Unit Corp

OTC:UNTC

Earnings Call Transcript 2017-Q4

[Operator]

Welcome to the Unit Corporation's Fourth Quarter 2017 Earnings Call. My name is John, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded.

During the course of the conference call today, the speakers will make statements that constitute projections, expectations, beliefs or similar forward-looking statements. The company's actual results could differ materially from the results anticipated or projected in any such forward-looking statements. Additional detailed information concerning the important factors that could cause actual results to differ materially from the information given today is readily available in today's press release under the heading forward-looking statements.

Additionally, during the conference, the company will be discussing certain non-GAAP financial measures. The reconciliation of these non-GAAP measures to GAAP measures can also be found in today's press release. This document is available on the company's website.

And I will now turn the call over to Larry Pinkston, President and CEO. Larry, you may begin.

[Larry Pinkston, executive]

Thank you, John. Good morning, everyone. I want to thank you for joining us this morning. With me today are David Merrill, Les Austin, Brandt Elias, John Cromling and Bob Parks. Les Austin joined us in November as Senior Vice President and Chief Financial Officer, and Brandt Elias is filling in for Frank Young, who is unable to participate on the call today. Each of these gentlemen will be providing you with updates concerning their segments, and then we will take questions at the end of the call.

I'll now turn the call over to David Merrill.

[David Merrill, executive]

Good morning. We are pleased to report very solid results for Q4 and 2017. The year was marked by improvement and successes in each of our 3 business segment. We continued to focus on growth in all 3 segments while maintaining capital budget in line with cash flow.

Despite headwinds from our reduced drilling activity through most of 2016 in our Oil and Natural Gas segment, we were able to begin growing production in the second quarter, which continued through the balance of the year.

Additionally, we were able to replace 300% of 2017 production with new reserves, resulting in a 27% increase to total proved reserves. In 2017, our contract drilling segment had a 72% increase in the number of rigs operating over 2016, and we've placed our 10th BOSS rigs into service during the second quarter. Our midstream segment achieved growth in liquids sold volumes and gas processed volumes in the fourth quarter due to increased activity levels around gas gathering and gas processing systems. The midstream segment also posted a record operating profit in 2017.

I'll now turn the call over to Les Austin.

[George Austin, executive]

Thanks, David. We reported net income for the fourth quarter of $89.2 million, or $1.71 per diluted share. This amount includes $81.3 million in tax benefit related to the revaluation of our net deferred tax liability as required under the December 2017 Tax Cuts and Jobs Act.

Adjusted net income for the quarter, which excludes the effect of noncash derivatives and the effect of the Tax Act, was $11.3 million, or $0.22 per diluted share.

Our non-GAAP financial measure reconciliation is included in our press release.

For the Oil and Natural Gas segment, revenues for the fourth quarter increased 19% over the third quarter because of increased production volumes and higher commodity prices. Operating costs for equivalent barrel for the fourth quarter decreased 3% from the third quarter because of higher production volumes.

In the contract drilling segment, revenue for the fourth quarter decreased 10% from the third quarter because of a decrease in a number of drilling rigs operating, offset slightly by an increase in average day rates. Operating cost for the fourth quarter decreased 10% from the third quarter primarily due to fewer rigs operating.

For the midstream segment, revenue for the fourth quarter increased 10% over the third quarter primarily because of higher liquids and condensate prices and increased processed volumes. Operating costs for the fourth quarter increased 14% over the third quarter because of increased gas purchase prices and volumes. We ended the fourth quarter of 2017 with total long-term debt of $820.3 million, an increase of $16.5 million over the end of the third quarter.

Long-term debt consists of $642.3 million of senior subordinated notes, net of unamortized discount and debt issuance costs and $178 million of borrowings under our credit agreement.

Our current credit agreement borrowing base remains unchanged at $475 million. The borrowing base consists of our oil and gas properties and the midstream business, but does not include our fleet of drilling rigs. Our senior leverage ratio was 0.65x EBITDA at the end of the fourth quarter, and the maximum senior leverage covenant is to be no greater than 2.7x EBITDA. Our 2017 operating segment capital expenditures, excluding acquisitions, were $277 million. We anticipate our 2018 capital expenditures will be $352 million, which will be within anticipated cash flow and proceeds from noncore asset sales, if any.

Of our capital expenditures budget, $272 million is reserved for our Oil and Natural Gas segment, a 26% increase over 2017, excluding acquisitions; $47 million will be used for our drilling segment, a 30% increase over 2017; and $32 million will be used for the midstream segment, a 44% increase over 2017.

At this time, I will turn the call over to Brandt for our Oil and Natural Gas segment update.

[Brandt Elias, executive]

Thank you, Les. Good morning. Now I'll provide operational updates for our quarries in Wilcox, Granite Wash and Hoxbar plays as well as some guidance for our drilling program in 2018. Production in the fourth quarter grew 6% compared to the third quarter. Total production was 4.3 million BOE, compared to a production of 4.1 million BOE during the third quarter of 2017.

2017 we were able to replace 300% of our production with new oil and gas reserves. In the Wilcox area in South Texas, we continued our strategy of exploration growth and developing high reward, low-risk re-completions and infill drilling in the Gilly field area.

In 2017, Unit spent approximately $15 million, executing 40 re-completions and workovers, which increased production to 5,000 BOE per day, or 500%. In addition, 2 higher rate of return infill wells were drilled and completed in the Gilly field area in the fourth quarter, adding 2,200 BOE per day.

At our Cherry Creek exploration prospect, pipeline and surface facilities for Trinity #1 were completed in November, adding 900 BOE per day. We plan to drill a second well this year to help further delineate Cherry Creek prospect and provide more data about the potential size of the field.

In addition to the Cherry Creek prospect, we drilled and completed a successful discovery well in our Brandt exploration prospect, adding 1,700 BOE per day in December. As a result of these operations, production from this area continues to increase, with 2017 exit rate 12% higher than 2016 exit rate.

2018, we expect to take up a Unit rig in February and drill 8 vertical and 2 horizontal wells this year. Drilling capital for this 10-well program is approximately $55 million.

In our Granite Wash play, production per day in the fourth quarter increased 12% over the third quarter. Our first lateral in the B-interval of the Granite Wash was brought online in the fourth quarter. Production from the B-interval is doing very well and is currently exceeding our type curve expectations.

In early February 2018, we brought on our first 3 9,500-foot laterals in our Buffalo Wallow field. This targeted the C1 interval of the Granite Wash. The wells are in their early part of flowback, but we expect production to meet or exceed our C1 type curve. In 2018, we will focus on drilling the C1 member of the Granite Wash in Buffalo Wallow field, drilling 11 wells for an estimated cost of $71 million. We are very pleased with the results of these wells produced from the C1 member of the Granite Wash.

In the SOHOT area, production for the fourth quarter increased 7% over the third quarter due to the addition of 2 new wells. Both wells had initial rates above our Marchand type curve. Production continues to exceed type curve expectations.

In January of 2018, we completed our first extended lateral in the core area of our SOHOT play, the Schenk Trust 1-17HXL, with a 20-day IPE of 2,500 BOE per day, consisting of 76% oil and 15% natural gas liquids.

For 2018, we will continue our 1-rig development program in our core SOHOT area, with 9 wells, with 6 of the new wells being extreme laterals, for an estimated cost of $34 million.

For 2018, we're also planning to utilize a Unit rig to drill out first [indiscernible].

Unit currently has 17,000 net acres in the STACK, and we'll continue to add to this position in 2018. The drilling program will start with 2 wells in the western STACK play in Dewey County, testing the lower Osage and Meramec formations before moving to Custer County to drill 2 laterals in the dry gas over-pressured window in STACK.

Total cost for these wells are an estimated $33 million for 2018.

In summary, I'm pleased with production growth we've seen in the fourth quarter as well as with some of the recent developments we've seen in our core assets. We're also excited about the potential development this year in our STACK position. Production for 2018 is estimated to be between 17.1 million and 17.4 million BOE, which would represent a growth of 7% to 9% over 2017 production.

At this time, I will now turn the call over to John for the drilling company update.

[John Cromling, executive]

Great. Thank you, Brandt. 2017 was a very good year for the contract drilling segment, even though our rig utilization declined slightly during the fourth quarter. The average day rate for the fourth quarter was $16,645, an increase of $191 per day over the third quarter. The average total daily revenue with no elimination of intercompany profit was $16,973, an increase of $140 over the third quarter.

Our total daily operating cost, before intercompany eliminations, increased by $82 for the fourth quarter as compared to the third quarter. This increase was primarily due to some end of the year G&A expenses.

The daily direct rig expenses continued to improve during the fourth quarter, as they have done in the past 9 months. The average per day operating margin for the fourth quarter, before elimination of the intercompany profits, was $5,550, which is a small increase over the third quarter. Our non-GAAP reconciliation can be found in today's press release. We began the quarter with 33 operating rigs and decreased to 31 by quarter's end. Presently, we have 32 rigs active.

Our activity level has remained relatively consistent with the industry activity level. Currently, all 10 of our BOSS rigs are operating with 4 of them under term contracts.

During the last year, we have put into service 2 new BOSS rigs and upgraded 9 1,500-horsepower SCR rigs to varying degrees with walking systems, 7,500 PSI mud systems, dirt pumps and/or hydraulic catwalks.

We have several additional SCR rigs, which are excellent candidates for refurbishment as market dictates. The land rig utilization rate declined during the fourth quarter for the industry and for Unit. However, the inquiries for rigs has increased the past few weeks, and the land rig count has slowly increased during the first quarter of 2018.

Unit is also experiencing similar results.

At this time, I'll turn the call over to Bob for Superior Pipeline.

[Robert H. Parks, executive]

Thank you, John. The midstream segment completed a successful year, improving operating profit by 7% over 2016 results. 2017 operating profit was $51.7 million, which was a record for Superior. These results were achieved by improved prices throughout 2017 by our continued focus on efficient operations and our commitment to monitor and reduce field direct operating expenses.

During the fourth quarter of 2017, we increased our gas processing volumes 6% and our gas liquids volumes 10% compared to the previous quarter. These increases were achieved by 7 new wells in several of our key systems, such as Hemphill, Cashion, Segno and Bellmon, as producers continued to be active in these areas.

I will now focus on several key areas of our midstream business. At our Cashion processing facility in Central Oklahoma, we are completing a $14 million pipeline expansion project, which will allow us to gather and process gas from a producer that has a significant acreage dedication and is rapidly growing in the Cashion area. The main trunk line has been completed, and we've installed several laterals to connected wells.

During 2017, we've connected 12 new wells to our Cashion system from 3 different producers. Our total throughput volume averaged 37.3 million cubic feet per day in the fourth quarter and our total processing capacity for the facility is approximately 45 million cubic feet per day. As volumes continued to increase, we're evaluating the need for additional processing capacity in the Cashion area.

At our Hemphill facility in the Granite Wash area, our total throughput volume averages approximately 68.5 million cubic feet per day for the fourth quarter of 2017, and we produced approximately 188,600 gallons of natural gas liquids per day. During 2017, we've connected 6 new wells to the system. All 6 of these wells were in the Buffalo Wallow area, and we are scheduled to connect several more wells in this area during 2018.

We are currently constructing a pipeline to the next well pad, and we are upgrading our compression facilities in order to handle the expected additional volumes.

With our total processing capacity at approximately 135 million cubic feet per day, we have sufficient plant capacity to handle the expected additional volumes from the system.

In the Appalachian area, our Pittsburgh Mills gathering facility continues to be one of the best cash flowing systems for Superior.

Our average total throughput for 2017 was approximately 130 million cubic feet per day, and we expect to connect the next well pad to the system at the end of 2018.

We completed all initial environmental studies, permitting and right-of-way issues related to this next pad and expect to start physical construction of the pipeline in the first quarter of 2018. This new pad will have 7 wells on it, and we expect to receive production from this pad by the end of 2018.

Additionally, we've received notice from the producer that it will drill 7 infill wells on existing pads in 2018.

We expect to receive production from the first 3 wells in July and the next 4 wells in September. So if these wells can be drilled on existing pads, there will be minimal capital cost and excess production for our gathering system.

In summary, 2017 was a record year for Superior Pipeline. These results were achieved by our ability to connect new wells to our systems, our continued focus on efficient operations along with our effort to control direct operating expenses. Also, with our mix of commodity-based contracts as well as fee-based contracts, we were also able to see better financial result from improving prices over the year.

With 29% of our total volumes exposed to commodity pricing, we expect to see increased margins in our processing systems, assuming ethane and propane prices improve in 2018.

We expect to continue extending several of our key assets as well as connecting new wells for our existing systems. These factors as well as improving processing economics will propel the midstream segment to another successful year in 2018. At this time, I'll turn the call back over to Larry for his final comments.

[Larry Pinkston, executive]

Thank you, Bob. We began 2017 with an optimistic outlook for the year despite the continuation of a volatile commodity backdrop.

We approached the changing economic conditions in our industry in our normal disciplined manner. We believe this approach positioned us for a solid execution during 2017.

As you have heard from the presenters, we have been able to grow each of our 3 business segments while keeping capital expenditures in line with cash flow. We are pleased with the production growth that we have achieved over the last 3 quarters. We are also pleased to achieve our second highest rate of production replacement with new reserves since 2000 without a significant acquisition. We have been able to add

to our inventory of prospective wells which is a

very key item for growth.

Best of all, the returns on the wells we have seen in our core areas compete very well with all the other active basins. The continued success of our BOSS drilling rigs is very gratifying, as is our continued improvement in rig utilization. Our midstream business recorded a record operating profit for the year. Our assets are well placed and our commodity and fee-based contracts exposure mix is paying off in those wells for the future.

Overall, we are pleased with our results for 2017. We look forward to an even stronger 2018, and we will continue to grow our company in a manner consistent with the best interest of our shareholders, our customers and our employees.

I would now like to turn the call over for questions.

[Operator]

[Operator Instructions] And our first question is from Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

First, maybe just looking to rig side. It seems like talking -- listening to a lot of E&Ps putting their budgets out for the year, they continue to be quite active. I'm just wondering, is that sort of in sync with what you're seeing on bidding activities? Or any color you can give around that?

[John Cromling, executive]

Neal, this is John. That's true. We have seen a large increase in inquiries through January and now through part of February and that's also the same reason why we saw a decline in December because the people have had already used up their budget and they waited till the New Year to begin. But yes, we're seeing the benefits of that now.

[Neal Dingmann, analyst]

That sounds great there. And then moving to upstream side, maybe a question for Frank just on -- Frank, you have some interest in acreage, certainly on the STACK and STACK extension. Maybe you mentioned that a little bit. Could you just talk about, again how much activity we potentially could see there towards the latter half of this year.

[Brandt Elias, executive]

Yes, Neal. This is Brandt. I can answer that question for you. So we plan on picking up a rig and spudding our first well in March of this year. And we will -- as I stated, we will test 2 wells in the western STACK position that we currently have and then we will move that rig to the over-pressured dry gas window and drill 2 over there. Anticipated production for the first 2 wells will be started in the third quarter and then even dry gas wells will come on later in the third quarter.

[Operator]

Next question is from Marshall Adkins from Raymond James.

[J. Marshall Adkins, analyst]

Just following up on that last question, Brandt. I'm sure you've got something in mind in terms of type curves of other wells in that vicinity in the STACK. Can you give us just some frame of reference on what you're looking for in terms of well productivities out of the STACK stuff you'll be drilling this year?

[Brandt Elias, executive]

Yes. I can give you some more insight on that. For Western STACK position, the active players down there are Tapstone and some others. For the lower Osage, we anticipate a little bit drier gas well, rates anywhere between 5 to 10 million a day, and the oil rates will be a little bit lower, maybe 50 to 100 barrels a day on the IPEs there. And then for the Meramec, which is a little bit shallower, it's going to be more oily, 3 to 5 million a day gas, 200 to 500 barrels a day oil there. This is kind what we're looking at.

[J. Marshall Adkins, analyst]

Perfect. And then staying with the E&P theme, you all gave pretty good guidance on what you're thinking on realized prices after differentials and hedging. Just to put it in the frame of reference of our thought process, obviously, we're very bullish on crude. I'm curious as to how much of that is locked in with hedges and how much is just the differential to Cushing WTI prices at least from the oil side, I guess, Henry Hub on the gas side. Could you help us -- help me to at least, to my modeling cause I'm probably more bullish on the oil outlook than you all -- reconcile those 2 issues?

[David Merrill, executive]

Marshall, this is David. On the hedging side, we're about 75% hedged on the oil side of our anticipated 2018 production. 2/3 of those are swapped and the other 1/3 is collars and 3 ways. And the swaps are in the low to mid-50s. So that's where we are on the oil side.

[J. Marshall Adkins, analyst]

And I presume there is wiggle room on those collars, so there is upside to those. Correct?

[David Merrill, executive]

That's correct.

[J. Marshall Adkins, analyst]

All right, keep going. Sorry to interrupt.

[David Merrill, executive]

And I think you were -- you asked what our differentials typically run on WTI. They -- currently, they run at about $2 on WTI.

[J. Marshall Adkins, analyst]

Okay. And then so you got the oil hedges. How about gas? I presume you have some on that as well.

[David Merrill, executive]

We do. We're about 50% hedged throughout the course of the year, varies a little bit by quarter, but averages around 50%. We're around 40%, 50% swaps. And of course, you can do the math on the collars and 3 ways, and our swaps are right around $3. And the collars and 3 ways give us a little more upside, too.

[J. Marshall Adkins, analyst]

And the differentials to Hub?

[David Merrill, executive]

Overall, we have different delivery points, but whenever you blend it all, we're about a $0.40 differential.

[J. Marshall Adkins, analyst]

Okay. All right. Perfect. And last question for me. Sorry for all the detail here, but you mentioned some possibility on the rig side for more upgrades or, I don't know, if we call them reactivations, how many more do you -- are you thinking about doing or how many more can you do? And it sounds like you're -- so far what you've done is you've taken the SCRs and just beefing them up. You're not actually converting them to AC. So could you give me just a little more detail on what you're doing on the upgrades and/or reactivations?

[John Cromling, executive]

That's true, Marshall. We're not changing any of those to AC, but we are adding those different items that I mentioned earlier. There's probably at least 20 more that would be a prime candidate to do that and then probably another 10 that would be -- that would require more work to make those marketable for what people want right now. So we have a lot of room to grow in it, and it's just having the right opportunity where we can get enough term on the contract in order to justify making the expenditure. And most usually, that's around 6 months.

[J. Marshall Adkins, analyst]

And so the acceptance of those relative to just the BOSS rig or AC rigs, how's that coming?

[John Cromling, executive]

Well, it's gone pretty good, really. I'm not going to say that the BOSS rigs are not preferred, but -- because they just have such abilities that the other rigs can't have. But not every operator needs a BOSS rig that has the walking capabilities and high pump outputs and all those things. So we just have to fit the rig with the opportunity. And as part of the value, we have quite a diverse fleet of rigs. So we just have to look at each one of them individually.

[Operator]

[Operator Instructions] And our next question is from Charles Robertson from Cowen and Company.

[Charles Robertson, analyst]

All right. Starting off on the E&P side. It looks like you've exited the year on a pretty strong clip into 2018. Reflecting on that, it seems to me just that your guidance is maybe a little bit conservative, especially if you're adding another rig. Any thoughts on that?

[Larry Pinkston, executive]

Charles, you know us. We tend to be conservative in any kind of forecast we give out. A lot of us depend on how good the early wells we drill in a year. And we certainly don't want to account all of them being good, but a certain portion of them being good. So is there upside potential on our production? Sure. I mean, there is, but we always feel good about the rate we put out. But key is going to be some of the wells, getting them online. It's not really a question of getting them drilled, but more getting them online and on production early enough in the year to make a substantial difference.

[Charles Robertson, analyst]

And maybe one for Brandt here. In the Granite, any sort of change in the well design, obviously, moving into the B rather than the C?

[Brandt Elias, executive]

No. Yes, there's no change in the well design. The C1 has been the target that we've been going after the most. It has a little bit better oil rates, a little bit more liquids than what we've seen in the B and the other sand. So we wanted to continue that development in the C1 and basically kind of finish it out going from this year into next year.

[Charles Robertson, analyst]

And then on the drilling side, obviously, you mentioned the BOSS rig and preference. Thoughts there on adding an additional rig during the year? Is that a possibility?

[John Cromling, executive]

That's certainly a possibility and that's why the capitalized budget for the drilling company is what it is to allow us the opportunity to build another BOSS rig and/or do refurbishments for rigs. So we'll be making that decision very soon on whether we begin that process or not. But again, it's just a fact of evaluating the opportunities but you can cash flow and go from there.

[Charles Robertson, analyst]

And on the interest that you're seeing, is that built on the public as well as the private side?

[John Cromling, executive]

Yes, it's a good mixture. In certain areas, for instance, Oklahoma, we'll have more private companies that we work for in the Permian and in the Rocky, so would be more public companies. So it's a good mix of both.

[Charles Robertson, analyst]

And then on the midstream side, obviously, processing and looking for the additions there. What do you see as challenges to executing on that throughout the year?

[Larry Pinkston, executive]

Well, we're well situated with our current processing plant capacities. As pricing improves for ethane going forward, we'll start recovering ethane again. So we're pretty excited about our situation today and what the upside is as we go forward with both volumes and pricing.

[Operator]

[Operator Instructions] And I am seeing no further questions, Larry, so I'll turn it back over to you for closing remarks.

[Larry Pinkston, executive]

All right. Thank you, John. I want to just thank everybody for joining us this morning. It was a very exciting quarter. It was a very exciting year for us coming out of 2016, which wasn't very exciting. We are looking very much forward in 2018. We thank everybody. It is pretty well lined up to have -- it should be a good year. But appreciate you joining us this morning. We look forward to visiting with you some more in the future. Thanks.

[Operator]

Thank you. Ladies and gentlemen, that concludes today's conference. Thank you for participating, and you may now disconnect.