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QEP Resources (NYSE:QEP)

Q3 2013 Earnings Call

November 06, 2013 9:00 am ET

Executives

Greg Bensen - Director of Investor Relations

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

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

Analysts

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

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Eli J. Kantor - Iberia Capital Partners, Research Division

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

Operator

Greetings, and welcome to the QEP Resources Third Quarter Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Greg Bensen, Director of Investor Relations for QEP Resources. Thank you, Mr. Bensen, you may begin.

Greg Bensen

Thank you, Manny, and good morning, everyone. Thank you for joining us for the QEP Resources Third Quarter 2013 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; Perry Richards, Senior Vice President and Head of our Midstream business; and joining us for his final earnings call before his retirement, Executive Vice President, Jay Neese. If you have not already done so, please go to our website, www.qepres.com, to obtain copies of our earnings release, which contains tables with our financial results and a slide presentation with maps and other supporting materials.

In today's conference call, we will use a non-GAAP measure adjusted EBITDA, which is referred to as adjusted EBITDA in our earnings release and our SEC filings, and is reconciled to net income in the earnings release with the SEC filings. In addition, we will 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 SEC filings.

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

Richard J. Doleshek

Thank you, Greg, and good morning, everyone. In terms of reporting our results, we issued a financial and operating results news release yesterday in which we reported third quarter 2013 operating and financial results, we updated operating activities in our core areas, we updated our guidance for 2013. Chuck will provide more color on our operating activities and updated guidance for 2013 in his prepared remarks. We continued to gain operational momentum in the third quarter and we accomplished an important corporate objective with the successful IPO of our midstream master limited partnership, QEP Midstream Partners LP. With regard to the MLP, let me say how proud I am of the accomplishments in the IPO. This is one of the fastest transactions to market in terms of the time between when the original S-1 was filed and when we priced the offering just 91 days. The offering was extremely well received. It was oversubscribed multiple times, had 70% institutional ownership and it was anchored by some of the most well-regarded institutional investors in space. The IPO price is at the high end of the range, $21 per unit, which resulted in the evaluation that reflected a 14x multiple of forecasted EBITDA and a yield to investors of 4.76% based on the minimum quarterly distribution. Our only disappointment was the reaction or lack thereof, of QEP's stock prices in the transaction.

MLP does have an impact on the data we report in our financial statements. We continued to consolidate the results of MLPs operations throughput, revenue, expense, capital, et cetera, but we deduct the 42.2% financial results for the portion of MLP that we don't own in the [indiscernible] that labeled noncontrolling interest. We can discuss that more in Q&A if you want.

Turning now to our financial results, we generated $395.1 million of EBITDA in the third quarter, which is a record for the company. If you include the public shares of MLP's EBITDA, that excludes the nonrecurring charge in the quarter, we would have reported EBITDA of about $405 million. In comparing the third quarter of 2013 to the second quarter of the year, our results were driven by continued strong financial performance of QEP Energy, our E&P business, and slightly weaker performance at QEP Field Services, our gathering and processing business. QEP Energy reported equivalent production of 78 Bcfe, essentially flat with our second quarter, but net equivalent price realizations that were 3.7% higher than the second quarter driven by a larger crude oil count contribution to the revenue stream.

From the EBITDA standpoint, the $395.1 million generated in the third quarter was $5.6 million higher than the second quarter and $64 million or 19% higher than the second quarter of 2012. QEP Energy contributed $344 million, or 87% of our aggregate third quarter EBITDA, and QEP Field Services contributed $52 million or about 13%. QEP Energy's EBITDA was up $12 million or 4%, while Field Services' EBITDA was down $6.7 million or 11.5%, more than the second quarter levels. Field Services' third quarter results were lower than the previous quarter reflecting about $4.45 million of what we described as leakage attributed to the 48 days in the quarter that the public owned, therefore 2% share of the MLP.

Factors driving our third quarter EBITDA include QEP Energy's production, which was 78 Bcfe, 0.1 Bcfe higher than the 77.9 Bcfe reported in the second quarter of the year. The quarter's production was 4% lower than the 81.5 Bcfe produced in the third quarter of 2012. Over a year ago, natural gas comprised 79% of our net production compared to just 71% in the current quarter.

Oil volumes were 2.64 million barrels, up 11% in the second quarter of the year, and NGL volumes were 1.15 million barrels, up 3.5%. Natural gas volumes were down 3% in the second quarter of the year, and down 14% in the third quarter of 2012, driven primarily by declined production in our Haynesville field. Oil volumes were up 83% or 1.2 million barrels from third quarter of 2012, NGL volumes were down 17% or 233,000 barrels from the third quarter of 2012. QEP Energy's net realized equivalent price, which includes the settlement of our commodity derivatives, average $6.71 per Mcfe, which was $0.24 per Mcfe higher than realized in the second quarter and $1.57 per Mcfe higher than we realized in the third quarter of 2012. The equivalent price reflects field-level prices that were $3.52 or $0.31 per Mcf lower, field-level NGL prices that were $41.36 a barrel or $0.04 per barrel higher and field-level crude oil prices that were $95.98 a barrel or $8.66 a barrel higher than the respective levels in the second quarter of the year. Field-level crude oil revenues account for 51% of total field-level revenues, which was 7% higher than second quarter of the year, and up from 36% in the third quarter of 2012. QEP Energy commodity derivative portfolio contributed $27 million of EBITDA in the quarter compared to $31 million in the second quarter of the year and $92 million in the third quarter of 2012. The derivatives portfolio added about $0.35 per Mcfe to QEP Energy's net realized price in the quarter compared to $0.40 per Mcfe in the second quarter of the year, and $1.13 per Mcfe in the third quarter of 2012.

QEP Energy's combined lease operating and transportation expenses were $109 million in the quarter, up from $105 million in the second quarter of the year, and up from $103 million in the third quarter of 2012. On a per unit basis, lease operating expenses were $0.56 per Mcfe, down $0.03 per Mcfe in the second quarter and transportation expense was $0.84 per Mcfe, which is up $0.08 from the second quarter.

Finally, QEP Field Services' third quarter EBITDA was $51.6 million, which is about $6.7 million lower than second quarter of the year. Remember, our reported EBITDA does not include the $4.5 million, which is a portion of the MLP EBITDA that QEP does not own. Processing margin was up $7.6 million or 25% in the second quarter as a result of $8 million of deficiency payments in the quarter related to minimum volume commitments [indiscernible] gas plants. The average margin is down $4 million or 10% in the quarter compared to the second quarter of the year on essentially flat gas gathering volumes of 1.22 million MMBtus per day. The decrease in gathering margin is associated with lower other gathering revenues, which include deficiency payments related to minimum volume commitments, water handling and condensate sales.

We reported net income attributable to QEP of $37.3 million in the quarter, driven by a $13 million gain on asset sales and a $54 million unrealized loss in the mark-to-market value of our derivatives portfolio. Sequential G&A expenses were up $8 million primarily as a result of higher costs associated with our employees, salary bonus and benefits, higher expense for outside professional services and negative swing in the mark-to-market value of stock-based compensation. We expect G&A will tick back down somewhat in the fourth quarter.

In the first 9 months of the year, we reported capital expenditures, including acquisitions on an accrual basis of about $1.18 billion. Capital expenditures for E&P drilling and completion activity was $1.07 billion, and capital expenditures in our Midstream business were $55.5 million. In addition, we also reported $39 million of acquisitions. If you exclude acquisitions for the first 9 months of the year, we spent about $16 million less than our EBITDA.

With regard to our balance sheet, at the end of the quarter, total assets were $9.3 billion and shareholders' equity was about $3.4 billion. Using the proceeds from the IPO and a portion of the proceeds from the various asset sales that we closed in the year, we've reduced debt at the end of the quarter to $2.9 billion, which was about a 1.8x multiple of our midpoint of our 2013 EBITDA guidance. Our debt at the end of the quarter consisted of $2.2 billion of senior notes, $300 million under our term loan due in 2017 and $365 million drawn under our $1.5 billion revolving credit facility.

At the end of the quarter, we had about $123 million of cash from the proceeds of various asset sales on our balance sheet. If you assume that we acquired all that cash to pay down debt, our net debt multiple of midpoint EBITDA guidance, would be about 1.75x, so we feel pretty good about what we have accomplished with regards to our de-leveraging efforts.

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

Charles B. Stanley

Thank you. Richard has already hit the financial highlights. I'll briefly touch on some operational results for the quarter, our plans for the remainder of the year, and then I'll make some comments about our recent shareholder letter before we move on to Q&A.

Now, QEP's diversified upstream portfolio and focused investment in high return areas, such as the Williston Basin crude oil play, Pinedale and [indiscernible] based liquids-rich gas plays, combined with our complimentary Midstream business, led to a series of significant company performance records in the third quarter. These include record oil volumes, record fee-based processing revenues at Field Services and perhaps, most importantly, record high quarterly EBITDA. We completed the IPO of QEP Midstream Partners in August. As Richard mentioned already, it represented one of the fastest and largest MLP IPOs on record. We used the IPO proceeds along with proceeds from the sale of some non-core upstream assets, which has allowed us to strengthen our financial position, reducing net debt by over $500 million from the prior quarter. Going forward, we expect our Midstream business and MLP to continue to maximize margins on time and completion around QEP production, while providing new growth of opportunities for QEP and for our new partnership, QEPM.

While total production declined slightly from last year, growth in EBITDA and a reduction in net debt means that our EBITDA per debt adjusted shares also improved and we expect that, that metric will continue to do so as we grow high-margin crude oil production in the coming quarters. Our asset managers continue to make great progress driving increasing share of liquids as a percentage of our total production volumes. Crude oil production was up 11% from last quarter and 83% from the third quarter of 2012. At an average of approximately 28,700 barrels of oil per day, crude oil represented 20% of total QEP production in the third quarter, and that's up from less than 18% last quarter, and 11% from a year ago. And for the first time in QEP history, crude oil revenue represented more than half of our total field level E&P company revenues.

Combined crude oil and NGL volumes represented 29% of QEP Energy production in the third quarter, up from 27% in the second quarter and 21% of total production in the third quarter of last year. Earlier in the year, weather issues caused us some delays that we thought we could overcome in the Williston Basin but bottlenecks and third-party gathering systems, especially at downstream delivery points and greater than expected timing impacts from shutting in QEP-operated producing wells during offset completion activity will cause us to slightly miss our goal of 70% year-over-year total crude oil production growth in 2013.

That said, our current forecast of 60% year-over-year crude oil production growth is a remarkable achievement and it sets the stage for continued crude oil production growth in 2014. The continued impact of growing high-margin oil production on our financial results is also clear as Richard's already noted, QEP Energy delivered record adjusted EBITDA of $344 million in the third quarter. That's up 4% from the second quarter of this year and 29% from the third quarter of last year. Now let me give you a bit more color on our operational results for the quarter and our plans for the remainder of the year. As I do so, I ask you to refer to the slide presentation that accompanied our release yesterday afternoon. We’re currently running 8 rigs in the Williston Basin, the same as last quarter but they've moved around a bit. We now have 5 rigs working at South Antelope, which is 1 fewer than last quarter and 3 rigs working to the East on a Fort Berthold reservation, up from 2 during the previous quarter. Well results on our South Antelope property continued to be very strong and 90 day cumulative production volumes continue to track a roughly 1 million barrel of oil equivalent EUR type curve for both the Three Forks and for the Middle Bakken. Completion activity picked up in the Williston Basin with 21 QEP-operated well completions in the third quarter and that compares to 27 total well completions during the first half of this year. Overall, we're pleased with the technical results from the Williston Basin and the future potential. We continue to evaluate the potential for increased well density on our acreage. We're obviously monitoring the results of pilot programs that are being conducted by nearby offset operators and we also have a planned pilot program to evaluate the applicability of increased density development on our own acreage. As we drive efficiencies in our drilling and completion operations through pad drilling, we continue to make good progress on well costs at both South Antelope and at Fort Berthold. We're targeting an average of $10 million gross completed well costs by year-end. Remember that on the Fort Berthold reservation, because our acreage configuration is under our -- the shape of our acreage configuration largely under Lake Sakakawea, on average we drill a longer lateral than we do over in the South Antelope properties. Considering the longer laterals and certain costs and fees that are unique to the reservation, we would expect that the completed well cost would remain slightly higher than the South Antelope on the Fort Berthold reservation. Field-level crude oil prices for all of QEP Energy which is dominated, of course, by our volumes in the Williston Basin, improved in the second quarter due to higher benchmark prices. However, after experiencing a narrow average basis differential in the first half of the year of about $5 a barrel, the average discount widened in the third quarter to over $10 a barrel, due primarily to a decrease in Clearbrook pricing and a narrowing of the Brent WTI spread on volumes that we have contracted to the East Coast. This basis differential led to a negative impact of about $12 million on third quarter EBITDA and has caused a reduction of our full year EBITDA guidance of nearly $30 million.

Please see Slides 5 through 7 in the accompanying slide deck for more details on our Williston Basin operations.

Turning to Pinedale, production volumes were up 9% compared to the prior quarter. At the end of the third quarter, we had a total of 79 new producing wells completed and turned to sales for the year, including 22 wells that were completed during the third quarter. QEP has an average 75% working interest in the new wells that have been completed to date. We're on track to complete about 110 wells this year. Note that this includes 29 wells that we operated for a third-party but only own an overriding royalty interested in, so a fair amount of our completion activity for the second half of the year will have minimal impact on QEP Energy net production but obviously, all of those volumes flow through our midstream system, so we'll continue to benefit QEPM through increased volume on the gathering systems, and Field Services through processing plants. We continue to run 4 rigs at Pinedale through the year-end but remember, as we have always done, we will suspend well completion activity during the coldest months of the winter.

See Slides 8 and 9 for details on our Pinedale activity.

In Uinta Basin, we continue to make good progress on our Red Wash Lower Mesaverde liquids-rich gas play. We realized that running just 1 rig in the play through much of this year has been a bit confusing to some but we've been working on a new way of developing a portion of this play. We're evaluating some early well results from a fundamentally different well design that we think could radically alter the economics in a way we approach development of this significant asset. We'll provide more color on this approach as soon as we get a little more production data from the first well and get some more wells down. Clearly, this project presents not only a significant growth opportunity for QEP Energy but also for our Midstream business and since this project like most of our other development projects in the Rockies is located on federal land, largely within a single federal unit, simultaneous permitting and construction of both the midstream and upstream infrastructure will be critical to our success. At the end of the quarter, we also had 1 rig in the Uinta Basin that was focused on doing horizontal and vertical oil wells in the Green River formation. Slide 10 shows more details on our Uinta Basin activities.

Turning to the Midcontinent, during the third quarter, we participated in a number of outside operated wells that were either drilling or waiting on completion in the Cana play. See Slide 11 for the location of the recently completed wells and other details.

At Field Services, EBITDA declined slightly from the second quarter primarily as a result of the EBITDA attributable to the noncontrolling interest associated with QEP Midstream. The startup of our new $150 million a day cryo plant, Iron Horse II, located in Uinta Basin which happened in the first quarter of this year, helped us deliver record fee-based processing revenue and volume in the third quarter. About half of the capacity of this new plant is contracted to third parties under our fee-based arrangements, while the remainder is available to process QEP Energy's gas volumes from the Red Wash Mesaverde play. The processing arrangement between QEP and Field Services is also fee-based. During the quarter, Field Services also completed construction of an expanded rail loading facility. This is associated with our 10,000-barrel a day expansion of our existing fractionation facility at the Blacks Fork complex in Wyoming. This facility will provide additional options for marketing purity propane, ISO and normal butane, and gasoline-range products to what are, oftentimes, premium value markets both locally and regionally, either via trucks or across this new expanded rail loading facility to other parts of the U.S.

As Richard mentioned, we're very pleased with the execution of the QEP Midstream Partners or QEPM MLP IPO last in August. As a reminder, QEP Midstream contains a subset of QEP's gathering assets and those were primarily located in the Green River Basin in Wyoming, the Williston Basin in North Dakota and Uinta Basin in Utah. QEP continues to own gathering and processing assets which are obviously candidates for future drop-downs. We believe that the market's strong reception of the QEPM IPO is a clear indicator of the quality of our midstream assets and the people who run them. We're excited about the doors this opens for new investment opportunities and the potential benefit for both QEP and QEP Midstream going forward. You'll note that we recently announced the appointment of 2 additional independent QEPM board members, who round out QEPM's conflicts committee. The appointment of Gregory King and Donald Turkleson and the considerable expertise that they bring to our board are a significant step in progressing the growth plans of our Midstream business.

We view 2013 as a pivotal year for QEP as we continue to dramatically shift our production mix of QEP Energy from one that's dominated by natural gas to one that's more balanced. We're making significant progress on achieving this goal, as we expect to increase crude oil production by approximately 60% this year compared to 2012 levels. And natural gas volumes, as a reminder, are expected to decrease about 10% or so in 2013, as we allocate capital to higher return oil projects, which should have been primarily responsible for our strong growth in EBITDA. Most of it, not all of the gas production volume decline is being driven by declines in the Haynesville Shale and Northwest Louisiana due to the absence of new drilling and completion activity.

Finally, I want to briefly address the recent letter made public by our largest shareholder, Jana Partners. The letter, as most of you know, called on QEP to add midstream expertise to our board and management team, to align management incentives more closely to midstream performance, to consider other structural changes at QEP Field Services and to return capital to shareholders. As we stated in our press release on October 22, we maintained an ongoing dialogue with all of our shareholders, including Jana, and we are intensely focused on developing strategies and taking near term actions that we believe will create long-term value for all of our investors. We have had constructive conversations with Jana for nearly a year now. They've made a number of suggestions during that time, some of which we'd already been considering, and other suggestions which would constitute new initiatives. We've taken all of their suggestions seriously and we reviewed all of them with our board. During 2013, we successfully implemented a major structural change to our company, the formation's successful IPO QEP Midstream Partners, an initiative that Jana strongly supported. As we discussed with Jana prior to the receipt of their letter, our board and management team are actively reviewing the proposals they outlined with our financial and legal advisors. As part of this evaluation, we also intend to solicit the views of our other shareholders in the days and weeks ahead, consistent with our fiduciary duty to develop strategies and take actions that benefit all of our investors before we make any final decisions. Beyond that, we won't comment any further on the letter or our discussions with shareholders on today's call. With that, Manny, I'd like to open up the line for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from Brian Gamble of Simmons & Company.

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

Just wanted to start off with some questions on your oil side and maybe specifically the Bakken. I understand if you don't want to go outlook any sort of 2014 guidance, but maybe you could clear out sort of some of the issues that happened during the quarter, the bottlenecking and third-party issues over, maybe work through what you potentially see as the completion schedule for Q4 and then if you want to touch on a potential exit rate for the year, that would be helpful.

Charles B. Stanley

Well, let me try to take those questions, maybe not in the same order that you asked them. Brian, in simple terms, the way I look at this is -- we're on a very steep growth trajectory and if I think of it as an inclined curve, it just shifted 1.5 months or 2 months as a result of some delays that we had. Some of them were self induced. We added a sixth rig in the South Antelope area and that sixth rig introduced some additional offset shut-ins that we had not planned for when we were scheduling our completion activity. So we had more existing producing wells shut-in and we would have normally anticipated because of the addition of that sixth rig and the proximity of the individual pads to each other. So that impacted production volumes. Our growing volumes on third-party gathering systems resulted in problems, redelivering that oil from their gathering systems to downstream markets, so either interstate pipes that take it out of the state or rail loading facilities and it caused us to have to delay or slow down completion activity while they got caught up. We're just now seeing some new facilities put in place that are connected to the gathering systems that will allow us to deliver oil directly into pipes that in turn deliver it to rail loading facilities. We actually were forced during the quarter to take oil off of the gathering system and truck it to rail loading facilities, which not only slowed us down but also resulted in lower realized prices as a result of additional costs associated with trucking oil that should have gone down gathering systems. The third sort of delay was basically weather-related and it was a -- in part caused us to move the sixth rig into South Antelope from Fort Berthold. We talked about that, I think in the first quarter call -- I'm sorry, in the second quarter call, and that introduced some planning problems for us and in addition, in South Antelope, we had to go to some pads that we had not anticipated going to, that resulted in near proximity completion problems that resulted in more shut-ins. Going forward, we're comfortable now with the 60% plus growth rate for the year. That implies a 33,000-barrel a day rate. Coincidentally, we're at -- we monitor the production obviously, daily. We're at that rate today. What I would point out is that there's volatility as we shut wells and continue to complete additional wells through the end of the quarter. We've got at the end of the third quarter, about 22 remaining wells that are standing -- that are either drilled in case waiting on completion or nearly down and waiting on completion. So we have a substantial inventory of remaining wells to complete that should drive production through the end of the year. And then as to your question on '14, we -- we will give guidance in early January for 2014 volumes. But looking at the plan that the team has presented to me and thinking about the sort of a shift in delay of several months, we would anticipate ongoing production growth as we leave '14 and move -- I'm sorry, leave '13 and move on into '14 and I'm not going to give you a percentage growth for next year but we're comfortable that we'll continue to be able to deliver production growth into 2014.

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

Great, I appreciate the color. And then maybe, as my quick follow-up, you mentioned the planned pilot program from a [indiscernible] basin standpoint, any color you want to provide there?

Charles B. Stanley

We -- obviously, there's a lot of industry activity going on across the basin and a couple of observations, one, the geology, even though it's -- at 40,000 feet, it looks layer cake. There's quite a bit of variability in both the Middle Bakken and in the Three Forks. While pilot programs run by other operators will give us a hint as to the applicability on our acreage, the only way we'll know for sure will be through piloting on our own acreage and that's why we have plans in the very near future to commence drilling an infield pilot of our own. The fundamental prize and the fundamental opportunity is to increase recovery of the oil in place in both the Bakken and Three Forks because as we know, we're -- with current recoveries, we're leaving a substantial volume of the oil in place in the ground and we're looking for ways to, obviously, enhance the recovery. First, through maximizing the efficiency of our completions and absent the ability to recover substantial additional reserves through maximizing completion design efficiency, drilling additional well bores. And there's always going to be a trade-off between rate acceleration and incremental recovery on those incremental -- on those new wellbores we drill and that's a question you can only answer as we've learned through years of piloting in places like Pinedale, that you can never model it, you have to actually go out and put holes in the ground and watch the wells perform over time.

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

Any specific space in your targeting there, or just kind of feel it out as you go?

Charles B. Stanley

Well, the first pilot will add 2 wells to the spacing unit. So we go from 4 to 6.

Operator

The next question is from Hsulin Peng of Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

So my question is a follow-up on previous quarters. Chuck, you had mentioned that you are experimenting with more proppants. I think it was like 5 million pounds. So I was just wondering if you had an update for us in terms of what you're seeing with that experimentation?

Charles B. Stanley

Generally, Hsulin, good morning, generally we're seeing a pretty strong correlation between increased proppant density per stage and initial well performance and if initial well performance indicates ultimate recovery, then we should see better recoveries over the life of the well. We've made a substantial increase in the total volume of proppant on total number of pounds of proppant, 3 million pounds to 5 million pounds and we slightly changed the recipe that we're using and we continue to obviously monitor the results as we pump additional fracs.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So that sounds good. And the well -- the production results that you talked about in the press release this quarter, does that reflect this new completion technique or just a few?

Charles B. Stanley

Well, it does, although it probably averages through some wells that were put online early in the quarter that did not have the higher proppant concentration. But it's a reflection of a move toward the higher proppant concentrations, maybe 1/3 were at the lower concentration. And 2/3 -- I'm sorry, I got it backwards. 2/3 at the lower concentration, 1/3 at the higher concentration.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then shifting over to Lower Mesaverde, I know you mentioned you're trying this new completion design. Can you just give us more color as to exactly what you are trying there?

Charles B. Stanley

No, I prefer not to at this point. I'd like to gather more data, really understand the well results and then we'll lay it all out when we have more data. But Hsulin, to suffice it to say, we're very encouraged by the very early time series of production that we see which is radically different than the vertical wells that we drilled on pads to date.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So when do you think you could tell us, give us more color on it?

Charles B. Stanley

You're persistent. Perhaps, in conjunction with our guidance update, at least some initial results. It may be at the end of the first quarter.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. That sounds good. And then, 2 quick follow-ups -- 2 quick ones. The asset divestitures. Can you talk about which assets you divested, specifically?

Richard J. Doleshek

Hsulin, it's Richard. The 3 packages that we sold, 2 in the second quarter, 1 in the third quarter, were our Powder River assets, some assets down in the Four Corners area in the San Juan basin and then the package that we had marketed in the Tonkawa and Marmaton. And that was the one that closed. The last one was the one that closed in the third quarter, about $13 million recorded gain.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then last question, Richard. Regarding the G&A, I think you said that overall, G&A will go down in the fourth quarter, but more specifically, Midstream, I think 3Q was about close to $60 million. Is that, I mean given cost, given the Midstream MLP, is that -- how should we think about a trend for Midstream G&A?

Richard J. Doleshek

There was about $2.5 million of what I'll call noise in the Midstream business that related to a feasibility study for a gas plant that we decide to expense in the quarter. So think about that number less $2.5 million and then the normal allocation of what goes from corporate down to Field Services. That was -- you found a piece of what I've talked to about the nonrecurring stuff that occurred in the quarter.

Operator

The next question is from Brian Corales of Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Chuck, I think you just mentioned that you're currently at about 33,000 barrels a day. Did I hear that correctly?

Charles B. Stanley

Yes, around 33,000.

Brian M. Corales - Howard Weil Incorporated, Research Division

So can we just assume that you roughly had about 4,000 barrels a day from the third quarter kind of deferred to the fourth or is this all new completions and this 33,000 is probably going to grow?

Charles B. Stanley

Well, as I said earlier, I think I said earlier, we still have 22 wells to complete and we will have to shut-in offset wells, including some of the recently completed wells as we frac and put the last 22 wells online. So the volatility associated with pad development, especially when we have the wells all kind of lined up in a line which is what we do and we have what is referred to locally in North Dakota as the QDP highway with a bunch of rigs lined up along it and now a bunch of completions lined up along it, and it results in substantial amount of production volumes being shut-in while we go about completing new wells on pads. So what we try to do and this is learning curve for us and I would hasten to point out that the team is focused on making sure that we go back to our normal practice of over -- of under promising and over delivering. We are making sure that we don't miss on this current guidance and as a result, you're going to see volatility. The trend is going to be generally upward, Brian, but there's a lot of volatility associated with this result of offset shut-ins.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, no it's fair. And maybe switching tunes to the midstream side, I know you just added some people to the conflicts committee. I mean, can we assume that you're probably going to see dropdowns relatively quickly? I mean, is there an assumption to be made there?

Charles B. Stanley

Well, certainly, we needed a conflicts committee before we could accomplish the dropdown, and we, in fact, had our first QEPM board meeting yesterday with the fully constituted independent directors slate. A couple of observations. One, when we IPO-ed QEPM back in August, we intentionally put in place a $0.5 billion revolving credit facility and as you know, at the IPO, that facility is undrawn. So we put in place a tool to use, to finance the first dropdown without being in sort of perpetual registration with the SEC if we wanted to finance the first drop using equity issuance or units. So I think you can read from that, that this management team anticipated the likelihood that we will do our first drop before the 365-day anniversary of the IPO. And so we have a conflicts committee in place, we have a tool to finance the dropdown and those are the 2 sort of points that I can give you as indication of our attempt.

Operator

[Operator Instructions] .

And the next question is from Eli Kantor of Iberia Capital Partners.

Eli J. Kantor - Iberia Capital Partners, Research Division

A question on your Bakken activity. Are you seeing any change in well performance when you're bringing in these offsetting wells back online?

Charles B. Stanley

You mean as far as shutting them in and then bringing them back?

Eli J. Kantor - Iberia Capital Partners, Research Division

That's right.

Charles B. Stanley

No. I'm looking at Jim Torgerson. Not really, I mean, they do build up pressure and sometimes, you'll see a slightly higher rate when they come back online just because they've been shut-in. But no substantial change in performance and as I mentioned, when we look at the 90-day sort of cumulative production versus our type curve, we see well performances effectively in line with what we had forecasted from our acquisition model.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay, that's helpful. I was hoping for an update on your upstream divestment plan. In the past, you guys have talked about potentially selling the Granite Wash, essentially selling the Cana. Looks like some of your peers in your area have had success making asset sales recently. Do those assets still look good from a divestment standpoint and are there any other upstream properties that you might look to sell?

Charles B. Stanley

Eli, we continue to evaluate all of our upstream portfolio to determine whether the value of holding the asset is greater -- holding it and developing it is greater than we can receive for it through sales to a third party. We continue to look at both Midcontinent assets and other assets in our portfolio and will obviously monitor the market and make decisions going forward. We continue to discuss it with our board and with our asset managers to challenge them on maximizing shareholder value for those assets.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay. Last one for me. Just on current appetite for making upstream acquisitions. Are there any -- obviously, oil growth is a top priority. Are there any basins that look attractive in picking up new acreage and assuming that Williston makes the most sense, given your existing footprint in the area, what does deal flow look like in the Williston relative to the last couple of years?

Charles B. Stanley

Deal flow has obviously been pretty high over the past year in the Williston. There are some additional opportunities out there that we continue to evaluate. We've looked at other acquisition opportunities primarily for crude oil, obviously, there's only a handful of basins that meet our criteria that have substantial black oil production, repeatable resource play type resource opportunities and we're -- we have a team of folks both in A&D and new ventures look at opportunities not only to acquire assets but also to develop our own play, both in existing basins and we are continuing to evaluate several basins which we're not currently active.

Operator

The next question comes from Andrew Coleman of Raymond James.

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

The question I have, first, was just on, I guess, a different side what Eli asked. As you look at your existing assets, particularly at the Cana, one of your peers discussed a potential new secondary play there, coming off of Cana and Anadarko Woodford in the Merrimack [ph], have you all looked at that? Or is that something that you have a view on right now or should we look more to the guidance update?

Charles B. Stanley

Well, obviously, we evaluate all of our acreage and yes, we have looked at it. In fact, we participated in a well or 2 in that play. So we're very much aware of it and we continue to think about it on our acreage. Obviously, just a reminder, Andrew, when we show acreage numbers in plays like the Cana, that's just acreage associated with the circle we arbitrarily draw on our map and basically, to show you more of that particular play. But we have several hundred thousand acres of acreage in the Anadarko Basin. So when you're thinking about our footprint, it goes beyond just the margins of the page, so to speak, in the play summaries that we've included in our investor materials.

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

Okay, good. And I know 3 months ago, that you all decided not to divest that property. Is it possible that some of that value for -- that's why could have been a part of the reason or was the valuation at the time only related to the Cana?

Charles B. Stanley

I'd rather not get into the details of our thought process around that.

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

Okay, I understand. And then the last question I had is, you mentioned that the change in basis there between -- as well as the TI Brent spread on your Bakken barrels. What's the current mix of your takeaway right now?

Charles B. Stanley

Well, we've got about 7,000 barrels a day going to a Brent market and the rest of it is going to a mixture of Clearbrook and LLS related Gulf Coast related pricing. And obviously, the Filcon market in North Dakota has been impacted somewhat by refinery outages, by some pipeline issues that I'm sure everybody is aware of. And has been -- it was kind of a sloppy quarter as a result, but there's some new facilities that have come online that should allow for more straightforward train loading and access to, not only Brent and LLS markets by rail, but also potentially West Coast markets. So the facilities bottlenecks we hope are behind us.

Operator

We have no further questions in queue at this time. I would like to turn the floor back over to management for any additional remarks.

Charles B. Stanley

Well, thank you very much. On behalf of my colleagues here at QEP, we appreciate your calling in today and for your interest in our company. We'll be on the road at several conferences and meeting with the shareholders and we look forward to seeing you soon.

Operator

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

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