QEP Resources (QEP) Q3 2019 Earnings Call Transcript

QEP Resources (QEP)
Q3 2019 Earnings Call
Oct 24, 2019, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Greetings, and welcome to QEP Resources third-quarter 2019 earnings conference call. [Operator instructions] As a reminder, this conference call is being recorded. It is now my pleasure to turn the conference over to your host today, Mr. William Kent, director of investor relations.

Thank you. You may begin.

William Kent -- Director of Investor Relations

Thank you, Rob. And good morning, everyone. Thank you for joining us for the QEP Resources third-quarter 2019 results conference call. With me today are Tim Cutt, president and chief executive officer; Richard Doleshek, executive vice president and chief financial officer; Bill Buese, vice president of finance; and Joe Redman, vice president of energy.

If you've not done so already, please go to our website, qepres.com, to obtain copies of our earnings release, which contains tables of our financial results, along with the slide presentation with supporting materials. In today's conference call, we'll use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA in our earnings release and SEC filings and free cash flow. These measures are reconciled to the most comparable GAAP measure in the earnings release and SEC filings. In addition, we'll be making numerous forward-looking statements.

We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control. We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks, facing our business in our earnings release and SEC filings. With that, I'd like to turn the call over to Tim.

Tim Cutt -- President and Chief Executive Officer

Thanks, Will. Good morning, and thank you for joining the call today. I'll begin with an update to our third-quarter operational performance, followed by a brief update to our business strategy, before turning the call over to Richard to discuss the financial performance and guidance for the full year. I'm pleased to report that operational performance during the third quarter in all categories was in line with or better than guidance.

In particular, oil production exceeded our expectations due to the continued outperformance of our most recent DSUs in the Permian Basin. G&A expense, excluding special items, is now in line with and projected to -- at the projected run rate for 2020, down 45% from the 2018 quarterly run rate and work is well under way to continue to lower nonemployee G&A expense going forward. Lease operating expense continues to improve against our year-to-date budget. Our strong operational performance, coupled with continued focus on operating expenses resulted in QEP being free cash flow positive in the third quarter and positions the company to generate significant free cash flow in the fourth quarter.

Oil in condensate production in the Permian Basin increased by 20% from the second to third quarter of 2019. Permian gas sales remained higher than forecast, giving our focus on environmental stewardship and the resulting reduction of flared volumes. The DSUs completed in 2019 drilled on a go-forward spacing assumptions detailed on Slides 9 through 12 of the IR deck are currently producing on or above their projected production profile, enabling us to stay ahead of our volume plan. The two Permian rigs moved from Mustang Springs to County Line during the third quarter and fracking operations, included in Mustang Springs in late August.

We expect fracking operations will begin in County Line late in the fourth quarter. As a result of the planned suspension of fracking activity, we delivered peak Permian production in the third quarter and expect production to decline from the third to fourth quarter. In the Williston Basin, we initiated production from our seven-well Vegas pad located on South Antelope late in the third quarter. At quarter end, we had three of the seven wells on production and the early performance of these wells is very encouraging.

With the addition of these wells, we expect oil production to increase in the fourth quarter back to levels roughly equivalent to the first quarter. During the fourth quarter, the forecasted of the increase in the Williston Basin production is anticipated to offset the decline in the Permian Basin, resulting in overall production for QEP growing slightly from the third to fourth quarter I'll spend the next few minutes explaining the planned timing of our development program as we move forward, understanding and ultimately modeling this timing is critical to understanding the cadence at which QEP will deliver free cash flow. In the Permian, due to improved operational efficiencies, a single frac crew can support a three to four-rig program. Based on our planned 2-rig program, we expect drilling activity to continue year-round in the basin with new wells being completed and put on production in the first three quarters of the year.

In the Williston, we expect drilling activity to begin in the first quarter of each year, while the majority of the completion activity, including the execution of our refrac program will be completed in the warmer months from April through September to ensure lower completion and construction cost. This operational seasonality will mean that capital spend during the first half of the year will be significantly higher than the second half of the year and volumes will generally peak in the third quarter. This will likely translate into cash out spend during the first half of the year before significant free cash flow generation in the second half of the year as demonstrated on Slide 13 of the IR deck. We understand that this nonlinear trajectory is departure from the past, but is extremely important to understand the seasonality as we transition to a development program that consumes less capital and delivers positive annual free cash flow at $50 oil.

During the last call, I mentioned that we were evaluating a variety of options to maximize the value of our substantial water business, including a full or partial sale or joint venture transaction. We continue to evaluate these options and look forward to sharing our plans with order business during the year-end call. Before turning the call to Richard to discuss our financial results, I wanted to spend a minute discussing the announced transition of our CFO position. As you read in yesterday's announcement, Richard Doleshek will leave the company at the end of the year after more than 10 years of service.

Richard will be replaced by Bill Buese, our current VP of Finance and treasurer, effective January 1, 2020. Richard has been mentoring Bill for several years in preparation for this change, and we are confident that we will experience a smooth transition. Consistent with our focus on reducing corporate overhead, Bill's role of VP finance, will be eliminated. This move concludes our reduction of officer headcount, which has been reduced by 60% from 2018.

I'd like to thank Richard for his excellent service and congratulate Bill on his promotion. With that, I'll turn the call over to Richard.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Thank you, Tim, and thanks for your kind words. I'm actually grateful to have been a part of QEP from its inception. I believe we did a lot of good things, but I can honestly say, I won't miss the 7 a.m. Mountain Time earnings Calls.

Bill and I've worked together for the last 7.5 years, and I'm highly confident on his abilities and excited about this opportunity for him. I'll now give some more color about the third-quarter results and update our 2019 guidance before we open up the call for Q&A. Our third quarter was the best quarter of the year and sets the stage for a strong year-end at the start of 2020. In the third quarter, we generated $193.5 million of adjusted EBITDA.

The higher adjusted EBITDA compared to the second quarter is reflective of, among other things, 11.5% higher equivalent production, accompanied by lower G&A, lower LOE and lower production tax expenses. The impact of which was partially offset by higher adjusted transportation expense and lower field level prices when compared to the second quarter. We know that the transportation expense looks high, but the expense in the quarter includes the present value of future payment obligations, firm pipeline transportation service in an area in which we no longer have production operations. For the third quarter, we reported net income of $81 million.

Value net income was a $92 million unrealized gain associated with our commodity derivatives portfolio. At the end of the third quarter, the derivative portfolio was a net asset of $92 million compared to a net liability of $1 million at the end of the second quarter. We continue to enter into commodity derivative contracts during the third quarter, and as of September 30, we held contracts, excluding basis swaps totaling 18.2 million barrels of oil, which covers about 75% of forecasted 2019 oil production and doubles the volume covered by derivatives for 2020 such that greater than 60% of forecasted 2020 oil production is now covered by fixed price swaps at $58.31 a barrel. During the quarter, we delivered $17.5 million of free cash flow.

And as a reminder, we define free cash flow as adjusted EBITDA plus noncash stock-based compensation, less cash interest expense and cash capital expenditures, including acquisitions. With regards to our balance sheet at the end of the quarter, total assets were $5.6 billion and shareholder equity was about $2.8 billion. Total debt was approximately $2.1 billion, all of which were senior notes. We had nothing outstanding under the revolving credit facility, we had $92 million of cash, which is about the same level as the end of the second quarter.

Further, yesterday, we announced the early redemption of the $52 million of senior notes that are due to mature in March of 2020, and we'll use cash on the balance sheet to fund that redemption. In terms of 2019 guidance, there are several updates driven by better well performance, higher gas capture rates, increased capital efficiency and our continuous focus on driving down costs. We are increasing our overall production guidance to a range of 32 million to 32.6 million barrels of oil equivalent, a 6% increase at the midpoint from our previous guidance. We are increasing our oil guidance for the full year to a range of 21.6 million to 21.9 million barrels, an increase of 0.5 million barrels at the midpoint.

We're increasing our guidance for natural gas volumes to a range of 30.4 to 32.9 Bcf, a 13% increase at the midpoint. And finally, our guidance for NGL volumes for 2019 has increased to five million to 5.2 million barrels. The team's continued strides in cost reduction and improved efficiencies position us to lower our 2019 capital guidance by additional $15 million at the midpoint. In addition, we're lowering our G&A guidance by $5 million as well for the year.

There are additional details about our guidance in our earnings release. I'll now turn the call back over Tim to provide briefly before we open the call for Q&A.

Tim Cutt -- President and Chief Executive Officer

Thanks, Richard.In summary, we are delivering against the improved business plan that I described during the last call. We're committed to generating free cash flow and delevering our balance sheet. We're confident in our ability to deliver on this commitment as a result of our improved performance and deliverability of our high-quality, all dominant asset base, a significant decrease in drilling completion facility costs as well as the successful and sustainable reduction of corporate overhead. Clearly, none of this would be possible without the contributions of our high-quality workforce that persevere through an unprecedented level of change during the last three quarters.

The individuals in this organization have set the company up for success, and I want to thank each of them personally. With that, we'll open up the call for questions.

Questions & Answers:

Operator

Thank you. [Operator instructions] Our first question comes from Gabe Daoud with Cowen & Company. Please proceed with your question.

Gabe Daoud -- Cowen and Company -- Analyst

Hey. Good morning, everyone. Maybe just starting with 2020, given the efficiencies and D&C savings, you guys have realized thus far. And I guess the fact that you mentioned Permian spend in 2020 would be about $45 million less than '19.

What does the updated budget look like in '20? I guess, just trying to figure out what that $600 million run rate number could ultimately look like given the savings this year?

Tim Cutt -- President and Chief Executive Officer

Yes, Gabe, we're still working through 2020. We've got the preliminary numbers out there. I mean, if you think about our plan over the next several years, we're going to be plus or minus $600 million, I think, next year, a bit lower than that. And so we need to work all of these savings through.

We're moving out of Mustang Springs into County Line. And so we want to make sure that we're conservative on our thinking of what changes that could bring, but we're still confident that if you think about our program of plus or minus $150 million up in North Dakota and $450 million or less in the Permian. I think that's a good number to start with. And as we get closer, we'll continue to update on that.

Gabe Daoud -- Cowen and Company -- Analyst

OK. Understood. Thanks, Tim. And then I guess, just as a follow-up, maybe just talking about the balance sheet, I guess, for a second and redeem the 20 notes, but how should we think about the way you guys will handle the 21 notes.

I think it's about $400 million, just curious on that.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Gabe, it's Richard. We're going to evaluate what to do with those. Clearly, we're going to have a bunch of cash at year-end and continue to generate cash through next year. So the maturities in March of '21, so it gives us some time.

But obviously, that's going to be our focus -- is trying to reduce those as we approach the maturity date.

Gabe Daoud -- Cowen and Company -- Analyst

All right. Thanks, guys. Richard, all the best to you, and congrats, Bill.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Thanks, Gabe.

Operator

Our next question comes from Derrick Whitfield with Stifel. Please proceed with your question.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Good morning and congrats on a strong press release and ops update. Richard, also -- hope you can enjoy some time away from the business in the coming months.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Thank you. Thank you.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Tim, over the last year, QEP has done an exceptional job of taking operating capital costs out of the business, your Midland DC&E costs are arguably the lowest in the basin. As you look forward, where do you see the greatest remaining cost opportunities, capital or operating?

Tim Cutt -- President and Chief Executive Officer

Yes. So thanks for that. We've put a huge focus on that. A lot of the costs have come out in the completion costs.

We're still optimizing there. I mean, we've gone to a simul frac, where we produced -- we're basically fracking two wells simultaneously. The next phase of that is to increase our pump rates. We've had pump rates on each well of maybe 60 barrels a minute.

We think we can raise that to about 80 barrels a minute. And what that does is just speed the whole process up. And so speed is our friend, the way we work our contracts with our suppliers. We're focused on that.

We're drilling again. So $12 -- I mean, 12 days per well, that will continue to bring that down. I think we've still got more to do on the facility cost. We have started, obviously, doing the -- build the skids in the shop and bringing the location, which would -- the same kind of thinking to our last pad in North Dakota, and it was a phenomenal outcome.

I mean, our previous pad, I say, I'm just going to throw numbers. I'd say, it was a $20 million to $30 million project. Our Vegas pad was completed on the facility side of sub-$10 million. So it's that just continuous improvement thinking about -- how to work straight things, how minimize the time on-site and get things hooked up really just in time, so that's important.

And then on the opex side, I'm not sure if you asked about that. But this is something that where we have spent a huge amount of time on, and that will come just a little bit of time. I'll give you an example. In North Dakota, most of our wells are on run pump up there, and we're in the process now of converting over to gas lift.

Gas lift will be a lot more efficient. We'll have less workover on the rigs. And so it's just a whole bunch of blocking and tackling going forward.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

And perhaps for Richard with my follow-up. With regard to the water infrastructure business, how would you characterize where you are in the evaluation process?

Richard Doleshek -- Executive Vice President and Chief Financial Officer

I think from the valuation process, we're pretty well done with that. We think we understand what the implication of a cellular monetization would be to our operating and capital process. And now we're really in the -- is it a full sale, is it a joint venture, partial monetization? Is it both sets of -- both areas or just one area. So we're sort of in the fine-tuning phase.

But I think from the standpoint of our evaluation of what we have and what a transaction will do to us going forward. I think we're substantially completing that.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

All right. Thanks for your time and responses. Thank you.

Operator

Our next question comes from Neal Dingmann with SunTrust. Please proceed with your question.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Morning. Congrats, Richard and Bill, we look forward to working with you. Tim, my question for you or Richard. I'm just wondering, when you kind of guide for 2020, I'm wondering, is your primary target for next year, that free cash flow around 120, and this will ultimately set your activity? Or I'm just wondering, again, I know you don't have and you mentioned earlier, you don't have full 2020 out.

But I'm just wondering, is it more and then again, you certainly have added some hedges, and that will help. Just wondering what sort of when you all think about it and sit down, is the primary driver that you want to generate x amount of free cash flow? Or do you want to generate x amount of activity? Just sort of trying to get your mindset there.

Bill Buese -- Vice President of Finance

Yes, that's a really good question. So as we went through our budget process, we kind of back calculate it and say it wasn't going to affect to delever the balance sheet. And what -- how much cash we're going to have in the balance sheet at the end of the year? How much do we need for 2021? And what do we need to do throughout the year, end of this year and next year to make sure we have cash on hand to deal with the 2021. So I think you're right.

I mean that 120 is important number to us. Do remember, we have another $37.5 million, that should come on top of that in the form of tax refunds, all of that has been considered. So we've had a few questions over the last day or two, just about -- things are improving. We haven't changed that 120.

Do you understand we're modifying things as we get closer to the year? NGL prices are off, differentials have come off a little bit. And so we're making sure that everything we're doing at least substantiates at a $55 price for that volume is not hedged, we'll deliver that $120 million. So it's an important number to us. I'm not going to say that caps us anyway.

So we figure out how to go faster, better, cheaper. Hopefully, we can do more to deliver higher volumes and then build into the end of next year and a stronger movement into 2021. So we started on the journey in a pretty tough time through the strategic process, our organization is fairly lean now. We're very focused and excited about the plan.

And I think the 120 is a good number to keep coming back to, as we move variables around. But don't think we're not aiming to improve on that as time goes forward.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Great color. And then just maybe a dovetail into that. Well just in terms of -- you've talked a lot about the perm on the Bakken side, still very, very great asset, and you've had a bit of a decline there. I think, more just because of, obviously, the amount of activity and capital put there.

I'm just wondering, anything else you could talk about there? Do you -- in terms of -- will you bring out maybe more refracs? Will you try to be more active there next year? I mean, obviously, you've got a great oil content there. Just anything you can say about the Bakken in general.

Bill Buese -- Vice President of Finance

So if you heard on my talk -- on my speaking notes. The activity that we've just completed on the Vegas pad will actually take us back to volumes, when you look at full quarter, fourth quarter to the full quarter, first quarter, we're going to have fairly equivalent volumes between those two quarters. So we've stepped back up after a fairly long decline period with almost no activity. We will start drilling the Disco pad early in the year, and then we'll have all of our completion activities starting in the spring all the way into the very early fall between 18 refracs and bringing on six new drill wells there.

So our plan is to basically keep the Williston relatively flat, about eight million barrels per annum. And you're going to see the volumes oscillate as we're active, and we're bring it along, production will peak, and then will come off for a few quarters come back up. Very similar to the Permian. The only difference in the Permian is each of our peaks will slowly get higher and higher as we go forward.

We think the Bakken over the next seven years will stay relatively flat at those rates. And we do feel great about the refracs. We have 30 refracs that are online, they're all performing as expected. We're looking forward to moving forward.

We continue to high-grade our inventory there, but between FBIR and South Antelope, we have about 100 opportunities there, and we've got a pretty special circumstance with how we completed our original wells field, to get in there, set pipe and almost frankly, I like our new wells.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Very good. Thanks for the time, Bill.

Operator

Our next question comes from Kashy Harrison with Simmons Energy. Please proceed with your question.

Kashy Harrison -- Simmons Energy -- Analyst

Good morning. Thank you for taking my questions. Congrats, Richard, on the next stage. So just a few questions from me.

I was wondering if you could discuss what the desired leverage target is before you begin more aggressively returning capital to shareholders up and beyond the dividend.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Hey, Kashy. And thanks for the good luck and the good wishes. It's Richard. Our leverage target, first step, is to deleverage down below two times debt multiple of EBITDA and we're getting close.

If you sort of look at the cash flow, the cash in the balance sheet, any potential proceeds from monetization and look at what consensus EBITDA is for next year. By the time we get to the end of next year, we should be at or floating with that two times, first step target. When we first spun out of Questar, we were at 1.25 times, and that gave us a ton of flexibility to pursue acquisitions and do other things. So I think we're going to be on the path that we're on right now with a fairly consistent development program, refrac program until we get to two times.

And then I think in terms of doing anything more aggressive and that we've got to be below that target.

Kashy Harrison -- Simmons Energy -- Analyst

OK. And then that's actually is a good segue to my next question, which is how much EBITDA is associated with the water infrastructure assets? I know it could take all sorts of different structures, but I'm just trying to get a handle on the amount of cash flow associated with the water infrastructure assets as it stands today.

Bill Buese -- Vice President of Finance

So Kashy, deb that water business is embedded inside the E&P asset. And so we don't generate a financial statement around it, the costs are the LOE associated with Barnett. And so if you said, "Hey, it was a stand-alone business, we have calculated a theoretical sort of EBITDA assuming contract rates for disposal, freshwater source, etc. So I mean, as it stands today, that business is just part of our LOE, and we don't generate, but we could.

We -- on the whiteboard and write out some numbers. I think if we were at the capacity that we've generated and head market rates, that number would probably in the $40 million to $50 million three-year EBITDA range.

Tim Cutt -- President and Chief Executive Officer

Yes. And Kashy, I'll build on that. I mean, one of the ways you can think about the opportunity here is that we process, produce order from $0.15 to $0.20 a barrel. And as you know, buying treated water for fracking isn't $70 barrel type of range.

We inject water for $0.10 a barrel. The market rate of that probably $0.40 to $0.50 a barrel. So there's -- that's where the economics sit. And we can easily expand the capacity of that business by adding additional processing tranche for fairly low capital investment.

So the big infrastructure is there. We just have to figure out the best way to leverage that and who the best partner potentially would be to grab some of that margin.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. That's very helpful. And then finally, last one for me, just more of a modeling nuance question. Can you help us think through what a good run rate is for the LOE adjusted transport line item? Just trying to think about how that number could evolve as we look toward 2020.

Tim Cutt -- President and Chief Executive Officer

Joe wants it.

Joe Redman -- Vice President of Energy

Yes. Most of our transportation and processing volumes move through contracts. And so that's really a direct relationship to our volume forecast of the year, and there's not a lot of subjectiveness for variability in that outside of volume.

Kashy Harrison -- Simmons Energy -- Analyst

So yes, I mean a good rate per unit.

Tim Cutt -- President and Chief Executive Officer

Yes, it's about $3 a barrel equivalent. If you take out the onetime charge associated with the pipeline commitments. On average, it's going to be plus or minus, $3 Boe.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. All right. That was it for me. Thank you.

Operator

Our next question comes from Gail Nicholson with Stephens. Please proceed with your question.

Gail Nicholson -- Stephens Inc. -- Analyst

Good morning. I just want to dig into LOE a little bit more. You guys saw a really good decrease quarter over quarter. I mean, you talked about transitioning to gas lift versus Rod Thompson at the Bakken.

With that transition to gas lift, could you talk about the potential LOE savings you could see in the Williston? And then where does the Permian sit on an LOE aspect versus the Williston today, currently?

Tim Cutt -- President and Chief Executive Officer

OK. I'm going to flip this over to Joe Redman. He's our head of production.

Joe Redman -- Vice President of Energy

Thank you for the question on our operating expenses. In the Williston, we have been employing an initial lift method of ESPs and gas lift. We'll probably be using some gas lift optimization around our new drilling as we go forward. And I think that will come in at a lower op cost than we've historically seen around our ESPs.

We've also been working in that field just around our fixed expenses and then bidding activities. We've done the same in the Permian, and we are continuing to drive our LOE down there kind of through similar methodologies. And as you mentioned, our LOE in the Permian is quite a bit less of -- we're running this year in the range of about $4 Boe.

Gail Nicholson -- Stephens Inc. -- Analyst

OK. Great. And then just looking at the refrac in the Williston, can you remind me what the current cost of those are? And do you think there's any incremental room for potential improvement on the cost side as you look in 2020?

Tim Cutt -- President and Chief Executive Officer

Yes. So I'll take that one. So right now, it's about $5 million per well on the refrac. We absolutely, as we get back into a rhythm here, we have more in series, want to take that cost down.

So we're already talking to our suppliers around how to do that. And we've encouraged that the lower it goes, the more we can do. And the same thing on the drilling and facility costs in the Williston. We talk about 100 locations remaining in the Williston, but that number expands all the way up to about 700.

If you get better price and much lower cost. And so we are very motivated to bring those costs down. So I don't want -- I wouldn't want to guess a number, but we're 5, we will get to 4, probably not, but we're going to work toward that.

Gail Nicholson -- Stephens Inc. -- Analyst

OK. Great. Thanks so much.

Operator

[Operator instructions] Our next question comes from Betty Jiang with Credit Suisse. Please proceed with your question.

Betty Jiang -- Credit Suisse -- Analyst

Good morning. I have a question on the artificial lift strategy change. Could we get a bit more detail in Bakken? I see -- understand that you have seen the benefit of shortest cleanup time, but do you expect to see any change in the shape of production? Or is there any change in the decline profile?

Tim Cutt -- President and Chief Executive Officer

Yes, Betty, that's a good question because this has been quite a big change for us. And we've been watching what industry is doing. We've been testing all of our technical thoughts around this, and we concluded that going a little bit harder, early, not only won't hurt things, we might actually help things. And so we've moved to a strategy that opens up the wells a bit quicker.

We're still staging about 100 ps -- drawing about 100 PSI for change in choke size, but you can see the production is coming on quiet quicker. And when it does that, the pressures come down in your ESP and you can get on with producing quite a bit quicker. We don't know over time. We've talked a lot in the past.

We've been dinged a little bit for coming on slowly, but we've always said by day 365, we're kind of caught back up. Same thing could happen here. We could go back to where you get back on a decline curve to where you're -- ultimately, you are as fairly similar. We still think regardless from a productivity of well, and NPV of the well, it still makes sense to bring these on a bit quicker.

So final tell, you can see on DSU 13, we're getting close to the curve there over the next several months, we'll see where that goes. But we feel good that that's declining and flattening as expected, and we're encouraged by what we're seeing.

Betty Jiang -- Credit Suisse -- Analyst

Great. Thanks for that. And then my next question is on the 4Q oil guidance, just with no completions in the Permian. Could you just help us understand the dynamics between the Bakken and the Permian, that's driving the implied increase in oil volumes? And then also just on 2020, with the lumpiness of the completion profile.

Does -- how does 4Q '20 product oil volumes compared versus 4Q '19.

Tim Cutt -- President and Chief Executive Officer

Yes. OK. So on the first question, sorry, remind me, what you're asking?

Betty Jiang -- Credit Suisse -- Analyst

The dynamics between the Bakken and the Permian, that's driving the increase.

Tim Cutt -- President and Chief Executive Officer

Yes, got it. So yes, So you're going to -- we have a substantial increase right now in the Bakken, bringing those new well loan. Remember, the Bakken wells average north of 2,200 to 2,500 barrels of oil each per day, and we did seven wells. Part of keeping the cost out on the facility, we built a 10,000 barrel a day facility.

That facility will stay flat for the next two, three months and then start declining. And so over the next three months, we should have -- we should see all of the gains and maintain those gains over that three months. And so you'll see a big uplift there. And then you start to go on decline.

And we just now started to go on decline in the Permian. Obviously, that decline is more modest than the uplift of the Bakken. And so you see flat to slightly increased production quarter over quarter. Betty, I think it's early for us to speculate on the fourth quarter of next year, we put some numbers out on what we think will happen.

We want to continue to get better. We want to continue to get faster. That takes more dollars out. That allows us to do a little bit more.

And I think the shape of that curve for next year is generally set, where you're down a little bit more in the first quarter, you start building again on the second, peak in the fourth -- in the third, and then you come off -- start coming off again in the fourth. And so I think for us to get an accurate kind of '19 fourth quarter to '20 fourth quarter, we're going to have to get a little bit closer to it. And again, our whole goal is to get better every single day. And so as we get closer to this, we'll continue to guide and update as we can.

Betty Jiang -- Credit Suisse -- Analyst

Right. Thank you for that.

Operator

Our next question comes from Kevin MacCurdy with Heikkinen Energy. Please proceed with your question.

Kevin MacCurdy -- Heikkinen Energy -- Analyst

Hey. Good morning, guys. To follow-up on the question around LOE. Per barrel costs were materially lower quarter over quarter.

Can that continue? Is that kind of the new standard going forward?

Tim Cutt -- President and Chief Executive Officer

Ken, I think we had a few prior periods in there. I think if you look at our forecast, what we put for the full year, you'll calculate a good accurate number for the LOE.

Kevin MacCurdy -- Heikkinen Energy -- Analyst

OK. Fair enough.

Tim Cutt -- President and Chief Executive Officer

So we get all these and you're lumpy. You have things that come go and they can be a little bit lumpy. But generally, we've had a substantially low quarter. It may come back up a little bit in the fourth quarter.

But overall, it's dependent on seasonality and a lot of different things.

Richard Doleshek -- Executive Vice President and Chief Financial Officer

And Kevin, just to give you an example, workover expense, which is fixing things that break was down more than $1 million from the second quarter to the third quarter, we don't control that. Rod parts when they want to part. So we had a really good third quarter in terms of fixed break stuff.

Kevin MacCurdy -- Heikkinen Energy -- Analyst

Great. So maybe some lumpiness, but overall, the trend is down?

Tim Cutt -- President and Chief Executive Officer

Absolutely. Yes, if you look at our unit cost is coming down. It's clearly month-over-month, quarter over quarter as we add in new facilities, as we add in new water injection facilities, production facilities, more wells, the absolute costs goes up, and you'll see the unit cost kind of move with our production profile that we described in the deck.

Kevin MacCurdy -- Heikkinen Energy -- Analyst

Thanks. And my next question is, you mentioned that the frac crews coming back to the Permian in late fourth quarter. What month will we start to see churn in line? I'm just trying to get an idea of production for Q1?

Tim Cutt -- President and Chief Executive Officer

Yes. We've had a few questions about kind of capital profile in the fourth quarter. I mentioned in my talk, we will start late in the quarter. We expect to start fracking again in December.

We have built an inventory by December of about 40 wells in County Line. And that enables us to get started and go on a continuous frac program into next year, into late second quarter, early third quarter. And so December is the optimum time to get started. Those four wells will be fracked, but they likely won't come online until early in February.

So you'll see kind of January continue to decline. February, we start to bring those back online.

Kevin MacCurdy -- Heikkinen Energy -- Analyst

All right. Thanks for that. Great quarter, guys.

Operator

Ladies and gentlemen, we've reached the end of the question-and-answer session. I'd now like to turn the call back to Tim Cutt for closing comments.

Tim Cutt -- President and Chief Executive Officer

Yes, not much more to add. I appreciate the questions. I appreciate the interest. I hope you see that we're serious about delivering what we've set out to deliver.

I just really want to say another thanks to our organization. We've gone through a lot. We've made a lot of changes. But we've landed on a very, very strong organization, capable of doing great things and I've been super impressed.

So I just want to thank the organization. With that, I think we'll close.

Operator

[Operator signoff]

Duration: 37 minutes

Call participants:

William Kent -- Director of Investor Relations

Tim Cutt -- President and Chief Executive Officer

Richard Doleshek -- Executive Vice President and Chief Financial Officer

Gabe Daoud -- Cowen and Company -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Bill Buese -- Vice President of Finance

Kashy Harrison -- Simmons Energy -- Analyst

Joe Redman -- Vice President of Energy

Gail Nicholson -- Stephens Inc. -- Analyst

Betty Jiang -- Credit Suisse -- Analyst

Kevin MacCurdy -- Heikkinen Energy -- Analyst

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