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Edited Transcript of UNT earnings conference call or presentation 21-Feb-19 4:00pm GMT

Q4 2018 Unit Corp Earnings Call

TULSA Feb 26, 2019 (Thomson StreetEvents) -- Edited Transcript of Unit Corp earnings conference call or presentation Thursday, February 21, 2019 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* David T. Merrill

Unit Corporation - COO

* Frank Q. Young

Unit Petroleum Company - EVP of Exploration & Production

* George Les Austin

Unit Corporation - Senior VP & CFO

* John H. Cromling

Unit Corporation - EVP of Drilling - Unit Drilling Company

* Larry D. Pinkston

Unit Corporation - President, CEO & Director

* Robert H. Parks

Unit Corporation - Manager & President of Superior Pipeline Company LLC

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Conference Call Participants

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* James Marshall Adkins

Raymond James & Associates, Inc., Research Division - MD of Equity Research & Director of Energy Research

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

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Presentation

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Operator [1]

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Welcome to Unit Corporation's Fourth Quarter 2018 Earnings Call. My name is Sophie, and I'll 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 may 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 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 those non-GAAP measures to GAAP measures can also be found in today's press release. This document is available on the company's website.

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

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Larry D. Pinkston, Unit Corporation - President, CEO & Director [2]

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Thanks, Sophie. Good morning, everyone. Well, thank you for joining us this morning. I have with me today David Merrill, Les Austin, Frank Young, John Cromling and Bob Parks. Each of these will be providing you with updates about their areas of responsibility. We'll take questions at the end of the call.

Just a few words about 2019 going forward. With a drop in -- with the 40% drop that we had in West Texas crude price in December through January, which had a very clear reaction in operator capital expenditure plans for 2019. According to the Baker Hughes U.S. land rig count data, the rig count has dropped by 33 rigs from a fleet to valley to date, essentially returning to the end of third quarter levels. We have and it appears that other operators have held back their capital expenditure plans until the picture becomes clear as to the direction the commodity prices are headed.

We run multiple iterations for our budget in preparation for presenting our clients for 2019. As always, our focus is to maintain a very strong balance sheet, which is the principal reason anticipated cash flow is a basis upon which we determine our capital expenditure plans each year.

And I would like to turn the call over to David to cover 2018 operations.

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David T. Merrill, Unit Corporation - COO [3]

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Thank you, Larry. Good morning, everyone. As Larry stated, our capital plan for 2019 is in line with our anticipated cash flow. The commodity swings recently experienced have resulted in us establishing a capital budget range of $336 million to $422 million for 2019. This represents a reduction of 27% to 8% year-over-year, with the upper end of the capital range requiring commodity prices to improve throughout the year. If commodity prices do not improve, we will trend to the lower end of the range.

As noted in our press release this morning, our capital budget allows us to estimate year-over-year production growth of 2% to 5%. Despite the fourth quarter commodity price challenges, we continue to make progress on several fronts. Our oil and natural gas segment worked through some production delays, while still achieving its year-over-year production guidance. The segment was also able to drill and complete very strong new wells in our Penn sands prospect area, which has led us to make some bolt-on acquisitions in Western Oklahoma, which Frank will discuss in further detail in a minute. Our contract drilling segment was able to deploy our 12th and 13th BOSS drilling rig during the first quarter of 2019. And for our midstream business, completion of 2 organic projects will provide for incremental growth opportunities going forward.

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

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George Les Austin, Unit Corporation - Senior VP & CFO [4]

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Thanks, David. We reported a net loss attributable to Unit for the fourth quarter of $77.8 million or $1.49 per diluted share, which includes a pretax noncash write-down of $147.9 million, associated with the removal of 41 drilling rigs from our fleet.

Adjusted net income attributable to Unit for the quarter, which excludes the effect of noncash derivatives and this noncash write-down, was $13.8 million or $0.27 per diluted share. Our non-GAAP financial measures reconciliation is included in our press release.

For the oil and natural gas segment, revenues for the fourth quarter decreased 5% from the third quarter of this year, with lower oil and NGL prices offset by increased natural gas prices. Equivalent production decreased 1% in the fourth quarter from the third quarter of this year.

Operating cost for the fourth quarter decreased 3% from the third quarter of this year, primarily due to lower production tax expense, partially offset by increased LOE. For the contract drilling segment, revenues for the fourth quarter increased 5% over the third quarter of this year due to 3% higher day rates during the quarter offset by 1.1 fewer rigs operating in the quarter. Operating cost for the fourth quarter were 12% higher compared to the third quarter of this year due to increased employee costs and indirect and drilling G&A expenses.

For the midstream segment, revenues for the fourth quarter decreased 4% from the third quarter of this year, primarily due to decreased liquid recoveries and decreased volumes transported, combined with decreased liquids and condensate prices. Operating cost for the fourth quarter increased 1% over the third quarter of this year because of increased purchase prices.

We ended the fourth quarter of 2018 with total cash and cash equivalents of $6.5 million and long-term debt of $644.5 million. Long-term debt consists entirely of our senior subordinated notes, net of unamortized discounts and debt issuance costs. The Unit credit agreement borrowing base remained unchanged and undrawn at $425 million, and the $200 million availability of our superior credit agreement was undrawn as well.

Our net leverage ratio was 1.8x at the end of the fourth quarter. Our 2018 capital expenditures excluding acquisitions of $31 million were $458 million. We anticipate our 2019 capital expenditures will be between $336 million and $422 million. This range is in response to the current commodity price environment and is designed to be within anticipated cash flow and proceeds from noncore asset sales if any. Of the total capital expenditure budget, $271 million to $315 million is reserved for the oil and natural gas segment compared to $338 million for 2018. $30 million to $65 million will be used for the drilling segment compared to $75 million for 2018. And $35 million to $42 million will be used for the midstream segment compared to $45 million for 2018.

At this time, I will turn the call over to Frank for our oil and natural gas segment update.

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Frank Q. Young, Unit Petroleum Company - EVP of Exploration & Production [5]

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Production for 2018 was 17.1 million barrels of oil equivalent, which was at the low end of our anticipated production rate going into 2018, a 17.1 to 17.4 million Boe. The primary reasons for being at the low end of our production guidance were unanticipated delays in production in the Texas Panhandle due to post-fracture stimulation frac plug drill-out as well as 2 laterals that had to be redrilled after completion hardware failure and unanticipated requirement to shut-in wells during the commissioning of a third-party interstate top line in Western Oklahoma and lowered NGL recovery in our Gulf Coast area due to 3 new wells producing dryer gas than anticipated.

In late September of 2018, Unit drilled the Schrock 22/15 #1HX, the first Red Fork extended lateral drilled in Oklahoma in our Penn sands prospect area. The IP30 for this well is over 2,000 barrels of oil equivalent per day with an oil cut of about 80%. After 4 months, the well is still producing 1,650 barrels of oil equivalent per day with an oil cut of about 40%. In addition, we brought on a second Red Fork lateral in late October, the Frymire 1-18H, which had an IP30 of 850 barrels of oil equivalent per day, that was primarily wet natural gas with some oil. Well cost for 1 mile Red Fork laterals are about $6 million and for 2-mile laterals about $7.5 million.

Following these exciting well results, we acquired offsetting oil and natural gas assets in December, located primarily in Custer County, Oklahoma for $29.6 million. The acquisition added approximately 8,700 net acres to our Penn sands area, including 44 through developed producing wells and about 2.6 million barrels of oil equivalent of proved reserves. Of the acreage acquired, approximately 82% is SOHOT production. This acquisition provides Unit approximately 20 to 30 potential horizontal Red Fork drilling locations, which are anticipated to have a significant percentage of oil in the total production stream.

Unit currently has 1 rig drilling Red Fork horizontal wells in this area, with plans to add a second rig for the second quarter. At midyear, the Red Fork drilling program will be reassessed in light of oil reserves and commodity prices to decide if the program will continue for the second half of 2019.

In our Southern Oklahoma Hoxbar Oil Trend or SOHOT play in western Oklahoma, primarily in Grady County, we continue drilling horizontal wells in the oily Marchand sand. We're having success picking up smaller chunks of acreage at a reasonable cost in this play that will allow us to add a second rig to our drilling program in the second quarter. We'll also reassess this drilling program midyear and lot of commodity prices to determine how many rigs, if any, we'll continue to run in the second half of 2019.

Activity also continued in the non-operated portion of the stack play in western Oklahoma during the fourth quarter. And we expect this activity to continue throughout 2019. For 2018, we participated in 65 STACK wells with an average working interest of approximately 4%. Results from this drilling program have been good. Offset well results near our operated dry gas stack area have impressive flow rates of reserves. And we look forward to potentially beginning an operated drilling program once Cheniere's Midship Pipeline is commissioned in the fourth quarter of 2019 and realized gas prices improve.

In our Texas Panhandle Granite Wash play, we continued our 1-rig drilling program in our Buffalo Wallow field. Results from our first 2 Granite Wash G extended lateral wells in the field have been good with initial rates from each well exceeding 10 million cubic feet equivalent per day of gas and NGLs. After 4 months of production, one of these wells continues to produce in excess of 10 million cubic feet equivalent per day. While the other well, which is only producing from about 35% of the lateral loops and obstruction in the lateral has declined to about 4.5 million cubic feet equivalent per day. We plan to do a workover on this well at some point in 2019 to remove this obstruction and at that -- we expect the well's production to significantly increase.

We're continuing with this drilling program through the first quarter of 2019 before moving the rig to our more oily western Oklahoma assets. Once Cheniere's Midship Pipeline is commissioned, which is projected to be in the fourth -- third or fourth quarter of '19 and realized gas prices improve, we expect to move the rig back to this field to continue with our drilling program.

Fortunately, our land position in this area is largely held by production, allowing us to drill when pricing is most optimum. All of the gas produced from Buffalo Wallow field is gathered and processed by Superior units' midstream subsidiary. In our Wilcox play located primarily in Polk, Tyler, Hardin, and Goliad Counties, Texas and Southeast Texas, we continued our development drilling and recompletion program in the Gilly field during the fourth quarter. Additionally, we drilled a successful delineation well in our Shoal Creek prospect that has continued to increase in production since coming online in October and is currently producing approximately 8.5 million cubic feet equivalent per day of wet gas and oil.

We will continue delineating this prospect in 2019. We anticipate completing approximately 13 vertical wells during 2019, with 5 of them being exploration or delineation wells and 8 being development wells. One of the delineation wells will be the much-anticipated Wolf Pasture #1, which will be the first delineation well in our Cherry Creek prospect located approximately 7 miles southwest of the Gilly field. In addition, we plan to complete approximately 10 behind pipe gas and liquid zones during 2019.

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

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John H. Cromling, Unit Corporation - EVP of Drilling - Unit Drilling Company [6]

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The contract drilling segment experienced the effects of the commodity price fluctuations during the fourth quarter, with rig utilization dipping slightly. Despite the challenges of fluctuating operator activity levels, we were successful in closing in on the completion of our 2 latest BOSS drilling rigs.

Our rig utilization decreased throughout the quarter from 34 to 32 rigs, and currently, we have 32 rigs operating. All 13 of our BOSS rigs are now operating with 9 of them under long-term contracts. Our 12th BOSS rig was placed into service in January and is operating in Wyoming.

The operator for this rig also extended contracts on 2 other BOSS rigs that are currently drilling for them. Our 13th BOSS rig was recently placed into service operating in the Permian. 11 of the 19 SCR rigs presently working are under long-term contract. We have several additional SCR rigs that are excellent candidates for refurbishment as the market dictates. It is important to note that all the above projects are being funded by operating cash flow and within the CapEx budget we tested midyear in 2018.

The average day rate for the fourth quarter was $18,047, an increase of $458 per day over the third quarter. The average total daily revenue for intercompany eliminations was $18,230, a slight increase from the third quarter. Our total daily operating cost for intercompany eliminations increased by $558 for the fourth quarter as compared to the third. The increase was primarily a result of higher indirect cost. The average per day operating margin for the fourth quarter before elimination of intercompany profits was $5,859, which is a decrease of $432 from the prior quarter. Our non-GAAP reconciliation can be found in today's press release.

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

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Robert H. Parks, Unit Corporation - Manager & President of Superior Pipeline Company LLC [7]

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Thank you, John. Following a record year of operating profit in 2017, the midstream segment had another outstanding year in 2018. We had a 24% increase in gas liquids sold volumes year-over-year, driven by higher processed volumes at our Cashion and Hemphill facilities as a result of new well connects at each system.

I'll now provide an update on several key midstream assets. At our Pittsburgh Mills gathering facility in Pennsylvania, during the fourth quarter of 2018, our average total gathered volume declined to approximately 129.7 million cubic feet per day. This decrease in gathered volume was due to declining volume from the 7 infill wells that were connected late in the second quarter of 2018. We completed construction of a new pipeline to connect another new well pad and completed a compressor station upgrade as well. This new well pad includes 7 wells, which have been connected to our Kissick compressor station located on the southern portion of our gathering system.

We began receiving gas from the first 2 wells on January 24, 2019 and the additional 5 wells began production in February. The flow from these new wells will peak out at 130 million cubic feet per day as they are being connected to production equipment. Once all the wells are on the production equipment, we expect them to produce around 100 million cubic feet per day for an extended period of time.

At our Hemphill facility in the Texas Panhandle, the average total throughput volume increased approximately 75 million cubic feet per day for the fourth quarter of 2018 and total production of natural gas liquids was approximately 301,500 gallons per day. During the fourth quarter, we connected 5 new wells in the Buffalo Wallow area. And since the beginning of 2018, we connected a total of 13 new Buffalo Wallow wells. These new wells contributed to our overall increase in throughput volume on the system. Unit Petroleum continues to operate a rig in this area and we anticipate connecting additional wells in 2019. The Buffalo Wallow compression station expansion project was completed. And we have the flexibility to add additional compression capacity in order to accommodate future volumes.

At our Cashion processing facility located in central Oklahoma, the average throughput volume for the fourth quarter of 2018 increased to approximately 49 million cubic feet per day and natural gas liquids production increased to approximately 246,900 gallons per day. This was an active area for us during 2018. And since the first of last year, we connected 22 new wells to the Cashion system. We expect to continue to connect additional wells in 2019. This system is operating at full processing capacity, and we're adding an additional 60 million cubic feet per day processing plant to the Cashion system. This 60 million cubic feet per day plant has been relocated from our Bellmon facility to reading site on the Cashion system.

The $20 million plant and compressor project is currently under construction and will increase the total processing capacity on our Cashion system to approximately 105 million cubic feet per day. The construction of this new processing plant compressor station is anticipated to be completed and operational by the end of the first quarter of 2019.

In summary, we had a successful year, and are pleased with both our operational and financial results for 2018. As previously mentioned by Les, we established a $200 million stand-alone credit facility for Superior, which in combination with the sale of a 50% interest in the midstream business to outside investors in April 2018, will further enhance our ability to grow our segment. The results for the fourth quarter of 2018 showed positive increases in several key areas and with completion of the expansion project at our Cashion and Pittsburgh mill systems, we feel we are well positioned for continued growth in 2019 and beyond.

I will now turn the call back over to Larry for his final comments.

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Larry D. Pinkston, Unit Corporation - President, CEO & Director [8]

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Thank you, Bob. We began 2019 focused on growing all of our business segments, while maintaining our capital expenditures in line with cash flow. We're very excited about some of the results we have seen in all of our core plays and particularly in the Penn sand area. We have been successful heading to this position at a very reasonable acreage cost and with the majority of the acreage added being held by production. One of our strategies has been to position to allow our cash flow nonacreage explorations dictate our development base. We're pleased to get our 12th and 13th BOSS rigs deployed as scheduled during the first quarter of 2019, and we ordered -- we had ordered the long lead time components for our 14th BOSS rig last fall. At this time, completing that rig will likely depend -- will be dependent on obtaining a long-term contract. We're optimistic on growth in our midstream segment as we continue to progress on our organic prospects.

At this time, I would like to call -- turn the call over for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question comes from Marshall Adkins from Raymond James.

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James Marshall Adkins, Raymond James & Associates, Inc., Research Division - MD of Equity Research & Director of Energy Research [2]

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Larry, you mentioned that -- pretty clear that you're going to spend within cash flow, which certainly is one objective I think that the investors are looking to see these days. But another is a path to excess free cash flow generation and real returns over the cycle. So comment on, let's say, oil prices go up and your volumes continue to increase, is there a path to generating excess free cash flow? And if there is, do you pay down debt? Do you give that cash back to shareholders in some form? Just comment overall structurally on that aspect of your thought process.

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Larry D. Pinkston, Unit Corporation - President, CEO & Director [3]

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Yes. Well, Marshall, yes, I mean, all of those are definitely part of the whole consideration. The -- I think the defining moment in those will be when our cash flow and/or our investment program has reached the size that we can have good growth, not 20% kind of growth, but good growth in our E&P division. We were adding a few BOSS rigs to our rig fleet and then meeting the opportunities on our midstream rather than trying to ramp up to grow production by 20% or grow rigs multiple times more than even on a spec basis, I think at that point in time you look at either paying down debt and/or returning some -- in some form cash to the shareholders. And that's different than most -- than previous cycles. We've always tried to ramp up. As most of the industry has tried to ramp-up production well beyond what would be, I guess, a normal expected production growth, reserve growth, rig growth. So yes, I mean, are those in consideration? Sure they are. We don't see that. We'd like to be able to see that, but that will be a stretch to be able to see that happen in 2019.

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James Marshall Adkins, Raymond James & Associates, Inc., Research Division - MD of Equity Research & Director of Energy Research [4]

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Right. Right. So just to make sure I'm clear, it sounds like going forward versus historical, I guess, norms for the industry as a whole, your objective going forward is, yes, let's get growth, but let's not spend every dime of cash flow when we're -- when we do get favorable commodity prices, which, of course, I expect to see in the next couple of years. But let's put some of that away in some form or another. Is that a fair way of characterizing your thoughts?

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Larry D. Pinkston, Unit Corporation - President, CEO & Director [5]

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Yes, sir. You hit the nail on the head.

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James Marshall Adkins, Raymond James & Associates, Inc., Research Division - MD of Equity Research & Director of Energy Research [6]

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Perfect. Shifting gears over to the, if I could just to the E&P side real quick. It was a little bit -- reading the press release, it sounds like the Penn sands prospect with the Red Fork laterals are totally different than the SOHOT. It's generally in the similar area of Oklahoma, but it's a totally different play, that's correct. Is that correct is my question?

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Frank Q. Young, Unit Petroleum Company - EVP of Exploration & Production [7]

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Yes. Marshall, that's right. The Penn sands play is a prospect area that encompasses more than just 1 geological interval. One of those is the Red Fork interval, which the acquisition targeted. In SOHOT, we're targeting only the Hoxbar interval and within that just the Marchand sand right now because the Marchand sand is oily. The one consistency between the 2 prospects is that we're focused on adding acreage, where we can drill oily -- oil wells rather than resin wells that are primarily natural gas.

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James Marshall Adkins, Raymond James & Associates, Inc., Research Division - MD of Equity Research & Director of Energy Research [8]

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Right, right. Okay. I got it. And you're pretty clear in your comments on kind of evaluating first half and then you go from there. One last one for me, if I could. John, on the rig side, you wrote down a bunch of rigs. It sounds like you still got 20-or-so SCRs working today. You got maybe another 24, 25 STACK still. You talked about holding those for potential upgrades. Any thoughts on the cost of upgrading those and the likelihood of upgrading those versus just continue to put money into new BOSS rigs?

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John H. Cromling, Unit Corporation - EVP of Drilling - Unit Drilling Company [9]

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Yes. We've always considered the upgrades. I think the upgrades that we're going to see -- let me mention first, of those STACK rigs, some of them already have all of the upgrades done but they are located in North Dakota. And so there's still the possibility of relocating those rigs to the Permian or to the mid-continent area. Most of the upgrades I think what we'll see now are just additional walking systems, additional 7,500 meg systems, and we'll continue to do that as for -- as those rigs are needed. So I don't think we'll see a major refurbishment of a complete rig like we've done in the past. Going forward, we would rather use that larger amount of money for additional BOSS rigs.

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Operator [10]

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Our following question comes from Neal Dingmann from SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [11]

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Maybe question for Frank. Frank, on those 2 Red Fork wells, why just the difference? If you could just talk about sort of the color on both of those 2?

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Frank Q. Young, Unit Petroleum Company - EVP of Exploration & Production [12]

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The area where we made the acquisition is in an old field that had been developed vertically. And within that field, the vertical wells had different -- differing amounts of oil cuts. And when we drilled the Frymire well, it was in a part of the field that was more gassy. To be honest, we were expecting more oil production than we got, although not as much as the Schrock. So the vertical wells in that section may have done a better job of grading the oil reserves than what we had thought they did. The Frymire is still an economic well, but it's just not as oily as we had hoped. But the vertical drilling done in that field gives us a pretty good indication of where to drill the wells that are going to be more oily.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [13]

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Got it. Okay. And then just over on the rig side, it's nice you continue to expand the BOSS fleet. Just your thoughts and I think I've asked you this before, just on bidding activity, your thoughts on being able to roll out any more of those? I assume, if you did, it would have to be under sort of a contract before you'll bring the 14th, 15th out, but maybe just talk about, how you're seeing just inquiries in general?

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John H. Cromling, Unit Corporation - EVP of Drilling - Unit Drilling Company [14]

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Well we still see a excellent reception to our BOSS rigs. Even though we just have 13 right now, we've been able to keep those busy. The performance has been everything that we've advertised it to be. So as we continue to perform like that, we think the market will still be good for them. And we have 2 or 3 months before all the components arrive that we had already ordered and then time to finish the rigs. So we feel pretty confident that we'll be able to obtain another long-term contract for 14.

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Operator [15]

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(Operator Instructions) We have no further questions at this time.

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Larry D. Pinkston, Unit Corporation - President, CEO & Director [16]

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Well, thank you, everyone, for joining us this morning. It concludes all of our comments. And we hope to see many of you all in the upcoming conferences that are -- that we'll be attending. Thank you very much.

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Operator [17]

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Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.