QEP Resources' CEO Discusses Q4 2013 Results - Earnings Call Transcript

| About: QEP Resources, (QEP)

QEP Resources, Inc. (NYSE:QEP)

Q4 2013 Earnings Conference Call

February 26, 2014 9:00 AM ET


Greg Bensen – Director, IR

Chuck Stanley – Chairman, President and CEO

Richard Doleshek – EVP, CFO and Treasurer


Brian Corales – Howard Weil

Tim Rezvan – Sterne Agee

Hsulin Peng – Robert W. Baird

Andrew Coleman – Raymond James

Eli Kantor – Iberia Capital Partners

Brian Gamble – Simmons


Greetings, and welcome to the QEP Fourth Quarter 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host, Greg Bensen. Thank you, you may begin.

Greg Bensen

Thank you, Brenda, and good morning, everyone. Thank you for joining us for the QEP Resources fourth quarter and full year 2013 results conference call. With me today are Chuck Stanley, Chairman, President and CEO; 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 www.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 the SEC filings. In addition, we’ll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control, and we refer everyone to our more robust forward-looking statement disclaimer in 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.

Chuck Stanley

Thanks Greg, and good morning everyone. This morning I’d like to briefly touch on some operational results from the fourth quarter and full year 2013 and then touch on our plans for ‘14. Richard will then quickly review our fourth quarter financial results and full year results and walk you through our guidance assumptions for 2014. And then we’ll turn the call over for Q&A.

2013 was quite a year for QEP, we had record high levels of crude oil production, estimated year improved reserves, fee based processing revenue and perhaps most importantly record high EBITDA.

We accomplished these company records while decreasing net debt by more than $200 million and with a capital program that was equal to EBITDA. On the E&P front, our focus on allocating capital to the highest return projects in our portfolio, has resulted in a dramatic shift in our production and reserves mix as higher return, higher margin crude oil development projects dominate our capital investments.

QEP Energy EBITDA grew 17% from 2012 driven by a 62% year-over-year increase in crude oil production. Oil volumes accounted for 20% of total companywide production in 2013, up from 12% in 2012 and just 8% in 2011. Over the past four years, we’ve grown crude oil production at a 50% compound annual growth rate which has allowed us to grow QEP Energy EBITDA over that same four-year period at a robust 13% CAGR.

Clearly, we are making steady progress on a profitable rebalancing of our E&P asset portfolio and production mix and is bearing fruit in the form of steady EBITDA growth. To help accelerate this transition, yesterday we closed on a previously acquisition of significant new crude oil dominant development properties in the Permian Base in West Texas, which will provide QEP with more than 10 years of high return drilling inventory.

We’ve also launched our previously announced Midcontinent asset divestiture program and data rooms are now open for both our Granite Wash and Cana assets. By structuring the Permian Acquisition and the Midcontinent divestiture transactions as a reverse like trying to exchange, we are tax efficiently facilitating our entry into a second world-class crude oil province as we divest in non-core properties.

During 2013, we undertook several strategic initiatives unlock value in our Midstream gathering and processing business. In August of last year, we completed the IPO of our new Midstream master limited partnership, QEP Midstream Partners or QEPM.

The IPO of QEPM was one of the fastest and largest MLP IPOs in history and we raised net proceeds of approximately $450 million. The market clearly like the QEPM story, we priced an offering at the high-end of the $19 to $21 range, with an order-book that was multiple times oversubscribed. And QEPM units continue to trade well today, with an implied yield of approximately 4.5%.

In December of last year, we announced plans to unlock additional value for QEP shareholders by fully separating our Midstream company, QEP Field Services including its ownership of QEPM and the GP and Midstream assets 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 segments.

Turning to QEP Energy’s 2013 results, our total production declined slightly from last year. EBITDA grew 17%, primarily as a result of increased oil production. Crude oil reserves revenue represented nearly half of Field level revenue in 2013 and combined crude oil and NGL revenue comprised 65% of Field level revenue in the fourth quarter.

Back on February 4, we announced estimated year-end 2013 crude reserves for QEP Energy. Estimated total crude reserves were 4.1 trillion cubic feet of gas equivalent, up slightly from a year ago. As a direct result of our allocation of capital to the highest return projects in our portfolio, estimated proved crude oil reserves grew 25% to 149 million barrels. Crude oil represented 22% of year-end 2013 estimated proved reserves and that was up from 18% in 2012.

Perhaps more significantly the year-end 2013 SEC pretax PV-10 of our proved reserves was $6 billion, up 48% from year-end 2012. Please see our February 4 release if you like more details.

Now, let me give you a little more color on our operational results from the fourth quarter of last year and more detail on plans for 2014. As I do so, I’d ask that you refer to the slide presentation of the company that was released yesterday afternoon.

Our oil production increased 15% from the prior quarter, our natural gas reduction continued to decline due to the ongoing decline in the Haynesville and also due to the impact of some severe winter weather on our operations in multiple areas and due to some downstream maintenance of Pinedale.

In terms of 2014 guidance, please keep in mind that we assume no upstream remit in asset sales even though we have multiple assets in the Midcontinent for sale today. We’ll update guidance after the sales close.

Let’s turn to the individual area results. We had eight rigs in the Williston Basin at year-end, the same as in the third quarter but they moved around a bit. At the end of the year, we had six rigs working at South Antelope, which is one more than last quarter or the third quarter and two rigs working on the Fort Berthold which is down from three in the third quarter of last year.

Completion activity picked up in the Williston Basin with 26 QEP operated well completions in the fourth quarter, compared to 21 in the third quarter and 27 during the whole first half of the year. Overall, we remain very pleased with the technical results from the Williston Basin and with the future potential of the play.

We continue to evaluate the potential for increased well density on our acreage, we’re monitoring the results from several pilot programs that are being conducted by nearby operators. And we have our own pilot program underway to evaluate applicability of increased density development on our own acreage.

In early February, we released some new information about our South Antelope property that I believe is very compelling. Based on our year-end reserve work, EURs continue to track our initial expectations of roughly 1 million barrels of oil equivalent per well in both the Middle Bakken and Three Forks reservoirs.

As we drive efficiencies in our drilling and completion operations repair drillings, we’ve also made significant progress on completed well cost during the year with a reduction and actual gross completed well cost of more than $1 million from our initial assumptions at the time of the acquisition. And our well cost today are approximately $1.5 million less than nearby third party operated wells in which we have an interest.

The latest batch of QEP operated completed wells will come in at about $10 million gross drilled, completed and equipped well cost. In spite of initial delays that are downstream and weather related issues, our current South Antelope oil production has grown to levels that are commensurate with the company’s expectations at the time of the acquisition.

Finally, we had some great numbers around the value we’ve created through the South Antelope Acquisition in our subsequent development activity. We acquired the properties in 2012 for $1.4 billion and since that time, the cash capital expenditures have exceeded adjusted EBITDA from the properties by approximately $100 million.

At the end of 2013, the South Antelope proved reserves at a pretax PV-10 value of about $2.2 billion or approximately $700 million above the cumulative net investment through the end of the year. Including probable reserves and associated development cost, the year-end 2013 pretax PV-10 value of South Antelope was over $2.8 billion, nearly double the net capital investment today.

We’re excited about these results and we think it’s a great example of our asset evaluation and follow-on development skills and our sound and stringent capital allocation process. We’re optimistic that we’ll have similar results to share about our Permian Basin Acquisition in coming years.

We had some questions about location inventory levels remaining in the Williston Basin as we created some confusion yesterday at our reported PUD inventory, on the slides of the company that we released.

Let me give you a little background. At the end of 2012, we reported a total gross remaining location inventory of little over 300 locations at South Antelope and about 450 locations on a Forth Berthold reservation. At year-end 2013, that inventory was approximately 250 locations at South Antelope and about 400 remaining locations on the reservation.

The decline in PUD inventory on the reservation acreage was related to conversion of PUD locations to producing wells into our development schedule over the next five years that resulted in us for moving some PUDs from our inventory.

Field level crude oil process for all our QEP Energy dominated by the volumes from our Williston Basin, declined by about $10 a barrel from the third to the fourth quarter last year, due to lower benchmark prices, primarily related to pricing at Clearbrook.

QEP’s average basis differential increased slightly from the third quarter to over $10 a barrel, due primarily to decreases in Field level pricing in the quarter’s result of temporary widening of the basis.

Looking at 2014, and the Williston Basin, we have planned to invest about 55% of our total QEP Energy capital budget in the Williston Basin and are currently running eight rigs on our Williston properties. Please refer to slide 6 through 8 for more details on our Williston operations.

As I already mentioned yesterday, we closed on our new Permian Basin properties. At the close, the estimated net production from the assets, were just over 7,000 barrels of oil equivalent a day, which is about 66% crude oil. There are currently two operated vertical rigs running on the properties. We plan to add several additional rigs shortly, one of which will be targeting our horizontal wells and we will ramp through at least six rigs operated on the property by the end of the year, including at least three drilling horizontal wells.

After acquisition cost, we plan to invest approximately 15% of our total QEP Energy 2014 capital budget in the Permian Basin. See slide 9, for more details on the Permian Basin properties.

Turning to Pinedale, production volumes declined slightly compared to the prior quarter of 2013, as gas volumes declined about 14%, while NGL volumes more than doubled as a result of our election to recover ethane during the fourth quarter. While the ethane frac spread was near breakeven in the quarter, improved propane recovery as a result of running the plants in ethane recovery helped to improve the overall NGL frac spread.

Even after more than a decade of operation at Pinedale, we continue to improve our efficiency and drilling and completion operations and cut nearly a full day out of our drill times during 2013, down to an average of under, 12 days.

For the full year we completed and turned to sales 111 new Pinedale wells including 33 wells during the fourth quarter. QEP had an average 78% working interest in the new wells that were completed in 2013.

It’s important to note however that, of those 111 wells that were completed in 2013, there were 29 wells that we operate for third party, but in which we only own an overriding royalty interest, so a fair amount of our completion activity in the second half of last year will have a minimum impact on 2014 estimated QEP net production.

We plan to continue to run four rigs at Pinedale through 2014 and currently plan to complete between 110 and 115 wells. Remember, as we always do, we suspend well completion activity during the coldest months of the winter, so that reduces some volatility to production and activity levels during the coldest months of the year.

We have planned to invest about 15% of our total QEP Energy capital budget at Pinedale, see slides 10 and 11 for more details.

In the Uinta Basin, we continue to make good progress on our Red Wash Lower Mesaverde liquids-rich gas play. Last quarter we talked about early results from our fundamentally different well design that we think could radically alter the economics and the way we approach development of this significant asset.

Production performance from that first well continues to be very encouraging, and we’re now drilling our second well incorporating new design. We’ll provide more color on this approach as soon as we get more production data on the first well, improved ourselves with the second well that the new approach is repeatable.

With multiple trillion cubic feet of equivalent probable reserves in our 100% working interest 80% net revenue interest acreage position, clearly this project presents not only a significant future growth opportunity for QEP Energy but also for our Midstream business.

During the fourth quarter of 2014, in addition to the one rig we had running, drilling our new well design and a massive work-play we also had one rig running focused on drilling vertical oil wells in the Green River formation.

Currently we plan to invest in that 5% of our 2014 capital budget in the Uinta Basin, but we may reconsider that capital allocation with additional encouraging results from the alternate well design project is currently underway. Slide 12, shows more details on our Uinta Basin activities.

Turning to the Midcontinent, during the fourth quarter of 2013, we participated in eight outside operated wells through an average working interest of 19%, those were all in the Cana and Woodford. Recalling back in December, when we announced the acquisition of our Permian Basin properties, we also announced simultaneously our intention to sell Midcontinent properties to help fund the acquisition and to concentrate our operational investment focus.

As I mentioned earlier, our Cana, Woodford and Granite Wash data packages are already out in the market. Data rooms are open and we’ve had very strong interest from potential buyers. We structured the purchase of the Permian assets in the sale of Midcontinent assets, as I mentioned earlier as a reverse $10.31 exchange. And just to be clear, that means that we transfer the tax basis from the divested assets over to the newly acquired Permian assets.

We have 180 days from the February 25, closing of the Permian Basin Acquisition, in order to complete the divestiture of the Midcontinent assets in order to take advantage of the reverse $10.31 exchange.

Finally, to help with your modeling, the production from the first two Midcontinent asset packages, and I say first two because there are others to come including a package that we’ll have our assets including our scoop acreage, that will come down the road.

But for the first two, the Cana and Granite Wash, the current production is approximately 102 million cubic feet equivalent of gas per day. And that’s down a little bit from the 2013 average of 110 million cubic feet a day. And that included some impact of weather in the fourth quarter where we had some freeze-off in the western Midcontinent. Please see slide 13 for the location of the recently completed Cana wells that I mentioned earlier and for other details of the Woodford play.

At Field Services, EBITDA increased slightly from the third quarter despite an increase in EBITDA attributable to non-controlling interest associated with the QEP Midstream MLP that was $8.5 million for the fourth quarter.

Adding that $8.5 million of QEP Midstream EBITDA back to field services reported fourth quarter figures of sort of gross EBITDA of $65.3 million, which was up 17% from the prior year.

During 2013, Field Services brought along two major projects. Earlier in the year, we brought on the 150 million cubic foot day Iron Horse II cryogenic processing plant located in the Uinta Basin that came online early in the first quarter of last year. Iron Horse II operates under fee-based contract with half of the space committed to a third party and the other half committed to QEP Energy.

During the third quarter, Field Services also completed construction of expanded rail loading facilities associated with our 10,000 barrel a day expansion of our NGL fractionation facility at Blacks Fork in western Wyoming. This facility will provide additional options for marketing our purity propane, ISO and normal butane, and gasoline range products to what are, oftentimes, premium value markets both locally and regionally, either by trucks or across the U.S. by our expanded rail loading facilities at the plant.

In the fourth quarter and now in the first quarter of 2014, the flexibility of end-market supported by the new fractionation facility has resulted in improved NGL pricing for field services.

As I mentioned earlier, we’re pleased with the execution of our QEP Midstream partners or QEPM MLP IPO last August. As a reminder, QEP Midstream contains a subset of QEP’s gathering assets primarily located in the Green River Williston and Uinta Basins in the Western U.S.

QEP continues to own gathering and processing assets at Field Services, which are obviously candidates for future drop-downs. In December 2013, we announced our intention to separate Field Services from QEP we also provided an update on this process in late January. And we continue to work diligently with our advisors on the process and are making good progress on preparing SEC filings and other documents to affect the separation.

We planned to invest $80 million of capital on Field Services projects in 2014 including the capital investment at QEPM.

So, looking forward, 2014, we viewed 2013 as a very successful year for QEP as we continue to dramatically shift the production mix of QEP Energy’s assets from one dominated by natural gas to one that is more balanced.

Included the forecasting growth in 2014, we expected compound annual growth rate in our oil production in nearly 50% from 2010 through the end of this year. We intend to continue making significant progress on rebalancing our E&P asset portfolio, and production mix this year as we execute on development of our newly acquired Permian Basin properties and on, as we focus on continued development of our other assets, while divesting of non-core Midcontinent properties.

While, we expect natural gas volumes would decrease again this year, allocating capital with higher return oil projects should lead to continued strong crude oil growth and attended growth in EBITDA.

We also made significant progress highlighting the value of and improving the competitiveness of our Midstream business in 2013 through the formation of IPO of QEPM. In 2014, we expect to unlock additional value for shareholders as we continue to execute on our plan to fully separate Field Services from QEP resources.

During February, we welcome three new directors to our board, Tom O’Connor, Bill Thacker and Bob Heinemann. Tom O’Connor brings a wealth of experience across the natural gas business including his most recent role of Chair and CEO of DCP Midstream LLC, one of the largest Midstream companies in the U.S. Tom’s brings experience will be invaluable as we work towards separation of Field Services from resources, from QEP Resources.

Bill Thacker, also brings additional significant Midstream Energy expertise to our board, including his time of Chair and CEO of Texas Eastern Products pipeline company and is non-executive Chair of Copano Energy LLC. Prior to Texas Eastern, Bill worked for Unocal Corporation in a variety of positions, including President Unocal Pipeline Company. Bill has agreed to serve on our board until the completion and the separation of our Midstream business QEP Field Services from QEP Resources.

Bob Heinemann brings significant E&P expertise to our board through his experience as President, CEO and a Director of Berry Petroleum, where he developed and executed the company’s growth and capital allocation strategies.

During his tenure, Berry increased production from approximately 15,000 barrels of oil equivalent per day to over 40,000 barrels of oil equivalent per day, and increased total enterprise value from $375 million to approximately $4 billion.

Bob’s replacing Keith Rattie, who is retiring from our board. On behalf of our board, our shareholders and our partners, I’d like to thank Keith for his many years of dedicated and valuable service. And we’d also like to welcome Tom, Bill and Bob to the board. And we look forward of benefiting from their extensive experience in the Midstream and upstream sectors as we work together to create value for all of QEP Resources shareholders.

As I look toward the end of 2014, 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 and a variety commodity price market conditions.

The ramp in liquids production will continue at the midpoint of our crude oil and NGL production guidance, combined liquids production for 2014 should average over 50,000 barrels per day. And that’s a 25% year-over-year increase in total liquids production volumes.

Looking at the midpoint of our guidance, and using the same net realized process as 2013 which aren’t that different in fact from today’s strip prices QEP Energy should deliver double-digit EBITDA growth again this year. And with substantial footprints in two premier U.S. oil plays, the Permian and the Williston Basin, and a deep inventory of low cost liquid rich gas projects, we’re confident that our portfolio can support multiple years of profitable growth.

With that, I’m going to turn the call over to Richard.

Richard Doleshek

Thank you, Chuck. Good morning everyone. Chuck has discussed our operating results, now to give you some color about our financial results.

For the full year we generated $1.537 billion of adjusted EBITDA which is record for the company. And if we included the public’s 40% share of QEP Midstream partners, EBITDA would we reported would have been $1.55 billion.

For the fourth quarter, EBITDA was $377 million. When compared with fourth quarter of 2013 to the third quarter of the year, our results were hurt by weather related issues that negatively impacted production. And weaker oil prices partially offset by better results in QEP Field Services.

QEP Energy reported equivalent production of 75.1 Bcfe, flat from the third quarter due to weather related issues, declining volumes in Pinedale as we suspended completion activities for the winter and continued decline in Haynesville.

Oil production grew by 15% in the quarter by using the 621 equivalent conversions the growth in liquids volumes then offset to gas volumes decline. Average net fuel level equivalent price realizations were essentially flat from the third quarter and overall net realized prices were approximately $0.19 per Mcfe higher driven by the growing contribution of oil to our revenue stream and a larger contribution from our commodity derivatives portfolio.

From an EBITDA standpoint, the $377 million generated in the fourth quarter was $18 million lower than the third quarter, and $13 million lower than the fourth quarter 2012. QEP Energy contributed $320 million or 85% of the average fourth quarter EBITDA and QEP Field Services contributed $57 million or about 15%.

QEP Energy’s EBITDA was down $21 million or 6% compared to the third quarter, and QEP Field Services EBITDA was up $5 million or 10% as compared to the third quarter and $1 million higher than the fourth quarter 2012.

Included in the public for 18% share of the MLP’s EBITDA, Field Services EBITDA would have been $65 million or 70% higher than the fourth quarter of 2012. Factors driving or fourth quarter EBITDA include QEP Energy’s production which was 35.1 Bcfe or 2.9 Bcfe lower than the 78 Bcfe reported in the third quarter.

Oil volumes were 3.04 million barrels, up almost 400,000 barrels or 15% from the third quarter levels and NGL volumes were 1.43 million barrels up 280,000 barrels or 24% from the third quarter due to partial recovery of ethane during the quarter.

The quarter’s direction was 10% lower than the 83.9 Bcfe produced in the fourth quarter 2012. Natural gas volumes were down 13% in the third quarter of the year and down 21% from the fourth quarter of 2012. Haynesville volumes were down 42% from a year ago as for natural declines and no QEP operated growing activity in 2013.

Adverse weather conditions did impact our fourth quarter production by about 2.5 Bcfe. We continue making progress increasing the crude oil component of our total production. In the fourth quarter of 2013, crude oil comprised 24% of our net production compared to 17% a year ago.

Our guidance for natural gas volumes for 2014 was 175 Bcf to 190 Bcf, a decline approximately 17% at the midpoint of guidance due to continued decline at Haynesville. Our forecast for oil volumes for 2014 is 14 million to 15 million barrels up 42% from 2013 at the midpoint.

Our guidance for NGL volumes for this year is 4 million to 4.5 million barrels, the mid-point of which is down about 12% from 2013, assuming that we will remain an ethane rejection all year.

QEP Energy’s net realized equivalent price which includes the settlement of our commodity derivatives averaged $6.90 per Mcfe which was $0.19 per Mcfe higher than realized in the third quarter of the year and $0.73 per Mcfe higher than we realized in the fourth quarter of 2012.

QEP Energy commodity derivatives portfolio contributed $41.5 million of EBITDA in the quarter compared to $27.2 million in third quarter of the year and $74 million in the fourth quarter of 2012. The derivatives portfolio added about $0.55 per Mcfe to QEP Energy’s net realized price in the quarter compared to $0.35 per Mcfe in the third quarter of the year to $0.88 per Mcfe in the fourth quarter of 2012.

QEP Energy’s combined lease operating and transportation expenses were $113 million in the quarter, up from $109 million in the third quarter of the year and up from $111 million in the fourth quarter of 2012.

On a per unit basis, lease operating expenses were $0.68 per Mcfe and transportation expense was $0.82 per Mcfe. Our guidance for lease operating and transportation expenses for 2014 is $1.50 to $1.65 per Mcfe for full year 2014.

Finally, QEP Field Services fourth quarter EBITDA was $56.8 million which was about $5.2 million higher than the third quarter and year. Our current EBITDA is not included $8.5 million which is the 40% portion of the MLP’s EBITDA that QEP does not own.

Processing margin was down about $3 million or 8% in the fourth quarter compared to the third quarter as a result of lower deficiency payments offset by higher NGL sales but gathering margin is up $10.5 million or 28% compared to the third quarter due to higher efficiency payments.

Reported net loss attributable to QEP at $52 million in the quarter and was driven by an $89 million impairment which included writing off $59.5 million of goodwill that was on our balance sheet relating to the 2001 SEI Acquisition, we also experienced some expiring leases and had a minor amount of producing property impairment.

Sequential G&A expenses were up $5.6 million, primarily a result of higher expense for outside professional services, bad debt expense and contributions. Our guidance for G&A expenses for 2014 is $190 million to $210 million.

Capital expenditures on accrual basis were E&P drilling and completion activities or $1.45 billion in capital expenditures and our Midstream business were $86 million. Initially we reported $41 million of acquisitions. If you exclude acquisitions for the year, our capital spending was about equal to our EBITDA.

We are forecasting the midpoint for 2014 capital spending to be about $1.7 billion for QEP Energy, of that $80 million for QEP Field Services and $25 million for corporate, again excluding acquisitions.

With regard to our balance sheet, at the end of the quarter, total assets were $9.4 billion and shareholder equity is about $3.4 billion. Our debt at the end of the year was approximately $3 billion which is about 1.95 times multiple of our 2013 EBITDA.

Our debt at the end of the year consisted $2.2 billion of senior notes, $300 million under our term loan and $480 million under our revolving credit facility.

And as Chuck mentioned, we closed the Permian Basin acquisition yesterday. And we funded that acquisition with $50 in cash, $300 million drawn under our term loan which we expanded to $600 million for the acquisition without changes in pricing or maturity of the facility. And the remainder of the purchase price was drawn under our revolving credit facility which currently has about $450 million availability.

We’ll begin recording the financial and operating results of the acquired properties beginning in March, so our first quarter 2014 results will only include one month of contribution from the transaction.

With that Brenda, we’d like to open the line for questions.

Question-and-Answer Session


(Operator Instructions). And our first question comes from the line of Brian Corales with Howard Weil. Please proceed with your question.

Brian Corales – Howard Weil

Good morning, guys. Could you, the 102 million for the Cana and Granite Wash, how much is oil and how much is gas or what percent oil?

Chuck Stanley

The liquids break down is about – it’s about 40% liquids and 60% natural gas Brian.

Brian Corales – Howard Weil

And is that split evenly with oil and gas?

Chuck Stanley

It’s about 2:1 on the liquid side, it’s about 2:1 ratio NGLs to condensate.

Brian Corales – Howard Weil

And then, the Permian, you mentioned both vertical and horizontal rigs, is vertical, is it the whole acreage or is it to try and learn a little bit more based on the success horizontal around you, I’m just maybe – question what vertical?

Chuck Stanley

It’s both Brian in some areas we feel like we need some more open hole log data and cores. And obviously, the only way to get those is drilling vertical wells. There is, a portion of the acreage that we need to establish production in the Atoka in order to hold up the deeper part of the section.

So there is some acreage remaining that needs to be (inaudible) before we shut down a vertical program. But it’s also to help drive additional data collection.

A lot of the wells out there, most of the wells out there are drilled and cased and case hole logs are run. And that just doesn’t give us the detailed, physical data that we need in order to fully evaluate all of the horizontal targets. So, the team is requested more overhaul logs and some cores to further calibrate our Petrophysical model.

Brian Corales – Howard Weil

Okay. And then Chuck, kind of big picture, I mean you’re going through obviously this kind of portfolio rationalization and assuming the entire spend or sale of the Midstream. And what do you envision your E&P portfolio looking like, I mean, I know you have some core assets in the Bakken. But how does that you enter the Pinedale, the Haynesville and Permian, are those going to be bigger, smaller, what would you – what ultimately is QEP going to look like?

Chuck Stanley

Well, I think it would be fast forward, we’ve got great position in the Williston Basin, continue to develop the assets that we have there, substantial remaining inventory. The Permian Basin Acquisition is a new entry for us, there is some opportunities there that continued to grow that position and starting just in capturing some of the working interest partners in some of the leases that the minority working interest partners, private company interest.

So, two core world-class oil basins in places where we think we can continue to do what we do best which is manufacture holes in the ground, we’ve demonstrated our ability to do it over the years at Pinedale, we’re doing it now in the Williston Basin where we’re seeing a substantial decrease in completed well cost.

At the end of the day, the profitability these resource plays are driven by the ability to basically occupy pads and drill multiple wells from pads to drive down cost and generate superior returns.

So, two oil plays with good footprints in each of them and we’ve studied the basins, we know where we wanted to be and we’re in the right areas of both those basins. Then, Pinedale is a great gas asset we continue to develop that asset. It’s profitable, it has substantial remaining inventory in over 600 remaining locations. So, it’s visible inventory in the future.

The Uinta Basin, is the sleeping giant in our inventory if you will in that – it’s a huge acreage position, it’s 100% working interest, high NRI, 87% NRI, a very exciting first well that is down has been producing now for little over six months.

I’m circumspect about giving a lot of detail on it for competitive reasons right now but it’s a step change in our view of the economics of the play. And it would move the sort of merit order in capital attraction if you will, capital allocation of that play up substantially in our portfolio and give us a huge runway of future development opportunities based on one well.

Now we have another well that’s drilling, we’re learning a lot on how to drill these wells because the rock is a challenging drilling target, its hard cemented stand-stone at each bit. We’ve found some bits that are real better in it, but we’re still on a steep learning curve. But the first well we drilled, we only think we got about a third of the completion that we thought we were going to get. And we still had a well that was dramatically better than our pre-drill expectation.

So, stay tuned. We’ll hopefully have some results on the second well within a few months. Sort of hopefully by the end, when we come back to you with our first quarter results.

And then, the Midcontinent as we said, I view the divestiture of the Midcontinent assets is just sort of a logical pivot away from a gas dominant asset and asset where we made a lot of money over the years but it doesn’t fit our business model for large continuous acreage positions where we can manufacture holes in the ground, it’s a more fragmented position. It’s a position where for instance at Cana, it’s a largely non-hop driven activity level so it again doesn’t fit our criteria for operated contiguous acreage.

The Haynesville is an interesting option on gas and obviously one that today is attracting no capital. But the production is continuing to decline. But we know from our previous experience there that we can drill wells there that are quite economic in the $400 to $450 million gas price environment, it’s just that today it’s at the end of our merit order in capital allocation.

Brian Corales – Howard Weil

That was helpful. Thank you.

Chuck Stanley

Thank you.


Thank you. And our next question comes from the line of Tim Rezvan with Sterne Agee. Please proceed with your question.

Tim Rezvan – Sterne Agee

Good morning folks. Chuck, you mentioned, it appears that drop-downs are still on the table as the Midstream separation gets sorted out. I couldn’t help notice that the $500 million repurchase allocation you’ve discussed is equal to the credit facility on QEPM. Can you give any color on the timing or possible funding for this repurchase given all the moving pieces in the portfolio?

Chuck Stanley

The size of the revolver and your share repurchase totally fortuitous. When we put up, when we setup QEPM, and thought about a credit facility for the company, we identified a credit facility size that would allow us to fund one or two dropdowns without having to go directly to unit issuance prior to the first year anniversary because as you know basically we have to refresh the registration of all these units during the first year.

The magnitude of share repurchases was something that the board felt comfortable looking at the leverage metrics in balance sheet of QEP resources and looking at our capital needs and our capital investment programs over the next several years. So, totally fortuitous

With respect to drop-downs, yes, they are still on the table. There is nothing in our announced strategy around separating our mid-stream business that precludes us from doing a drop-down prior to the full separation of Field Services from resources.

Tim Rezvan – Sterne Agee

Okay. Thanks for the color there. And then just one last one, I wanted to clarify some of your closing comments, did you say you think you’re going to see 10% EBITDA growth from QEP Energy in 2014?

Chuck Stanley

Right. If you just look at our sort of midpoint of our guidance, and assume pricing that is sort of in-line with last year’s realized prices which is not far from the current forward strip. We get to low double digit EBITDA growth. And at the high end of the range is mid-teens EBITDA growth. So it looks like at Energy sort of year-over-year comparable EBITDA growth from last year.

Tim Rezvan – Sterne Agee

Okay, thank you.

Chuck Stanley



Thank you. And our next question comes from the line of Hsulin Peng with Robert W. Baird. Please proceed with your question.

Hsulin Peng – Robert W. Baird

Good morning, gentlemen. So, I want to get more color about your 2014 production guidance. First, can you talk about how much production is attributed to the Permian acquisition, I guess consistent with your prior expectations. And secondly, also the gas production decline year-over-year was fairly meaningful.

And I know you talked about Haynesville production decline but can you talk about the key drivers, I think Pinedale looks like it’s also going to decline if I model that correctly?

Chuck Stanley

Well, let me start with the last part. Pinedale is flat up slightly year-over-year. The contribution from the Permian around 1.5 million BOE I think if I’m – 1.5 million barrels plus the gas. And then, the Haynesville question, Haynesville continues to define I think we’ll forecast about 30% to 40% decline, 35% is sort of the midpoint of our forecast for decline from the existing wells in the Haynesville. Steeper decline than we had anticipated and taken indication of the nature of the rock – reservoir rock in the Haynesville. And that is the biggest driver of the year-over-year forecasted gas decline and it’s just a direct reflection of non-allocating capital to that play.

Hsulin Peng – Robert W. Baird

Thank you. And difference on the midpoint, I know you mentioned that in fourth quarter, productions was impacted by adverse weather. I guess I maybe – can you talk about what your current production is and how that looks like in 2014?

Chuck Stanley

Well, current production volume is around 101 and 102 million cubic feet, equivalent a day. For the sale assets and I don’t have the remaining, it’s about $30 million or so, $35 million a day equivalent for the remaining assets that are not on the block yet.

Hsulin Peng – Robert W. Baird

Okay. And how will that – what does that look like for ‘14?

Chuck Stanley

Well, when we talk about that – we think about that as a sort of flattish production profile over the year.

Hsulin Peng – Robert W. Baird

Okay, got it. And then kind of moving over to Midstream separation, I used to, I mean, I know so you’re already working on that pack. But are you still talking to other third party for potential other alternatives, can you talk about the three?

Chuck Stanley

Richard, do you want to take it?

Richard Doleshek

Yes, sorry, in the strategic initiatives, press release a couple of weeks ago we talked about a parallel path where we are filing the Form 10, which is the equivalent to the S1 registration segment, the SEC and we’re in the middle of the period there. But we’re also running the parallel path that’s working at the other sort of strategic alternatives whether that’s a straight out sale, whether that’s a merger or that’s a spin merge, etcetera, etcetera.

So, we got lots of sticks in the fire I guess on the separation front, the one that we can fold, the most directly is the Form 10 file which is the spin transaction but we’re spending lots of time on with our advisors on all the alternatives.

Hsulin Peng – Robert W. Baird

Okay. So that’s still under table. And then, I guess, on this train, quick questions on the financial result. The data, there is a line item called other gathering revenue for Midstream. And that number has come up to the last few quarters to up to the $20 million. Can you just kind of remind us what’s included in that line?

Richard Doleshek

Yes, again it’s Richard. We put deficiency payments there, so that the math works, when you look at the gathering volumes and the gathering revenue, you can back into that per unit, we charge. If we were to prove the efficiency payments with no associated volumes that make those rates look unusual. So we bump into deficiency payments into that other gathering revenue stream. And we had a very large payment that we recorded in the fourth quarter in tune of $13 million odd that made that number very high relative to the previous quarters.

Chuck Stanley

And Hsulin, you remember back several years ago when we diverted gas away from Blacks Fork to a third party processing plant as we were completing Blacks Fork II and doing a tie. And we actually process gas at a third party plant. And we reported the revenues associated with that processing in that same bucket that same line item, so it didn’t distort the processing results.

Hsulin Peng – Robert W. Baird

Okay, got it. And the last question and I’ll back someone else, ask question. Is to, you talk to NGO pricing outlook, I know that 4Q NGL pricing was down meaningfully, a bigger decline even in terms of prices of TI, was there any particular reason and what is your forecast internally for 2014 please?

Chuck Stanley

The main driver Hsulin was that we chose to go into ethane recovery during the quarter. And that obviously diluted the value of the, per barrel. Going forward, we’re in and out of ethane recovery, we’d have some very high natural gas prices spot in a daily natural gas prices here, caused us to go into ethane rejection. Today I think we would be in ethane recovery because gas prices have pulled back.

So, we’re managing the plants to maximize the value of the NGL stream, but going forward I would expect to continue to see natural gas price volatility and some volatility in liquids pricing that will continue to make our average NGL price somewhat volatile as we turned the plants up and down and some days recover ethane and some days we don’t.

Hsulin Peng – Robert W. Baird

Okay, I’ll go back in the queue. Thanks.

Chuck Stanley



Thank you. And our next question comes from the line of Andrew Coleman with Raymond James. Please proceed with your question.

Andrew Coleman – Raymond James

Good morning fellas and thanks for taking my questions. I guess, first question was so you’re going down a parallel process looking at potential drop-downs as well as the full separation. I mean, should we infer anything in terms of the timing of ultimate decision on the full process being closer to the second half of ‘14 or if you think it could be done earlier in ‘14?

Richard Doleshek

Andrew, its Richard. If you look at just the calendar and how year-end financials were at first core financials called out audits. If you look at the calendar that we established last year for the MLP, that’s probably not a bad count or to think about with regard to navigating the SEC process with financial service being audited. We’ll be prepared and audited and submitted. So I think if you look at ‘13 and sort of think about what that means, but ‘14 is probably not a bad proxy.

Chuck Stanley

And with respect to your comment about drop-downs, that’s – I kind of think of that as mutually exclusive and during this time when we’re working through the separation of the Midstream business from resources, we’re going to continue to run the partnership according to our original plan.

So, we’re growing the distribution, we grew at a penny. And we have the ability to continue to grow with the existing assets but we also are focused on making sure that we continue to put assets down at the partnership level to support our original plan of growing the distribution between, 10% to 20% on annual basis.

Andrew Coleman – Raymond James

Okay, thank you. And then, thinking about the share buyback, I think if I heard Richard’s comments, we had to put $300 million more term loans, we have about $400 million capacity on the credit facility right now. I guess, not knowing that the ultimate end result on the asset sales, should we be thinking about their – sort of looking at the, what your credit facility might be readjusted to in the second quarter, as we start that process. And do you think that might give you any extra capacity to I guess, accelerate the share buyback?

Richard Doleshek

Andrew, it’s Richard again. Remember, our credit facility is a straight corporate facility, there is no barring base REIT determination that goes along with asset sales. So, while we would have to go back to the bank to get approval to sell those assets, I’m not sure we expect a reduction at credit facility. I think it’s more likely that the credit facility gets restructured when the separation occurs, because all of a sudden, you’ve got a subsidiary that’s going away.

But in terms of the assets – the mid kind of asset sales, we don’t really envision any change to the structure of the term loan or the revolving credit associated with those – with the asset sales.

With regard to the $500 million facility beyond the MLP, we talked about putting in place such that we could facilitate drop-downs without having to refresh the registration statement. And we don’t become self-eligible until the day after the one-year anniversary.

So, we have that facility in place, I think it’s safe to say that we in this space, using that facility to facilitate a drop-down from resources to the MLP, most likely that one-year anniversary day. So, I think in terms of timing of what’s going on, with regard to the share purchase, we certainly want to get some visibility around the asset sales and how that’s going to reduce the leverage on the balance sheet and combine the timing of the first drop in MLP before we crystallize what we’re going to do in terms of the share repurchase program.

Andrew Coleman – Raymond James

Okay. All right, so we could get some acceleration there and you’ll – I guess, the last question is looking at I guess kind of a combo here I could squeeze to, is also still package I guess if you could maybe give me an idea where that acreage is in relation to the maps that are out there currently showing your Cana stack package.

And then, second of all, on the production of the $100 million that you’re talking about right now is any of that still shut in with weather impacts?

Chuck Stanley

The answer to the second question is no, there is no material shut-ins now. And on the scoop you set the weight for the data package to come out and you’ll see the acreage. I mean, it’s scattered acreage across the scoop play. And we’ll have that stuff will be out in the data package here, shortly.

Andrew Coleman – Raymond James

Okay. Thank you very much. Good luck.

Chuck Stanley



Thank you. And our next question comes from the line of Eli Kantor with Iberia Capital Partners. Please go ahead with your question.

Eli Kantor – Iberia Capital Partners

Hi, good morning guys.

Chuck Stanley

Good morning, Eli.

Eli Kantor – Iberia Capital Partners

I was hoping to get a little color on how you guys are thinking about potentially building out the oil inventory going forward, it seems like the focus recently in Williston and Permian has been on de-risk areas where pricing is pretty competitive more on less proven acreage which we may carry achieve a price tag or on minimizing exploration risks?

Chuck Stanley

Eli, that’s a great question. I think what we’re seeking as a balance between obviously cost and risk and one thing that we can do is, as we demonstrated what the Antelope – South Antelope Acquisition, we bought into an area that was pretty substantially de-risk but where we thought we could apply our skill-sets in particular the whole manufacturing to create significant additional value.

As I said, at the time of the acquisition, we like to focus on contiguous acreage blocks, stacked reservoirs, we like crappy conventional reservoirs rather than pure Shales because we think that they have a much more reliable tendency to give up liquid hydrocarbon in a predictable way.

You don’t have ugly surprises around reservoir property changes and fluid property changes like you do in shales with retrograde condensates. And so it’s taken us to areas where we’ve identified decent rock and all the sort of technology and G-Wiz and efficiency gains that you can throw at an asset, won’t overcome marginal to poor quality geology.

And so, our core focus has been on identifying areas in basins where we think there is a set of reservoirs that we can work on and deliver value to our shareholders through whole manufacturing and through driving down costs through our sort of culture of developing assets and not jumping all over the place.

Can we also have as a part of our portfolio strategy, some higher risks, more exploratory acreage that would obviously hopefully be at a lower cost? Yes, that’s not precluded in our strategy. But obviously, it really does require some patience in converting that acreage to future production. So, we’re looking at opportunities like that. The interesting thing is, in some of the recent transactions, we’ve seen what I would call exploratory acreage traded values, it’s not just similar from evaluation that we’ve put on acreage that we’ve acquired.

Eli Kantor – Iberia Capital Partners

I understand. One other question from me I guess, on the Mesaverde. I understand you guys not wanting to discuss details of this new completion design. But wondering how quickly you could ramp activity with the size of that ramp I look like, there is new completion in line if we can prove that repeatable?

Chuck Stanley

Reasonably quick, the Uinta Basin is federal lands one of the leveling steps is just getting drilling permits out of the BLM which takes time. But the good news is that well results would suggest that we might not need many rigs and we might not need to drill a large number of wells to get a pretty quick production response.

Eli Kantor – Iberia Capital Partners

And just, while I take a look at your completion activity in 4Q versus what you did in second and third quarter, and I spoke with Greg about a little bit. But it looks like you’re running one rig, good number of wells that you actually completed kind of fell quarter-over-quarter. Is that just a product of moving into pepping some new zones versus more had the dominant in second and third quarter?

Chuck Stanley

Are you speaking about the Uinta Eli?

Eli Kantor – Iberia Capital Partners


Chuck Stanley

Yes, the one rig was basically drilling through the quarter and no completions occurred as a result of this radical change in our well design.


Thank you. And our next question comes from the line of Brian Gamble with Simmons. Please proceed with your question.

Brian Gamble – Simmons

Good morning, guys. A couple quick ones. On the production impact in the fourth quarter, you mentioned 2.5 Bcf. I know you said nothing left in the Cana that’s shut in. But as far as that total impact, any carry-over into Q1? And then in that same vein, is there anything abnormal about the Pinedale drilling this year versus previously or should we expect the same type of seasonality that we would normally expect in a given year?

Chuck Stanley

So, there is probably a little carryover in the first quarter as we had some cold weather in January as well that impacted production a bit but not anywhere near as it was in December. We also had some unscheduled maintenance that I mentioned in the fourth quarter at Pine Dale that impacted volumes for a few days as well.

On your second question, as far as drilling activity at Pinedale four rigs running, same sort of completion activity. I think we’re looking at maybe a handful or more completed wells in ‘14 versus ‘13, 110 to 115, five or six more than last year.

The big variable last year, with respect to QEP Energy production was, I mentioned to you that in my prepared remarks that we drilled and completed a number of wells for a former affiliate Wexpro Company. And those wells while we operated them, we don’t have an actual working interest in them.

So, we only have a very small overriding royalty interest. So there is lot of drilling and completion activity conducted by QEP, that resulted in no production impact in the second half of the year from this forget the number of wells, 20 some wells that we completed – drilling completed for Wexpro. That number would be down some in 2014, there would still be some wells I think, it’s somewhere around 10 or 12 wells that was drilled into Wexpro this year.

So, the impact on correlating activity and completion levels versus production response will be substantially less for the sort of those low working, zero working interest wells in 2014.

Brian Gamble – Simmons

And on the Williston, good cost control there. You mentioned the expectation that it continues to improve in 2014, any type of magnitude that you want to provide for that? Are we talking another $1 million by the end of the year or are we just talking minor improvements as the year progresses? How would you do that?

Chuck Stanley

I think we implement the efficiencies, there is trade-offs obviously between completion design and optimizing recoveries in the wells versus cutting costs. And one way to cut cost is to punch model our jobs and fewer stages. And that’s like the right answer.

So, let’s – let us continue to focus on driving down the incremental cost on a dollar-by-dollar basis, can we get another $1 million out of the well cost. I think that’s going to be tough, given the area where we’re drilling and the size of the frac jobs we’re pumping in the well results, we’re getting, we don’t want to mess it up frankly.

Brian Gamble – Simmons

Great, and then shifting to the Permian, quickly. You mentioned, obviously, your capital spending plan. You mentioned the rigs that you’re planning on running. You mentioned six by year-end. Then you made a remark about the potential for more than three horizontals. If you went to, say, four or five horizontals, would it be within that six-rig cadence and if there was incremental rigs, would there be incremental capital on top of the $1.8 billion spending level or would you be reallocating that from another basin?

Chuck Stanley

It’s too early to say how we will reallocate. We probably would reallocate the increment, the base cases that we have basically three regular horizontal wells out of the total six. That would likely just shift, we may drop one vertical rig and add a horizontal rig.

Let us get out there obviously we just closed on the property yesterday. Let us get out there, get some wells down get some horizontal results. And that’s going to drive the sort of the – the rig allocation methodology if you will between horizontal and vertical.

Brian Gamble – Simmons

Great. I appreciate that, Chuck.

Chuck Stanley



Thank you. Ladies and gentlemen, this concludes our question-and-answer session. I’d like to turn it back over to Chuck Stanley for closing remarks.

Chuck Stanley

Well, thank you all for dialing in today. And thank you for your interest in QEP. Both Richard and I will be on the road, Richard later today and I will be on the road next week involved in several conferences and doing some one-on-ones with their investors. Thanks for dialing and thanks for your interest in the company.


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

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