Unit Corp

OTC:UNTC

Earnings Call Transcript 2019-Q3

[Operator]

Welcome to the Unit Corporation's Third Quarter 2019 Earnings Call. My name is Rebecca, and I will be your operator for today's call.

The company is currently in registration with the SEC with regard to an exchange offer and can only discuss what is publicly available. As such, Unit will not be taking questions and refer you to the registration statement and soon to be filed 10-Q for the most recently completed quarter. 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 may 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 those non-GAAP measures to GAAP measures may also be found in today's press release. This document may be available on the company's website.

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

[Larry Pinkston, executive]

Thank you, Rebecca. 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.

During the third quarter, as we have all year, we continued to navigate a very challenged commodity price backdrop for both natural gas liquids and natural gas. Despite pricing disconnects and the general industry upheaval, we remain focused on balance sheet presentation. As such, our oil and natural gas segment deployed capital toward our more oil-prone prospects earlier in the year as oil pricing has been stronger comparatively. As we discussed during the second quarter call, our E&P segment capital expenditure plan was first half through the year focused, and we have since released all rigs that we were operating. The reduction of our raw-operated rigs, coupled with the continued weekly decline in working U.S. land rigs, has adversely affected our contract drilling fleet utilization.

In the current environment, we are focusing on controlling that those things -- that we are -- that are within our ability to control. As a result of actions taken, a reduction in capital expenditures are anticipated to generate free cash flow during the fourth quarter that will be used to reduce debt.

I would now like to turn the call over to David Merrill.

[David Merrill, executive]

Thank you, Larry.

As you are probably aware, earlier this week, we filed a preliminary registration statement offering to exchange our 6.625% senior subordinated notes maturing in 2021 for new notes. The purpose of the exchange is to extend the maturity profile of our existing indebtedness and eliminate short- to medium-term refinancing and related risks associated with our capital structure.

As Larry mentioned, our focus on growth of our oil production has been -- has begun to come to fruition during the quarter. Also, due to completion activities for wells drilled in the second quarter, we saw a nice uptick in quarterly production. Frank will have more on those details in a minute.

Our operated rig count has fallen. However, for the contract drilling segment, 100% of our BOSS rigs have remained fully contracted since inception, and construction of our 14th BOSS rig is substantially complete. The rig is expected to begin work later in the fourth quarter.

Our midstream segment with contracts largely structured on fee-based contracts has held its own despite lower revenue due to lower commodity pricing and operating largely in ethane rejection.

I'll now turn it over to Les Austin.

[George Austin, executive]

Thanks, David.

We reported a net loss attributable to Unit for the third quarter of $206.9 million or $3.91 per diluted share. Adjusted net loss attributable to Unit for the quarter, which excludes the effect of noncash derivatives and impairment charges, was $15.7 million or $0.30 per diluted share versus an adjusted net loss of $12.9 million or $0.24 per diluted share in the second quarter of 2019. Although we experienced an improvement of 28% higher oil production, this was more than offset by 32% lower natural gas liquids prices and 8.2 fewer rigs operating. Our non-GAAP financial measure reconciliation is included in our press release.

For the oil and natural gas segment, revenues for the third quarter was relatively unchanged from the second quarter of this year with higher oil, natural gas liquids and natural gas volumes being offset by lower oil, natural gas liquids and natural gas prices. Equivalent production was 6% higher compared to the second quarter of this year primarily driven by the higher oil production discussed previously. Operating costs for the third quarter decreased 2% from the second quarter of this year primarily due to lower lease operating expenses somewhat offset by higher production taxes.

For the contract drilling segment, revenue for the third quarter decreased 13% from the second quarter of this year due to 8.2 fewer rigs operating in the quarter somewhat offset by increased day rates. Operating costs for the third quarter were 2% lower compared to the second quarter of this year primarily due to fewer rigs operating.

For the midstream segment, revenues for the third quarter decreased 10% from the second quarter of this year primarily due to decreased condensate prices and gas liquids volume. Operating costs for the third quarter decreased 12% from the second quarter of last year because of the decreased purchase prices.

We ended the third quarter of 2019 with total cash and cash equivalents of $600,000 and long-term debt of $784.4 million. Long-term debt consists of $646.2 million in senior subordinated notes net of unamortized discounts and debt issuance costs and $134.1 million outstanding on the Unit Corporation revolving credit agreement and $4.1 million outstanding on the Superior revolving credit agreement which is nonrecourse to Unit Corporation.

Our Unit Corporation credit agreement borrowing base was reduced to $275 million effective September 26, and the Superior credit facility is a $200 million facility. As David previously stated, we have initiated a debt exchange for our $650 million senior subordinated notes, which mature in May 2021. Our net leverage ratio on Unit Corporation indebtedness was 2.8x at the end of the third quarter.

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

[Frank Young, executive]

Thanks, Les.

During the third quarter, we continued to see positive results from our Red Fork play in Western Oklahoma. With these results, we had a 28% increase in our oil production along with a 6% increase in total equivalent production over the second quarter. We also continue to concentrate on reducing our operating costs in this lower commodity environment. Operating costs were 2% lower quarter-over-quarter. Our production staff has done an excellent job of lowering compression costs, saltwater disposal costs and workover costs during the third quarter.

Total oil volumes through the first 3 quarters of 2019 are 10% higher compared to the first 3 quarters of 2018. This is due to our shift to drilling oil-prone zones in our Penn sand prospects in Western Oklahoma, mainly in the Marchand and Red Fork intervals. In the third quarter, 8 new horizontal wells were brought on line, which consisted of 4 Marchand horizontals and 4 Red Fork horizontals. Three of the Red Fork wells were in our Thomas field while our fourth was in a new prospect area called [ Peanut ] that we have been leasing during 2019. The average IP30 of the 4 Red Fork wells was 2,150 BOE per day with an average oil cut of 72% and average working interest of 86%.

The Wingard Farms 2128 number 1HX, which Unit has a 94% working interest in, was completed in early July with a lateral length of 7,000 feet and had an IP30 of 2,800 BOE per day and has cumulative oil production of 141,000 barrels to the end of the third quarter. The Saratoga 1720 number 1HX, which Unit has a 68% working interest in, was completed in mid-July with a lateral length of 9,300 feet and had an IP30 of 3,000 BOE per day and has cumulative production of 134,000 barrels at the end of the third quarter.

Our first well in our [ Peanut ] prospect, the Hayes Trust number 1H-12, which Unit has a 92% working interest in, was completed in mid-August with a lateral length of 3,600 feet. The lateral was cut short due to running out of Red Fork sand while drilling the well. But even so, the well had an IP30 of 1,600 BOE per day with 81% being oil. Our AFE costs for Red Fork horizontal well with a 7,500-foot lateral is approximately $7 million.

In Houston, we continue to show excellent results with our STACK play primarily in the Wilcox interval by recompleting 3 wells and performing a workover on a fourth well. Combined, these 4 wells had an IP30 of 17 million cubic feet of gas per day and 300 barrels of oil per day with a total cost of only $1.4 million. These wells are a result of continued development and exploitation of our behind-pipe potential in the Wilcox play.

The results from our Red Fork program and our steady execution in our SOHOT play have made a significant impact on oil volumes while our Wilcox recompletion program continues to provide very low-cost production adds that received premium Gulf Coast pricing. In 2020, we will continue to focus our capital spending on these same areas. During this time that we aren't running rigs, we will continue our effort to decrease expenses, and we will continue with our strategy of adding acreage and prospects at low cost that still provide drilling inventory a 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 turn the call over to John for the drilling company update.

[John Cromling, executive]

Thank you, Frank.

During the third quarter, we substantially completed the construction of our 14th BOSS rig. In early December, this rig will go into service for one of our valued operators in North Dakota who also extended the long-term contracts on 2 other BOSS rigs that are presently operating for them. This is a true complement for the quality of the BOSS rigs and to the crews who operate them.

We began the quarter with 25 rigs operating and closed the quarter with 18 rigs operating. All 13 of our BOSS rigs are operating with 10 of them on term contracts. We also have 5 SCR rigs under term contracts. We averaged 20.4 rigs operating during the quarter.

The average day rate for the third quarter was $19,276, an increase of $785 per day over the second quarter. The average total daily revenue before intercompany eliminations was $19,692, an increase of $730 over the second quarter.

Our total daily operating costs before intercompany eliminations increased by $1,623 for the third quarter as compared to the second. The increase was primarily due to less rigs operating, thus increasing the daily costs due to fixed costs and expenses related to stacking rigs, which were nonrecurring. The average per day operating margin for the third quarter with no elimination of intercompany profits was $4,635, which is a decrease of $891 from the previous quarter.

Our non-GAAP reconciliation can be found in today's press release. We expect that rig activity will remain flat during the fourth quarter and increase during the first quarter of 2020 due to operators having new drilling budgets for the year.

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

[Robert H. Parks, executive]

Thank you, John.

While operating in this low-priced environment, Superior has continued to produce attractive financial results. Operating profit before depreciation was $11.3 million for the third quarter of 2019, which was a 4% decrease compared to the second quarter of 2019. This decrease was primarily due to lower realized gas, NGL and condensate prices between the quarters along with lower gathered volumes.

Additionally, year-to-date through the third quarter, we have had a 14% increase in gas-gathered volume over the same period in 2018. This was due to setting 7 new long lateral wells for our Pittsburgh Mills system in the Appalachian area and continuing to connect new wells and expand our Cashion processing facility.

We have invested approximately $41.4 million in capital projects during 2019. This amount includes $7.3 million spent on purchasing 5 existing rental compressors at our Hemphill facility. The majority of the remaining capital expenditures are for our Cashion facility to expand the gathering system and connect new wells along with completing the installation of the new Reeding processing plant.

I will now discuss several of our key midstream assets. At our Cashion processing facility, the average throughput volume for the third quarter of 2019 increased to approximately 63.5 million cubic feet per day, and natural gas liquids production increased approximately 276,000 gallons per day. Several producers continued to actively drill in this area. And during the third quarter, we connected 11 new wells to the Cashion system. This brings the total number of wells connected to the system since the first of this year to 27, and we anticipate making several additional wells to the system in the fourth quarter. We are continuing to develop and expand the system in order to accommodate the active producers in the area. The new 60 million cubic feet per day Reeding processing plant is fully operational. And with the addition of this processing plant on the Cashion system, our total processing capacity at the Cashion facility is approximately 105 million cubic feet per day.

At our Pittsburgh Mills gathering facility in Pennsylvania during the third quarter of 2019, our average total gathered volume was approximately 171 million cubic feet per day compared to 206 million cubic feet per day for the second quarter. This decrease in gathered volume from the previous quarter was due to the 7 new wells connected at the end of the first quarter declining from their high initial production volume. At the end of the third quarter 2019, these 7 new wells are continuing to average a total of approximately 70 million cubic feet per day, and the decline rate appears to have begun to moderate. The production from these wells flows to our Kissick compressor station, which has recently been upgraded to handle the higher volumes from this area.

At our Hemphill facility in the Texas Panhandle, the average total throughput volume for the third quarter of 2019 was approximately 69.2 million cubic feet per day, and total production of natural gas liquids decreased to approximately 177 gallons -- 177,000 gallons per day from 289,000 gallons per day in the second quarter. The decrease in natural gas liquids is the result of operating in ethane rejection mode due to low NGL prices. During the third quarter, we connected 2 new wells to the system that were leased by a third-party midstream operator.

In summary, we are continuing to develop and expand our Cashion facility in order to provide gathering and processing services to the active producers in the area. Given the low-priced environment, we are pleased with the third quarter financial results for our midstream segment. Despite this environment, we have continued to add additional wells to key systems. With the installation of the new Reeding processing plant at our Cashion facility, we have increased total processing capacity on the system, which allows us to handle additional volumes from active producers.

Finally, due to the available $200 million stand-alone credit facility, we are actively searching for and evaluating possible acquisition and expansion opportunities. Our midstream segment is well positioned for growth and looks forward to continued success in the future.

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

[Larry Pinkston, executive]

Thank you, Bob.

As we mentioned earlier, we are currently in the registration with the SEC with regards to an exchange offer and can only discuss what's publicly available. As such, we will not take questions and refer you to our registration statement and soon-to-be-filed 10-Q for the most recently completed quarter.

Thank you for joining us on the call today. Operator, I'll turn the call back over to you.

[Operator]

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