to 51.1 million Boes.

QEP Energy's net realized equivalent price, which includes a settlement of our commodity derivatives averaged $34.54 per Boe in the second quarter, which was $2.20 per Boe higher than we realized in the first quarter and $7.17 per Boe higher than we realized in the second quarter of 2017. The weighted average field equivalent price in the second quarter was $37.77 per Boe, which was 5% higher than we realized in the first quarter.

The equivalent price reflects field-level crude oil prices that were $62.21 a barrel, natural gas prices that were $2.55 per Mcf, and field-level NGL prices that were $22.84 per barrel. Field-level crude oil revenues account for 77% of total field-level revenues, which was about 6% higher than in the first quarter, but 19% higher than a year ago. Derivative settlements were an outflow of $45.6 million, resulting in a loss of about $3.23 per Boe in the quarter compared to an outflow of $43.4 million or a loss of $3.70 per Boe in the first quarter.

Combined lease operating and transportation expenses including the $12.4 million of transportation expenses that were netted against revenue were $110 million in the quarter, down from $119 million in the first quarter and down from $142 million in the second quarter of 2017.

On a per unit basis, lease operating expenses were $4.71 per Boe, which is $1.47 per Boe lower than the first quarter due to substantially higher production, however, workover expense was $3.6 million lower than in the first quarter. Transportation expense was $3.09 per Boe, which was down $0.89 per Boe from the first quarter, mostly due to increases in volumes through our lower cost Mustang Springs gathering system.

We have lowered our guidance for combined lease operating and transportation expenses including the transportation expenses that are netted in revenue for full year 2018 to a range of $8.50 per Boe to $9.50 per Boe, the midpoint of which is $0.50 lower than our previous guidance midpoint.

G&A expenses were $56 million in the quarter, down $4 million from the first quarter. Outside professional services were $5.7 million lower in the quarter and salary and benefits were $3.6 million lower in the quarter, offset somewhat by a full quarter of retention expense, severance costs associated with the Uinta Basin divestiture and higher share based compensation expense. We increased the midpoint of our guidance for G&A expenses for full year 2018 by $10 million, reflective of the additional restructuring and share based compensation expenses we incurred in the second quarter.

For the second quarter, we reported a net loss of $336 million. Contributing to our net loss was a $403 million impairment related to the divestiture of our Uinta Basin assets. In addition, DD&A expense was $46 million higher in the quarter, driven by higher production. And unrealized loss on our derivative portfolio was $24 million higher than in the first quarter, driven by higher forward curves for oil and natural gas prices.

Capital expenditures on an accrual basis in the second quarter were $366 million, of which $245 million was directed to the Permian Basin; $70 million to the Williston Basin; and $49 million to the Haynesville. In addition, we also reported $9 million of acquisitions in the quarter. We did not revise our guidance for capital expenditures excluding the acquisition and divestiture activity for full year 2018 from our previous guidance, with the midpoint remaining at $1.12 billion.

With regard to our balance sheet, at the end of the quarter, total assets were $7.4 billion and shareholder equity was about $3.4 billion. Total debt was $2.675 billion, of which $1.2 billion were our senior notes and we had $575 million drawn on the revolving credit facility.

I'll now turn the call over to Chuck.

Charles B. Stanley - QEP Resources, Inc.

Good morning, everyone. Since Richard has already discussed our second quarter operational and financial results, I'll spend a few minutes providing an update on our progress on the strategic initiatives that we announced in late February. I'll provide some additional color around our operation results and then we can move on to Q&A.

In late February, we announced that our board of directors approved certain strategic initiatives that were designed to transition QEP to a pure play Permian Basin oil company. Since the announcement in February, we've engaged advisors to market our Uinta and Williston Basin assets, we conducted a robust marketing effort for both the Uinta Basin and Williston assets, and we had good interest from both private or PE-backed companies and public companies through the data room and through the presentation phases, but we ultimately only received bids from private equity backed entities in both the Uinta and Williston processes.

On July 5, we entered into an agreement to sell our Uinta Basin assets for $155 million, including the assumption of certain gas gathering and processing obligations, and subject to customary purchase price adjustments. We expect this transaction to close in September. The bids we received for our Williston Basin assets both on a combined and individual basis did not reflect the value of the underlying quality and economics of these assets.

Given the robust cash flows, strong operational results of both new drilled wells and from our recent refracs, which both by the way generate pre-tax returns at current commodity prices of 55% to 65%, and the significant remaining new drill and refrac inventory on these assets, we simply couldn't sell them for the offers we received.

To put our Williston assets into context, during the first half of 2018, they produced approximately 8.2 million barrels of oil equivalent or approximately 32% of our total oil equivalent production. For the first half of this year, at the field level, our Williston assets generated about $392 million of revenue and incurred direct cash operating expenses before allocation of G&A, interest expense and derivative gains and losses of approximately $115 million.

Furthermore, we estimate that in order to keep production flattish year-over-year, we would need to invest between $220 million and $240 million annually, and that represents roughly a one rig program plus approximately 16 to 20 refracs. We will continue to engage in discussions with potential buyers for all or a portion of our midstream Williston assets, but clearly a successful buyer is going to have to value additional drilling and refrac upside in their bids.

Regarding the Haynesville, as we mentioned in our release yesterday, in response to inbound inquiries we've entered into confidentiality agreements and begun providing data to several parties who've expressed an interest in a transaction involving these assets. Given the current upstream asset market backdrop, our transition to a pure play Permian Basin oil company may take longer than originally anticipated, but QEP's board and this management team remain committed to the strategic initiatives that we announced in February.

Now, let's turn to the second quarter results. We were very pleased with the outstanding results we posted in the second quarter not only in the Permian Basin, but also from our Williston Basin and Haynesville assets. Activity levels during the quarter included five rigs and for a part of the quarter two completion crews in the Permian Basin, which dropped to four rigs in early July and one completion crew in mid-May. And in Williston Basin, we had one rig running through mid-April and one completion crew until mid-June when each was released, while in Haynesville, we had one rig until May and one frac crew until June when both of those were released.

As you can see in the summary of our key accomplishments during the second quarter on slide 3, we really hit it out of the park on all of our assets. You can also see our updated guidance on slide 4 in the current version of our investor presentation that we posted in conjunction with our earnings release yesterday on our website.

In the Permian Basin, our operations team continued to make great progress as they continued to advance our tank-style development program. In addition to delivering a new quarterly Permian Basin net production record of 44,100 barrels of oil equivalent per day, which was up 43% from the first quarter this year, we continued to achieve additional operational efficiencies both on the drilling and on the completion front.

Continued improvements in our drilling operations have allowed us to cut an average of three days of drill time, generating savings of approximately $400,000 on each well we drilled in the second quarter of 2018 compared to the fourth quarter of last year. These gains more than offset approximately $200,000 of cost inflation in materials and services that we've experienced in the Permian Basin over the same time period. These operational efficiency gains on the drilling front allowed us to drop the four active rigs on our Permian assets in early July.

On the completions front, we put on production a total of 37 gross wells in the Permian Basin during the quarter, eight on County Line and the remaining 29 on Mustang Springs. That's four more than we originally forecasted. This increased pace of completed well delivery was a direct result of continued productivity gains from the two frac crews that we have working for us in the Permian.

During the second quarter, the two crews put away over 388 million pounds of proppant in 1,680 frac stages over a total of 3.8 active crew months for an average of a little over 440 stages per frac crew per active crew month. The efficiency gains on drilling and completion of individual wells was facilitated by our approach to developing our assets using tank-style development, which we're absolutely convinced is the right approach to advance development of our over 44,000 net acre core Midland Basin assets.

At the end of the second quarter of 2018, in the Permian Basin, we had 25 gross operated horizontal wells in the process of being drilled, of which 13 only had surface casing set, but had no drilling rig present. We had two wells that were drilled and cased at total depth, but were under drilling rigs. We had 12 wells that were out from under the drilling rigs waiting on completion, five wells undergoing completion and eight fully completed wells that were awaiting production that are part of what we call the pressure wall inside of our tank. Five of the eight wells we put on production on County Line during the second quarter cleaned up and reached peak 24-hour IPs, averaging 164 barrels of oil equivalent per day per 1,000 feet of lateral.

At Mustang Springs, six of the 29 wells put on production during the quarter had cleaned up and reached peak 24-hour IPs, averaging 152 barrels of oil equivalent per day per 1,000 feet of lateral. You can see the location of these wells and the summary of the results on slide 9.

As we first reported in May, in the first quarter this year, we completed a high-density half mile wide drilling spacing unit that contained 22 wells designed to test an ultimate well density of 47 wells per mile spread over five producing target horizons. Of these 22 wells, five were drilled in the Middle Spraberry, seven in the Spraberry Shale, one in the Dean, two in the Wolfcamp A and seven in the Wolfcamp B formations.

These wells continued to clean up during the second quarter and achieved an average peak 24-hour IP of 88 barrels of oil equivalent per 1,000 feet of lateral per well and had an average IP30 of 75 barrels of oil equivalent per 1,000 feet of lateral per well. The performance of these wells met our expectations given that they were drilled and completed on very high density, effectively 47 well bores per half mile wide unit, and we pumped an amazing amount of frac fluid into these wells, over 5 million barrels of water into that half mile wide DSU.

As a reminder, due to the large total frac fluid volume pumped in wells completed in tank-style development, we expect delayed individual well clean-up and suppressed peak oil rates when compared to the performance of a single well or groups of three or four wells completed in non-tank-style development. The results of this density test not only help us optimize the number of wellbores per mile in each target horizon, but they also help us determine the total optimum well density across all horizons inside our tank.

With the first half of the year in the books, I'd like to draw your attention to the guidance table that we included in our release yesterday. You'll note that while we've put a total of 67.1 net Permian wells on production during the first half of 2018, we expect to put on production an additional 31 net wells during the remainder of this year as our drilling and completion activity shifts to longer laterals during the second half of 2018 and into 2019. With this level of completion activity, we expect flattening of our production profile in the second half of this year, while setting ourselves up for 20% to 25% Permian Basin oil production growth next year.

We continue to get a lot of questions about how we're addressing Permian oil takeaway challenges. As I mentioned to you last quarter, our approach is multi-faceted. We start with a contiguous acreage footprint which has been a deliberate focus of our acquisition efforts that allows us to develop our own infill gathering systems to eliminate tank batteries at individual well sites, and thus the need to truck oil. At the end of the second quarter, less than 1,500 barrels per day out of a total of roughly 50,000 barrels per day of gross oil production was being trucked from well sites and these volumes were mostly from our legacy vertical wells that are scattered across our assets.

From gathering systems on our acreage, we focus on flow assurance by moving our oil by pipe to end markets where we receive excellent value for our high quality Midland Basin crude oil. We do this by aligning ourselves with large creditworthy counter-parties who hold firm capacity to the major market hubs at Cushing and along the Gulf Coast, which not only gives us physical flow assurance, but also gives us pricing exposure to markets outside the Permian Basin.

To further maximize value of our high quality Midland crude oil, we also work with midstream service providers to ensure delivery of a neat or unblended barrel of our crude oil to buyers. Finally, we protect our financial margins through the use of derivative transactions that swap local Midland Basin basis against other markets such as Cushing. You can see a summary of our oil marketing strategy on slide 10 and on slide 23 a summary of our derivative positions, which include our basis swaps.

We also get a lot of questions about our ability to source, handle and dispose of water across our Permian assets. As part of our tank-style development approach, we've designed, constructed, own and operate a water system at Mustang Springs that includes water supply wells, produced and flow-back water recycling facilities for frac use and produced water disposal wells. We're currently recycling about half of our flow-back and produced water into our completion and operations, and we believe we got more than sufficient recycling capacity to cover our future development plans, while providing significant cost savings over the traditional water handling methods. You can see a summary of our water handling infrastructure and the benefits therefrom on slide 11.

Turning to the Williston Basin, net oil equivalent production averaged approximately 49,000 barrels of oil equivalent per day during the second quarter of 2018. That was an 18% increase compared to the first quarter of 2018. We put 11 gross wells on production during the quarter, six in the Middle Bakken and five in Three Forks first bench, and they were all on South Antelope and all had outstanding results.

The wells were completed with an average lateral length of 10,030 feet and had an average peak 24-hour IP of 289 barrels of oil equivalent per day per 1,000 lateral feet, with the best well reaching a peak IP of 3,842 barrels of oil equivalent per day or 377 barrels of oil per day per 1,000 lateral feet. Seven of the 11 wells achieved peak IP30 rates during the quarter averaging 213 barrels of oil equivalent per day per 1,000 feet of lateral.

In addition to the newly drilled wells, we refracked and returned to sales seven operated wells during the quarter, they were all on South Antelope and all also had excellent results. Three of the seven wells had been on production long enough to achieve an average gross peak IP30 uplift from pre-frac rates of 844 barrels of oil equivalent per day per well. The remaining four wells were still cleaning up at the end of the quarter and after the end of the quarter, in early July, they reached an average peak IP30 uplift over pre-frac production volumes of 1,654 barrels of oil equivalent per day per well, with the best well delivering a peak 24-hour IP uplift of 1,952 barrels of oil equivalent per day. And these are all from approximately 10,000 foot laterals.

Based on these results, as well as those from previous quarters, you can see why we are so excited about the large inventory of refrac locations that we've identified across our Williston Basin acreage. At the end of the second quarter, we had no drilling or completion activity in the Williston. You can see slides 13 to 15 for more details on our Williston assets and on the recent results.

In the Haynesville/Cotton Valley, net gas equivalent production averaged approximately 314 million cubic feet or 52,300 barrels of oil equivalent per day during the second quarter. That was a 10% increase compared to last quarter.

During the second quarter, we put on production one new well with a lateral length of approximately 10,000 feet. The well has just commenced flow-back at the end of the second quarter, not yet reached peak rate. Today, it's making over 30 million cubic feet a day. We had to complete fracture stimulation of a second well also on the same pad and also with a roughly 10,000 foot lateral length. And we were in the process of drilling off the frac plugs at the end of the quarter and that well continues to clean up.

In addition to the newly drilled wells, we continued our highly successful refrac program during the quarter in the Haynesville, completing and returning to sales a total of six wells during the quarter with an average incremental 24-hour uplift of 13 million cubic feet equivalent of gas per day gross. For the record, four of these refracs were in a high density section, which was originally developed with eight wells per 640 acres. So that was our first experiment with going into what is – what was a fully developed section and refracking every other well to examine results and we were quite pleased with the outcome.

At the end of the second quarter, we had no active drilling rigs, refrac crews in the Haynesville and you can see slide 16 and 17 in our slide deck for additional details on our Haynesville assets and on the activity.

In summary, we're extremely pleased with the very strong results and continued operational efficiency gains we've posted across our entire portfolio during the second quarter. Regarding the strategic initiatives we announced in February, QEP's board and management remains committed to the strategy of becoming a pure play Permian Basin oil company. While we continue to engage with potential buyers for our Williston and Haynesville assets, we're also working with our advisors on a range of potential alternatives transaction structures to achieve the ultimate goal of becoming a pure play Permian Basin oil company.

With that, Jen, we can open the lines for questions.

Question-and-Answer Session

Operator

Thank you. Our first question comes from the line of Gabe Daoud with JPMorgan. Please proceed with your question.

Gabriel J. Daoud - JPMorgan Chase & Co.

Hey, good morning, everyone. Maybe just starting with the strategic initiative process and I guess specifically the Williston, could you maybe just provide a little bit more color on where you stand from a timing perspective? Is it possible to see the Haynesville transact, I guess, before the Williston at this point? And then, if you don't get properly valued for refracs and undeveloped acreage, is there a chance that you'd just pull the deal entirely and keep the asset for cash flow?

Charles B. Stanley - QEP Resources, Inc.

Good morning, Gabe. I'll start with it and let Richard add any additional color. So, there're multiple questions in one question. I'll start by saying that, yes, it is possible that we get to a deal on the Haynesville before we get the one on the Williston Basin assets, but we've had inbounds, we've provided data, we'll see whether any of the folks that we're talking to come to a value that we think is reflective of the value of the underlying assets. And just like the Williston Basin, we're not going to accept value – an offer from any potential buyer that doesn't fully reflect what we think is the value of the assets.

We have a view of what we think they're worth based on our own analysis and DCF of both the existing PDP volumes as well as the significant undeveloped potential of our acreage for new drills and for refracs. And just as a reminder, it's on the slide in our slide deck, but I just want to remind everybody. In case you forgot, we also own a midstream business that sits on top of a large portion of our Haynesville footprint. So, it too provides a unique value proposition for a potential owner with respect to the total package. So, long answer to the first question, which is yes, it's possible, Haynesville goes before Williston.

With respect to the Williston process, we're continuing to talk to some folks that bid during the first round. One of the things that we've done is, as you saw in the release and as I mentioned in my prepared remarks, we've recently put on line another set of what I would consider to be outstanding refrac wells that have only been on really since the end of July. So, the original bidders didn't see those, they saw them in progress, but didn't see the results from them.

We think that the more results we put up on these refracs, the more it de-risks the perception that these are high-risk undertakings. In fact, we're very comfortable with them because obviously we've had great success in the Haynesville and a lot of folks who just looked at the Williston assets are not familiar with the incredible results we've been delivering in the Haynesville for over a year. So, part of our job is going to be to go back and make sure that folks understand the value of these refracs, and that they generate returns that are competitive with new drill returns across our acreage and across the Williston in general.

Gabriel J. Daoud - JPMorgan Chase & Co.

Thanks, Chuck. That's helpful. And then just following up on one of your last points on the prepared remarks, so you said something about additional structures, could you maybe just elaborate a little bit on that?

Charles B. Stanley - QEP Resources, Inc.

Well, Gabe, there is a potential to do transactions with potential counter-parties where cash might not be the only consideration, a potential spin, merge, et cetera. And we've had our advisors analyzing a number of different scenarios that would allow us to achieve a simplified structure and the ultimate goal of our strategic initiatives of becoming a Permian Basin pure play through means other than a straight sale for cash of the assets. Certainly from an execution perspective, timing perspective, ease of evaluating value perspective, a straight sale for cash is preferred, but it's certainly not the only potential transaction structure that we're considering.

Gabriel J. Daoud - JPMorgan Chase & Co.

Got it. That's helpful. And then just one final one for me on the strategic initiatives. On the Haynesville, is the thinking still having the potential buyers bid separately for midstream and upstream? Is that still the thinking?

Charles B. Stanley - QEP Resources, Inc.

We'll certainly consider offers for either or for both combined, Gabe. I think if I were in the shoes of a buyer, an upstream buyer, I would want the midstream assets as well because I think it provides a unique opportunity to realize higher value of every molecule that you produce out of the Haynesville and Cotton Valley across the asset.

Gabriel J. Daoud - JPMorgan Chase & Co.

Great. Thanks a lot, Chuck.

Charles B. Stanley - QEP Resources, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Brian Corales with Johnson Rice & Company. Please proceed with your question.

Brian Corales - Johnson Rice & Co. LLC

Good morning, guys. Can you maybe provide, on the Bakken, what the PDP PV-10 is, like at current pricing?

Charles B. Stanley - QEP Resources, Inc.

Richard is shaking his head; we don't have that number in front of us.

Brian Corales - Johnson Rice & Co. LLC

Or maybe can you also break out how much Antelope is producing versus the Reservation or ballpark?

Charles B. Stanley - QEP Resources, Inc.

Yeah. It's about a one-third, two-third split, maybe a little bit higher than that. So maybe it's 70% South Antelope and 30% for Berthold, but maybe 75%, 25%, somewhere between 65% and 75% comes out of South Antelope.

Brian Corales - Johnson Rice & Co. LLC

That's fair enough. And then it looks like the second half of the year, you're all going to have free cash flow. Any thoughts, I mean you talked about the refrac program in the Bakken working well. Any thoughts about putting another completion crew up in the Bakken or adding a rig either back to the Permian or Bakken to try to help stem some of those declines that are going to be coming out – coming from the Bakken?

Charles B. Stanley - QEP Resources, Inc.

Brian, we're in discussions with our asset teams to develop some proposals for potential second half activity on both of those assets. Obviously, we are focused on stemming the decline that would result if we shut down all activity on the assets in the second half of the year. And as we work up those programs, we'll be meeting with our board again to discuss potential additional capital investments on those assets in the second half.

Brian Corales - Johnson Rice & Co. LLC

Okay. And one final one if I could. Would you all be comfortable buying your stock back in this environment without any kind of line of sight on a sale or is the balance sheet going to – are you too worried about the balance sheet?

Richard J. Doleshek - QEP Resources, Inc.

Yeah, Brian; it's Richard. Using the availability of the revolver to buy back stock right now just doesn't feel good. (31:52) if I would answer, not interested in doing that.

Brian Corales - Johnson Rice & Co. LLC

Okay. Even with free cash?

Charles B. Stanley - QEP Resources, Inc.

As a reminder, when we talked about the strategic initiatives, we said we would use proceeds from asset sales to, one, pay down debt; two, fund the outspend; and then three, depending on market conditions, buy back stock. It certainly feels like at this point until we get more clarity around the sale of one or both of these packages of assets that our focus should be on maintaining a strong balance sheet.

Brian Corales - Johnson Rice & Co. LLC

All right, guys. Thank you.

Operator

Thank you. Our next question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Morning, guys. Say, Chuck, my question was more on the Bakken refracs given the huge success you've had. I know you don't know the full plan of that asset now, but I don't know, number one, do you have any plans for more refracs the second half of this year and now given the success you've seen, would that change?

Charles B. Stanley - QEP Resources, Inc.

Well, we're certainly looking at that. We don't have board approval for additional capital for the second half of the year. We talked to them earlier this week about the remarkable results that we're seeing there. And they asked us to look at a program to spend additional capital in the second half of the year, which we're in the process of doing.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Very good. And then just lastly, Richard for you, or Chuck, just one, is there still – I guess it's hard. It's kind of a what-if situation depending on what happens with the Bakken. Let's say in short order, nothing happens yet near term with the Bakken. What's the leverage metrics you're trying to achieve or at least trying to stay at? Could you talk maybe about the leverage ratio and how you see it for the remainder of the year?

Charles B. Stanley - QEP Resources, Inc.

Yeah. Neal, we're – today, depending on what period you use, we're still over 3 times that multiple of EBITDA, which is high for where we have historically been and where we'd like to be. Our target's always been to get closer to 2 times. So, kind of calibrate between 3 times and 2 times, gives you some guidance as to where we'd like to be. But it was mentioned earlier, we do expect to be free cash flow positive in the second half of the year, which is something that we haven't been since 2016. And so, we're going to try to manage the balance sheet such that if the current commodity price deteriorates, we're not stuck, so the focus still is on the balance sheet.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Very good. Good answers. Thanks, guys.

Operator

Thank you. Our next question comes from the line of John Nelson with Goldman Sachs. Please proceed with your question.

John Nelson - Goldman Sachs & Co. LLC

Good morning, and thank you for taking my questions. I was just curious, can you tell us what a generic Bakken refrac PV-10 would be?

Charles B. Stanley - QEP Resources, Inc.

Hi, John. It ranges from $3 million to $5 million depending on where on the asset you complete or recomplete a well and it ultimately is driven by oil in place and by the original well performance that gives us an indication, if we calibrate for the various reservoir parameters, that gives you a range of potential outcomes.

John Nelson - Goldman Sachs & Co. LLC

So, if I just – sorry, go ahead.

Richard J. Doleshek - QEP Resources, Inc.

That's a net – it's NPV.

John Nelson - Goldman Sachs & Co. LLC

Yeah. So, if I use kind of just round numbers relative to the locations you put on the slide deck, is it fair to say then that the kind of spread between bid ask is kind of somewhere between – was that $900 million to $1.5 billion, is that how you're thinking about the spread – bids being too low?

Charles B. Stanley - QEP Resources, Inc.

John, I'm just not going to comment on bids we received, the value of those bids or our expectation at this point. I don't think it is constructive to the process.

John Nelson - Goldman Sachs & Co. LLC

Okay. Fair enough. Second question was you guys had a better results from the Permian well density tests that you said they are going to be helpful in informing kind of future well densities that you choose. Can you maybe just elaborate on kind of what you learned and if there's any update or narrowing in on the range within certain horizons as to how tight you can go?

Charles B. Stanley - QEP Resources, Inc.

That's a great question. Obviously, as I said in my prepared remarks, this was a super high density experiment that we did. And what we've learned is, as I said, when we put that much frac fluid in a half mile wide spacing unit, it results in suppressed IPs, longer clean-up and longer IP30s, IP90s, IP120s because we're having to recover 5 million barrels of frac fluid out of that rock volume.

What we learned from the density studies and we're continuing to do them at lower densities and higher densities going forward is we're starting to see optimal density in each of the target horizons and we're adding additional, sort of, what I would call intermediate target horizons like the Dean in our development plan going forward to spaced out the wells not only horizontally, but also vertically to sort of quasi wine rack them to maximize the drainage of the reservoir.

When we look at optimal well density, we still think it's in the mid-30s to low 40s across our assets. And as we think about it, we're going to be adding additional target horizons and spreading wells out across those new target horizons in addition to the four that we've talked about repeatedly, the Middle Spraberry, Spraberry Shale and Wolfcamp A and B. So, you'll start to hear us talk about intermediate zones between those horizons as well as potentially a deeper Wolfcamp zone.

John Nelson - Goldman Sachs & Co. LLC

I guess just to be clear on that last point, so across the four main zones you still think it's kind of mid-30s to low-40s, and then if you can add those increment – those intermediate zones, those would be incremental or just...

Charles B. Stanley - QEP Resources, Inc.

I think...

John Nelson - Goldman Sachs & Co. LLC

...they would – yeah.

Charles B. Stanley - QEP Resources, Inc.

...that some of the replacement zones will supersede the densities at the four target horizons. So if you look at a fully developed mile wide section, you will see somewhere between 35 and 43 wells per spacing unit, John, including all zones. But what we see when we stimulate this rock, as we mentioned before, there are no vertical barriers. So we see frac communication and water flow, frac water communication across all of the stimulated rock volume. It becomes one big tank. And so, what we're trying to do is optimize the take points across that tank to maximize recovery of oil in place. So, we stop thinking about individual target horizons and just think about well bores within a cube of rock. Does that make sense?

John Nelson - Goldman Sachs & Co. LLC

Yeah. That's really helpful. I'll let somebody else hop on. Thanks.

Charles B. Stanley - QEP Resources, Inc.

Thanks.

Operator

Thank you. Our next question comes from the line of Kashy Harrison with Simmons/Piper Jaffray. Please proceed with your question.

Kashy Harrison - Simmons / Piper Jaffray

Good morning, everyone, and thanks for taking my question. Say, with the deferral of the Williston divesture to a later date, I was just wondering how you think about deploying capital to the region beyond year-end 2018? So, for example, let's say you have these assets in your hands at year end, would you expect to deploy some capital next year or does it become more of a PDP blow down asset moving forward?

Charles B. Stanley - QEP Resources, Inc.

Kashy, we're looking at a number of scenarios. In discussion with our board earlier this week, what-ifs, and at this point, it's what-ifs, what if we own the asset for six months, what if we own it longer, what should we do with respect to additional capital investment, not only in the Williston, but also in the Haynesville.

Obviously, we need to maintain operations, maintain cost structure there. As you correctly pointed out, there is an argument for a blow down, which doesn't consume the remaining locations in the Williston. It simply allows us to harvest cash out of it. If you think about that, that scenario would require very little additional capital investment, some workovers, no doubt, but not a lot of additional capital investment.

And over a course of four years, at current forward prices, a blow down scenario would throw off over $1 billion of cash, net of operating expense. So that's one scenario that we have thought about and that we are debating both at the management level and also discussing with our board. We haven't made a decision yet and some of that is going to be dependent on our ongoing conversations with interested parties and whether or not we're able to reach an agreement on valuation and consummate a transaction.

Kashy Harrison - Simmons / Piper Jaffray

Got you, got you. That's very helpful. Maybe switching gears a little bit to the Permian, you guys did a great job outlining your marketing strategy on page 10 of the presentation, but I was just wondering, however, if you could share some color on what your operation team is telling you regarding the status of these pipes in the Permian here more recently? What I'm getting at is, are the pipes effectively full at this point? Do you think there's still some – or do you think there's still capacity, just trying to get your sense on where you think the pipes are today?

Charles B. Stanley - QEP Resources, Inc.

Kashy, it's going to be direct observation of what we read and from talking to other folks. At this point, we have not seen any signs of physical tightness with respect to moving oil. We're not seeing a big jump up in the level of the truck activity, et cetera. Of course, we don't see it other than as I mentioned in my script associated with a little bit of in-field oil gathering, about 1,500 barrels a day we do and then we have one purchaser who takes some oil off of our gathering systems to a refinery in the area, but, and they take that by truck rather than by pipe. But that has nothing to do with physical constraints. And so we're waiting to see signs of physical tightness. We just haven't seen them yet.

As for the status of the pipes, it's – I'm not going to tell you anything more than what you read and write about yourself as to the status of each of the projects that's underway to either loop the existing systems or to build new takeaway infrastructure to various export markets, whether it'd be along the Gulf Coast or up to Cushing.

Kashy Harrison - Simmons / Piper Jaffray

Got it. Well, that's helpful. Thanks for the time guys and have a good rest of the day.

Charles B. Stanley - QEP Resources, Inc.

Thanks, Kashy.

Operator

Thank you. Our next question comes from the line of Gail Nicholson with KLR Group. Please proceed with your question.

Gail Nicholson - KLR Group LLC

Good morning. You guys have seen a really good improvement in well cost over in the Permian, especially in Mustang Springs since the fourth quarter of 2017. Do you think that there is more incremental room for improvement or do you kind of think you're up the learning curve in regards to the efficiency gains that you've achieved year-to-date?

Charles B. Stanley - QEP Resources, Inc.

Well, Gail, I know my drilling completion folks are going to like hearing this. But I think we should be able to get the drill times down to zero and an infinite number of frac dates. Look, we have a very talented team of folks who are really good at manufacturing holes in the ground and every quarter they amaze me that they continue to squeeze out additional efficiency gains.

If you look at our history and other resource plays where we've been manufacturing holes for years, we have continued to achieve incremental performance improvements on both the drilling and on the completion front. Obviously, we started out with a collective knowledge of all of our previous drilling efforts, so we started out at a better spot, but we've been able to continue to squeeze additional days out of the drill time and we've been able to get more and more frac stages pumped on a monthly basis.

At some point, every day or every hour becomes an incremental victory and it gets harder and harder to do so, but we're continuing to make progress. And it's not only just operational efficiency. A lot of it is being driven by the nature of our development activity. And again, I think it speaks volumes for tank-style development because we have very little wasted time in between individual operations, whether it's a drilling rig moving from one well to the next or a frac crew moving from one well to the next, it's all in a very compact footprint and it's all choreographed to minimize downtime on the service companies that are providing our well construction services.

Richard J. Doleshek - QEP Resources, Inc.

And, Gail, I think the one place we have an expectation about improvements is more in-basin sand. Currently, we're not near where we thought we would be in terms of the use of in-basin sand. On the negative, steel is costing us a lot more. And so, how those two balance out, we'll see. But certainly, the 5% lower than the fourth quarter of last year is pretty remarkable given the pressures that we've seen. So, yeah, some upside, but also some downside.

Gail Nicholson - KLR Group LLC

Great. And then, you talked about the idea of not looking at necessarily an individual recovery per well, but maximizing recovery of the oil in place per DSU. Is there an internal goal like you want to try to recover 20% of oil in place per DSU or how you guys look at – how you conceptualize that?

Charles B. Stanley - QEP Resources, Inc.

Well, we'd like to recover 100%, but unfortunately the physics of the rock limit that. Look, when I was a kid, it was beat into your head and there's a direct relationship between permeability of the rock and ultimate recovery of oil in place. And as we've continued to evolve technology and the use of nano-fluids and things like that, we've continued to see enhancement of those sort of fundamentals that we were all taught 25, 30, 40 years ago in terms of the rock physics and limitations.

We think that we have the best chance to maximize recovery of oil in place by maximizing the stimulated rock volume which is what we're trying to do by building these pressure walls and supercharging the rock. When we pump 5 million gallons of water – I'm sorry, barrels of water into a half section, we're raising the internal pressure of that cube by 2,000 PSI to 3,000 PSI over discovery pressure. So we're energizing that cube and we're also hopefully maximizing the complexity of the fracture network which allows us to touch the maximum amount of oil in the reservoir and we hope that translates into higher recovery of oil in place. Time will tell. I think mid-teens to upper-teens is probably an achievable goal, but we will see if we can do better than that over time.

Gail Nicholson - KLR Group LLC

Okay, great. And then just on regards to that blow down scenario where you talked about $1 billion of free cash flow generation out of the Williston over the next four years, what is the PDP decline rate assumption on an annual basis for that?

Charles B. Stanley - QEP Resources, Inc.

Well, if we stop drilling – if we don't do any more refracture, any more drilling, first year PDP decline is in the 29% to 31% range. The next year it flattens a little more, probably into the mid-20%s and then the third year, it's in the low-20%s and it hypes out after that.

Gail Nicholson - KLR Group LLC

Okay, great. Thank you so much.

Charles B. Stanley - QEP Resources, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Kevin Maccurdy with Heikkinen Energy Advisors. Please proceed with your question.

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

Hey, guys. Things are going very well in the Permian and arguably you have the capacity for more activity from an operational standpoint. What gets you to increase activity? Is it just a financial constraint or are there any midstream constraints that keep you from accelerating till next year?

Charles B. Stanley - QEP Resources, Inc.

Well, we're obviously watching out of basin takeaway capacity. We also are obviously watching the results of the high density pilot wells that we just drilled and talked about in the first quarter and really are seeing results on the second quarter. And then the biggest thing, Kevin, is operational efficiency. And what we've tried to do is right-size the well delivery pace and the rig count – the rig fleet to match it to a high utilization of a single frac crew and, at 4 to 1; 4 rigs to 1 frac crew, we're optimally situated right now to match the pace of drilled and cased wells coming out of the drilling rig line to the completion crew.

And so it – increasing activity is not just adding a rig. It's adding multiple rigs to optimize around another frac crew. So it's not an incremental dollar decision. It's a step change in activity level. So we're comfortable where we are right now. We think we can deliver mid-20s percent oil production growth next year with a four rig program and one frac crew, maybe even less than four rigs if we continue to see the sustained drilling improvements that we have in place today.

So, the next step would be, do we go to six rigs and add two – and add another frac crew and that's a decision that's obviously a big increment in the capital. And so, it's something, again, we're waiting and watching the macro environment, in particular takeaway and how it impacts the in-basin cost, in-basin price realizations and we'll make that decision as we go forward into the end of the year and next year.

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

Okay. And as a follow-up, given you have no active rigs in the Haynesville, will you have any turn-in lines there in the second half of the year?

Charles B. Stanley - QEP Resources, Inc.

Well, again, as I mentioned earlier, we're discussing with our directors a potential capital program in the second half of the year. My inclination would be to reinstate our refrac program there because that would have a meaningful impact on PDP decline, if we just go in and continue our very successful program targeting the wells, the roughly 4,500 foot wells that we're drilled across our acreage. We have a robust remaining inventory there of refrac candidates and as we demonstrated, we can meaningfully drive production from the asset with just that refrac program.

Richard J. Doleshek - QEP Resources, Inc.

Hey, Kevin. It's Richard. Remember, the two wells that we had drilling in the second quarter, one came on in the quarter and then one lapped over. So we will have that second Baxter well (53:04) that officially comes online in the second half of the year in July. They were both right at the end of the quarter, one made it and one did not.

Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC

Great. Thanks for the clarity.

Operator

Thank you. Ladies and gentlemen, at this time, there are no further questions. I would like to turn the floor over to Chuck Stanley for closing comments.

Charles B. Stanley - QEP Resources, Inc.

Thank you, all, for dialing in today and thank you for your interest in QEP. I think our next IR activity will be here in Denver in a couple of weeks. So, we look forward to seeing some or all of you at that event.

Operator

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