QEP Resources (QEP) Q4 2016 Results - Earnings Call Transcript

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QEP Resources, Inc. (NYSE:QEP) Q4 2016 Earnings Call February 23, 2017 9:00 AM ET

Executives

William Kent - QEP Resources, Inc.

Richard J. Doleshek - QEP Resources, Inc.

Charles B. Stanley - QEP Resources, Inc.

Analysts

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Gabriel J. Daoud - JPMorgan Securities LLC

David R. Tameron - Wells Fargo Securities LLC

Brian Michael Corales - Howard Weil

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

John Nelson - Goldman Sachs & Co.

Gail Nicholson - KLR Group LLC

Operator

Greetings, and welcome to the QEP Resources Fourth Quarter and Full Year 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded.

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

William Kent - QEP Resources, Inc.

Thank you, Jessica, and good morning, everyone. Thank you for joining us for the QEP Resources fourth quarter and full year 2016 results conference call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer, and Richard Doleshek, Executive Vice President and Chief Financial Officer.

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

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.

Thank you, Will, and good morning, everyone. I'll touch on to our fourth quarter and full year 2016 results and our initial guidance for 2017. Then turn the call over to Chuck. We all hope that the industry is through the trough of the most recent commodity price cycle, and that we are now on a road to recovery.

In 2016, in response to continued lower and volatile commodity prices, we focused on controlling what we could control. We reduced our capital spending, tightened our belts, and lived inside cash flow. And despite an incredibly challenging year, QEP exited 2016 in better financial shape at the end of the year. At year-end, we had more cash, less debt, and arguably better assets.

With regards to our results for full year 2016, we generated $626 million of adjusted EBITDA compared to $1,029 million in 2015. Our fourth quarter EBITDA was $174 million which compares to $169 million in the third quarter of the year, and $254 million in the fourth quarter of 2015.

Production in the fourth quarter was 13.7 million barrels, or 770,000 barrel oil equivalent lower than the record 14.4 million barrels of oil equivalent we reported in the third quarter of the year. Oil volumes were 4.9 million barrels, down 142,000 barrels from the third quarter levels. About 110,000 barrels of that decrease was in the Williston Basin, where we got whacked pretty hard by weather in December.

NGL volumes were 1.5 million barrels, down 140,000 barrels from the third quarter. About 100,000 barrels of that decrease was also in the Williston Basin. Natural gas volumes were 44 Bcf, down 3 Bcf from the third quarter of the year. Pinedale was down about 1.4 Bcf, but Haynesville was up about 1.1 Bcf from their respective third quarter levels.

Crude oil comprised 36% of our total production in the fourth quarter of 2016, which was up 1% from the third quarter of the year, about the same percentage in the fourth quarter of 2015. Our guidance for oil volumes for 2017 is, 21 million barrels to 22 million barrels, the midpoint of which is up 6% from the 20.3 million barrels we produced in 2016.

Our guidance for NGL volumes for 2017 is 5.75 million barrels to 6.25 million barrels, the midpoint of which is about the same as production in 2016. It assumes that we'll be in ethane rejection all year in the locations at which we can recover, make a recovery or rejection election.

Our guidance for natural gas lines for 2017 is 180 Bcf to 190 Bcf, an increase of 4.5% at the midpoint of range in the 177 Bcf we produced in 2016, reflecting increased workover activity in Haynesville and higher associated gas production from our oil properties. Chuck will give you more color about the drivers of our production guidance for 2017 and our oil production outlook for 2018 in his prepared remarks.

QEP Energy's net realized equivalent price, which includes the settlement of our commodity derivatives, averaged $27.31 per Boe in the fourth quarter, which was our highest realization of the year, and $2.10 per Boe higher than we realized in the third quarter, but $5.54 per Boe lower than we realized in the fourth quarter of 2015.

The weighted average field-level equivalent price in the fourth quarter was $27.27 per Boe, which was 14% higher than we realized in the third quarter. The equivalent price reflects field-level crude oil prices that were $44.24 per barrel, natural gas prices that were $2.95 per Mcf, and field-level NGL prices that were $18.49 a barrel.

Field-level crude oil revenues accounted for 58% of total field-level revenues, which was down slightly from the third quarter. Derivative settlements only added $0.5 million of proceeds, or $0.04 per Boe in the quarter compared to $19.5 million, or $1.35 per Boe in the third quarter.

Combined lease operating and transportation expenses were $132 million in the quarter, up from $127 million in the third quarter of the year, and down from $138 million in the fourth quarter of 2015. On a per unit basis, lease operating expenses were $4.49 per Boe, which is up $0.98 per Boe from the third quarter due to additional expenses and not a lot of volumes out of the Mustang Springs acquisition. And transportation expense was $5.14 per Boe which was down $0.10 from the third quarter. Our guidance for lease operating and transportation expenses for full year 2017 is $9.50 to $10.50 per Boe.

G&A expenses were $39 million in the quarter, down $28 million from the third quarter. As you recall, the third quarter included a loss contingency expense of $25 million. For the year, G&A was $198 million, up $17 million from 2015. However, if you exclude the $32.7 million of usual legal expenses and loss contingencies in 2016, G&A was down $15 million from the previous year.

Included in the $198 million of G&A in 2016 was a $40 million of share-based compensation expense compared to about $31 million of share-based compensation expense in 2015. Our guidance for G&A expense for full year 2017 is $160 million to $170 million, of which approximately $31.5 million is share-based compensation expense. Excluding unusual items and share-based compensation expense, we expect 2017 G&A expense to be modestly higher than 2016.

For 2016, we reported a net loss of $1.245 billion. Contributing to the net loss was $1.2 billion of impairments of proven and unproven properties in goodwill driven by lower forward commodity prices in the early part of the year. We also recorded $367 million of unrealized loss on derivatives reflecting the lower value of our commodity derivatives portfolio at year end 2016 compared to year end 2015. In addition, DD&A expense was down $10 million in 2016, compared to 2015.

Capital expenditures on an accrual basis for E&P activities in 2016 were $521 million. In addition, we also acquired $645 million of properties in the year. For 2017, excluding acquisitions, we are forecasting the midpoint for capital spending to be $975 million, which includes about $55 million for midstream infrastructure primarily in the Permian Basin. The Permian Basin will be allocated about 60% of the 2017 capital budget, which marks the first year since 2013 in which the Williston Basin has not received the largest portion of the capital program. And Chuck will give you additional details about our 2017 capital program in a second.

Year end proven reserves were a record 731.4 million barrels of oil equivalent, up 21% from the year end 2015. We had 77.3 million barrels equivalent of positive revisions, primarily such as our Haynesville workover program. Lower SEC prices resulted in negative revisions of 18.5 million barrels of equivalent and extensions and discoveries added 42.6 million barrels of equivalent.

In total, we replaced 215% of production through extensions in non-price related revisions. In addition, acquisitions added 83.3 million barrels equivalent. 49% of the proved reserves were developed, 42% of the proved equivalent reserves were liquids. The SEC PV-10 value of the proven reserves was $1.9 billion, and the pre-tax PV-10 of the reserves was $2.4 billion.

With regard to our balance sheet, at the end of the year, total assets were $7.25 billion, shareholder equity was about $3.5 billion. Total debt was approximately $2.05 billion, all of which was of senior notes. At year end, we had $444 million of cash and no borrowings under our revolving credit facility. And earlier this month, we received some good news from the debt rating agencies. Moody's upgraded the ratings for our senior notes from B1 to Ba3. And S&P reaffirmed the rating of our senior notes at BB+, but revised our outlook from negative to stable.

I'll now turn the call over to Chuck.

Charles B. Stanley - QEP Resources, Inc.

Good morning, everyone. Since Richard has already discussed our 2016 results, I'd like to spend my time discussing our plans for 2017, and initial outlook for 2018, with a particular focus on the Permian. Then we'll move on to the Q&A.

As you saw in our release yesterday, 2016 was a solid year for QEP despite the commodity price headwinds that confronted our industry and our company. We responded by reducing our operated rig count and pushing harder on our service providers and suppliers for price concessions, while challenging our asset managers to stay focused on operational efficiency, capital discipline and safety. For most of the first half of 2016, we ran three rigs across our portfolio with one each in the Permian and Williston Basins, and one at Pinedale.

In the fall, as oil prices began to improve and in anticipation of closing our Mustang Springs acquisition, we picked up two additional rigs in the Permian Basin. These rigs that were added during the latter part of the third quarter initially went to work drilling wells on our County Line property, while we worked to close the Mustang Springs acquisition and to lay the groundwork for our innovative Mustang Springs development plan, which I'll discuss in more detail in a moment.

The addition of the two rigs at County Line allowed us to accelerate our well density testing in the Spraberry Shale which we think will be relevant for both of our Permian assets going forward. With three rigs drilling on multi-well pods during much of the fourth quarter at County Line, we saw a pause in the cadence of well completions which resulted in an increase in the number of drilled but uncompleted or DUC wells in the Permian at year end, to 13 to be exact.

Towards the end of the fourth quarter, two of the rigs moved from County Line to Mustang Springs, thus daylighting the 13 DUCs that we have now begun completing in early 2017. You can see the location of those drilled and uncompleted wells on slide 8.

In early January of this year, we added a fourth rig to the Permian Basin, and we should have a fifth rig operating in the basin before the end of the first quarter. We plan to operate five rigs for the remainder of 2017 in the Permian, alternating between three and four rigs at Mustang Springs with the remainder working on County Line which will allow us to optimize completion sequencing on both assets.

Let me spend a few moments looking back at our history of our County Line asset, specifically on the evolution of our knowledge on that property, and how it informs our approach to development of both assets going forward. Recall, we acquired County Line back in February 2014, and since that time, we've drilled 59 horizontal wells in multiple targets in the Leonard, Spraberry and Wolfcamp formations. And we've been collecting a large amount of data on reservoir characteristics, well mechanics, well placement and individual targets, completion design and development sequencing. Analysis of the data that we've collected combined with the results of wells that we've drilled to-date, are driving our strategy for developing our asset going forward.

We focus on answering three primary questions during the additional development phase at County Line. How much oil is in place in each target? What is the performance of a single parent well drilled in each reservoir? And third, and most importantly, what is the correct well spacing geometry and sequencing of well completions that will allow us to maximize the economic recovery of oil in place?

The calculation of oil in place is critical, because it really sets the size of the price and ultimately constrains our predictions around individual well recoveries, or ultimate estimated recoveries and well spacing, or density within each of our target reservoir intervals. We answer the question about oil in place by conducting detailed core analysis and then tying that core analysis to log data from vertical well control we have across the basin and across our specific assets.

So, the other thing we do is we drill parent wells. Without single or parent well controls, it's impossible to discern the degree of well-to-well interference at different well spacings and geometries. And wherever possible, we like to drill a single standalone parent well in each target ends of interval in order to establish baseline performance.

We do have some challenges with parent wells as you can imagine. First, we continued to evolve our completion design over time, which has obviously impacted positively the performance of the wells that we're drilling. And second, we have relatively short period of time of performance of some of these parent wells, which obviously impacts our ability to forecast estimated ultimate recovery. But these wells are still important as a reference or baseline for us to examine as we go forward with full field development on both County Line and Mustang Springs.

So, once we have an in-place estimate for oil and a parent well grid to help establish the baseline, we can then tackle the ultimate question, which is, what is the appropriate well density and geometry in each target interval that will maximize the economic recovery of oil in place? The only way to answer that is to fully develop a block of rock at a given density, which is basically the spacing between the wellbores and geometry, for example a wine-rack pattern, and then observe the performance of those wells over time.

At County Line, we've been doing this in various benches in the Spraberry Shale and Middle Spraberry. And as a result in the pullback in prices, we've been able to do so with a single rig which has allowed us more time to make observations and optimize both our completion design and the spacing and geometry of our wells.

So, what do we learn from our work at County Line and elsewhere across our asset portfolio? First, oil in place is probably not the gating factor on high-density development of QEP's Midland Basin assets. From our work there, it appears to be more than sufficient oil warehouse in each of our main targets to support the base case in upside well density assumptions that we have made without violating fundamentals rules of thumb around recovery factors or the percentage of recovery of oil in place in low permeability unconventional reservoirs.

Second, recognizing vertical barriers to frac growth matters, because it informs the wellbore placement within each of our target horizons. The rock work that we do from core, in particular, rock mechanics work and in the integration of that work with open hole logs helps us with this, as does the collection of microseismic data that we collect simultaneously with frac jobs that we didn't analyze to evaluate frac height and frac width.

Third, completion design matters, especially as more complex fracture networks increase the probability of maximizing stimulated rock volume and ultimate recovery of the oil in place around each wellbore.

And then finally, we're convinced that the timing of well completions matter, adding new wells to infill and existing density patterns presents challenges, including mechanical interference with offset wells, or what we call frac bashing, which can result in us having to clean fracs then out of the existing wellbore. Sometimes we see existing wellbores completely water out when they are hit by new well frac fluid which can require sometimes up to a month to clean up and get back on to the original well performance.

And in some instances, we've observed suppressed early time flow back and production performance of new wells that we drilled in an infill pattern as a result of reduced reservoir pressure that's been caused by production from the older offset wells. We also suspect that the pressure sinks caused by production from existing wells can reduce fracture complexity, and thus stimulated volume of rock in the infill wells. We've observed some of these negative impacts in the two Spraberry Shale with infill wells return to sales during the fourth quarter.

Taking these observations into account, our current conclusion is that drilling and completing blocks of rock at the ultimate density is the right approach to developing stacked unconventional reservoirs. Simultaneously, completing families of wells and virgin blocks of rock before any production begins minimizes well-to-well mechanical interference issues between lateral and vertical offset wells. It maximizes the fracture complexity and well stimulation effectiveness. It eliminates potential negative impacts from uneven reservoir pressure created by existing production. And really importantly, it drastically reduces offset well shut-ins if you try to come back in an infill an existing pattern. This is the approach that we will take to developing the remainder of County Line and will also drive our development of Mustang Springs.

So, turning to Mustang Springs, at year end, we had two rigs working on the asset. Both of these rigs were initially drilling the parent wells in each of the four initially identified target intervals on the asset, the Middle Spraberry, the Spraberry Shale, the Wolfcamp A and Wolfcamp B horizons. As I described earlier, we'll use the performance of these four parent wells to establish baseline production data in each of our targeted reservoirs against which we can then compare the performance of wells that we'll be drilling in our density pilot.

You can see the location of the parent wells at Mustang Springs on slide 10. Once we finish these four pilot wells, or parent wells, and move the rigs immediately to the first density pilot at Mustang Springs, which we'll use to investigate a continuum of well densities on a mile-wide spacing unit across the four primary target horizons. You can see the location of this pilot on slide 25.

Within this spacing unit, we will have two sub-pilots with different well densities. On the East Half of the 1-mile DSU, we will drill a higher well density pilot in the Wolfcamp in the A and B intervals with wells spaced approximately 750 feet apart, and our lower well density pilot in the overlying Middle Spraberry and Spraberry Shale intervals where we will drill a wine-rack pattern in two benches in each interval with wells spaced 1,750 feet apart and 1,250 feet apart respectively. On the West Half of the unit, we'll flip the pattern with lower density well spacing in the Wolfcamp A and B and higher density spacing in the Spraberry Shale and Middle Spraberry. You can see slide 26 for details.

We will sequence the well completions to avoid mechanical interference, bringing on each of the four families of wells in the order that's shown on slide 27. We should see production from the first family of six wells towards the end of the second quarter, and the final family of eight wells will be coming online in the fourth quarter of this year. When complete, we believe this density pilot will be one of the most extensive of any drill to-date in the Permian Basin.

As we finish drilling the density initial pilots, the rigs will move on to the next spacing unit and we'll continue drilling and completion activity of rolling forward and alternating between three and four rigs on Mustang Springs with the remaining rigs working on County Line for a total of five rigs working in the Permian in 2017. And as we observe the performance of the initial pilots, we can make midcourse corrections on well spacing and geometry as we push the development front forward.

As you can surmise, during the completion schedule that we show on slide 27, production volumes from Mustang Springs will be back-half loaded in 2017, but we will be well-positioned for growth in 2018 and beyond. In fact, assuming for current forward curve commodity prices, we expect 2018 oil production from our Permian assets to grow 60% to 80% over the midpoint of our forecasted 2017 volumes. We currently plan to invest approximately 60% of our forecasted 2017 drilling and completion budget in the Permian basin.

We'll also build our own infill infrastructure at Mustang Springs. We'll build oil and gas gathering lines, centralized oil storage and measurement facilities, and centralized gas dehydration and compression. For crude oil, we plan to interconnect with pipes that will provide access to multiple downstream markets and buyers. And for gas, we're building interconnection with at least two regional gas gathering systems with several gas processing plants that will provide access to multiple markets for both the residue gas and NGL.

We're also building our own system for sourcing, handling, storing, processing, recycling and ultimately disposing of water associated with our operations. We estimate that over the life of the field, we should be able to stay between 25% and 50% of the cost of third-party provided infill systems. Nevertheless, we're setting these systems up both physically and commercially contractually, such that they can easily be monetized should we decide to do so in the future. This year, we plan to invest between $50 million and $60 million on infill infrastructure, mostly in the Permian. And as Richard noted earlier, this capital is shown separately in yesterday's release.

So now, let me give you a quick update on our Central Basin Platform, Woodford Oil Project. As a reminder, we drilled our initial horizontal wells to test a new play concept outside of the footprint over our County Line and Mustang Springs/Midland Basin assets. And that well was completed and turned to sales in the first quarter of last year.

After initially flowing back at total fluid rates of about 3,000 barrels a day and a peak rate of almost 550 barrels a day of oil, the production from the well declined dramatically. And even on pump, the well performance seemed weak and didn't match our expectations that were based on the rock properties we measured in the core that we cut in the reservoir and on the wireline logs that we observed porosity and permeability on.

When we pulled the pump, we found a hard and soluble precipitant coating the inlet and coating the pump body itself. And our analysis from that material indicated that we may have damaged the initial well with completion fluids that caused precipitation of insoluble minerals in the wellbore and potentially in the rock itself and the Woodford formation target itself, thereby limiting flow from the reservoir into the well and ultimately production rates.

After we finished our data analysis on the first well, we determined the only way to definitively test our hypothesis about this precipitate material is to drill and complete a new well using a different water source for the completion fluids. We'll likely get the well drilled in the first quarter, but won't likely have any definitive test results until mid-year.

Now, turning elsewhere to our portfolio, we continue to run one rig in the Williston Basin, and that rig will be drilling infill wells at South Antelope and will also be drilling on Fort Berthold. While one rig will likely keep production flat from the Williston Basin, it will allow for more efficient high-density development on our South Antelope asset as it reduces the magnitude of offset well shut-ins for drilling and completion activities.

As we announced in November, we successfully resolved our midstream dispute on South Antelope. We're pleased by the outcome of the resolution, which provides us with increased capacity and a longer term contract for the purchase of our gas in the field. Importantly, as we continue to optimize performance of our Williston assets, and as a result of the reduced drilling and completion activity, we expect that the current forward prices of these assets will generate significant free cash flow in 2017 of over $300 million and will play a significant role in funding the outspend in the Permian that will drive QEP's long-term growth. We plan to invest about 20% of our drilling and completion budget in the Williston in 2017.

We also plan to run one rig at Pinedale, where we will invest less than 5% of our drilling and completion capital. Our 2017 drilling and completion activity at Pinedale was concentrated along the crest of the structure, and it's in an area known as participating Area C where QEP has a significantly lower working interest of 21%. Pinedale will also be a significant contributor of free cash flow in 2017, delivering over $100 million at current commodity prices.

Finally, we plan to continue our successful Haynesville Shale workover program or refrac program in 2017 with plans to refrac over 20 wells before year end, and the completion cadence should be about two wells per month. We'll keep our frac crew busy continuously in that asset. The Haynesville program will attract a little more than 15% of our 2017 capital.

In summary, we remain focused on maximizing the economic recovery of oil from our premiere assets through the optimization of individual well completion design, well work placement in spatial geometry and operational efficiency. While our drilling, completion and reservoir teams are focused on the sub-service, our facilities teams will be focused on engineering design and construction of the infill infrastructure Mustang Springs will allow us to maximize efficient operations and provide optimal market access for our productions.

As we shift our focus to development of our core Permian Basin assets, we're well-positioned to drive long-term oil production growth in the second half of 2017 into 2018 and beyond. As Richard noted, while our 2017 guidance at the midpoint anticipates 6% year-over-year crude oil production growth compared to last year, as we stand up additional rigs and restart the growth engine, we will accelerate crude oil volume growth into 2018, when we anticipate 15% to 20% growth in crude oil production volumes compared to the midpoint of our forecasted 2017 volumes. We anticipate this growth will be driven by the Permian where volumes should be up approximately 70% this year, and 60% to 80% next year as we ramp up completion cadence at both Mustang Springs and at County Line.

With that, Jessica, we can open the line for questions.

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen, at this time, we will be conducting a question-and-answer session. Our first question is coming from the line of Josh Silverstein with Deutsche Bank. Please proceed with your question.

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Thanks. Good morning, guys. Just trying to get a little bit more information on the development strategy in the Permian. A lot of wells, over 150, you guys are expecting to bring online between the second half this year and into 2018. What's the split between the Mustang and the County Line asset? Just trying to get a sense as if you do a chunk at one area then move to the other area, just to maximize the facility build-out as you were talking about?

Charles B. Stanley - QEP Resources, Inc.

It's roughly 50-50, Josh. I don't have the exact count. But if you think about it, in order to optimize both drilling and completion cadence, we will treat the Mustang Springs and County Line assets as one asset. That's one of the beauties as we said when we announced the acquisition there, roughly 10 miles apart. So, our ability to move rigs and completion crews back and forth across the 10-mile distance is one of the beauties of the asset, and will allow us to optimize both drilling and completions and minimize offset well shut-in time.

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Got it. That's helpful. And then, as you guys are ramping up through next year, how does the oil mix shift change with some of the portfolio changes? Obviously, the Permian starts to ramp-up, the Bakken comes down, the Haynesville comes up a little bit, but does the mix shifts change much from where we are in 2017?

Charles B. Stanley - QEP Resources, Inc.

So, we'll see absolute growth in equivalent production volumes. But the mixture will remain roughly the same.

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Got you. That's helpful. And if I could just throw one last one in. I know the Bakken is going to be a little de-emphasized now with the Permian much more the focus. What gets you guys to add some activities there? Is it mostly commodity price or is there something else that you guys want to see before going towards the second rig?

Charles B. Stanley - QEP Resources, Inc.

It's import – commodity prices. As I mentioned in my prepared remarks, Josh, as we infill South Antelope, one of the things to keep in mind is that we have shut-in offset wells for both drilling and completion activity. So, if we piled a bunch of rigs in South Antelope in 2017, it would actually have a negative impact on current production, but it would drive longer term production growth because of having to shut wells in for drilling and completion activity. On the Fort Berthold reservation, we could add a rig and not negatively impact current production volumes. However, the well cost are higher there and returns are not as attractive as adding potentially a sixth rig in the Permian Basin.

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Great. Thanks, guys.

Charles B. Stanley - QEP Resources, Inc.

Thanks.

Operator

Thank you. Our next question is coming from the line of Gabe Daoud with JPMorgan. Please proceed with your question.

Gabriel J. Daoud - JPMorgan Securities LLC

Hey. Good morning, guys. If we can maybe just go back to the Permian, maybe just walk us through a little bit more the completion cadence this year. Obviously, the press release says 30 to 40 wells in the third and fourth quarter. Full year, you're completing 75 to 80. Just trying to think about the trajectory throughout the year. I mean, I'm assuming obviously a big ramp in the second half, but volumes should grow a bit sequentially in the first half. Is that right? Is that the right way to think about it?

Charles B. Stanley - QEP Resources, Inc.

Well, just to remind you at the beginning of – in January 1, we had 13 DUCs waiting on completion at County Line. We have drilled the four parent wells at Mustang Springs. We're in the process of completing those. The rigs are already over on the pilot. And as I mentioned in my prepared remarks, we had a fourth rig show up early this year, a fifth rig will be here before the end of the quarter, or near the end of the quarter.

And those rigs will then sit on – if you think about at Mustang Springs, those rigs are going to sit drilling wells on pods, and we're not going to daylight any of those wells until basically near the end of the second quarter. I'd refer you to slide 27 (sic) Gabe, so you can see the sequence of completions at Mustang Springs. We'll continue to bring on wells obviously at County Line. But again, there we're going to be sitting on pads drilling pods of four to six wells between each of those rigs. So, there will be lumpiness in the volume forecast coming out of the Permian.

Gabriel J. Daoud - JPMorgan Securities LLC

Got you. Okay. And then, so 2018, growth 15% to 20%. Does that assume – like what kind of rig activity does that assume from 2017? Is there another rig addition in the Permian to get there or the...

Charles B. Stanley - QEP Resources, Inc.

So Gabe, we add one rig in the Permian on the oil side, and we keep the same rig count in the Williston in 2018. So, it really just adds an additional rig in the Permian on the oil side. And then potentially we pick up a rig, and obviously, we continue to look at the gas futures market and debate adding a rig in the Haynesville versus continuing the refrac program, and that's an ongoing discussion with our board about allocating additional capital there.

Gabriel J. Daoud - JPMorgan Securities LLC

Got you. That's helpful. I'll just sneak in, I guess, one more on the Permian kind of two part, I guess, Mustang Springs and even County Line. Can you just remind us how much of the acreage is amenable to 2-mile laterals at this point? And then, also if you could just remind me, County Line has gone from, I think, 27,000 acres net from the second quarter to about 20,000 acres net today. If you could just remind us what happened there?

Richard J. Doleshek - QEP Resources, Inc.

Yeah, Gabe, it's Richard. On the County Line acreage, the 27,000 acres was the total amount that we acquired in 2014 from EnerVest. And so, it was roughly 20,000 acres, 21,000 acres on that County Line block, and 5,000 acres or 6,000 acres down in Crockett County, and we just made it clear what the County Line block was versus the total acquisition. So, that's the difference from the 27,000 acres to 20,000 acres.

Charles B. Stanley - QEP Resources, Inc.

And with respect to 7,500-foot versus 10,000-foot laterals, it's in flux Gabe because if you compare the outline of our Country Line block now to what it looked like several years ago, we have done a number of trades in order to allow us to continue to lock-up the acreage and drill longer laterals. We're doing the same thing in Mustang Springs; if you noticed in the subsequent event section in our 10-K, we closed on a number of acquisitions and we're continuing to work on a number of acquisitions to allow us to maximize the number of 10,000-foot laterals that we can drill. And I'll give more color on that as we get those acquisitions closed.

Richard J. Doleshek - QEP Resources, Inc.

The initial picture we had in our model from last year Gabe, was that of the 16 DSUs, they were roughly equally split between 5,000, 7,500 and 10,000 feet. I don't think we have many 5,000-foot DSUs in the current plan.

Charles B. Stanley - QEP Resources, Inc.

Right. The 5,000's have gone away, and the 7,500 and 10,000 is probably roughly 50-50. And we'll see how successful we are in acquiring additional leases around the perimeter.

Gabriel J. Daoud - JPMorgan Securities LLC

Got you. Thanks so much, guys. I'll hop back in.

Operator

Thank you. The next question is coming from the line of David Tameron with Wells Fargo. Please proceed with your question.

David R. Tameron - Wells Fargo Securities LLC

Hi, morning. Chuck, getting back to the Bakken, you talked about the reservoir pressure in the press release which as you know all – mostly it's kind of a nasty word for a lack of better description. But can you just talk about exactly what's going on out there? And I know you've talked about being able to put more rigs back out there, or the lack thereof. But can you just talk about what exactly is going on in the field from your (37:30)?

Charles B. Stanley - QEP Resources, Inc.

So, at South Antelope, David, as you know, we put up some of the highest IP wells in the basin, and it was because if you just rewind the clock back to the acquisition of South Antelope, we talked about that it was in the sweet spot, it was overpressured, it had good oil – high oil saturations in both the Three Forks and in the Bakken, slightly gassier, which obviously is dissolved in the oil and gives abnormally high reservoir pressure. And as a result, given the depth of the reservoirs and given the pressure, the initial wells that we drilled out there free flowed for three to six months, in some instances, even longer. And free-flowing wells have no meaningful mechanical restriction on the rate at which they can produce.

So, they were able to basically produce unconstrained, keeping in mind that there is a physical restriction in the diameter of the pipe in the hole. But 3,000, 3,500, 4,000 barrel a day total fluid volumes were not unusual. And obviously, as we've infilled and developed the field, we have drawn-down the reservoir pressure. It hasn't changed the oil and play's number. It has drawn-down the reservoir pressure that we see when we drill an infill well. And so now, unlike the initial wells that we drilled out there, we're having to put pumps in these wells to move the fluid going forward, and those pumps have physical restrictions on how much fluid they can move. So, the second round of wells are going to have a lower IP and a flatter decline, because they're not going to have that initial headline-grabbing IP, but they will come on and produce steadier at a lower rate for longer. So, that is in part what's going on.

And as I mentioned in my prepared remarks, we have to shut-in a lot of producing wells as we come back in to infill the existing pattern, in part, because we got pumping units on these wells. We have to move to pumping units out of the way, bring in a rig, drill our infill wells, and then complete them, and then we can put the original wells back on production along with the new wells. So, it does negatively impact the production from the existing family of wells. And as I said, that's a lesson that we take with us very thoughtfully into our development of Mustang Springs, because we want to minimize the shut-in time of existing wells going forward. So, picking the right spacing, drilling the wells at the optimal pattern initially, the initial development of the field, and not having to come back in and try to infill in and around existing the production is our goal going forward.

David R. Tameron - Wells Fargo Securities LLC

Okay. That's helpful color. And back to the Permian, obviously, you guys choose the right way to develop it, longer term. How confident are you, or I guess, how much anticipation, or how much can you forecast what – I guess I'm trying to figure out if six months down the road, come mid-year, you start looking at this and going well, this didn't work, this didn't work, so we're going to change it, the way we're developing it. I mean, what are you looking for? What are the big guide posts over the next three to six months, and how should we think about – are you 75% which is set on this development schedule, or how should we think about that?

Charles B. Stanley - QEP Resources, Inc.

With what we know, which is based largely on the wells that have been drilled around us by other operators. And of course, don't forget we have 90 vertical wells drilled through the target intervals on our property, and our experience that we can basically import the Mustang Springs from County Line, we feel pretty confident in what we forecasted for well performance, and we obviously have a lot of experience drilling on pads, working on multiple wells simultaneously that we've developed over the years starting at Pinedale and coming forward to these assets.

So, operationally, I'm not concerned. Based on reservoir performance across the basin and looking at the results that offset operators are putting up, I feel very good in the forecast that we've laid out, and all we can do is wait and watch at this point. But based on the oil in place in Mustang Springs, based on the rock quality that we've observed from the vertical wells, and from our knowledge at County Line, we feel very comfortable.

David R. Tameron - Wells Fargo Securities LLC

Okay. I struggled to ask the questions, but I appreciate the succinct answer. Thanks.

Operator

Thank you. Our next question is coming from the line of Brian Corales with Howard Weil. Please proceed with your question.

Brian Michael Corales - Howard Weil

Good morning, guys. I just want to hit on the CapEx numbers. They look a little high compared to, I guess, what I was trying to give my estimate, how much inflation are you all baking in on your CapEx?

Charles B. Stanley - QEP Resources, Inc.

So, Brian, we have assumed that we're going to see some cost increases from service providers, and I don't want to give them a roadmap so that they show up about an hour from now with their proposed increases. But, we think that we can mitigate a large part of the cost increases that we anticipate through continued efficiency, especially, when you look at the program that we've laid out in our guidance of spending our time manufacturing holes from pads, not moving around a lot, utilizing frac crews very efficiently, because they're going to basically be able to work on multiple wells, zipper-fracking wells simultaneously. So, ultimately, if we see a single-digit overall cost inflation in completed well cost over the year, that's what we've assumed. And I think some folks are assuming that, but aren't showing that in their current well cost.

Brian Michael Corales - Howard Weil

Okay. And then kind of on the same line of thinking, as you go in the Permian kind of bigger wells, more pad development, can you talk about what do you think what the savings you could have on a per-well basis?

Charles B. Stanley - QEP Resources, Inc.

Well, it's hard to estimate and tell we're up and running. But based on our experience elsewhere, we see opportunities to continually improve both just drilling times and getting wells to TD, minimizing the well-to-well rig move times, because we're just going to be skidding. And ultimately, with frac crews working on multiple wells simultaneously with owning and operating our own water handling systems, we would anticipate – if you look at the history of Pinedale, the ability to continue to drive down costs and think about Pinedale over the course of five years, we drove our well costs down by almost 50% in an inflationary environment. So, we have a team of people that I have confidence can continue to deliver cost savings and cost reductions just based on efficiencies. We're in the early stages. We just put two rigs to work, drilling our first pods of high-density wells. And as we gear up and move in frac crews to work on completing those wells, we'll start to see the performance.

Brian Michael Corales - Howard Weil

Okay. And one more if I could. Just, have you all seen M&A prices in the Permian kind of flatten? Are they continuing to be strong? Can you maybe just comment something there?

Charles B. Stanley - QEP Resources, Inc.

It's still, obviously, the place that has garnered the most attention of acquirers, and obviously, there are number of sellers, it does feel like that the $1 per acre values, implied values for acquisitions has flattened some toward the end of last year. But time will tell. I think part of it is going to be driven by what you think around oil and gas prices going forward.

Brian Michael Corales - Howard Weil

All right, guys. Thank you.

Charles B. Stanley - QEP Resources, Inc.

Thanks, Brian.

Operator

Thank you. And the next question is coming from the line of Neal Dingmann with SunTrust. Please proceed with your questions.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good morning, guys. Just another question you had on the County Line. I know you guys continue to do a lot of test in there both on the infill and the downspacing. Chuck, I think this was asked, but just wondering, what do you guys perceive of the long-term implications there if – I'm looking specifically at that slide 8 and 9 where you really lay out, and wondering what this could mean if it's successful as some think of it as I think.

Charles B. Stanley - QEP Resources, Inc.

So, obviously, our current evaluation on County Line has focused on getting the ultimate spacing, and we started with an assumption of only drilling eight wells. And for instance, the Spraberry Shale, we currently have pilots that are in the ground and they're being completed that will inform us on up to 16 wells in just the Spraberry Shale interval. We have a similar pilot evaluating up to nine wells in the Middle Spraberry. And obviously, we have not turned our attention to the deeper Wolfcamp intervals with any modern completion technology and with our knowledge around geosteering and recognition of frac baffles and barriers that we've developed while we've been working on Spraberry. So, ultimately, I think it drives inventory higher as we move from a potential of 34 development locations per mile-wide spacing unit to over 50, if we're successful in proving up additional horizons in the Wolfcamp, and in the Leonard, and on driving ultimate density higher within the target intervals.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

What you all said right now, given the current pricing environment on hedging, thinking about adding or just any comments you could add on hedging right now?

Richard J. Doleshek - QEP Resources, Inc.

Yeah. Neal, it's Richard. Our target is typically to be covered 50% by derivatives by the end of the first quarter of the production year. If you look at our table, we're well north of that. We're approaching 70% on gas this year and north of 50% on the oil side and we've begun to layer in 2018. I think we'll be targeting our 50% level by mid-year this year for 2018. So, I'd say, we're a little more cautious than "normal," less concerned than last year, which is where we put the foundation of the derivatives in for this year. But, we'll be targeting that 50% level by the midpoint of this year for 2018.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Great.

Charles B. Stanley - QEP Resources, Inc.

And there's adequate headroom at the well level for well level returns, even burdening newly drilled wells with allocated share of acquisitions cost to support locking in a portion of our cash flows with derivatives and still generating acceptable returns.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Great point, Chuck. Thanks, guys.

Operator

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

John Nelson - Goldman Sachs & Co.

Good morning and thank you for taking my questions. I was hoping to get a little bit better color, understanding on your 2018 guidance, and what I'm having a hard time reconciling is how both total and oil volume guidance are equivalent, when I think you talked about 80% of your capital dollars going to the more oily plays in the Permian and the Bakken. Could you just help me kind of understand why those two are equivalent?

Charles B. Stanley - QEP Resources, Inc.

You're talking about the commodity mix in part, John, that's being driven by the assumption of picking up a rig next year in the Haynesville. And as you'll recall from the history in the Haynesville, it responds marvelously to capital investment. So, with the continued refrac program and picking up a rig, we drive gas volumes in the Haynesville. And, of course, we continue to see associated gas volumes increase at Mustang Springs and County Line in particular, as we pick up a sixth rig in the Permian.

John Nelson - Goldman Sachs & Co.

Okay. So, it's just capital efficiency of the kind of those Haynesville dollars that...

Charles B. Stanley - QEP Resources, Inc.

Yeah, I mean, the...

John Nelson - Goldman Sachs & Co.

...help keep this to equivalent.

Charles B. Stanley - QEP Resources, Inc.

As you can imagine, if you're drilling 7,500 and 10,000 foot laterals at IPs north of 20-million-cubic feet a day on 100% working interest acreage, you drive gas volumes up substantially. And as I mentioned in a previous answer to a question, we continue to dialogue internally and with our board about capital allocations at Haynesville as we watch the gas markets.

John Nelson - Goldman Sachs & Co.

That's really helpful. And, I guess, as my second question, I'm just trying to think about the cushions that may be built into guidance are what could potentially drive upside over the year. As I listen to kind of the program you lay out in the Permian, you've got bigger pads, and I think about 25% of your wells testing fairly tight spacing. So, I would imagine kind of risking on timing of when those pads come on, and also haircuts for kind of the downspacing impact could be meaningful. Could you just speak to kind of how you thought about risking each of those relative to your usual kind of guidance construction?

Charles B. Stanley - QEP Resources, Inc.

Yeah, I think the timing is pretty well laid out. I mean, if you look at the Gantt chart that we show for Mustang Springs, our sequencing of when those pods come on, could they get on slightly earlier if we get the wells drilled quicker? Yes.

But our biggest unknown, and you've nailed the two variables, one of them is just when the wells come on. And then second, do we see mechanical interference if we draw up a block of rock? Are we going to see suppressed IPs at higher well densities or not? And my guess, my gut says, we're not. But our guidance is predicated on there being some mechanical interference and lower IPs as a result of the increased density. And so, you're right, that could be potential upside to the volumes.

Keep in mind, however, there's a bunch of wells coming on toward the end of the year. So, even if they do come on at higher rates, the impact of that higher production volume is going to be suppressed, because you're only looking at a half to a quarter of the year of total production volume. So, on the exit rate, it could be meaningful, but maybe not so much on the cumulative production over the year.

John Nelson - Goldman Sachs & Co.

Okay. And how much of that's risk relative to how you think about a non-higher density well?

Charles B. Stanley - QEP Resources, Inc.

It varies by horizon and by spacing in that pilot, but some of the wells are getting haircut by 20% to 25% off of a type curve – off of a parent well type curve, just to be conservative at this point, because we don't know.

John Nelson - Goldman Sachs & Co.

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

Operator

Thank you. Our last question is coming from the line of Gail Nicholson with KLR Group. Please proceed with your question.

Gail Nicholson - KLR Group LLC

Good morning. Just in regards to the current fracture stimulation design evolution. You're using higher proppant loading in the Wolfcamp versus the Spraberry, and what's kind of the cost difference between the higher proppant loading and higher barrels of fluid per lateral foot? And then what kind of the drive of the reasoning for that?

Charles B. Stanley - QEP Resources, Inc.

So, first, we continue to watch our own well performance and we've also – we're good students. We're good at copying the success of others. And so, we've been watching the evolution of both proppant loading and total fluid count. And Gail, with respect to proppant loading, the cost is proportional, so you can just take 1,400 pounds per foot, 1,800 pounds and look at that as proportional increase in proppant cost. The slightly longer pump times with not materially longer pump times for stimulating the wells. And fluid, we're using a pretty benign fluid, so fluid cost is not a big driver.

What we are continuing to work on – and I think proppant loading is part of the equation, but in order to maximize fracture complexity, or how efficiently we break up the rock to connect it to the wellbore, the thing that also seems to be a big driver is stage spacing or cluster, and within each stage cluster spacing, which we think combined with additional proppant can be a big driver.

We're basing our proppant loading estimates on offset well performance and also on the core work that we've done to help us optimize. And obviously, there will be a point at which there will be diminishing returns and we may back off, but it's an evolutionary approach that we've taken at County Line, and you can see that on slide 24 as we push higher loading and tighter interval or stage spacing, and therefore cluster space.

Gail Nicholson - KLR Group LLC

So, from a standpoint of the projected recoveries, are you assuming that there's an uplift for the evolution design, or is that still kind of a question mark based upon well performance this year?

Charles B. Stanley - QEP Resources, Inc.

Based on our observation from other areas, and from County Line, we think that we will see enhanced recoveries with these more efficient stimulations. And the reasoning is that we are contacting more of the rock and connecting that rock to the wellbore and therefore draining more of the oil in place. So, we'll potentially have a much more efficiently stimulated rock volume that will allow for enhanced drainage of the oil in place, and therefore, a higher recovery factor.

Gail Nicholson - KLR Group LLC

Okay. Great. Thank you.

Charles B. Stanley - QEP Resources, Inc.

Thank you.

Operator

Thank you. We have reached the end of our question-and-answer session. So, I'd like to pass the floor back over to management for any additional concluding comments.

Charles B. Stanley - QEP Resources, Inc.

Thank you all for calling in this morning. We appreciate your interest in QEP, and we look forward to seeing you at a number of conferences that will be coming up over the next few weeks. Have a good day.

Operator

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

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