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QEP Resources (NYSE:QEP)

Q2 2014 Earnings Call

August 07, 2014 9:00 am ET

Executives

Greg Bensen - Director of Investor Relations

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

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

Analysts

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Brian M. Corales - Howard Weil Incorporated, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

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

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Dan McSpirit - BMO Capital Markets U.S.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Operator

Greetings, and welcome to the QEP Resources Second Quarter Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Greg Bensen, Director of Investor Relations. Thank you, sir. You may begin.

Greg Bensen

Thank you, Latonya. And good morning, everyone. Thank you for joining us for the QEP Resources Second Quarter 2014 Results Conference Call. With me today are Chuck Stanley, Chairman, President and Chief Executive Officer; Richard Doleshek, Executive Vice President and Chief Financial Officer; Jim Torgerson, Executive Vice President and Head of our E&P Business; and Perry Richards, Senior Vice President and Head of our Midstream business. If you have 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 and the slide presentation with maps and other supporting materials.

In today's conference call, we will use a non-GAAP measure, EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings and is reconciled net income in 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. And we refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks, facing our business and our earnings release and SEC filings. With that, I'd like turn the call over to Chuck.

Charles B. Stanley

Thanks, Greg. And good morning, everyone. I'd like to begin with a quick review of our progress on some key strategic initiatives, then I'll briefly touch on some operational results for the quarter and then finish with our plans for the remainder of 2014. I will then turn it over to Richard who will review our second quarter financial results, as well as our 2014 guidance assumptions before we move on to Q&A.

Over the past several years, we've been successful in executing on our strategy to transition QEP into a more balanced and focused portfolio of E&P assets, with an emphasis on growing higher margin crude oil and liquids-rich gas production while divesting of non-core assets to better focus our human and financial capital. In the second quarter of 2014, we made great progress on our strategy.

Let me touch on a few highlights of the quarter. First, we posted record EBITDA. Our record EBITDA was driven by record quarterly production which included a 67% increase in higher-margin crude oil volumes from last year.

Second, we continue to make operational progress in the crude oil basins, the Williston and Permian, with daily production increases of 15% and 16%, respectively, over the first quarter of this year.

We continue our technical innovation in the Uinta Basin and we're now unveiling an exciting new horizontal development approach for the lower Mesaverde play there. We also improved our balance sheet and operational focus through upstream asset sales in the sale of a 40% interest in Green River Processing to our affiliate, QEPM, which closed on July 1. And we also made substantial progress on the separation of QEP Field Services from QEP Resources.

Let me elaborate a bit on that last point. In December of last year, we announced plans to unlock additional value for our shareholders by fully separating our midstream business, QEP Field Services, including its ownership in QEP Midstream Partners from QEP Resources. When complete, we believe the separation will better position both our E&P and our midstream businesses to compete and thrive in their respective business environments. We're pursuing multiple avenues to achieve the midstream separation, ranging from the outright sale of the business to a straight spinoff of the business to QEP shareholders. To prepare for the possibility of a straight spin for various spin-merge transaction structures, we follow the Form 10 with the SEC in the second quarter as promised.

Last quarter, we also told you that we had finalized the confidential information or CIM that contains asset level operational, commercial and financial operation for QEP Field Services. The confidential information memorandum was distributed to interested party shortly after our first quarter call. We received very strong indicative offers and we are currently in the second and final round of that process and expect to receive final binding offers in the next few weeks -- offers in the next few weeks. The range of proposed, potential transactions includes various merger of combination structures, offers to purchase QEP Field Services for cash and several other alternative transaction structures.

So what are the next steps in the separation process? After receiving the final offers in the second round, we'll either choose to pursue one of the proposals and then proceed to the negotiation and execution of a definitive transaction agreement or we'll decide to proceed down the path of a straight spinoff of Field Services. Our ultimate objective is maximization of shareholder value and the continuation of profitable midstream operations as part of a viable, competitive midstream industry. We expect to reach a final decision on the right path forward in the third quarter and we hope to complete the separation before the end of this year. In the meantime, we'll continue to maximize value for both our E&P and midstream businesses.

To this end, on July 1, we closed on the sale of a 40% membership interest in Green River Processing LLC to QEP Midstream Partners for gross proceeds of $230 million. Green River processing owns our Blacks Fork and Emigrant Trail processing assets in Southwestern Wyoming. By selling a membership interest in Green River at a valuation that was well above QEP's EBITDA multiple and below that of QEPM's, this transaction will be accretive to both entities. To further focus our E&P asset portfolio, we closed on the sale of certain non-core E&P properties, primarily in the Midcontinent region for a total proceeds of approximately $702 million before post-closing adjustments.

Combined with the proceeds from the Green River Processing drop-down, these transactions go a long way toward offsetting the $942 million purchase price of our Permian Basin acquisition. As a reminder, we structure the recent purchase of the Permian assets and the recent sales of non-core E&P assets as a reversed 1031 exchange, meaning that we will be able to transfer the tax basis from the divested assets over to the newly acquired Permian assets.

We have additional non-core Midcontinent assets to market that we hope to sell before year end, including our acreage located in the Woodford SCOOP play. Our remaining Midcontinent assets have aggregate net production of approximately 21 million cubic feet of gas equivalent a day. Assuming that the sales are all completed by year end, we will have completely exited the Midcontinent region and the result will be a much more focused upstream portfolio.

Just to give you a feel for this, we're trading 70 -- 2,769 gross wells in the Midcontinent at the end of the year last year 2013 with an average working interest of about 30% for approximately 300 wells in the Permian Basin with a 94% working interest and a much stronger growth profile. I believe the sale of our Midcontinent assets to invest in the Permian was the right strategic decision for us. The second quarter was our first full quarter operating our Permian properties and our team continues to make great progress with the assets. We currently run 7 rigs and we completed 2 horizontal wells and several vertical wells since taking ownership back in February, with very encouraging results. I'll go into more detail in a few minutes on the Permian.

In total, our strategic initiatives, including the Permian acquisition and the sale of non-core E&P properties and a drop-down of our Green River Processing interest to QEPM, have left us with a more focused asset portfolio with higher growth potential and higher operating margins. And we'll have a strong balance sheet to help fund future growth. Clearly, we've made substantial progress, transforming QEP into a more focused and balanced upstream company by optimizing our upstream portfolio and we are well along the path of maximizing shareholder value through the separation of our midstream business.

I'm equally pleased with the ongoing performance of our business this quarter. Our asset managers delivered record EBITDA, record oil production, record oil revenue and record total production, which was up 8% from the prior year on a 6:1 basis and on a 20:1 basis it was up over 31%. As a result of this ongoing performance, you'll note that we've raised our full year 2014 crude oil NGL and total production guidance.

Now let me give you a little more color on our operational results by area in more detail on our plans for the remainder 2014. As I do so, you can refer to the slide presentation which accompanied our release yesterday afternoon. In the Williston Basin, we currently have 7 rigs running down from 1 -- down 1 from last quarter due to improvements in drilling efficiencies. Our spud to TD times continue to come down on average to 18.6 days in the second quarter compared to an average of 26.2 days in 2013. That's nearly a 30% improvement and is consistent with operational improvements that our team has delivered in the past in other areas.

At the end of the second quarter, all 7 rigs in the Williston were working on our South Antelope acreage. Completion activity increased in the Williston Basin in the second quarter this year with 31 gross QEP operated wells completed and turned to sales during the quarter; and that compares to 14 in the first quarter and 26 in the fourth quarter last year. We expect to average 22 to 25 gross QEP operated completions per quarter in the Williston for the remainder of 2014.

We continue to evaluate the potential for increased well density on our acreage. The results of our request pilot test and those of nearby operators are encouraging for potential down spacing and/or infill drilling in the future. In addition, we've recently made a dramatic shift in completion methodology which we think offers additional upside. In the past, we've been placing between 3 and 3.5 million pounds of proppant in a typical long lateral Bakken or Three Forks well. But in recent wells, we have placed approximately GBP 10 million pounds of proppant and we're doing it through bore entry points or more perf clusters.

From the data that we've analyzed, we believe that this increase in estimated -- this will result in an increase in estimated recoverable oil and will generate a return of over 50% at $90 flat crude oil prices. Incremental cost for this completion design vary from $1.3 million to about $2.5 million, and it really depends on our ultimate selection of preparation where we use sliding sleeves or plug in perf. The increase in profit volumes and entry points is obviously putting up with pressure on the well cost. But we expect that we should be able to offset most of this with our increased drilling efficiency. As a result, our 2014 capital budget in the Williston Basin is basically unchanged from last quarter with about $920 million, or roughly half of our 2014 planned capital expenditures.

I'd also note that the larger frac jobs will slow down the pace of well delivery in the second half. So keep that in mind as you digest our production guidance.

You can see Slide 6 through 8 for more details on our Williston Basin operations.

Turning to the Permian, we made great progress in the 5 months after closing on the acquisition at the end of February. Since closing, we've increased drilling activity on our acreage from 2 to 7 rigs with 5 of those rigs drilling vertical wells and 2 drilling horizontal wells. We plan to add a third horizontal rig soon. Remember, we've got some science to do to evaluate the horizontal potential of some of the target intervals and this is accomplished through our vertical well program. Plus, we've collected the data from our vertical wells we plan to shift our emphasis to horizontal development.

Our plan at the time of acquisition was to ramp the 6 rigs by the end of 2014. Clearly, we've made better progress on that schedule than planned, and the team is now focused on accelerating a transition to horizontal development. Production from initial QEP-operated vertical and horizontal wells is tracking performance and is in line with our expectations. We completed 1 horizontal Wolfcamp B well in the second quarter, and it is performing quite well with a maximum average 30-day rate of -- average rate of 637 BOE per day. We've also recently completed a horizontal Wolfcamp D well and this is still cleaning up after stimulation. We plan to continue drilling horizontal wells in the Wolfcamp B and D and we'll also test the Spraberry horizontal later this year. Our vertical development programs are also performing quite well with an average maximum daily rate of 359 BOE for the wells that we've completed in the second quarter.

Overall, we are very pleased with our Permian Basin acquisition. Our ongoing reservoir evaluation work, coupled with reports of strong initial well performance from horizontal wells drilled by nearby operators continue to affirm the quality of the acquired properties. Combining these early results with the substantial progress we've made in offsetting the acquisition cost with non-core E&P asset sales, it's abundantly clear to me that making this acquisition was a right strategic move for QEP.

Excluding the acquisition cost as a result of the faster ramp up and rig count, we now plan to invest about $340 million or about 10% increase from our last quarter estimate in the Permian Basin.

Slides 9 and 10 show you more details on our Permian Basin properties. At Pinedale, production volumes increased 21% compared to the first quarter due to typical seasonal responses, we resume completion activities in the middle of the first quarter, and due to more of our first half 2014 completion activity being concentrated in areas where we, QEP, has a high working interest. It's important to note that even though ethane frac spreads were near breakeven during the quarter, propane margins remained strong and as a result of better propane recoveries and ethane recovery mode and improved NGL price environment led us to recover ethane throughout the quarter.

We've also adjusted our 2014 production guidance to reflect that we'll likely to continue recovering ethane for the full year. For the second quarter, we completed in terms of sales, 35 new wells at Pinedale. And at the end of the second quarter, we have 50 gross Pinedale wells with QEP working interest that were drilled, cased and awaiting completion. And the average work interest in those wells is 70%. We anticipate running 4 rigs at Pinedale throughout the remainder of 2014 and we should complete somewhere between 110 and 115 wells during the year. And of that 110 to 115 wells, are 10 wells in which QEP is the operator, but we have only a small overriding interest. We'll continue to get more -- while we continue to get more efficient at Pinedale, we increased our capital budget by about $40 million from last quarter to $310 million total, due to some additional nonoperating working interest that we picked up from other parties. Slides 11 and 12 show the details of our activities at Pinedale.

In the Uinta Basin, we continue to make good progress on our Red Wash lower Mesaverde liquids rich play. Last quarter, we talked about some early results from a fundamentally different well design that we think could radically alter the economics in the way we approach development of this asset. This new design is a horizontal development approach targeted at specific interval in the lower Mesaverde. We drilled and completed 3 wells so far using this technique and we are nearing completion of our fourth well.

We've learned some very valuable lessons along the way, but our initial results on these wells indicate that a horizontal development approach will improve the economics in the play and allow us to more efficiently unlock the value of this substantial asset. With multiple TCFE of probable reserves and our 100% working interest, 87% in our acreage position, clearly, this project represents not only a significant growth opportunity for QEP Energy but also for our midstream business. We currently plan to invest about $80 million in the Uinta Basin and that's up about $15 million in the last quarter.

Slide 13 and 14 show the details of our Uinta Basin activity and included in there is a type log for the Mesaverde section, identifying the interval that we're currently targeting for horizontal development. I'd also point out that the slide shows other potential horizontal target intervals within the Mesaverde and underlying formations.

Let me turn quickly to the Haynesville. While we don't have any operator rigs running in the Haynesville currently, we have seen a big increase in outside operated well proposals that we expect to generate good returns. So we've elected to participate in those well proposals; and as a result, we've increased our 2014 capital budget for the Haynesville to $80 million. We expect this relatively modest investment will help stem the production decline that we've seen in Haynesville, it will offset it but it will certainly slow down the decline. And then finally, we've allocated about $20 million -- it's barely visible on that bar chart in the slides that we provided to you, but that $20 million to some exploratory drilling this year to test some new play concepts in our portfolio.

Turning to Field Services. EBITDA was down compared to the second quarter of 2013. Rich will give you more detail on the moving pieces in the quarter. But the decline is primarily due to an increase in G&A related to transactions, bad debt expense, the cost of QEP and being a public company, as well as the timing of recognition of certain of our deficiency payments that come in throughout the year and did not -- they came in the first quarter end distort the first quarter results. And we do not have any in the second quarter.

Late in the first quarter, Field Services commenced construction on a new project to add capacity through debottlenecking our Vermillion gas processing plant, which is located in Southwest Wyoming. The debottlenecking project expanded the inlet processing capacity of the Vermillion cryo plant from 43 million cubic feet a day of raw gas or approximately 57 million cubic feet a day. The total capital cost for the project, gross capital cost is about $11.7 million, with a net capital cost of QEP of about $8.3 million. We started off the expanded plan about 1 week ago and it should be operating at full capacity in the next few days. We plan to invest $75 million in Field Services projects in 2014 and that includes our capital investments at QEPM.

I'm very proud of our accomplishments so far in 2014. We've closed on multiple transactions and we've made a substantial amount of progress on our key strategic initiatives, all while delivering solid results from our underlying business and improving our position for future growth. I believe we're well-positioned to continue liquids -- growing liquids volume in 2014 and beyond and while we expect our natural gas production volumes to decline again this year, we believe that continued capital allocation to high return oil projects will lead to strong crude oil production growth and corresponding growth in EBITDA. As we look forward to the end of this year, we expect to emerge as a more focused and balanced E&P company with a deep portfolio of high return investment opportunities capable of delivering superior returns in a variety of market conditions. With substantial footprints in 2 premiere U.S. oil plays and a deep inventory of low-cost liquids rich gas products including our Uinta Basin horizontal program, we're confident that our portfolio can support multiple years of profitable growth.

We're also well along the path of separation of our midstream business from QEP Resources. And we're excited about the value creation opportunity that this separation transaction presents for our shareholders. We look forward to updating you on our continued progress as we reach important additional milestones in the weeks and months ahead. With that, I'll turn the call over to Richard.

Richard J. Doleshek

Thank you, Chuck. And good morning, everyone. With Chuck having discussed our strategic and operational highlights for the second quarter of the year, I'll provide you with some color about our financial results before we go to Q&A.

For the second quarter, we generated record $401 million of adjusted EBITDA. If we include the public's 42% share of QEP Midstream Partners results, we would've reported $408 million of EBITDA. The $401 million of EBITDA generated in the second quarter was $15 million higher than the first quarter of the year and $11 million higher than the second quarter of 2013.

QEP Energy contributed $373 million or 93% of the aggregate second quarter EBITDA and QEP Field Services contributed $29 million or about 7%. QEP Energy's EBITDA was up $41 million from the first quarter of 2014, driven by a 20% increase in oil volumes, a 20% increase in NGL volumes, and 9% increase in natural gas volumes for the first quarter of the year's volumes.

Our fuel level prices were down about $0.17 per Mcfe for the first quarter and our realized losses for our commodity-driven portfolio were about the same as the first quarter. Excluding realized losses on the commodity driven portfolio, QEP Energy's EBITDA was up 11% from the first quarter of 2014 to about $407 million. QEP Energy's second quarter production was 83.9 Bcfe or 10.2 Bcfe higher than the 73.7 Bcfe reported in the first quarter. Oil volumes were 4 million barrels, up 669,000 barrels from the first quarter levels. The Permian Basin properties contributed 418,000 barrels of oil compared to 140,000 barrels in the first quarter.

Oil volumes in the Williston Basin were 2.8 million barrels, up 311,000 barrels and gas volumes were 48.6 BCF, an increase of 4.1 BCF due to the seasonal increase in Pinedale, offset by a 1.3 BCF decline in Haynesville. NGL volumes were 1.9 million barrels, up 318,000 in the quarter.

Our guidance for 2014, effective as of July 1 of the year, which includes adjustments from the Granite Wash and Woodford Cana asset divestitures, we forecast natural gas volumes to be about 165 to 175 BCF, this is a slight decrease from last quarter due to a change in our assumption regarding ethane rejection, i.e. we're going to leave it in the gas stream versus recovering ethane inside the NGL stream.

Our forecast for oil volumes is 14.7 million to 15.2 million barrels, an increase from our previous guidance and about 46% from 2013 at the midpoint. Our guidance for NGL volumes for the year is 6 million to 6.3 million barrels, the midpoint of which is about 28% from 2013, assuming that we remain in ethane recovery for the remainder of the year. In total, we are increasing our equipment production guidance by about 4% from last quarter.

QEP Energy's combined lease operating transportation expenses were $132 million in the quarter, up from $121 million in the second quarter and up from $105 million in the second quarter of 2013. On a per unit basis, lease operating expenses were $0.71 per Mcfe and transportation expense was $0.86 per Mcfe or $1.57 per Mcfe for the 2 items combined. Our guidance for lease operating and transportation expenses for 2014 is unchanged at $1.50 to $1.65 per Mcfe for full year 2014. QEP Field Services second quarter EBITDA was $29 million, which was down $24.2 million from the first quarter. And let me give you some color about that decline.

In the second quarter, there were $1.2 million of deficiency revenues recorded, while in the first quarter there were $10.5 million of deficiency revenues. As you all know, deficiency revenues are lumpy throughout the year. NGL sales were $10.2 million lower in the quarter as a result of lower volumes and lower individual product prices. In addition, as a result of new NGL transportation contract, we made some changes on how we report transportation expense.

Finally, Field Services general and administrative expenses was $4.3 million higher than the first quarter, primarily due to bad debt expense and professional services associated with the asset drop to the MLP. Gathering margin was up slightly in the first quarter as increased volume average daily rate were offset by a decrease in deficiency revenues. Although there was noise in the Field Services reported result this quarter, our outlook for the business is essentially unchanged and we anticipate adjusted EBITDA of approximately $80 million for the second half of 2014, which is consistent with the first half number, including the impact of the EBITDA that was sold to the Green River Processing transaction with the MLP.

Sequential G&A expenses were up $7.6 million, primarily the result of a charged bad debt expense. The noncash impact of change to the mark-to-market value of our equity compensation plans and expenses associated with the replacement of many of our corporate IT systems. I'm happy to report that we did go live with our new enterprise resource playing system or more simply, our accounting system in the second quarter. And we are up and running with significantly fewer hiccups than we expected. The team really did a great job.

So as a result of these and other impacts in the first half of the year, our guidance for G&A expenses for 2014 was increased, especially that we think G&A expense for the full year would be in the range of $225 million to $235 million. We reported net loss attributable to QEP of $90.3 million in the quarter, including $51.1 million of unrealized loss on derivatives and a $201 million loss on asset sales. Excluding the unrealized loss in nonrecurring items, QEP reported adjusted net income of $67.9 million or $0.38 per share as compared to first call consensus mean of $0.33 per share.

Capital expenditures on an accrual basis for E&P during completion activities were $761 million for the first half of the year and capital expenditures in our midstream business were $37.6 million and acquisition expenditures were $949 million. If you exclude acquisitions, our capital spending was in line with our EBITDA in the first half of the year. Excluding acquisitions, we are forecasting the midpoint of 2014 capital spending to be about $1.775 billion for QEP Energy, about $75 million for QEP Field Services and about $15 million for corporate.

With regard to our balance sheet, at the end of the quarter total assets were $10.6 billion and total debt was $3.9 billion, but we have $702 million of cash on the balance sheet. As you recall, we restructured the Permian acquisition and the sales of the various non-core E&P properties in reverse like kind of exchange and the bulk of the asset sales occurred on June 30. It was a complicated transaction to unwind. We weren't able to effect all the steps with the exchange due to the cash in hand and pay down debt on June 30. Hence, the cash in the balance sheet at the end of the quarter. However, on July 1, we took that cash and the $230 million proceeds from the sales of 40% interest of Green River Processing to QEPM, which closed on July 1, and pay down the outstanding balance under our revolving credit facility to $165 million.

So on July 1, our total debt was just under $3 billion, which is about 1.9x multiple of our annualized first half 2014 EBITDA. So we made good progress it just wasn't at the end of the quarter. With that, Latonya, we'd like to open the line for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

First, can you clarify that -- how many completions per quarter we should expect in the back half in the Bakken? I didn't catch that number.

Richard J. Doleshek

I think it's 20 -- 20 to 25. And Tim, as I said in my prepared remarks, with the change in completion design larger proppant volume and potentially moving to plug and perf, we're still not convinced that moving to plug and perf is the right answer. We're doing some studies on sliding sleeves that we believe don't show a material difference between sliding sleeves and plug and perf at least in the area where we're operating. But if we do the play in perf, it will slow us down. Obviously, it just takes longer to stimulate the well and then drill out the plugs. But also keep in mind that the offset wells will have to be shut in longer. So it will have an impact on production volumes. But 25 is probably a good quarterly number to use for Q3 and Q4.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

And then, I know you touched on this a bit in your prepared comments. I understand you have a 6-well pilot that's been producing testing downspacing. We've heard other operators talk about success, especially in the reservation area. What is holding you back from quantifying this information, given that the long-term kind of bare thesis on your limited inventory?

Charles B. Stanley

Well, we want to make sure that we have enough production history on the wells to confirm our reserve forecast and to verify that. But there is going to be some interference, to verify the level of interference that's impacting production volumes. It clearly is going to cut the average EUR on the infills, and the question is how much. So far, the duration of our pilot test, we've seen very minor interference and encouragement. We just like to watch it a while longer before we pound the table. And the real question for infill, for us, will be for example, in South Antelope, can we go from 4 wells per spacing, per reservoir to 8? And that will be a profound answer and one that we can extrapolate from the pilot we have. But we really need to go do it and make sure that the results hold up in a full 8-well per spacing unit test.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Do you think that's information you may be able to quantify by the end of the year?

Charles B. Stanley

We'll certainly have more production history on our pilot. It will give us more comfort. The other thing I'd point out is over in Fort Berthold, we have -- should've increased density spacing in several of our spacing units where we didn't drill parallel wells. You'll recall in the northern part of our Fort Berthold acreage, on the northwestern corner, we have some, what I would call, the hub-and-spoke geometry wells where we drilled out under the lake and because of topographical reasons, we couldn't drill the wells parallel to each other north to south. So we have some wells that are spaced -- at the heels, there's based very close together. And so we do have some production performance information from those wells. And again, I think that the results are encouraging for increased density. The thing that is the next, sort of, I think, step in the evolution -- bless you, Richard. The next step in the evolution of future enhanced production and future upside on our properties in the Williston is not only increased density but also the larger completion side, because we think the empirical evidence is very convincing that these larger completions increment reserves and ultimately, well performance. And in part, I think it's due to getting much more rock volumes stimulated in the near wellbore which we think will enhance recovery and will probably lead to the need for increased density. Looking at some of the offset operators who have recently completed some large stimulated rock volume wells adjacent to us, their strong evidence that marrying the larger fracs with increased density, well spacing, will result in more recovery of oil in plays. And that's the thesis that we're operating under right now.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay, I appreciate that color. And then just to clarify, are 100% of your wells now being completed with this larger completions?

Charles B. Stanley

Yes. 100% are being completed with some variation of the completion designs that I mentioned. Right now, we're using larger -- roughly 10 million pounds of proppant. More entry stages, we're increasing the number of entry stages and cluster spacing and looking for that optimization. There's obviously an optimization around increased cost versus increased recovery. But yes, we're -- everything we're doing now is the larger size.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay, thank you. And then one last one. On the midstream, you seem to be giving more color on the possibility of a sale there. If you do choose a potential partner and go to negotiate, at what point do you think that would be announced to the public? Is it possible we may not hear by the end of the quarter?

Charles B. Stanley

Well, Tim, as I said in our prepared remarks -- my prepared remarks, we have a process underway. We're in the second round. We're expecting final offers within the next several weeks. Depending on the nature of those offers, we should be able to clearly identify a preferred proponent and then it's a matter of negotiating each of the acceptable transaction documents before announcement. I can't imagine it's going to run through the end of September. We're targeting to have news out before the end of the quarter.

Operator

Our next question comes from David Heikkinen with Heikkinen Energy.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Chuck, you've talked in the past about the economic benefits of the integration of the midstream and the E&P business, particularly some of your Rockies assets. As you think about heading forward, how does the separation of the businesses impact your plans on capital spending and things like the acreage additions you had? Because of some non-consensus, it sounds like in the Pinedale, how will that change the economics of the decisions and the overall business plan?

Charles B. Stanley

That's a great question, David. First of all, as you know, we have always run our midstream business as a standalone business. And we put in place, from the beginning, commercial gathering and processing arrangements between our E&P entity, QEP Energy and Field Services that were -- arm's length, they're market based rates that we were charging between Field Services and Energy. And as -- if you've been watching our behavior over the past several years, we have been diligently converting the handful of keep-whole processing arrangements we have where we were shifting the liquids volumes to Field Services under keep-whole processing arrangements. We struck all of those arrangements so that they're all fee-based now. And our liquid revenues and exposure to the commodity is where it should be, which is in the E&P company. So when I think about the impact of a separation, I see very, very little economic change with respect to our investment decision-making and the economics of drilling wells in the Rockies, in areas where Field Service currently -- Field Services currently serves as our gathering processor. Because we ran the economics on places like Pinedale based on E&P company net backs and E&P company returns. If Field Services was processing gas on a keep-whole basis for one of our partners and making additional return on the liquids recovered in that gas stream that was upside for the midstream company but we didn't include it in our economics and in our decision-making process for drilling wells in the E&P business.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

How did you think about the -- that's a perfect answer. So the midstream business benefit and predictability of fee income just ties to the growth rate. And one of the things that we're looking out was if the guidance now on QEPM and then your outlook of $80 million of EBITDA in the back half of the year. Can you talk about how growth in that midstream business potentially shifts or does it shift, did you separate the business and no longer have a sponsor?

Charles B. Stanley

No. I think that the activity upstream of the Field Services in QEPM systems is driven by pretty compelling economics. And to the extent that we're making decisions today to invest E&P capital in these assets, we will continue to do so going forward. So I don't see a change in the trajectory of growth and throughput on Field Services systems going forward. In fact, in places like the Uinta Basin we're very encouraged with the results that we've seen from our early horizontal development activities there. There's a tremendous growth opportunity for Field Services because we'll have to build an entirely new gathering the high compression system and we'll also have to also build additional processing capacity as volumes ramp in the area. In addition to that, just remember, David, that all of these areas are dedicated to Field Services. So any activity that goes on in the area, they will benefit from going forward.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

That was a perfect segue into the growth in the horizontal program. As you think about the 3 wells and that uplift in both NGL to the contract term taking the liquids at QEP and then just the uplift in productivity in the Uinta, can you talk about how you think about that opportunity to unlock this multi-TCF potential in the Uinta? Is it as much growth as it could be?

Charles B. Stanley

Well, obviously we're very excited. We're taking a measured approach to make sure we understand the horizontal well performance. And everyone I think is probably -- we talked about it. There's 1 well that's been on now for almost a year. And it was a partial completion and the performance of that well is quite encouraging. We've got a second well that now has a decent amount of production history. We're forecasting EURs -- and you're an engineer you know how difficult it is with short time period especially when the wells are exhibiting relatively modest decline. But we're forecasting EURs on these wells in the 10 Bcfe plus range right now. And at current well costs, current AFE, we're looking at sort of low-to-mid 20s returns pretax and right at 20% return after tax. We think given the history of our drilling and completion shops ability to drive down cost that as we continue to work on well design and bit selection that we can continue to -- I'm looking at Jim Torgerson, he's nodding. I don't know if he's falling asleep or agreeing with me. We can continue to drive down cost. Just to give a little more color now, we're talking about horizontal development here. We're targeting the Sand Ridge interval in the Neslen and there's a slide in the slide deck that shows that interval on the logs. And one of the things that we found is it's a very difficult interval to drill. It's very abrasive and it tends to grind up drill bits as we're grinding up rock. And one of the things that we're trying on the latest well that we're drilling is actually undershooting the sand -- sandiest section and drilling in a salty interval where it's not as abrasive in an attempt to improve penetration rates and bit durability. And we'll see how that works. The performance of these wells is also quite strange because they do not decline. They do not exhibit this typical, unconventional, hyper but -- initial high rate and then rapid decline. They're quite reminiscent, at least from the few wells that we drilled in the lower Cotton Valley in Northwest Louisiana, to those wells in that they clean up and then they stay at a relatively constant production rate for some time. And especially the more recent ones that we've completed. So we've got a lot of reservoir modeling work to do as well. But we're very excited about the Pinedale-like inventory and Pinedale-like repeatability of this play. And we don't think that just this 1 interval, the current interval that we're targeting, is the only interval that we can develop using this technique. So the big focus today is on working on our well design and getting our well costs down to drive even better returns going forward. But obviously, when you can put on 10 million a day wells, you can very rapidly increase production volume here. So we're working on our plans going forward and we will update you as soon as we have formalized plans. Obviously, this will require additional rigs and additional infrastructure to make it into a rapid growth machine.

Operator

Our next question comes from Brian Corales with Howard Weil.

Charles B. Stanley

Brian? I think Brian is not there. Operator, can we go to David.

[Technical Difficulty]

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, sorry about that. To follow up on the Uinta, are you all testing these other zones in the near-term? Or is it just potential down the road?

Charles B. Stanley

We may test 1 in the near future, the Blackhawk would be the next one that we would test. They're similar. We can see them -- as is noted on the slide that we included in the deck, we can see them contributing production in vertical wells. So we know that they are gas-charged and valid targets. Our focus to date has been on trying to figure out how to drill and complete in 1, and we figured we can do that, that knowledge should be transferable to the other intervals.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, and then, just switching tunes to the Permian. What are your thoughts on one, adding acreage on the future horizontal wells? I mean, I guess we've seen the neighboring wells, some better rates. Are you all doing anything differently on the completion side, on the next few horizontal well that you all plan?

Charles B. Stanley

We're continuing to, obviously, study the completion designs that others are using. And we're working on our as well. I think our Wolfcamp B IP was comparable to some recently reported rates around us. A lot of the well performances is directly impacted by the fluid volumes that you pump and obviously it takes longer to clean these wells up. These wells don't hit peak rates for 30 days or more in some instances. So we're continuing to tweak that as we go forward. And also, I would point out that this first well was a 75-foot lateral -- 7,500-foot lateral. So you want to make sure as you're comparing offset well results that you're comparing apples-to-apples. Because some of the offset wells are 10,000-foot laterals.

Operator

Our next question comes from David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

And Chuck, you talked about, obviously, about the midstream. I want to come back to it one more time. Are you -- I know preference also means what has the most value and what has the most dollars. But kind of if -- one, do you care to give us your preference? And then two, like what other considerations are you thinking about in terms of if all the bits come in equal, what would be your preference or what else are you kind of thinking about?

Charles B. Stanley

Look, David, I think that the ultimate goal here needs to be the maximization of shareholder value. And so it's premature for me to talk about preference until we see final offers. We have very strong indications from a number of folks. We've invited a subset of those back in for a second round. As I mentioned in our call -- the prepared remarks, there's a variety of transaction structures that have been proposed by the subset of folks who are in the second round. And we've got a team of advisers who are going to help us think through -- us and the Board think through, which transaction, which individual proponent and which transaction structure we think generates the most value for our shareholders.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, let me ask one more on that, the tax rate. If you were to do an outright spend -- or I'm sorry, outright sale, can you do anything -- I assume this has a fairly low cost basis. What can you do to protect or is there anything you can do to protect the tax side of things? And would you care to venture out like effective tax rate on a potential sale?

Richard J. Doleshek

Hey, David. It's Richard. We absolutely have tools in our toolkit for managing the tax leakage. And it stands over a multiyear sort of process. So you'd have -- obviously, a pretty high cash tax leakage in your first year, and you'll be able to carry back future NOLs back to the transaction year. And we play, sort of an interesting game right now, trying to minimize our alternate minimum tax payments. And so whether you expense the IDC, your capitalized IDC and how you use those IDC benefits, is pretty complicated. We've got folks helping us think that through. But if you look at the MLP last year, IPO, our effective tax rate on that sale was in the 10% to 15% range. And again, we were able to use operating losses, E&C [ph] credits, et cetera. So it's really hard, if you look at it just from a transaction year, to get the complete picture. You have to look at how we're going to carry back that operating losses. So without having a good number to give you, that's kind of the guidance we put out there for you.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

That's helpful. Let me switch over to the forward guidance. If I back out, and Greg we talked a little bit about this last night, but when I start thinking about third and fourth quarter, if I back out the Midcon sale, it looks relatively flattish. And I know, Chuck, I know the first quarter is probably too low. The second quarter is probably too high. But even so, I would think you'd see a little more ramp in the second half there. Is that -- I guess just ask it bluntly, are you sandbagging or what's -- is there something else going on?

Charles B. Stanley

We're putting guidance out that we feel comfortable that we can meet. And as I said, David, we don't know yet how much impact switching out to these larger completions is going to have on our phase of well delivery up in North Dakota. And it's not just -- don't think about it just in terms of bringing new wells on. Think about it in terms of how much production we may have shut in around those new wells as we stimulate them. So we're trying to build some cushion in for that. We hope it's not as bad as we joked. But we want to make sure that people aren't getting too far out over their skis and projecting the ramp in completions. In the Permian, we're bringing -- we brought in a number of new rigs. We're still getting our feet under in the Permian. And we know that from our experience in the Williston, if there's a learning curve that we come up in, in the new basin and it takes us a little while to hit our stride and that's another piece. And then, our first half of the year in the Haynesville, we had -- we worked on some wells down there and we got some -- basically no-cost or low-cost production volume out of those wells in the first half of the year that sort of flatten the Haynesville decline a bit. It didn't stop it, the decline. It slowed the rate of decline for a while. It was sort of a one-time benefit. And now, we expect those wells will go back on their normal decline. And as a result, the second half is not going to be as first -- as good as the first half in the Haynesville, at least on the existing proved developed producing wells. Now as I mentioned in my prepared remarks, we are participating in a number of outside operated wells. But most of those wells probably won't be online until late in the year. So they won't have an impact. But it will be on '15 not '14 production.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, and last question. If you can speak to us -- assuming you get an influx of cash from the midstream separation, just remind me again what's your thought is for that, are you looking at more Permian acreage or what's the use of proceeds?

Charles B. Stanley

We'll cross that bridge when we get there. We don't know yet whether the transaction involving the midstream businesses is going to be for cash, whether there's going to be spin, merge or what the structure will be. So as we figure out the right answer for shareholders, we'll have more color around that.

Operator

Our next question comes from Brian Gamble with Simmons.

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

I wanted to start in the Williston, you mentioned, Chuck when you ran through the incremental cost of the proppant. What are we looking like for total well cost there? I know you mentioned the IRR, but if you can roll all the way to 10 million pounds of prop, maybe it depends on what's going in those proppants. If you could detail the sand and ceramic content of it. But what does that ultimately look like from a well cost standpoint?

Charles B. Stanley

So I mentioned -- just a straight increase in proppant volume and additional perf clusters probably adds $1.3 million, $1.4 million to the well cost. If we go full load cemented liner or plug and plug perf, when you add in additional rig time, or work over rig time or coiled tubing time and additional time to pump the frac jobs with wireline and plug and perf, you potentially add $2.5 million to $2.7 million to a well. We think that for the most part, we can offset sort of the midpoint of that with our increased efficiency. We were seeing well cost going down and what we've determined is that it's in our best interest from a return perspective to add that additional cost. And so we basically -- we haven't raised our capital budget for the year because we think we can offset the additional cost of this bigger frac jobs with efficiency gains in drilling and therefore not raise our capital budget. So these are $10 million to $10.5 million wells.

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

Great. And then the mix there of prop at the $10 million kind of level?

Richard J. Doleshek

It's all sand. We're not using any ceramics.

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

And then on the Permian side of things, you mentioned the third horizontal coming in soon. And that's quicker than previously expected. Are we going to continue to see that ramp? I mean what is the end of the year rig count look like, are we looking maybe swap off one of the verticals and add another horizontal by year end?

Charles B. Stanley

Yes, that will be the right general direction, exactly, when we do that. I don't have the rig schedule in front of me. But the key here is that we need more vertical well data to fully evaluate the horizontal potential. And as we gather that data, we can slow down and stop our vertical development and shift all horizontal. And so you're right directionally on the shift from vertical rigs to horizontal rigs.

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

So you when you say complete development mode up there that means no verticals left when you're completely done with the data, you don't need to drill and won't be doing any verticals?

Charles B. Stanley

We may have 1 rig or maybe 2 rigs drilling verticals for quite a while.

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

Okay. So there is some vertical later on as well.

Charles B. Stanley

Yes.

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

Great. And then on the second unit. You talked about the horizontals, 3 well so far. The rest of the year, how many more are we thinking. You mentioned the 1 that you might put into the Blackhawk interval. How many more wells are we expecting?

Charles B. Stanley

We'll probably have the 1 well that we're getting ready to complete and another well by year end. But it'll still be over year end into the first quarter, I think, before it gets online.

Operator

,

Our next question comes from Matt Portillo with TPH.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just on a quick question, a follow-up on the Bakken. In terms of the upsize frac, is that baked into your guidance or how do you guys risk that? And then I guess the second question alongside that is, it sounds like you've given the activity, all this has been allocated to the -- for the Antelope area, so far. But I was curious if you've tested outside frac in Fort Berthold?

Charles B. Stanley

I'll answer the second question first. We have not yet but we plan to do it soon. And then on the assumptions around upsize fracs, we have held our eyepiece constant. We have -- we have seen from offset operators with larger frac jobs that increase in IP and a sustained higher production volume over the first 12 months or more -- it really is about all we have is 12 months of production history from these wells. But until we have a family of wells that we have stimulated ourselves and watched the production performance for some time, we're reluctant to raise our assumed rate until we have our own actual well performance. So the guidance is based on our historic estimated IPs and rates. And so there's upside there from the bigger frac jobs if in fact we see similar performance to offset operators.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And just a quick follow up on that. So as we think about kind of the information you guys provided today, it's based on the early production data you've seen so far. And maybe some of the offset completions that you've seen via the operators but a lot of that has been heavily risked in your assumptions on incremental improvements or rates of return and also on your production guidance.

Charles B. Stanley

That's correct.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then I guess second, 2 other quick questions. In the Uinta, I was wondering if you can provide us maybe some color around the horizontal well cost, or I guess if you have a targeted well cost that you may be looking to achieve? And I'll have 1 quick follow up after that.

Charles B. Stanley

So they're all over the map. Our current AFE is about $14.8 million. We think that we can drive it down below that. The key, as I mentioned earlier, is hopefully with under shooting this very abrasive sand-prone interval and frac-ing up into it, we can improve our penetration rates and really cut down our completed well cost. So that's part of the strategy here for pushing the economics up is to drive down the drill times and therefore, well cost. Because this is a very abrasive interval.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And my last question just in regards to the Haynesville. Are you guys evaluating at all any re-frac opportunities or participating in non-operated re-fracs? We've seen some, I guess, fairly encouraging results early on but a fairly limited data set from the industry, so just curious how you guys were thinking about that.

Charles B. Stanley

We were watching it like everybody else is. We have obviously a team of people who are following the Haynesville and we obviously got re-frac candidates. It's very interesting early results, we agree with you. We just need to see more production history to convince ourselves that it's not just flush production from ballooning the rock of -- but so far, they look quite interesting.

Operator

Our next question comes from Dan McSpirit with BMO.

Dan McSpirit - BMO Capital Markets U.S.

How should we look at the relationship between EBITDA or cash flow to capital spending beyond 2014 as the company potentially allocates more capital to the Permian Basin, proceeds from the asset sales come in the door and what might that mean for leverage here going forward?

Charles B. Stanley

Well, we're trying to run a business which lives in and around cash flow. This year, we have an outspend. And I think you should've expected that. We sort of telegraphed that as we ramped up activity in the Permian. But -- and as a result, cash flow from the assets or lags, the initial flush investment as we ramp up activity and ramp up the well delivery machine. Going forward, we like to live in and around EBITDA. And that's been our philosophy in running the company for some time. I think that as far as leverage, I'll let Richard talk to you about our general view of leverage and balance sheet strength and liquidity.

Richard J. Doleshek

Dan, generally, we're trying to run on a leverage level less than 2x debt multiple to EBITDA. And so, if we have a couple hundred million dollars outspend versus EBITDA this year, with the EBITDA growth we see next year and probably that same level of outspend as we continue to ramp up in the Permian, that would ultimately result in a decreasing of leverage because that's a 1:1 ratio. So I think it's just -- just keep in mind 2x or less is sort of where we want to live. And we're probably going to have a bit of an outspend next year. We haven't put a formal guidance together yet. But we probably won't breach through that 2x just with developing our own properties.

Dan McSpirit - BMO Capital Markets U.S.

Great. And as a follow-up, if I may, maybe more for modeling here. Would there be much change expected in the -- maybe in the first year decline rate on the Williston Basin producers, the middle Bakken wells frac-ed or completed with this new and improved technique?

Charles B. Stanley

No, what we see is kind of a bulk shift in the production curve on the wells that had been online 1 year or so. So you see a sustained higher rate on the 30-day, 60-day, 90-day, 120-day, 365-day cumulative rate, Dan. You can go out with drilling info and look at, isolate those wells that had been online and we were -- we waited and watched those wells for some time until we saw the, what I think is very convincing, 12-month production history. What, Jim, probably 20 wells, 15 or 20 wells that have got 1 year on them now? And there -- some of them are standalone wells that are in an unstimulated block of rock but there have been a number of wells that have been drilled on tight density that all exhibit this -- it's really a bulk shift. It doesn't look like it fundamentally changes the shape of the decline curve, the B factor or internal decline rate. It simply shifts the whole thing up on IP. And that results in a substantial amount of incremental oil being recovered over the first 12 months of production.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And lastly here, what's the base decline rate on the Haynesville Shale operations?

Charles B. Stanley

Before we perturbed it in the first quarter and into the second quarter, it was about 34%, 35%, right in that range.

Operator

Our last question comes from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

The first one just, I guess, another different take on Tameron's point earlier. Which is, can you quantify or approximate the ethane projection uplift in the second quarter? Or how much it might be in the sort of four quarters?

Charles B. Stanley

So we don't make any money on ethane. I mean, we make a penny, we lose a penny on a daily basis. What we do, though, when we run the plans on ethane recovery is we recover more propane. And that has basically allowed us to make a slightly higher margin per barrel of recovered liquids than we would make if we let the ethane go down the line and then recover as much propane. It was significant in the first quarter. It's still positive this quarter. And you tell me what liquids prices and gas prices are going to be for the rest of the year and I'll tell you what we're going to make. But it's slightly better than letting methane go down the line and not getting full propane recovery.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay, right. Or I can talk to Greg and I'll give my couple of scenarios and then we can kind of see -- check from there. I guess second of all, I guess with the extra activity for the Haynesville, do you have a sense of what the decline might slow to? Are we talking about 5 to 10 wells? Are we talking about more than that being drilled?

Charles B. Stanley

No. I mean, yes, it's a $50 million, roughly, increment in our capital budget. It's not going to impact 2014 production materially if at all. Because of the timing of well completions. But it will have an impact on 2015. It's -- the average working interest that we're participating with, it varies, anywhere from a few percent up to about 20% of these wells are getting drilled. But they're being drilled by operators who are basically infilling full sections. So the wells are being drilled and cased and are being left standing while the whole section is being drilled up and then they'll all be completed at once. So when they all come on, it's going to have a positive impact on our decline. But we don't have full visibility on when that's going to happen.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

And then you mentioned that the SCOOP sale, I mean, is that the last set of your non-core stuff? I mean, I guess, with that coming at some point? And then if you get cash from the midstream, I mean, would it be possible to see some debt payment as a result of that? Or where would you like to put -- apply that back into organic obstacles if you got cash?

Charles B. Stanley

So first, let me clarify, Andrew, the SCOOP is in the market. But the remaining assets, the -- our coal mine and other assets that we have, are not yet in the market. So we have additional assets beyond the SCOOP that, kind of, that we plan to sell. And we hope to get those deals done late this year. They may flop over into next year. The proceeds from those sales will go to repay debt likely. But it's going to be -- the timing on close is going to be late this year for most of the assets.

Operator

At this time, I would like to turn the call back over to management for closing comments.

Charles B. Stanley

Thank you, all, for your interest in QEP. We're going to be attending a number of conferences coming up through the remainder of the year. We look forward to seeing you all in person.

Operator

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time, and have a great day.

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Source: QEP Resources' (QEP) CEO Charles Stanley on Q2 2014 Results - Earnings Call Transcript
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