Unit Corp

OTC:UNTC

Earnings Call Transcript 2019-Q2

[Operator]

Welcome to the Unit Corporation's Second Quarter 2019 Earnings Call. My name is Janine. I'll be your operator for today's call. [Operator Instructions] Please note that this conference will be 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 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 both 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.

[Larry Pinkston, executive]

Thank you, Jenny. Good morning, everyone. Thank you for joining us this morning. With me today are David Merrill, Les Austin, Frank Young, John Cromling and Bob Parks. Each will be providing you with updates about their areas of responsibility, and then we'll take questions at the end of the call.

Commodity prices have been very volatile and the industry has seen a continued softening in the U.S. drilling activity as companies exercise disciplined capital spending. Natural gas and natural gas liquid prices have deteriorated and differentials on natural gas continue to remain wider in Western Oklahoma and the Texas Panhandle. The market is showing indications the differential should start to improve during the latter part of the year and into 2020 as the new infrastructure is placed into service. The second quarter was influenced by a number of different factors which our team will go over in their comment. Given the outlook for commodity prices for the remainder of the year, our planned oil and natural gas segment drilling activities for the year has now been completed and all the drilling rigs we were operating have now been released. As anticipated we increased borrowings in our bank facility to fund those early 2019 activity levels but with capital spending now reduced, we anticipate those borrowings will be substantially reduced by year-end. I would now like to turn the call over to David Merrill.

[David Merrill, executive]

Thank you, Larry. While we have seen some very impressive results in our oil-focused plays from both our Red Fork and SOHOT drilling efforts, we are faced with very challenging commodity prices for both natural gas and natural gas liquids. With our capital expenditures being at the low end of our earlier projection and coupled with the first quarter third-party plant shutdown impacting our Wilcox production, our production for the year was expected to be 17 million to 17.2 million barrels of oil equivalent with production increasing in the second half of the year. The strong well results in our Red Fork and SOHOT plays resulted in a 6% increase in our oil production for the quarter over the first quarter, and we continue to have success adding to our leasehold position in these Penn Sands plays. We added approximately 2,100 net acres during the quarter at an average cost of less than $1,000 per acre. We continue to see the opportunity for adding to the position in a cost effective manner. Our contract drilling segment maintained 100% of our BOSS rig fleet under contract since the start of our BOSS rig program. Our 14th BOSS rig is now being built under a long-term contract. Our midstream segment has seen throughput growth as a result of execution on organic growth opportunities. We continue to look for additional expansion opportunities for the midstream segment.

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

[George Austin, executive]

Thanks, David. We reported a net loss attributable to unit for the second quarter of $8.5 million or $0.16 per diluted share. Adjusted net loss attributable per unit for the quarter, which excludes the effect of noncash derivatives was $12.9 million or $0.24 per diluted share versus adjusted net income of $4.5 million or $0.09 per diluted share for the first quarter of 2019. The primary factors contributing to the decline included 26% lower hedge natural gas prices, 22% lower natural gas liquids prices and 9% lower rig utilization. Our non-GAAP financial measure reconciliation is included in our press release. For the oil and natural gas segment, revenues for the second quarter decreased 10% from the first quarter because of the lower natural gas and NGL prices previously discussed. Equivalent production was relatively unchanged compared to the first quarter. Operating cost for the second quarter increased 11% over the first quarter, primarily due to increased lease operating expenses associated with initial production on new wells drilled.

For the contract drilling segment, revenues for the second quarter decreased 16% from the first quarter due to 9% fewer rigs operating in the quarter, partially offset by increased day rates. Operating cost for the second quarter was 7% lower compared to the first quarter of this year, primarily due to fewer rigs operating.

For the midstream segment, revenues for the second quarter decreased 16% from the first quarter of this year primarily due to decreased gas and gas liquids prices, partially offset by increased condensate prices and gas volumes gathered. Operating cost for the second quarter decreased 17% from the first quarter of this year because of decreased purchase prices. We ended the second quarter of 2019 with long-term debt of $756.6 million. Long-term debt consists of $645.6 million in senior subordinated notes, net of unamortized discounts and debt issuance costs, $103.5 million outstanding on the Unit Corporation revolving credit agreement and $7.5 million outstanding under the superior revolving credit agreement. The latter being nonrecourse to Unit Corporation. Our Unit Corporation credit agreement borrowing base remains unchanged at $425 million with a maturity date of October 2023, and the superior credit facility is a $200 million facility with a maturity date of May 2023. We continue to assess market conditions relative to refinancing our $650 million senior subordinated notes which mature in May 2021. Our net leverage ratio on Unit Corporation indebtedness was 2.4x at the end of the second quarter. At this time, I will turn the call over to Frank for our Oil and Natural Gas segment update.

[Frank Young, executive]

Good morning. The second quarter was a mixed bag for Unit Petroleum. On the downside, continued weakness in net realized natural gas and NGL prices reduced cash flow and in response we dropped rigs to keep capital spending in check. Entering the first quarter, Unit had 6 rigs running, focused primarily on drilling oil wells. By the end of July, Unit Petroleum had no rigs running. With a shutdown of our drilling activity coupled with the first quarter 14-day shut-in of our Wilcox production, we now estimate our production for 2019 at 17 million to 17.2 million BOE and our capital spending at $270 million. Production during the second half of 2019 will increase over the first half of 2019 due to the number of wells brought online during the second and third quarters. On the upside, our focus on drilling oil wells increased oil production by 6% over the prior quarter, and we expect our 2019 oil production will be approximately 13% higher year-over-year and approximately 20% of our commodity mix by the end of the year. The increase in oil production is a result of some very strong well results in our Red Fork horizontal play that I will discuss. Operating costs were 1% higher through the first half of 2019 compared to the first half of 2018 and 11% higher quarter-over-quarter. The quarterly increase was due to the increased concentration of new wells brought online during the second quarter as compared to the first quarter.

Looking forward, we expect gas differentials in the Texas Panhandle and Western Oklahoma to improve over the next several months due to Cheniere's Midship Pipeline and Kinder Morgan's Gulf Coast Express Pipeline, both expected to be placed into service later this year. Cheniere's line will increase take away capacity out of Oklahoma by 1.4 Bcf per day while Kinder Morgan's line will move 2 Bcf per day of Permian gas production straight to the Gulf Coast rather than coming up to the Texas Panhandle as it is now. Mid-Continent basis differentials to NYMEX for 2020 are currently approximately $0.40 tighter compared to what we experienced in the second quarter, which would benefit our realized gas price. Any improvements to NYMEX gas prices would add even further to our realized gas price. During the second quarter, we accelerated drilling operations in Western Oklahoma to take advantage of the better economics associated with the more oil-prone nature of our Thomas Red Fork play and our SOHOT Marchand play, both located within our Penn Sands prospect area. Overall, results from our SOHOT Marchand drilling program over the last 18 months have been in line with our top [indiscernible] expectations resulting in excellent rates of return in our drilling and completion CapEx spend in this play. But what I want to focus on today is our Red Fork play, which like the Marchand we are the industry leader in. The Unit's initial Red Fork well in the Thomas Field which came online in September of 2018 continues to perform exceptionally well. On a gross basis, the well which had IP30 of over 2,000 BOE per day has cumulative production of 440,000 BOE of which 52% is oil, 22% is natural gas liquid and 26% is gas.

During the second quarter and into early July, 3 new Red Fork horizontal wells were completed. On the Wingard 1522 #2HX, the casing failure after fracking a 7,500-foot lateral resulted in only 1,500-foot or 20% of the lateral being successfully completed. Even so, the well had an IP30 of 413 BOE per day. While the casing failure was disappointing, we likely would have had an IP30 of over 2,000 BOE per day if 80% of the lateral wouldn't have been lost. The next well, the Wingard Farms 2128 #1 HX, which Unit has a 94% working interest in was completed in early July with a lateral length of 7,000 feet. At the end of July, the well was producing were 2,800 BOE per day with 75% of that being oil. The last well, the Saratoga 1720 #1HX, which Unit has a 68% working interest in, was completed in mid-July with a lateral length of 9,300 feet. At the end of July the well, which was still clinging up after the frac and increasing in production was producing 2,600 BOE per day with 72% of that being oil. Unit has 2 additional Red Fork wells already drilled that should be completed in the third quarter. We have been successful in adding approximately 10,200 net acres at an average price of about $1,000 per acre within the Penn Sands prospect areas since the beginning of the year. Our Red Fork zone inventory now stands at 30 to 40 operated and 10 to 15 non-operated horizontal -- potential horizontal locations. While we continue to have high expectations for the Red Fork play, we have a limited data set of 7 horizontal wells. However, we will be gathering additional data throughout the year allowing us to provide further clarity of what to anticipate from this play. The results from our Red Fork program and our steady execution in our SOHOT play have made a significant impact on oil volumes. During this time that we aren't running rigs we will intensify our effort to decrease expenses, and we will continue with our strategy of adding acreage and prospects at low cost that still providing drilling inventory at competitive funding and development costs and cash flow margins. We will also continue to evaluate organic and acquisition opportunities that could improve our cash margin and provide upside drilling inventory. At this time, I'll now turn the call over to John for the drilling company update.

[John Cromling, executive]

Thank you, Frank. The commodity pricing fluctuations have continued during the second quarter thereby affecting drilling rig activity levels. We were able to maintain a consistent level of active rigs during the first 2 months of the quarter and then experienced an appreciable decrease in June. We averaged 28.6 rigs operating during the quarter. We are very pleased that we have been able to maintain a 100% contracted rate on our BOSS rigs since the inception of the BOSS program in 2013. During the first quarter, we placed our 12th and 13th BOSS rigs into service. In the second quarter, we obtained a long-term contract for our 14th BOSS rig with one of our valued operators in North Dakota and also extended the long-term contracts on 2 other BOSS rigs that the same operator has been using. This is a true complement for the quality of the BOSS rigs and to the crews who operate them. The 14th rig will go into service in late fourth quarter.

We began the quarter with 32 rigs operating and closed the quarter with 25 rigs operating. Currently, we have 21 rigs operating with all 13 of our BOSS rigs and 8 SCR rigs. The average day rate for the second quarter was $18,491, an increase of $153 per day over the first quarter. Average total daily revenue before intercompany eliminations was $18,962, a decrease of $1,377 from the first quarter. This was due to early termination fees in the first quarter and none in the second. Excluding the early termination fees, average total daily revenue for the quarter increased $307 over the first quarter. Our total daily operating cost for intercompany eliminations increased by $472 for the second quarter as compared to the first.

The increase was primarily due to fewer rigs operating and expenses related to stacking rig. The average per day operating margins for the second quarter before elimination of intercompany profits was $5,526, which is a decrease of $1,850 from the previous quarter, largely due to early termination fees received during the first quarter. Excluding the early termination fees, the average per day operating margin for the quarter decreased to $167 from the first quarter.

Our non-GAAP reconciliation can be found in today's press release. Interest in our BOSS rigs remain very high and we believe the BOSS rig will be the anchor for the future of our contract drilling business. In the meantime, we will continue to complete minor upgrades on the SCR rigs as necessary to meet operator needs. It is important to note that all of the above projects are being financed by operating cash flow and within our CapEx budget.

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

[Robert H. Parks, executive]

Thank you, John. Superior continued to produce solid financial and operational results during the second quarter of 2019. We had a 19% increase in total throughput volume over the second quarter of 2018. This is due to connecting new 7 new long lateral wells to our Pittsburgh Mills system in the Appalachian area and continuing to connect new wells to our expanded Cashion processing facility. Operating profit before depreciation was $11.8 million for the second quarter 2019, which was a 10% decrease compared to the first quarter of 2019. This decrease was almost entirely due to lower realized natural gas and fuel prices between the quarters. We invested approximately $17 million in capital project during the second quarter of 2019. This amount included $7.2 million spent on purchasing 5 existing rental compressors at our Hemphill facility. The majority of the remaining capital expenditures were spent at our Cashion facility completing the installation of the new 60 million cubic feet per day Reeding plant connecting new wells to the system. I'll now discuss several of our key midstream assets. At our Pittsburgh Mills gathering facility in Pennsylvania during the second quarter of 2019, our average total gathered volume increased to approximately 206 million cubic feet per day. This increase in gathered volume was due to adding the new 7-well pad during the first quarter of 2019.

During the second quarter 2019, these new wells continued to average a total of approximately 100 million cubic feet per day. This well pad is connected to our Kissick compressor station which has been upgraded to handle the higher volume. At our Hemphill facility with Texas Panhandle, the average total throughput volume for the second quarter 2019 was approximately 72.9 million cubic feet per day and total production of natural gas liquids increased to approximately 289,000 gallons per day.

During the second quarter, we connected 6 new Unit Petroleum wells to this system. At our Cashion processing facility located in Central Oklahoma, the average throughput volume for the second quarter of 2019 increased to approximately 56.7 million cubic feet per day and natural gas liquids production increased to approximately 273,000 gallons per day. Producers have continued to be active in this area. During the second quarter, we connected 9 new wells to the Cashion system. This brings the total number of wells connected to this system since the first of this year to 16. We are continuing to connect new wells to this system with several additional wells expected to be connected in the third quarter. We have completed construction and installation of the new 60 million cubic feet Reeding processing plant. This new processing plant is fully operational and has increased our total processing capacity on our Cashion system to approximately 105 million cubic feet per day.

In summary, we are pleased with the second quarter results for our midstream segment. Even in this lower price environment, we've added new wells to certain systems where active drilling continues. With the completion of the new Reeding plant at our Cashion facility, we have increased our total processing capacity and are able to handle expected additional volumes on this system. Additionally, with our established $200 million standalone credit facility available, we continue to evaluate possible acquisition and expansion opportunities which will contribute to the growth of the midstream segment in the future.

I'll now turn the call back to Larry for his final comments.

[Larry Pinkston, executive]

Thank you, Bob. In summary, we continue to focus on all opportunities. Our core areas have provided the diversity of production mix outcome that could be helpful against different commodity backdrop. As you heard, our Red Fork prospect which we began developing late last year has shown some very remarkable results. The Red Fork in conjunction with our Marchand results have been and should continue to be large contributors towards our move to increase overall production. The BOSS drilling rig program, which we have been able to maintain a 100% contracted rates, provides solidity to the quality of the rig design and customer acceptance. We have been looking for growth opportunities for our midstream business and as a symbol to capital partners that [ financing arrangements ] necessary to execute once the appropriate opportunity is identified. Our company has proven worthy of the task of weathering storms, and we will continue to do so. At this time, I'd like to turn the call over for questions.

[Operator]

[Operator Instructions] And we have a question from Marshall Adkins from Raymond James.

[J. Marshall Adkins, analyst]

Larry, I want to focus in on the thing I think most people are paying attention to, which is the free cash flow yield going forward. You got dinged pretty hard this quarter from gas prices suffering. It sounds like you're confident the differential improves going forward and you're going to lower CapEx. So what's the likelihood over the back half of the year that you're actually going to be free cash flow positive?

[Larry Pinkston, executive]

Well, I think -- unless everything totally [indiscernible] definitely will be cash flow positive. We're not running any drilling rigs now. We have just a few wells left to complete. Over 50% of the cost on our new BOSS drilling rig has already been incurred. Most of the components for that rig we had bought and ordered late last year. So our CapEx is going to be pretty minimal in the second half of the year, especially compared to what it was in the first half. We're fully expecting debt to be paid down significantly in the second half of the year.

[J. Marshall Adkins, analyst]

All right. Then let's take that one step further and look into next year. Is your strategy -- if oil prices cooperate, is the strategy to ramp spending back up and spend the full cash flow or generate additional free cash flow and pay down debt?

[Larry Pinkston, executive]

Yes. Our focus is going to be continue to pay down debt. We won't quit drilling forever. I mean at the beginning of next year we will start a capital program back up. But part of the process with the capital budget will be the likelihood or the probability of paying down debt as we spend capital.

[J. Marshall Adkins, analyst]

Right. Last one for me on the rig, the new rig, the additional rig. I mean not a lot of people are adding rigs right now. What's the payback -- what's the length of that contract? Is it like a 3-year contract? And what do you anticipate your kind of payback term on the new BOSS rig?

[John Cromling, executive]

Marshall, the contract on rig 414 is only 18 months. However, the other 2 rigs that we have working for the same operator, those contracts were extended by the same amount of time, virtually from the time we signed the contract. So in effect, we're getting 4.5 years of guaranteed income, which is right at the number that we expect from payout on the BOSS rig.

[Operator]

And our next question comes from Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

My questions are around how you sort of balance your CapEx with cash flow. I know you generally match this and you all talked about that. I'm just wondering, given how good of IPs you saw there are a couple of these wells on the press release. Maybe Larry if you or Frank, how you think about potentially accelerating that to growing that or again is it going to be try and stick to the strategy of sort of slowing down to make sure they match closer in the current period?

[Frank Young, executive]

The CapEx as I mentioned -- I mean, right now, we're not planning on running any more rigs for the rest of this year at least through late, late in the year. And I'm sure our focus will be when we you get back up drilling assuming gas prices and oil prices are still relative to where they are today, our focus is going to be in the Marchand and in the Red Fork. So of course, they will drill more wells in those 2 areas than we will in others.

[Neal Dingmann, analyst]

Very good. And then just lastly. Can you just talk maybe a little bit on the contract rig margins per day? They're down a little bit. I'm just wondering what was involved in given the sort of what you're seeing now quarter-to-date if you can talk about that and any color you've seen so far this quarter.

[John Cromling, executive]

Well, rig margins are going to be virtually unchanged in the next quarter because as we -- the BOSS rigs are all under long-term contracts so we know where they going to be. The remaining rigs are the big question marks. And on the open market now, day rates are certainly not going to increase when there are so many rigs available. We do feel like we can trim a little bit more off our daily cost so we may improve margins by 10%. But that's not going to be anything significantly up or down.

[Operator]

[Operator Instructions] And we have a question from Sheru Chowdhry from DSC Meridian.

[Sheru Chowdhry, analyst]

The question I have is just looking at the performance of the Superior midstream assets. How much of that business today is fee-based versus contract-based?

[Robert H. Parks, executive]

Approximately 2/3 of the business today is fee-based and 1/3 is price sensitive today.

[Sheru Chowdhry, analyst]

Understood. And just one more follow-up. Just looking at the drilling side of the business. I understand the comments that going forward, much of this is going to be contracted business. But I am just trying to understand the weakness in the current quarter. How much of that came from your decision to release the rigs from your own business? My assumption is that some of these rigs were actually being used in the E&P side.

[John Cromling, executive]

Yes. We were using -- we probably averaged 3 to 4 rigs during the second quarter that we were using. On a financial basis, we eliminate any profits we have off of those rigs that we show on a consolidated basis. So the bottom line is not the impact of whether we're running those rigs or not. Our revenues, total expenses, those categories still show the influence of those 4 rigs running for the quarter but on the cash flow and on earnings any profits that we have are eliminated. But as you laid out rigs, of course the more rigs you're running the more rigs that provide you the ability to spread fixed cost over. A lot of the fixed cost continues whether you're running the rig or not. So the fewer rigs you run the less rigs you have to spread your fixed costs over. So if that makes sense.

[Sheru Chowdhry, analyst]

Yes, it does. Just one more follow-up if I may. How much of the BOSS rigs -- actually, you know what, that answers the question. My assumption is that none of the BOSS rigs were being used in your E&P operations.

[John Cromling, executive]

No. We were running only SCR rigs.

[Operator]

Our next question comes from Teresa Fox from Stone Harbor.

[Teresa Fox, analyst]

I understand you have 2 BOSS rigs that are coming off contract in the third quarter. Is there any update on recontracting those? Did I miss that?

[John Cromling, executive]

I think there's only one BOSS rig coming off contract in the third quarter, and we're discussing that going forward with that operator. There's I think very little chance that it's not going to continue with the same operator, but I'm just not sure what terms would be at this point.

[Operator]

[Operator Instructions] We have no further questions at this time.

[Larry Pinkston, executive]

We want to thank you for joining us this morning. We appreciate it very much. It's been a tough summer but things will improve. We hope to see many of you at the EnerCom later this, I guess, next week, if you're there. Thanks, again, for participating this morning with us.

[Operator]

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