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QEP Resources (NYSE:QEP)

Q1 2014 Earnings Call

May 08, 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, Executive Vice President and Treasurer

Analysts

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

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

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

Gabriel Daoud - Jefferies LLC, Research Division

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

Dan McSpirit - BMO Capital Markets U.S.

Gregg W. Brody - JP Morgan Chase & Co, Research Division

Operator

Greetings, and welcome to the QEP Resources First Quarter 2014 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, Mr. Greg Bensen, Director of Investor Relations for QEP Resources. Thank you. Mr. Bensen, you may begin.

Greg Bensen

Thank you, Doug, and good morning, everyone. Thank you for joining us for the QEP Resources First 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 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 the risks facing our business in our earnings release and our SEC filings.

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

Charles B. Stanley

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

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

We closed on our Permian Basin acquisition on February 25, just before our year-end 2013 conference call. And since the close, the Permian asset team has made great progress with the asset, ramping from 2 to 5 drilling rigs since the close and we've already drilled and cased our first horizontal well.

Earlier this week, we announced that we've entered into 3 definitive agreements to sell certain non-core E&P properties, primarily in the mid-continent, for a total sales price subject to customer readjustments of approximately $807 million. As a reminder, we structured the recent purchase of the Permian assets and the current sales of non-core E&P assets as a reverse 1031 exchange, meaning that we'll be able to transfer the tax basis from the divested assets over to the newly acquired Permian assets.

We intend to bring several additional noncore Midcontinent assets to market soon including our acreage located in the Woodford SCOOP play. Our remaining Midcontinent assets including the SCOOP have aggregate net production of approximately 21 million cubic feet of gas equivalent a day. When the remaining divestitures are closed, we will have completely exited the mid-continent region with the results being a more focused upstream portfolio.

On May 6, we announced that we had entered into a definitive agreement with QEP Midstream Partners, LP, our midstream MLP, to sell a 40% equity interest in Green River processing LLC for gross proceeds of $230 million. Green River processing includes our ownership of Blacks Fork and Emigrant Trail processing assets in Southwestern Wyoming. By selling the equity interest at a valuation above QEP's EBITDA multiple and below QEPM's, the transaction will be accretive to both entities.

You will recall that on December of last year, we announced plans to unlock additional value for QEP shareholders by fully separating our Midstream business, QEP Field Services, including QEP Field Services' ownership of QEP Midstream Partners from QEP Resources. When complete, we believe this separation will better position both our E&P and our midstream companies to compete and thrive in their respective business environments.

We continue to pursue multiple avenues to achieve the midstream separation, ranging from an outright sale to a straight spinoff of the business to QEP shareholders.

In the first quarter, we made substantial progress on the preparation of documents required to effect the separation. First, to facilitate discussions with parties interested in an outright purchase of the business or a combination via spin merge, Reverse Morris Trust or similar transaction, we prepared a confidential information memorandum or CIM that contains asset level, operational, commercial and financial information for QEP Field Services. The work on the CIM is complete and invitations will be sent out soon to qualified parties. To prepare for the possibility of a straight spin or various spin merge transaction structures, we are also simultaneously preparing a Form 10, which we intend to file with the SEC later on this quarter.

While repositioning our upstream portfolio and announcing our first dropdown transaction with QEPM are big milestones, strong ongoing performance of our underlying business is also critical. And on that front, our talented asset managers really delivered in the first quarter.

Williston Basin oil production nearly doubled from first quarter 2013 and Permian production is consistently tracking ahead of our acquisition forecast. This drove an increase in average daily crude oil production of 11% compared to the fourth quarter of 2013. As a result of this performance, we've raised our full year 2014 crude oil production guidance by 0.5 million barrels net of the forecasted divestitures in the mid-continent. Clearly, we're making substantial progress on transforming QEP into a more focused upstream company by optimizing our upstream portfolio, and we're maximizing shareholder value through the separation of our midstream business.

Now, let's turn to some details about our first quarter results. QEP Energy EBITDA grew 3% from the first quarter 2013, driven by a 55% year-over-year increase in crude oil production. Total natural gas equivalent production declined 5% from last year on a 6:1 basis but increased by 15% on a 20:1 basis, which we feel is the more appropriate conversion ratio.

Liquids volumes comprised 40% of total company-wide production in the first quarter, dominated by crude oil volumes. Crude oil volumes accounted for 27% of total production in the first quarter, up from 16% in the first quarter of last year, and just 10% in the first quarter of 2012. We're making meaningful and steady progress on our financially-disciplined, return-focused transition to a more balanced upstream portfolio.

Despite the continued shift in commodity mix, our natural gas production was a strong financial contributor in the first quarter. Although overall gas production declined by 24% from the first quarter of 2013, field level natural gas revenue increased by 13% to its highest level in over 2 years due to the overall strengthening of natural gas prices and due to our exposure to the premium priced Rockies natural gas markets.

While our price risk management program has provided cash flow stability in recent years, it had a negative impact in the first quarter of 2014. Excluding the realized gains and losses on our commodity derivatives and looking at base operating results, EBITDA was up 30% from the first quarter of 2013.

Now, let me give you a little more color about our operational results by area and more detail on our plans for 2014. As I do so, I'd ask you to refer to the slide presentation that accompanied our release yesterday afternoon. In the Williston Basin we currently have 8 rigs running, the same number as last quarter but they have moved around a bit. At the end of the first quarter, all 8 rigs in the basin were working on our South Antelope property after we moved the last 2 remaining rigs from Fort Berthold during the quarter. Completion activity declined in the Williston Basin in the first quarter with 14 gross QEP-operated wells completed and turned to sales compared to 26 in the fourth quarter of last year and 12 during the first quarter of 2013.

We expect to average between 20 and 25 gross QEP-operated well completions per quarter in the Williston for the remainder of 2014.

Performance of both the recently completed wells and the older wells that have been on for some time remain strong and remain in line with our expectations. We continue to evaluate the potential for increased well density on our acreage, we're monitoring results of pilot programs that are being conducted by nearby operators and we also have a pilot program underway to evaluate the applicability of increased density development on our own acreage. We expect to be able to share the results of that project by year-end.

Finally, we continue to make good progress on well costs in the Williston, due primarily to ongoing operational improvements and efficiency gains due to pad drilling. We currently plan to invest about 51% of QEP Energy's 2014 capital in the Williston Basin. I'd refer you to Slide 6 through 8 for more details on our operations there.

Turning to the Permian. We've made great progress in the 2 months since closing on the acquisition at the end of February. We've increased our drilling activity from 2 to 5 rigs on our acreage, with 4 rigs directed at drilling vertical wells and 1 drilling horizontal wells. We also have a 6th rig moving into the area now, and it should start drilling vertical wells late this month or early next month.

Remember, we have a lot of science to do to evaluate the horizontal potential on some of the target intervals within the Wolfcamp and Spraberry interval. And this science will be done through data that's collected with the vertical well drilling program. Once we've collected that data, we plan to shift our emphasis to horizontal development. Our plan at the time of acquisition was to ramp to 6 rigs by the end of 2014. Clear that we've made better progress on that goal than we had originally scheduled, and the team is now focused on accelerating the transition to horizontal development.

Productions from initial QEP-operated vertical wells is tracking ahead of our expectation. We've made some minor tweaks to the completion design and the early performance indications point to improved EURs from that adjustment. We talked about that in detail in our release.

Finally, I'm proud to report that the Permian team has already drilled and cased our first horizontal well. It's a 7,500-foot lateral that's targeting the Wolfcamp B interval, and we should start completion operations on that well next week. We've also begun drilling our second horizontal Permian well. This second one will target the Wolfcamp D interval. We'll provide more information on results on our first horizontal well and the overall performance of our drilling program and completion operations on the second quarter call in August.

Overall, I have to say we're very pleased with our Permian Basin acquisition. Our strong -- our ongoing reservoir evaluation were coupled with reports of strong initial performance from nearby horizontal wells that are being drilled by other operators, continues to affirm the quality of the acquired properties. Combining these early results with substantial progress that we've made in offsetting the acquisition costs of the Permian property through the sale of non-core E&P assets, it's clear to me that making this acquisition was the right strategic move for QEP. Excluding acquisition costs, we now plan to invest approximately 20% of QEP Energy's 2014 capital budget in the Permian, and that's up from 15% that we discussed in our fourth quarter call due to our team's ability to get more rigs to work so quickly in the basin. See Slide 9 for more details on our Permian operations.

Turning to Pinedale. Production volumes declined about 15% compared to the fourth quarter of 2013, and that's due to the typical seasonal declines that we see as we defer completions through the coldest months of the year. And much of our first -- last half of 2013, well completion activity was also concentrated in areas where QEP was the operator but had only a small overriding interest in wells that are primarily Wexpro wells. So that also impacted the decline going into the winter.

It's also important to note that even though the ethane frac spread was near breakeven, the propane frac spread was significantly improved and due to an increase in the propane recoveries while running our plants in ethane recovery mode, the improved NGL price environment led us to recover ethane throughout most of the quarter.

For the first quarter, we completed and turned to sales 22 new Pinedale wells. And at the end of the first quarter, we had 55 gross wells with QEP working interests drilled, cased and awaiting completion. Those wells had an average working interest of 83%. And we also had 3 additional wells where QEP is the operator but only had a small overriding interests that are drilled and cased and awaiting completion.

We anticipate running 4 rigs at Pinedale throughout 2014, and we should complete somewhere between 110 and 115 wells this year, including wells -- 10 wells, for which QEP is the operator but only has a small overriding interest. We plan to invest about 13% of our total capital budget at Pinedale. Slides 10 and 11 show the details.

Turning to the Uinta Basin. We continued to make progress on our Red Wash Lower Mesaverde liquids-rich play last quarter. We talked about early results from a fundamentally different well design that we think could radically alter the economics of the play and the way we approach development. Production performance in that well continues to be very encouraging. You go out on the state, Utah State website, you can see the first well has produced nearly half a Bcf in its first 3 months online.

Early in the second quarter, we completed our second well incorporated in the new design. It's too early to give you any meaningful results on that well but the initial performance is equally encouraging. With multiple Tcf and probable reserves on our 100% working interests, 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 on investing approximately 5% of our capital budget in the Uinta Basin this year, but we may reconsider that allocation later on as we continue to see encouraging well results.

Slide 12 shows the details of our Uinta basin activities. At Field Services, EBITDA was flat compared to the first quarter of 2013, excluding the impact of the 42% noncontrolling interests of QEP Midstream Partners of $8.2 million. Adding the $8.2 million of QEP midstream EBITDA back to Field Services, reported figures results in a gross EBITDA of $61.4 million, which was up 15% from the prior year. We saw the benefit of our expanded fractionation capacities at Blacks Fork in the first quarter of 2014.

During the third quarter, you'll recall that we completed construction of the expanded rail loading facilities at the site and the expansion of our 10,000-barrel a day facility to 15,000 barrels a day. This facility will provide additional options for marketing purity ethane and iso/normal butane and gasoline range products. And in the first quarter, the flexibility of being able to access higher value in-market supported by the new fractionation facility resulted in improved NGL pricing. About $0.10 a gallon or so on the C3 plus components. And we expect this impact will be less pronounced obviously, as we move into the warmer months of this year.

Late in the first quarter, Field Services also commenced construction on a project to debottleneck our Vermillion gas processing plant that's located in Southwest Wyoming. When complete, the debottlenecking will expand the capacity of the Vermillion plant from 43 million cubic feet a day of raw gas to approximately 57% -- 57 million cubic feet a day, excuse me, and Field Services owns about 71% of the Vermillion plant, the remainder's owned by Wexpro Company, which is a Questar subsidiary.

The total gross capital cost for the project is approximately $10.5 million with a net capital cost of approximately $7.5 million for QEP Field Services. We think that project should be complete sometime in the third quarter. We plan to invest approximately $80 million in Field Services projects in 2014 including the capital that we'll invest in QEPM.

Looking forward to the remainder of the year, I'm really proud of everything we've accomplished so far. We've made substantial progress on multiple strategic initiatives, while delivering solid results from our underlying business. I think, we're well positioned to continue grow liquids volumes in 2014 and beyond. And while we expect natural gas volumes to decrease again in 2014, allocating capital to higher-return oil projects should lead to continued strong crude oil production growth with a 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 premier U.S. oil plays and a deep inventory of low-cost, liquids-rich gas projects, we're confident that our portfolio can support multiple years of profitable growth. We're also excited about the benefit to shareholders from the separation of our midstream business and about the progress we've made with that effort to date. I look forward to providing you updates on our continued progress throughout the year.

With that, I'd like to 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 first quarter of the year, I'll provide you some color about our financial results before we go to Q&A.

For the first quarter, we generated $386 million of adjusted EBITDA. If we include the public's 42% share of QEP Midstream Partners results, we reported about $394 million of EBITDA. The $386 million of EBITDA generated in the first quarter was $9 million higher than the fourth of 2013 and $11 million higher than the first quarter of 2013. QEP Energy contributed $332 million or 86% of the aggregate first quarter EBITDA, and QEP Field Services contributed $53 million or about 14%. QEP Energy's EBITDA was up about $8.9 million and QEP Field Services' EBITDA was down about $3.6 million from their respective levels in the fourth quarter of 2013.

Factors driving our first quarter EBITDA included QEP Energy's production, which was 73.7 Bcfe or about 1.4 Bcfe lower than the 75.1 Bcfe we reported in the fourth quarter due to declining gas volumes in Pinedale as we suspended completion activities for the winter, offset by a 10% increase in Williston Basin production and a 1.2 Bcfe contribution from the Permian Basin properties, which were included for just 1 month in the quarter. Oil volumes were 3.3 million barrels, up 270,000 barrels or 9% from fourth quarter levels. The Permian Basin properties added 140,000 barrels of oil during the quarter.

NGL volumes are 1.57 million barrels, up 134,000 barrels or 9% from the fourth quarter. Using the 6:1 equivalent conversion, our growth in liquids volume didn't offset the declining gas volumes. And as Chuck said earlier, we continue to make progress increasing the crude oil component of our total production by focusing our capital investment on the development of crude oil-related properties. In the first quarter of 2014, natural gas comprised just 60% of our net production compared to 75% a year ago. And crude oil comprised 27% of total equivalent production in the quarter compared to 16.5% a year ago.

And comparing the first quarter of 2014 to the fourth quarter of 2013, our results were positively impacted by stronger field level oil, gas and NGL prices, partially offset by a realized loss of $35.4 million from our derivatives portfolio compared to a $40.5 million gain in the fourth quarter.

Our guidance for 2014, pro forma for the Granite Wash and Woodford Cana asset divestitures, which we expect to close by midyear, forecast natural gas volumes to be 166 Bcf to 181 Bcf. Our forecast for oil volumes is 14.2 to 15.2 million barrels, an increase from our previous guidance despite the sale of approximately 300,000 barrels of production forecasted from the Midcontinent properties, and up 44% from 2013 at the midpoint.

Our guidance for NGL volumes for the year is 3.8 million to 4.3 million barrels, the midpoint of which is down about 16% from 2013, assuming that we will be in ethane rejection for the remainder of the year.

QEP Energy's combined lease operating and transportation expenses were $121 million in the quarter, up from $113 million in the fourth quarter of 2013, and up $97 million from the first quarter of 2013.

On a per-unit basis, lease operating expenses were $0.76 per Mcfe and transportation expense was $0.88 per Mcfe or $1.64 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 the full year.

Finally, QEP Field Services' first quarter EBITDA was $53.2 million, which was flat compared to prior-year period and down slightly from the fourth quarter. Processing margin was up about $8 million or 24% in the quarter compared to the fourth quarter of 2013 as a result of higher NGL sales. Gathering margin was down $14 million or 30% compared to the fourth quarter of 2013 due primarily to decreases in gathering volumes.

Sequential G&A expenses were up $1.7 million, primarily the result of higher expense for outside professional services, a Field Services employee retention program and expenses associated with the replacement of many of our IT corporate systems.

Our guidance for G&A for expense for 2014 is unchanged at $190 million to $210 million. We reported net income attributable to QEP of $39.7 million in the quarter including $45.5 million of unrealized loss on our derivative portfolio. Excluding the unrealized loss and other nonrecurring items, QEP reported an adjusted net income of $68.1 million or $0.38 per share as compared to first call consensus mean of $0.26 per share.

Capital expenditures on an accrual business for E&P drilling and completion activities were $1.26 billion in the quarter, including $945 million related to the Permian Basin acquisition. Capital expenditures in our midstream business were $21.5 million. If you exclude the acquisitions, our capital investments were about $45 million less than our EBITDA in the quarter. We are forecasting midpoint for our 2014 capital program to be about $1.65 billion for QEP Energy, about $80 million for QEP Field Services and $25 million for corporate, again excluding acquisitions.

And with regard to our balance sheet, we closed the Permian Basin acquisition at the end of February, which drove a $1.2 billion increase in total assets to $10.6 billion at the end of the quarter. We funded the acquisition with $50 million in cash, $300 million from our expanded term loan, which is due in 2017, and approximately $595 million under our revolving credit facility.

Our debt at the end of the quarter was approximately $3.9 billion, which was about a 2.5x multiple of our trailing 12 months EBITDA. Our debt consisted of $2.2 billion of senior notes, $600 million under the term loan and $1.1 billion under the revolving credit. Pro forma for the $1 billion-plus we announced to [ph] asset sales, our revolving credit balance would be $100 million and our total debt to trailing 12 months EBITDA would fall below about 1.9x.

With that, Doug, we'd like to open the line for questions and answers.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of David Tameron from Wells Fargo.

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

Chuck, can you talk about, you talked a little bit about -- can you talk about the Permian ramp, how we should think about it over the next, call it 6 to 9 months or even 2 or 3 quarters out?

Charles B. Stanley

Sure, David. As we stated back when we announced the acquisition, our original plan was to have 6 rigs operating in the basin by year-end, a mixture of vertical and horizontal rigs. What we've done is we've -- we picked up some additional vertical rigs. As I mentioned in my prepared remarks, one of the keys to designing a development program to target all the different horizontal intervals is making sure we have accurate rock property data on the individual flow units, and in order to that, we need to drill vertical wells that are data wells basically because historically in the area, the previous operator had drilled the wells, cased them and then run cased-hole logs and hadn't obtained open-hole log data, which is very important in order to design where you want to land the laterals and also frac design in order to get good rock properties. So we're -- our plan is to accelerate the vertical program to collect this data, give us an opportunity to plan our horizontal development based on detailed petrophysical work and then shift to a more balanced program. Ultimately, probably about half and half vertical rigs and the horizontal rigs. We've got a couple of hundred more vertical locations to drill. Obviously, we'll consume those relatively quickly if we continue with the nearly 100% vertical program and that's not the intention. So toward the end of the year, we should be more balanced. The -- I think it's too early to kind of give you guidance, 1 year guidance on activity levels because a lot of it's going to depend on the data collection that we're doing. There's obvious horizontal targets that Wolfcamp AB, the Spraberry AB, the Wolfcamp D is less well understood, although we're drilling a well in it right now to collect real-time data and the offset operator results so far have been very encouraging in Wolfcamp D. But we need some additional core, we need some additional open-hole log data before we can really give you full guidance. But if you want to just look at our thoughts around the next several years of production guidance, you can go back to our announcement back in December when we put out a slide deck, I don't know, about half a dozen slides or so, in conjunction with our announcement of the acquisition of the Permian assets. And our view on production volumes haven't changed, although obviously, we're striving to do better than that.

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

Okay. Let me jump to the Uinta. And it didn't sound like you went there in the prepared remarks. So, I guess this, I don't know what you call, but the new completion design. You've drilled 3 wells, and where I'm going with it is there's some state data out there that indicates the first well looks pretty good and I know you guys -- that wasn't -- you guys didn't get that well off completely from a -- I think you had some issues on the completion front. But the cume rate looks like it's about 3x what we had modeled for our vertical, just above 3x. Any -- do you want to give us any more color on that?

Charles B. Stanley

Well, obviously, the well has been online now for what, 7, 8, almost 8 months. And we forecast that well based on early time production data, putting a tight curve on it and as 6.5 Bcfe to 7 Bcfe range well, that's from, as you stated, a partial completion. It's 1 well. The second well we have drilled, we have completed, it's been to sales for a while now, but these wells are somewhat reminiscent of the lower Cotton Valley wells we drilled in Northwest Louisiana and for the first, for early time, they make all flow back water with very little gas and if you look at the state records, you can see that for the first well. So they take a while, a considerable amount of time to clean up before we can get real gas production performance and put a good forecast on the well. The second well, way too early to even comment on it other than to say it looks encouraging at this point. And then the third well is just drilling. So we really only have 1 data point, and yes, that data point is very encouraging and that's what's led us to pause in our original development plan -- original, it was really a Pinedale clone, if you will. A pad drilling directional wells and rethink the development plans here. I will say that we've gone back into some of the original wells we drilled, vertical wells we drilled after core work and additional petrophysical work and recompleted some of those wells in intervals that we thought were wet that turned out to be gas-bearing. So our overall view of the vertical development program has changed positively with the results of those recompletions. The recompletions were very encouraging, they added about 1 million a day of production to the wells initially. And arguably, fundamentally changed our economics around that program but given the early time results from the new completion design, we're going to drill a few more wells before we make a final termination, but early results are looking very encouraging.

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

Okay. And you are completing this. This isn't a Blackhawk or a Mancos. This is a Mesaverde. Are you getting in...

Charles B. Stanley

It's a lower Mesaverde interval and as you recall, the lower Mesaverde interval is interbedded sands and silt stones with some shale and it is, it looks identical to the stuff in Pinedale or anywhere else in the Uinta basin where you have discontinuous sand bodies. Some are more continuous than others. And we're targeting the lower Mesaverde sandstones.

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

Okay. And just 1 follow-up there. Just so the plans are, if I'm hearing you right, just have a 1-rig program out there, continue to drill, and watch the well performance and maybe this is more of a 2015 type of ramp, is that?

Charles B. Stanley

Yes. I mean we could potentially step up the drilling activity toward the end of the year, but it's not going to have a big impact on production volumes or capital because it'll be back-loaded.

Operator

Our next question comes from the line of David Heikkinen from Heikkinen Energy Partners.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

I would like -- because I was a thinking about your Field Services gathering volumes. Can you give us an outlook for what you're expecting heading forward?

Charles B. Stanley

Well I think the one area that is very obvious, obviously in decline because we've been deliberately funding oil and wet gas development areas, is the Haynesville system. And the Haynesville system is really what's been driving the decline in throughput. The other systems have been flattish, slightly down in the Vermillion and Uinta. But overall, the systems, especially the ones owned in the MLP, which is everything except Haynesville and Uinta, have been flat and to growing and we would anticipate modest growth and throughput on those systems this year.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

And I guess no third-party volume growth as others are ramping in the Haynesville, everything is just tied to your Haynesville at this point?

Charles B. Stanley

That's correct. There's a little bit of third-party but it's minuscule compared to the QEP operating volumes.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

And then in your guidance, particularly on the oil side, can you give some splits for volumes out of the Bakken and volumes out of the Permian? As we try to think about this ramp in the Permian, just want to make sure we're modeling that roughly appropriately.

Charles B. Stanley

Greg can throw some numbers out at you here.

Greg Bensen

Yes. So I mean, round numbers, Williston, we're expecting growth in 35%, 40% range on a Bcfe basis. The Permian. [indiscernible]

Charles B. Stanley

We've given some indication of Permian production growth at Bakken at the December 9 release, David.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

With the additional rig, I guess, that was the, I mean [indiscernible]

Charles B. Stanley

Yes. I mean, it's -- it should positively impact it. But remember, it's drilling vertical wells, and those wells come on a couple of hundred barrels a day apiece, so -- a couple or 300 barrels a day apiece, so it's not a big swing. The real catalyst for changing the trajectory of growth, and -- give us another quarter or 2, we'll be bringing on horizontal wells because obviously, based on what we've seen from offset operators, the horizontal production performance has been quite good. So it could fundamentally change our forecast but let us get the first well completed and online, please, and then we'll try to give you an update.

Richard J. Doleshek

And David, it's Richard. If you just kind of annualize or quarterize the first quarter for Permian and Williston, and Williston is still about 2/3 of our oil production. And if you just kind of grow those, that ratio's going to stay pretty consistent, maybe some degradation as we ramp Permian but that's probably not a bad ratio to use.

Charles B. Stanley

Yes, and there is some other oil production that we don't talk about very much, we've got 2,500, 3,000 barrels a day approximately coming out of the Uinta Basin, black wax that sort of baseline that doesn't move around very much.

Operator

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

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

The -- I want to shift over, talk about the Williston for a second. You mentioned, you shifted all the rigs over to the Antelope portion. Just wanted to get a little bit of color as to why that was. And then do you see growth during the quarter without the benefit of a lot of completions, just any color there would be helpful.

Charles B. Stanley

I'll take the second one first. We had a significant number of completions in the fourth quarter and they were toward the end of the fourth quarter, sort of back-end loaded. So, and I don't remember the number, 24 in the fourth quarter in round numbers? So the fourth quarter completion activity obviously drove our production response in the first quarter, we had 14 wells that were actually completed and turned to sales in the first quarter. A couple more that were drilled and cased that were almost completed during the quarter but the production response obviously, was compounded or helped by the fourth quarter activity. The shifting of rigs back and forth between South Antelope and the reservation is for basically operational efficiency and scheduling of completions. I wouldn't read anything more into it than that. In some of the areas where we're drilling, winter weather is, it's tough to be out on the extreme extension of some of the roads and close to steep drop-offs on the edge of the lakes. So we just prefer to stay away from those areas in the wintertime.

Richard J. Doleshek

26 Williston completions.

Charles B. Stanley

26, sorry.

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

Great. And then the Wolfcamp B, the horizontal, you mentioned you drilled and cased it, any storage [ph] there, go as planned, just any color?

Charles B. Stanley

Jim, it was not a difficult well to drill. It went pretty well for a first well.

Richard J. Doleshek

Very smoothly and ahead of schedule so far.

Charles B. Stanley

So, we'll -- stay tuned, I hope to have some good results on that well pretty soon. And one of the things I will say, I said it in the call, cryptically but I'll say it overtly and that is, we don't intend on issuing well results out of period. We prefer just to tell you about our well results on a quarterly basis because we view this as a development program. And first of all, we'll just need to get some production performance on these wells before we can really say much about them but I think it's just in everybody's interest to just do it on a quarterly basis.

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

And then finally on the CIM document that you're sending out, is there any timeframe as to when qualified buyers have to respond to that document?

Charles B. Stanley

Well first, will be -- the first thing we'll do, as typical with these processes is we'll send out a teaser, that will have a CA associated with it, confidentiality agreement. We'll have to negotiate and get those executed before we can send out the actual CIM, and then that'll start a process, Richard, you want to give a little more color around that?

Richard J. Doleshek

I think it's safe to say that we should have information in the qualified interested parties' hands during the month of May. And then how the process runs June, early July, we won't speculate but certainly, the information will be in the market in terms of that business and what it looks like this month.

Operator

Our next question comes from the line of Gabriel Daoud from Jefferies.

Gabriel Daoud - Jefferies LLC, Research Division

Just wanted to go back to vertical wells in the Permian. I guess, I know a lot of them are data wells, but I guess if you could just give some color on current well costs, and what you see them ending up going to I guess as the year progresses.

Richard J. Doleshek

It's about $3 million right now of well costs. But that includes some logging and [indiscernible] cores and stuff, some other testing that we won't do once we get into full development mode.

Charles B. Stanley

Yes keep in mind, we're kind of going the opposite direction from a typical development, just blowing down vertical well development program. We're drilling the wells to keep the hole engaged or keep a fairly constant diameter, which adds costs, slows you down a bit. And then as Jim mentioned, we're collecting a lot of science data to help guide our horizontal development. And really, I mean, this property and the acquisition is all about horizontal development. So I wouldn't dwell too much on the vertical wells.

Operator

Our next question comes from the line of Andrew Coleman from Raymond James.

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

First question was just generally on the Bakken. I don't think I heard this in your prepared remarks, but I guess can you detail any sort of completions or sort of varieties you're all looking at, some of your competitors are looking at the slick water fracs et cetera, have you looked at any of that?

Charles B. Stanley

Andrew. And yes, we have. There's a constant monitoring and debate and discussion going on in our shop around optimal completion design. We've -- we can make some general observations about the larger the size of the job in general, the better the well performance. Up to a point. It's interesting that there've been different things tried, large, huge volumes of proppant pumped in by some operators in some wells with encouraging results. Others now are focused of fluid volume at the expense of or to minimize the amount of proppant or reduced proppant, and seeing similar results. So there's a huge sort of dichotomy there of results and strategies. Our current design hasn't changed radically from what we were pumping 12 months ago. We've increased the size some but we haven't radically changed it. And I think like in many plays in many basins, the completion design has got to be tailored to the specific area of the basin and the rock properties. In South Antelope, we're making great wells in what I think is some of the best rock, highest oil saturation in the basin and it may not need the huge hammer so to speak that some of the more marginal areas in the basin where, if we transported our completion design there, might result in an uneconomic well. Whereas a massive frac using a huge volume of sand, may result in an economic well. So I think we can look at what's going on around the basin, we can learn from it to a certain extent but you really have to be cognizant of the variability of both the Middle Bakken and Three Forks reservoirs across the basin and design your fracs for the rock that you have in your area.

Gabriel Daoud - Jefferies LLC, Research Division

Okay. All right. And then thinking about the Midcontinent as a package that you have on the market, I think some of the acreage based on the teaser map that's out there, is that you're pretty close to some of the Cana acreage. Is there any rovers on that acreage that the buyers of the Cana package might have over SCOOP acreage? Or are those 2 packages completely separate?

Charles B. Stanley

All right. So let me just make sure I understand your question, so the 2 packages that we announced were a Granite Wash package and a Cana package. And the Cana package includes the core of the Cana and acreage up dip and to the East of the core of the Cana that some operators call it stack play. It does not include the Southern extension into the so-called SCOOP plays. So that will be the next package that's out there. With respect to Rovers, there are in some of the JOAs there's rights of first refusal for our partners to elect to take out a competing bid. But in aggregate, those are relatively small in dollar wise but there are multiple Rovers out there. We're -- We wouldn't anticipate a major change in ownership, if you will, as a result of the Rovers. The stack acreage to the South that will be marketed next, I'm sorry, SCOOP stacked, I keep getting them mixed up. The SCOOP acreage to the South that will be marketed, it's about 7,500 or so net acres in that part of the play. And we've got additional, out of the 21 million or so a day of equivalent production there, there's additional -- that's about 1/3 of the total production volume, 7 million or 8 million cubic feet equivalent a day.

Gabriel Daoud - Jefferies LLC, Research Division

And did you say that the data room had opened for that or is that about to open?

Charles B. Stanley

It hasn't opened yet. We're still putting the stuff in the data room.

Gabriel Daoud - Jefferies LLC, Research Division

Okay. Is that a second quarter kind of [indiscernible]

Charles B. Stanley

We're going to try to get it done before the window closes on the 1031 exchange, which is in August. And we'll just have to see if we can get the bids in and select the high bidder by then. It's going to be a push.

Operator

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

Dan McSpirit - BMO Capital Markets U.S.

Just turning to the Williston Basin. You mentioned in your prepared remarks, a pilot program underway to evaluate down spacing. If you could elaborate on that, that is how many wells per DSU both Middle Bakken and Three Forks, and what could it mean for the inventory count?

Charles B. Stanley

Dan. It's focused on the Middle Bakken. It would result in a pattern of basically 6 wells per DSU in the Middle Bakken instead of 4. The real question is, as we look at some of the offset operators who've gone back into the older parts of the field and drilled brand new wells in the reservoirs where there've been substantial depletion, multiple million barrels of oil recovered from a wellbore, snuggled up next to those wellbores. And drilled new wells that have come on and appeared to perform not much differently than the first well in a spacing unit. And I think that's the most important sort of data point because ultimately, it could lead to another round of in-filling the existing powder. And I think the in-member on that obviously, is a doubling of the number of well locations and that really is something that nobody has tried yet in an area where 3 or 4 wells are already in spacing unit. There's a lot of oil in the reservoir as you know and we're -- the recovery factors are still pretty skinny on a total oil in place number. So ultimately, I think that's the real pilot that needs to be done, is to go back into an area that has 4 wells per section and see how much additional incremental recovery you get from an infill program doing that. We haven't started, we haven't done anything like that. We're drilling, it’s basically a block of virgin rock with 6 wells versus 4 wells right now.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And then turning to the Permian Basin, can you sketch for us the field-level economics on horizontal wells, that is, early drilling complete cost how they may trend over time, and then the recoveries on those horizontal wells.

Charles B. Stanley

It would all be speculation at this point, Dan. I mean, we -- when we did the acquisition, we assumed for a 7,500-foot lateral, between 550,000 and 600,000 boe and that well, and the well cost of $7.5 million in round numbers gross completed well costs.

Richard J. Doleshek

9.

Charles B. Stanley

9 for the -- I'm sorry, $9 million for the -- I said $7.5 million, 7,500 foot, $9 million gross completed well cost, sorry. And that's based on our [ph] AFE estimates and on looking at what other operators have been doing in the area, but I just think it's too early to give you meaningful economics on the wells until we get our own wells down with our own drilling experience and get some well performance on them. I think the 550,000 barrels EUR, BOE EUR is probably conservative based on what we've seen from offset wells. But again, it's too soon to give you any more color than that. I will say that those wells even with the cost and EURs that we assume generated very robust 40%, 50% IRR. So that's certainly acceptable, and I think we can do better than that.

Operator

Our next question comes from the line of Gregg Brody from JPMorgan.

Gregg W. Brody - JP Morgan Chase & Co, Research Division

Sorry if you addressed this on the call, it's just been a busy 9:00 slot. Just you've announced some of asset sales. Can you talk a little bit about sort of how you're thinking about redeploying the cash? And maybe just a little bit of a focus on how you're thinking about your leverage management and sort of the credit?

Richard J. Doleshek

Hi Greg, it's Richard. So we finished the quarter with $3.9 billion of debt, the revolver was north of $1.1 billion, and so the immediate use of proceeds when we close the transactions on June 30 and July 1, will be to pay down the revolver. You get back to below 1.9x, that multiple EBITDA, which is kind of where we were at the end of the year. So when we kind of view what we're going to accomplish in the first half of the year is putting our balance sheet back to kind of where it was prior to the Permian acquisition, and levering up to make that happen. I think you've heard us say, that we think we're comfortable in the 1.5x to 2x, debt multiple EBITDA range. So I think in terms of what to expect from us on a transaction basis, we'll be above that kind of on a run rate basis, that's where you should expect us to be.

Gregg W. Brody - JP Morgan Chase & Co, Research Division

And then just in terms of the agencies, have you gotten any color from them, how they feel about this sort of clearly you're conservative in your metrics but the reduction in size, is there any feedback from them, in terms of how that [indiscernible]?

Richard J. Doleshek

Yes, but I think both agencies put out notes related to the transactions but either you have put out notes or will put out notes today. And they're both sort of reaffirming what their positions were back in December when we announced the transactions. I think obviously, increased liquidity makes the agencies feel better as we decrease the amount of Field Services contribution, which is perceived as a more stable contribution, they've -- that sort of offsets the improved liquidity to some degree, so that's sort of the trade-off.

Gregg W. Brody - JP Morgan Chase & Co, Research Division

Okay. So do you think you are going to remain BB?

Richard J. Doleshek

Yes, with the transactions closing, I would be surprised if we don't -- if we do not retain a BA1 BB+ rating.

Operator

There are no further questions in the queue. I'd like to hand the call back over to management for closing comments.

Charles B. Stanley

Well thanks, everyone, for dialing in today. I realized when I answered Andrew Coleman's question around the SCOOP that I had too many numbers rattling around in my head and not enough coffee this morning. I said 7,500 net acres, that's the 7.5 million a day of net production on the acreage. The actual acreage in our SCOOP play is about 39,000 net acres, and I apologize for that incorrect number that I threw out. We look forward to seeing you all in the near future as we attend various conferences, and we also have several non-deal roadshows planned for later on this year. Thanks for your interest in QEP, and have a good day.

Operator

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.

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Source: QEP Resources' (QEP) CEO Charles Stanley on Q1 2014 Results - Earnings Call Transcript
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