Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis (MD&A) provides you with an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year or period to period. MD&A is organized into these sections:
•
General;
•
Business Outlook;
•
Executive Summary;
•
Financial Condition and Liquidity;
•
New Accounting Pronouncements; and
•
Results of Operations.
Please read the information in our most recent Annual Report on Form 10-K in conjunction with your review of the information below and our unaudited condensed consolidated financial statements and related notes.
Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior Pipeline Company, L.L.C. of which we own 50%.
General
We operate, manage, and analyze the results of our operations through our three principal business segments:
•
Oil and Natural Gas
– carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.
•
Contract Drilling
– carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil and natural gas wells for others and for our oil and natural gas segment.
•
Mid-Stream
– carried out by Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. We own 50% of this subsidiary.
In addition to the companies identified above, our corporate headquarters is owned by our wholly owned subsidiary "8200 Unit Drive, L.L.C.".
Business Outlook
As discussed in other parts of this report, our success depends, to a large degree, on the prices we receive for our oil and natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United States affect us and our industry.
Fluctuating commodity prices can result in significant changes to our industry and us. Depressed commodity prices, particularly for the extended time, can result in industry wide reductions in drilling activity and spending which reduce the rates for and the number of our drilling rigs we were able to put to work. Such industry wide reductions in drilling activity and spending for extended periods also reduces the rates for and the number of our drilling rigs we can work. In addition, sustained lower commodity prices impact the liquidity condition of some of our industry partners and customers, which could limit their ability to meet their financial obligations to us.
During the last several years, commodity prices have been volatile. Our oil and natural gas segment began using two to three drilling rigs throughout 2017. With improved commodity prices during the first quarter of 2018, our oil and natural gas segment put four of our drilling rigs to work and increased the number to six drilling rigs for a brief period during the third quarter of 2018. We started the first quarter of 2019 with four drilling rigs operating, increased to six during March and through mid-second quarter and ended the second quarter with
four drilling rigs operating. O
ur plans are to now substantially reduce our borrowings under our credit agreement by year-end.
The following chart reflects the significant fluctuations in the prices for oil and natural gas:
The following chart reflects the significant fluctuations in the prices for NGLs:
_________________________
1.
NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.
In our oil and gas segment, we had no write-downs in 2018 or in the first six months of 2019. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve
revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at June 30, 2019, and only adjust the 12-month average price to an estimated third quarter ending average (holding July 2019 prices constant for the remaining two months of the third quarter of 2019), our forward looking expectation is that we would recognize an impairment of $107 million pre-tax in the third quarter of 2019. The actual amount of any write-down may vary significantly from this estimate depending on the final future determination.
For 2019, we believe the number of gross wells we will drill to be 85-95 wells (depending on future commodity prices).
Our contract drilling segment completed the construction of one additional BOSS drilling rigs during the third quarter of 2018. During the second quarter and third quarter of 2018, we were awarded term contracts to build our 12th and 13th BOSS drilling rigs. Construction was completed for one of these in January and it was placed into service for a third-party operator. Early in the first quarter of 2019, the other contract was terminated but we were able to find another third-party operator and it was placed into service in February. Our 14th BOSS drilling rig was contracted during the second quarter of 2019. Construction has started and the new drilling rig will be placed into service in the fourth quarter of 2019. Rig utilization fluctuated over the past year due to commodity prices changing and budget constraints on operators. We expect commodity prices and budget constraints on operators to continue to affect rig utilization throughout 2019. During 2018, utilization increased to a high of 36 drilling rigs but with a decline in commodity prices during the fourth quarter, declined to 32 drilling rigs as of December 31, 2018 and continued to decline to 24 drilling rigs as of June 30, 2019.
In December 2018, we removed from service 41 drilling rigs, some older top drives, and certain drill pipe that has been reclassed to 'Assets held for sale.' At June 30, 2019, our drilling rig fleet totaled 57 drilling rigs.
During 2018, due to low ethane and residue prices, we operated some of our mid-stream processing facilities in ethane rejection mode which reduces the liquids sold. At the end of 2018 and into the first part of 2019, as NGLs and gas prices improved, we began operating some of our mid-stream processing facilities in ethane recovery mode. We are continuing to monitor commodity prices to determine the most economical method in which to operate our processing facilities.
Executive Summary
Oil and Natural Gas
Second quarter 2019 production from our oil and natural gas segment was 4,151,000 barrels of oil equivalent (Boe), a increase of 1% over the first quarter of 2019 and a decrease of 1% from the second quarter of 2018, respectively. The increase over the first quarter of 2019 was primarily from a 14-day plant shut-down (12-days of which were in the first quarter of 2019) that resulted in a loss of slightly over 165 MBoe for the first quarter of 2019. The decrease from the second quarter of 2018 was primarily due to the 14-day plant shut-down (2-days of which were in the second quarter of 2019) and the associated delays in getting production ramped back up after the plant shutdown ended. We also had a series of weather related events in the Texas Panhandle and Oklahoma that caused well shut-ins and delays in operations.
Second quarter 2019 oil and natural gas revenues decreased 10% from the first quarter of 2019 and decreased 24% from the second quarter of 2018. The decreases were primarily from a decrease in commodity prices.
Our oil prices for the second quarter of 2019 increased 6% over the first quarter of 2019 and increased 6% over the second quarter of 2018. Our NGLs prices decreased 22% from the first quarter of 2019 and decreased 44% from the second quarter of 2018. Our natural gas prices decreased 26% from the first quarter of 2019 and decreased 15% from the second quarter of 2018.
Operating cost per Boe produced for the second quarter of 2019 increased 10% over the first quarter of 2019 and increased 13% over the second quarter of 2018. The increase over the first quarter of 2019 was primarily due to higher lease operating expenses from new wells drilled partially offset by lower general and administrative expenses and gross production taxes. The increase over the second quarter of 2018 was primarily due to higher lease operating expenses and saltwater disposal expenses and lower equivalent production.
At June 30, 2019, these derivatives were outstanding:
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Term
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Commodity
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Contracted Volume
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Weighted Average
Fixed Price
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Contracted Market
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Jul'19 – Oct'19
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Natural gas – swap
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60,000 MMBtu/day
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$2.900
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IF – NYMEX (HH)
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Nov'19 – Dec'19
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Natural gas – swap
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40,000 MMBtu/day
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$2.900
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IF – NYMEX (HH)
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Jul'19 – Dec'19
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Natural gas – basis swap
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20,000 MMBtu/day
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$(0.659)
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PEPL
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Jul'19 – Dec'19
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Natural gas – basis swap
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10,000 MMBtu/day
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$(0.625)
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NGL MIDCON
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Jul'19 – Dec'19
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Natural gas – basis swap
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30,000 MMBtu/day
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$(0.265)
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NGPL TEXOK
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Jan'20 – Dec'20
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Natural gas – basis swap
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30,000 MMBtu/day
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$(0.275)
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NGPL TEXOK
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Jul'19 – Dec'19
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Natural gas – collar
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20,000 MMBtu/day
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$2.63 - $3.03
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IF – NYMEX (HH)
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Jul'19 – Dec'19
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Crude oil – three-way collar
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4,000 Bbl/day
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$61.25 - $51.25 - $72.93
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WTI – NYMEX
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For the three months ended June 30, 2019, we completed drilling 63 gross wells (17.41 net wells). For all of 2019, we anticipate participating in the drilling of approximately 85-95 gross wells. Excluding a reduction in ARO liability and any possible acquisitions, our estimated 2019 capital expenditures for this segment is approximately $265.0 million (slightly lower than the original $271.0 million to $315.0 million range) due to lower commodity prices. Our current 2019 production guidance is approximately 17.0 to 17.2 MMBoe, although actual results continue to be subject to many factors.
Contract Drilling
The average number of drilling rigs we operated in the second quarter of 2019 was 28.6 compared to 31.4 and 32.2 in the first quarter of 2019 and the second quarter of 2018, respectively. As of June 30, 2019, 24 of our drilling rigs were operating.
Revenue for the second quarter of 2019 decreased 16% from the first quarter of 2019 and decreased 8% from the second quarter of 2018. The decreases were primarily due to less drilling rigs operating.
Dayrates for the second quarter of 2019 averaged $18,491, an 1% increase over the first quarter of 2019 and a 7% increase over the second quarter of 2018. The increase over the first quarter of 2019 was primarily due to lower dayrate drilling rigs being released and higher dayrate BOSS drilling rigs continuing to operate. The increase over the second quarter of 2018 was due to a labor increase passed through to contracted rigs rates and improving market dayrates.
Operating costs for the second quarter of 2019 decreased 7% from the first quarter of 2019 and decreased 8% from the second quarter of 2018. The decreases were both primarily due to less drilling rigs operating.
Currently, we have 14 term drilling contracts with original terms ranging from six months to three years. Two are up for renewal in the third quarter of 2019, four in the fourth quarter of 2019, five in 2020, and three after 2020. Term contracts may contain a fixed rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig early and pay an early termination penalty for the remaining term of the contract. We recorded $4.8 million in early termination fees in the first quarter of 2019. We had no early termination fees for the second quarter of 2019.
All 13 of our existing BOSS drilling rigs are under contract.
Our estimated 2019 capital expenditures for this segment is approximately $45.0 million (the midpoint of the original $30.0 million to $65.0 million range) due to the construction of our 14th BOSS drilling rig.
Our drilling rig personnel are a key component to the overall success of our drilling services. With the present conditions in the drilling industry, we do not anticipate increases in the compensation paid to those personnel in the near term.
Mid-Stream
Second quarter 2019 liquids sold per day increased 9% over the first quarter of 2019 and increased 5% over the second quarter of 2018, respectively. The increase from the first quarter of 2019 was due to higher processed volumes and better recoveries at our processing facilities. The increase over the second quarter of 2018 was primarily due to increased volume available to process at our processing facilities due to additional well connections along with operating in higher recovery mode. For the second quarter of 2019, gas processed per day increased 2% over the first quarter of 2019 and increased 3% over
the second quarter of 2018. The increase over the first quarter of 2019 was primarily due to higher volumes associated with wells connected mainly to our Cashion and Bellmon processing facility. The increase over the second quarter of 2018 was mainly due to new wells connected to the Cashion facility. For the second quarter of 2019, gas gathered per day increased 4% and 19% over the first quarter of 2019 and the second quarter of 2018, respectively. These increases are both due to connecting additional wells to our gathering systems primarily in Pennsylvania and Oklahoma.
NGLs prices in the second quarter of 2019 decreased 26% from the prices received in the first quarter of 2019 and decreased 45% from the prices received in the second quarter of 2018. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those commodity-based contracts fluctuate based on the price of NGLs.
Total operating cost for our mid-stream segment for the second quarter of 2019 decreased 17% from the first quarter of 2019 and decreased 18% from the second quarter of 2018. The decreases were both primarily due to lower gas and purchase prices.
In the Appalachian region at the Pittsburgh Mills gathering system, the average gathered volume for the second quarter of 2019 was approximately 206.4 MMcf per day. In the first quarter of 2019, we added seven new wells which accounted for the significant increase in gathered volume in the first quarter. In the second quarter of 2019, the production from these wells is declining as evidenced in the lower volume as of June 2019. These wells are all long lateral wells. The Kissick compressor station facilities located on the south end of the system have been upgraded and are able to handle the increased volume from these new wells.
At the Cashion processing facility in central Oklahoma, total throughput volume for the second quarter of 2019 averaged approximately 56.7 MMcf per day and total production of natural gas liquids increased to 273,075 gallons per day. We are continuing to connect new wells to this system from several third party producers. In 2019, we have connected 16 new wells to this system from several third party producers who continue to be active in the area. During the second quarter, we completed the addition of the new 60 MMcf per day Reeding processing facility on the Cashion system. This 60 MMcf per day processing plant was relocated from our Bellmon facility to the Cashion area and is now fully operational. The addition of this new processing facility increases our total processing capacity on the Cashion system to approximately 105 MMcf per day.
At the Hemphill processing facility located in the Texas panhandle, average total throughput volume for the second quarter of 2019 was 72.9 MMcf per day and total production of natural gas liquids was 288,762 gallons per day during this same period. Since the first of this year, we have connected six new wells to the Hemphill system. The six new wells connected in 2019 are Unit Petroleum wells. There are no Unit Petroleum wells currently being drilled in this area.
Our estimated 2019 capital expenditures for this segment is approximately $45.0 million (slightly higher than the original $35.0 million to $42.0 million range) due to the purchase of previously leased assets.
Financial Condition and Liquidity
Summary
Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreements. Our cash flow is based primarily on:
•
the amount of natural gas, oil, and NGLs we produce;
•
the prices we receive for our natural gas, oil, and NGLs production;
•
the demand for and the dayrates we receive for our drilling rigs; and
•
the fees and margins we obtain from our natural gas gathering and processing contracts.
We believe we will have enough cash flow and liquidity to meet our obligations and remain in compliance with our debt covenants for the next 12 months. Our ability to meet our debt covenants (under our credit agreements and our Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. For example, if we experience lower oil, natural gas, and NGLs prices since the last borrowing base determination under the Unit credit agreement, it could reduce the borrowing base and therefore reduce or limit our ability to incur indebtedness. We monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues ahead of time.
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Six Months Ended June 30,
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%
Change
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2019
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2018
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(In thousands except percentages)
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Net cash provided by operating activities
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$
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127,501
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$
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159,640
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(20)
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%
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Net cash used in investing activities
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(242,611)
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(167,350)
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45
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%
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Net cash provided by financing activities
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109,327
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111,317
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(2)
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%
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Net increase (decrease) in cash and cash equivalents
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$
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(5,783)
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$
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103,607
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Cash Flows from Operating Activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the quantity of oil, NGLs, and natural gas we produce, settlements of derivative contracts, and third-party demand for our drilling rigs and mid-stream services and the rates we obtain for those services. Our cash flows from operating activities are also affected by changes in working capital.
Net cash provided by operating activities in the first six months of 2019 decreased by $32.1 million as compared to the first six months of 2018. The decrease was primarily due to decreased operating profit in the oil and gas segment and a decrease in changes in operating assets and liabilities related to the timing of cash receipts and disbursements partially offset by increases in cash for derivatives settled.
Cash Flows from Investing Activities
We dedicate and expect to continue to dedicate a substantial portion of our capital budget to the exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells.
Cash flows used in investing activities increased by $75.3 million for the first six months of 2019 compared to the first six months of 2018. The change was due primarily to an increase in capital expenditures for development drilling and construction of BOSS drilling rigs and a reduction in cash proceeds on the sale of assets. See additional information on capital expenditures below under Capital Requirements.
Cash Flows from Financing Activities
Cash flows provided by financing activities decreased by $2.0 million for the first six months of 2019 compared to the first six months of 2018. The decrease was primarily due to an increase in the net borrowings under our credit agreements partially offset by sale of 50% interest in our mid-stream segment in 2018.
At June 30, 2019, we had unrestricted cash and cash equivalents totaling $0.7 million and had borrowed $103.5 million of the $425.0 million and $7.5 million of the $200.0 million we had elected to have available under the Unit and Superior credit agreements, respectively. The credit agreements are used primarily for working capital and capital expenditures.
Below, we summarize certain financial information as of June 30, 2019 and 2018 and for the six months ended June 30, 2019 and 2018:
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June 30,
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%
Change
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2019
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2018
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(In thousands except percentages)
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Working capital
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$
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(64,125)
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$
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26,330
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NM
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Long-term debt less debt issuance costs
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$
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756,590
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$
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643,371
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18
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%
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Shareholders’ equity attributable to Unit Corporation
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$
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1,389,873
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$
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1,444,250
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(4)
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%
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Net income (loss) attributable to Unit Corporation
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$
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(12,013)
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$
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13,653
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(188)
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%
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_________________________
1.
NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
Working Capital
Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had negative working capital of $64.1 million and positive working capital of $26.3 million as of June 30, 2019 and 2018, respectively. The decrease in working capital is primarily due to a decrease in accounts receivable due to lower revenues and by a decrease cash and cash equivalents from the sale of 50% interest in our mid-stream segment in 2018 partially offset by reduction in accounts payable. The Unit and Superior credit agreements are used primarily for working capital and capital expenditures. At June 30, 2019, we had borrowed $103.5 million of the $425.0 million and $7.5 million of the $200.0 million available under the Unit or Superior credit agreements, respectively. The effect of our derivative contracts increased working capital by $8.5 million as of June 30, 2019 and decreased working capital by $18.4 million as of June 30, 2018.
This table summarizes certain operating information:
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Six Months Ended
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June 30,
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%
Change
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2019
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2018
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Oil and Natural Gas:
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Oil production (MBbls)
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1,414
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1,429
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(1)
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%
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NGLs production (MBbls)
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2,417
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2,425
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—
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%
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Natural gas production (MMcf)
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26,659
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27,237
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(2)
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%
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Equivalent barrels (MBoe)
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8,274
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|
8,393
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(1)
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%
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Average oil price per barrel received
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$
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58.16
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$
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55.76
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4
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%
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Average oil price per barrel received excluding derivatives
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$
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55.86
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$
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64.08
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(13)
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%
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Average NGLs price per barrel received
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$
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14.11
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$
|
21.65
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(35)
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%
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Average NGLs price per barrel received excluding derivatives
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$
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14.11
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$
|
21.91
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(36)
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%
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Average natural gas price per Mcf received
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$
|
2.18
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$
|
2.40
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(9)
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%
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Average natural gas price per Mcf received excluding derivatives
|
|
$
|
2.11
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$
|
2.27
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(7)
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%
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Net impact of revenue recognition (ASC 606) per Boe
(1)
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|
$
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(1.26)
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|
$
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(0.82)
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(54)
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%
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|
Average realized price per Boe received
|
|
$
|
19.83
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|
$
|
22.70
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|
(13)
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%
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|
Average realized price per Boe received excluding derivatives
|
|
$
|
19.19
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|
$
|
23.77
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|
(19)
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%
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|
Contract Drilling:
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|
|
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|
Average number of our drilling rigs in use during the period
|
|
30.0
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|
31.9
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|
(6)
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%
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|
Total number of drilling rigs owned at the end of the period
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|
57
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|
95
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(40)
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%
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|
Average dayrate
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|
$
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18,412
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|
$
|
17,184
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|
7
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%
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|
Mid-Stream:
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Gas gathered—Mcf/day
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|
457,859
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|
382,005
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20
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%
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Gas processed—Mcf/day
|
|
163,725
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|
155,799
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|
5
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%
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|
Gas liquids sold—gallons/day
|
|
681,070
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|
627,305
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|
9
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%
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|
Number of natural gas gathering systems
|
|
21
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22
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|
(5)
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%
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Number of processing plants
|
|
12
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|
14
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|
(14)
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%
|
_______________________
1.
Pursuant to accounting guidance on revenue recognition (ASC 606); gathering, processing, and transportation costs are reflected as a deduction from revenue instead of as an expense when we arrange for another company to provide the good or service.
Oil and Natural Gas Operations
Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, and by worldwide oil price levels. Global oil market developments primarily influence domestic oil prices. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.
Based on our first six months of 2019 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $427,000 per month ($5.1 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first six months of 2019 was $2.18 compared to $2.40 for the first six months of 2018. Based on our first six months of 2019 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $224,000 per month ($2.7 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a $386,000 per month ($4.6 million annualized) change in our pre-tax operating cash flow. In the first six months of 2019, our average oil price per barrel received, including the effect of derivatives, was $58.16 compared with an average oil price, including the effect of derivatives, of $55.76 in the first six months of 2018 and our first six months of 2019 average NGLs price per barrel received, including the effect of derivatives was $14.11 compared with an average NGLs price per barrel of $21.65 in the first six months of 2018.
Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. At June 30, 2019, the 12-month average unescalated prices were $61.39 per barrel of oil, $32.38 per barrel of NGLs, and $3.02 per Mcf of natural gas, and then are adjusted for price differentials. We did not take a write down in the first six months of 2019.
We anticipate a non-cash ceiling test write-down in the third quarter of 2019. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at June 30, 2019, and only adjust the 12-month average price to an estimated third quarter ending average (holding July 2019 prices constant for the remaining two months of the third quarter of 2019),
our forward looking expectation is that we would recognize an impairment of $107 million pre-tax in the third quarter of 2019. The estimated third-quarter 2019 impairment would be partially the result of a decrease in our proved undeveloped reserves of approximately 16%. This decrease would be primarily due to certain locations no longer being economical under the adjusted 12-month average price for the third quarter. As a result, we may eliminate those locations from our future development plans. Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.
Our natural gas production is sold to intrastate and interstate pipelines and to independent marketing firms and gatherers under contracts with terms ranging from one month to five years. Our oil production is sold to independent marketing firms generally under six month contracts.
Contract Drilling Operations
Many factors influence the number of drilling rigs we are working and the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed.
Most of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes the demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first six months of 2019, our average dayrate was $18,412 per day compared to $17,184 per day for the first six months of 2018. The average number of our drilling rigs used in the first six months of 2019 was 30.0 drilling rigs compared with 31.9 drilling rigs in the first six months of 2018. Based on the average utilization of our drilling rigs during the first six months of 2019, a $100 per day change in dayrates has a $3,000 per day ($1.1 million annualized) change in our pre-tax operating cash flow.
Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed to be associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our income statements, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $14.8 million and $10.6 million for the first six months of 2019 and 2018, respectively, from our contract drilling segment and eliminated the associated operating expense of $13.1 million and $9.3 million during the first six months
of 2019 and 2018, respectively, yielding $1.7 million and $1.3 million during the first six months of 2019 and 2018, respectively, as a reduction to the carrying value of our oil and natural gas properties.
Mid-Stream Operations
Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 12 processing plants, 21 gathering systems, and approximately 1,500 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first six months of 2019 and 2018, our mid-stream operations purchased $24.8 million and $36.5 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $3.6 million and $3.4 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements.
This segment gathered an average of 457,859 Mcf per day in the first six months of 2019 compared to 382,005 Mcf per day in the first six months of 2018. It processed an average of 163,725 Mcf per day in the first six months of 2019 compared to 155,799 Mcf per day in the first six months of 2018. The NGLs sold was 681,070 gallons per day in the first six months of 2019 compared to 627,305 gallons per day in the first six months of 2018. Gas gathered volumes per day in the first six months of 2019 increased 20% compared to the first six months of 2018 primarily due to connecting additional wells to our Pennsylvania and Oklahoma facilities. Gas processed volumes for the first six months of 2019 increased 5% over the first six months of 2018 due to connecting new wells mainly at our Cashion processing facility. NGLs sold increased 9% over the comparative period due to increased volume available to process at our processing facilities from additional well connections along with operating in higher recovery mode.
Our Credit Agreements and Senior Subordinated Notes
Unit Credit Agreement.
Our Senior Credit Agreement (Unit credit agreement) is scheduled to mature on October 18, 2023. Under that agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $1.0 billion. Our elected commitment amount is $425.0 million. Our borrowing base is $425.0 million. We are currently charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. Total fees of $3.3 million in origination, agency, syndication, and other related fees are being amortized over the life of the Unit credit agreement. Under the agreement, we have pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties.
On May 2, 2018, we entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent to benefit the secured parties, granting a security interest in the limited liability membership interests and other equity interests we own in Superior (which as of this report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the Unit credit agreement.
The current lenders under our Unit credit agreement and their respective participation interests are:
|
|
|
|
|
|
|
|
|
|
|
Lender
|
|
Participation
Interest
|
|
BOK (BOKF, NA, dba Bank of Oklahoma)
|
|
17.060
|
%
|
|
BBVA Compass Bank
|
|
17.060
|
%
|
|
BMO Harris Financing, Inc.
|
|
15.294
|
%
|
|
Bank of America, N.A.
|
|
15.294
|
%
|
|
Comerica Bank
|
|
8.235
|
%
|
|
Toronto Dominion Bank, New York Branch
|
|
8.235
|
%
|
|
Canadian Imperial Bank of Commerce
|
|
8.235
|
%
|
|
Arvest Bank
|
|
3.529
|
%
|
|
Branch Banking & Trust
|
|
3.529
|
%
|
|
IBERIABANK
|
|
3.529
|
%
|
|
|
|
100.000
|
%
|
The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the Unit credit agreement.
At our election, any part of the outstanding debt under the Unit credit agreement can be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement but in no event less than LIBOR plus 1.00% plus a margin. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest is payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, 2019, we had $103.5 million outstanding under the Unit credit agreement.
We can use borrowings to finance general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets up to certain limits, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, and (e) general corporate purposes.
The Unit credit agreement prohibits, among other things:
•
the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;
•
the incurrence of additional debt with certain limited exceptions;
•
the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, on any of our properties, except in favor of our lenders; and
•
investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) over $200.0 million.
The Unit credit agreement also requires that we have at the end of each quarter:
•
a current ratio (as defined in the credit agreement) of not less than 1 to 1.
•
a leverage ratio of funded debt to consolidated EBITDA (as defined in the Unit credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.
As of June 30, 2019, we were in compliance with these covenants.
Superior Credit Agreement.
On May 10, 2018, Superior, a limited liability company equally owned between the company and SP Investor Holdings, LLC, entered into a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions. The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. The credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index.
Superior is currently charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement.
The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. Additionally, the Superior credit agreement contains a number of customary covenants that, among
other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of June 30, 2019, Superior was in compliance with the Superior credit agreement covenants.
The borrowings the Superior credit agreement will be used to
fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior. As of June 30, 2019, we had $7.5 million outstanding borrowings under the Superior credit agreement.
On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the agreement.
Superior's credit agreement is not guaranteed by Unit.
The current lenders under the Superior credit agreement and their respective participation interests are:
|
|
|
|
|
|
|
|
|
|
|
Lender
|
|
Participation
Interest
|
|
BOK (BOKF, NA, dba Bank of Oklahoma)
|
|
17.50
|
%
|
|
Compass Bank
|
|
17.50
|
%
|
|
BMO Harris Financing, Inc.
|
|
13.75
|
%
|
|
Toronto Dominion (New York), LLC
|
|
13.75
|
%
|
|
Bank of America, N.A.
|
|
10.00
|
%
|
|
Branch Banking and Trust Company
|
|
10.00
|
%
|
|
Comerica Bank
|
|
10.00
|
%
|
|
Canadian Imperial Bank of Commerce
|
|
7.50
|
%
|
|
|
|
100.00
|
%
|
6.625% Senior Subordinated Notes.
We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes) outstanding. Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost over the life of the Notes.
The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes. The Guarantors are most of our direct and indirect subsidiaries, but excluding Superior. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.
Unit, as the parent company, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. Excluding Superior, any of our other subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.
We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest.
If a “change of control” occurs, unless the Company has exercised its right to redeem all of the Notes, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. As of May 15, 2019, we may redeem the Notes at a redemption price equal to 100% of the principal amount of the Notes plus accrued and unpaid interest on the date of purchase.
The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of June 30, 2019.
We may from time to time seek to retire or purchase our outstanding Note debt through cash purchases and/or exchanges for securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Capital Requirements
Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures.
Most of our capital expenditures for this segment are discretionary and directed toward future growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing under the circumstances which provide us with flexibility in deciding when and if to incur these costs. We completed drilling 63 gross wells (17.41 net wells) in the first six months of 2019 compared to 34 gross wells (12.40 net wells) in the first six months of 2018.
At June 30, 2019 we had commitments to purchase approximately $0.5 million for casing over the next year. Capital expenditures for oil and gas properties on the full cost method for the first six months of 2019 by this segment, excluding $3.3 million for acquisitions and a $3.7 million increase in the ARO liability, totaled $195.5 million. Capital expenditures for the first six months of 2018, excluding $1.0 million for acquisitions and a $7.9 million reduction in the ARO liability, totaled $157.7 million.
We anticipate participating in drilling approximately 85 to 95 gross wells in 2019 and our total estimated capital expenditures (excluding a reduction in ARO liability and any possible acquisitions) for this segment is approximately $265.0 million (slightly lower than the original $271.0 million to $315.0 million range) due to lower commodity prices. Whether we can drill the full number of wells planned depends on several factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand for oil, NGLs, and natural gas, the cost to drill wells, the weather, and the efforts of outside industry partners.
Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures.
During the first quarter of 2018, we were awarded a term contract to build our 11th BOSS drilling rig which was constructed and placed into service in the second quarter of 2018. During the second quarter of 2018, we were awarded a term contract to build our 12th BOSS drilling rig.
During the first quarter of 2019, we completed construction and placed into service our 12th and 13th BOSS drilling rigs. One was delivered to an existing third party operator in Wyoming. Two additional BOSS drilling rigs under contract with the same customer were also extended. The other BOSS drilling rig was delivered to a new customer in the Permian Basin. This was following an early termination by the original third party operator prior to the drilling rig’s completion.
During the second quarter of 2019, we were awarded a term contract to build our 14th BOSS drilling rig. Construction has started and the drilling rig is expected to be placed into service with a third party operator in the fourth quarter. Two existing BOSS drilling rig contracts working for the same operator were also extended at the time of the new BOSS drilling rig award.
Our estimated 2019 capital expenditures for this segment is approximately $45.0 million (the midpoint of the original $30.0 million to $65.0 million range) due to the construction of our 14th BOSS drilling rig. At June 30, 2019, we had commitments to purchase approximately $1.1 million for drilling equipment over the next year. We have spent $24.9 million for capital expenditures during the first six months of 2019, compared to $23.0 million for capital expenditures during the first six months of 2018.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures
.
In the Appalachian region at the Pittsburgh Mills gathering system, the average gathered volume for the second quarter of 2019 was approximately 206.4 MMcf per day. In the first quarter of 2019, we added seven new wells which accounted for the significant increase in gathered volume in the first quarter. In the second quarter of 2019, the production from these wells is declining as evidenced in the lower volume as of June 2019. These wells are all long lateral wells. The Kissick compressor station facilities located on the south end of the system have been upgraded and are able to handle the increased volume from these new wells.
At the Cashion processing facility in central Oklahoma, total throughput volume for the second quarter of 2019 averaged approximately 56.7 MMcf per day and total production of natural gas liquids increased to 273,075 gallons per day. We are continuing to connect new wells to this system from several third party producers. In 2019, we have connected 16 new wells to this system from several third party producers who continue to be active in the area. During the second quarter, we completed the addition of the new 60 MMcf per day Reeding processing facility on the Cashion system. This 60 MMcf per day processing
plant was relocated from our Bellmon facility to the Cashion area and is now fully operational. The addition of this new processing facility increases our total processing capacity on the Cashion system to approximately 105 MMcf per day.
At the Hemphill processing facility located in the Texas panhandle, average total throughput volume for the second quarter of 2019 was 72.9 MMcf per day and total production of natural gas liquids was 288,762 gallons per day during this same period. Since the first of this year, we have connected six new wells to the Hemphill system. The six new wells connected in 2019 are Unit Petroleum wells. There are no Unit Petroleum wells currently being drilled in this area.
During the first six months of 2019, our mid-stream segment incurred $32.6 million in capital expenditures as compared to $13.8 million in the first six months of 2018. Our estimated 2019 capital expenditures for this segment is approximately $45.0 million (slightly higher than the original $35.0 million to $42.0 million range) due to the purchase of previously leased assets.
Contractual Commitments
At June 30, 2019, we had certain contractual obligations including:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
Less
Than
1 Year
|
|
2-3
Years
|
|
4-5
Years
|
|
After
5 Years
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
Long-term debt
(1)
|
|
$
|
862,480
|
|
$
|
47,945
|
|
$
|
697,400
|
|
$
|
117,135
|
|
$
|
—
|
|
Operating leases under ASC 840
(2)
|
|
507
|
|
507
|
|
—
|
|
—
|
|
—
|
|
Operating leases under ASC 842
(3)
|
|
8,075
|
|
4,519
|
|
3,297
|
|
195
|
|
64
|
|
Finance lease interest and maintenance
(4)
|
|
3,620
|
|
2,087
|
|
1,533
|
|
—
|
|
—
|
|
Drilling rig components and casing
(5)
|
|
1,584
|
|
1,584
|
|
—
|
|
—
|
|
—
|
|
Total contractual obligations
|
|
$
|
876,266
|
|
$
|
56,642
|
|
$
|
702,230
|
|
$
|
117,330
|
|
$
|
64
|
_______________________
1.
See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our June 30, 2019 interest rates of 6.625% for the Notes and 4.2% for our Unit credit agreement and 6.5% for our Superior credit agreement. At June 30, 2019, our Unit credit agreement and our Superior credit agreement had maturity dates of October 18, 2023 and May 10, 2023, respectively. The outstanding Unit and Superior credit agreements balance were $103.5 million and $7.5 million, respectively, as of June 30, 2019.
2.
We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through March 2020. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.
3.
We lease certain office space, land and equipment, including pipeline equipment and office equipment under the terms of operating leases under ASC 842 expiring through March 2032.
4.
Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $3.2 million and $0.4 million, respectively.
5.
We have committed to pay $1.6 million for drilling rig components and casing over the next year.
During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is included in our future drilling plans. For each dollar of the $150.0 million that we do not spend (over the three year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. At June 30, 2019, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $74.0 million. Total spent towards the $150.0 million as of June 30, 2019 was $22.4 million.
At June 30, 2019, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Amount of Commitment Expiration Per Period
|
|
|
|
|
|
|
|
|
|
Other Commitments
|
|
Total
Accrued
|
|
Less
Than 1
Year
|
|
2-3
Years
|
|
4-5
Years
|
|
After 5
Years
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
Deferred compensation plan
(1)
|
|
$
|
6,002
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Separation benefit plans
(2)
|
|
$
|
9,749
|
|
$
|
1,083
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Asset retirement liability
(3)
|
|
$
|
67,433
|
|
$
|
1,784
|
|
$
|
40,376
|
|
$
|
3,837
|
|
$
|
21,436
|
|
Gas balancing liability
(4)
|
|
$
|
3,372
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Repurchase obligations
(5)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Workers’ compensation liability
(6)
|
|
$
|
12,118
|
|
$
|
4,050
|
|
$
|
2,438
|
|
$
|
1,109
|
|
$
|
4,521
|
|
Finance lease obligations
(7)
|
|
$
|
9,400
|
|
$
|
4,081
|
|
$
|
5,319
|
|
$
|
—
|
|
$
|
—
|
|
Contract liability
(8)
|
|
$
|
8,513
|
|
$
|
2,889
|
|
$
|
4,960
|
|
$
|
638
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________________
1.
We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.
2.
Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.
3.
When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).
4.
We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.
5.
We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. Effective December 31, 2014, The Unit 1984 Oil and Gas Limited Partnership dissolved and effective December 31, 2016, the two 1986 partnerships were dissolved. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We had no repurchases in the first six months of 2018. The partnerships were terminated during the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.
6.
We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.
7.
The amount includes commitments under finance lease arrangements for compressors in Superior.
8.
We have recorded a liability related to the timing of revenue recognized on certain demand fees for Superior.
Derivative Activities
Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and natural gas production.
Commodity Derivatives
. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. At June 30, 2019, based on our second quarter 2019 average daily production, the approximated percentages of our production under derivative contracts are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
Q3
|
|
Q4
|
|
Daily oil production
|
|
|
51
|
%
|
|
51
|
%
|
|
Daily natural gas production
|
|
|
55
|
%
|
|
46
|
%
|
With respect to the commodities subject to derivative contracts, those contracts serve to limit the risk of adverse downward price movements. However, they also limit increases in future revenues that would otherwise result from price movements above the contracted prices.
The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our June 30, 2019 evaluation, we believe the risk of non-performance by our counterparties is not material. At June 30, 2019, the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
|
|
|
(In millions)
|
|
Bank of Montreal
|
|
$
|
6.1
|
|
Bank of America
|
|
2.1
|
|
Total net assets
|
|
$
|
8.2
|
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets. At June 30, 2019, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $8.5 million and non-current derivative liabilities of $0.3 million. At December 31, 2018, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $12.9 million and non-current derivative liabilities of $0.3 million.
For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. These gains (losses) at June 30 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Six Months Ended
|
|
|
|
|
|
June 30,
|
|
|
|
June 30,
|
|
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, included are amounts settled during the period of $2,658, ($6,855), $5,314 and ($8,928), respectively
|
|
$
|
7,927
|
|
$
|
(14,461)
|
|
$
|
995
|
|
$
|
(21,223)
|
|
|
|
$
|
7,927
|
|
$
|
(14,461)
|
|
$
|
995
|
|
$
|
(21,223)
|
Stock and Incentive Compensation
During the first six months of 2019, we granted awards covering 1,424,027 shares of restricted stock. These awards had an estimated fair value as of their grant date of $22.6 million. Compensation expense will be recognized over the three year vesting periods, and during the six months of 2019, we recognized $3.4 million in compensation expense and capitalized $0.6 million for these awards. During the first six months of 2019, we recognized compensation expense of $8.5 million for all of our restricted stock and capitalized $1.3 million of compensation cost for oil and natural gas properties.
During the first six months of 2018, we granted awards covering 1,250,880 shares of restricted stock. These awards had an estimated fair value as of their grant date of $24.4 million. Compensation expense will be recognized over the three year vesting periods, and during the six months of 2018, we recognized $3.7 million in compensation expense and capitalized $0.6
million for these awards. During the first six months of 2018, we recognized compensation expense of $9.5 million for all of our restricted stock and stock options and capitalized $1.0 million of compensation cost for oil and natural gas properties.
Insurance
We are self-insured for certain losses relating to workers’ compensation, general liability, control of well, and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships
We are the general partner of 13 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are considered by us to be reasonable. For the first six months 2018, the total we received for all of these fees was $0.1 million. Our proportionate share of assets, liabilities, and net income relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements.
The partnerships were terminated during the second quarter of 2019 with an effective date of January 1, 2019.
New Accounting Pronouncements
Measurement of Credit Losses on Financial Instruments (Topic 326).
The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable and certain debt securities, with a current expected credit loss model. The amendment will be effective for reporting periods after December 15, 2019. We are evaluating the impact this will have on our financial statements by reviewing our accounts receivable accounts and our historic credit losses.
Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement.
The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified and other disclosures were added. The amendment will be effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. Also it is permitted to early adopt any removed or modified disclosure and delay adoption of the additional disclosures until their effective date. This amendment will not have a material impact on our financial statements.
Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment.
The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.
Adopted Standards
Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting.
The FASB issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands Topic 718,
Compensation—Stock Compensation
to include share-based payments issued to nonemployees for goods or services. The amendment is effective for years beginning after December 15, 2018, and interim periods within those years. This amendment did not have an impact on our financial statements.
We adopted ASC 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.
The additional disclosures required by ASC 842 have been included in Note 12 – Leases.
Results of Operations
Quarter Ended June 30, 2019 versus Quarter Ended June 30, 2018
Provided below is a comparison of selected operating and financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended June 30,
|
|
|
|
Percent
Change
(1)
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
(In thousands unless otherwise specified)
|
|
|
|
|
|
Total revenue
|
|
$
|
165,146
|
|
$
|
203,303
|
|
(19)
|
%
|
|
Net income (loss)
|
|
$
|
(8,017)
|
|
$
|
8,150
|
|
(198)
|
%
|
|
Net income attributable to non-controlling interest
|
|
$
|
492
|
|
$
|
2,362
|
|
(79)
|
%
|
|
Net income (loss) attributable to Unit Corporation
|
|
$
|
(8,509)
|
|
$
|
5,788
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas:
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
77,815
|
|
$
|
102,318
|
|
(24)
|
%
|
|
Operating costs excluding depreciation, depletion, and amortization
|
|
$
|
36,242
|
|
$
|
32,418
|
|
12
|
%
|
|
Depreciation, depletion, and amortization
|
|
$
|
38,751
|
|
$
|
31,554
|
|
23
|
%
|
|
|
|
|
|
|
|
|
|
Average oil price received (Bbl)
|
|
$
|
59.94
|
|
$
|
56.46
|
|
6
|
%
|
|
Average NGLs price received (Bbl)
|
|
$
|
12.52
|
|
$
|
22.18
|
|
(44)
|
%
|
|
Average natural gas price received (Mcf)
|
|
$
|
1.86
|
|
$
|
2.18
|
|
(15)
|
%
|
|
Oil production (Bbl)
|
|
726,000
|
|
693,000
|
|
5
|
%
|
|
NGLs production (Bbl)
|
|
1,210,000
|
|
1,230,000
|
|
(2)
|
%
|
|
Natural gas production (Mcf)
|
|
13,288,000
|
|
13,738,000
|
|
(3)
|
%
|
|
Depreciation, depletion, and amortization rate (Boe)
|
|
$
|
8.94
|
|
$
|
7.14
|
|
25
|
%
|
|
|
|
|
|
|
|
|
|
Contract Drilling:
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
43,037
|
|
$
|
46,926
|
|
(8)
|
%
|
|
Operating costs excluding depreciation
|
|
$
|
29,308
|
|
$
|
31,894
|
|
(8)
|
%
|
|
Depreciation
|
|
$
|
13,504
|
|
$
|
13,726
|
|
(2)
|
%
|
|
|
|
|
|
|
|
|
|
Percentage of revenue from daywork contracts
|
|
100
|
%
|
|
100
|
%
|
|
—
|
%
|
|
Average number of drilling rigs in use
|
|
28.6
|
|
32.2
|
|
(11)
|
%
|
|
Average dayrate on daywork contracts
|
|
$
|
18,491
|
|
$
|
17,330
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
Mid-Stream:
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
44,294
|
|
$
|
54,059
|
|
(18)
|
%
|
|
Operating costs excluding depreciation and amortization
|
|
$
|
32,491
|
|
$
|
39,703
|
|
(18)
|
%
|
|
Depreciation and amortization
|
|
$
|
12,102
|
|
$
|
11,175
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
Gas gathered—Mcf/day
|
|
465,714
|
|
391,047
|
|
19
|
%
|
|
Gas processed—Mcf/day
|
|
165,682
|
|
160,506
|
|
3
|
%
|
|
Gas liquids sold—gallons/day
|
|
711,192
|
|
676,503
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
Corporate and Other:
|
|
|
|
|
|
|
|
General and administrative expense
|
|
$
|
10,064
|
|
$
|
8,712
|
|
16
|
%
|
|
Other depreciation
|
|
$
|
1,935
|
|
$
|
1,918
|
|
1
|
%
|
|
Gain on disposition of assets
|
|
$
|
422
|
|
$
|
161
|
|
162
|
%
|
|
Other income (expense):
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
3
|
|
$
|
411
|
|
(99)
|
%
|
|
Interest expense, net
|
|
$
|
(8,998)
|
|
$
|
(8,140)
|
|
11
|
%
|
|
Gain (loss) on derivatives
|
|
$
|
7,927
|
|
$
|
(14,461)
|
|
155
|
%
|
|
Other
|
|
$
|
6
|
|
$
|
5
|
|
20
|
%
|
|
Income tax (benefit) expense
|
|
$
|
(1,874)
|
|
$
|
2,029
|
|
(192)
|
%
|
|
Average long-term debt outstanding
|
|
$
|
731,037
|
|
$
|
646,760
|
|
13
|
%
|
|
Average interest rate
|
|
6.5
|
%
|
|
6.7
|
%
|
|
(3)
|
%
|
_________________________
1.
NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
Oil and Natural Gas
Oil and natural gas revenues decreased $24.5 million or 24% in the second quarter of 2019 as compared to the second quarter of 2018 primarily due to lower unhedged NGLs and natural gas prices and from lower NGLs and natural gas production volumes. In the second quarter of 2019, as compared to the second quarter of 2018, oil production increased 5%, natural gas production decreased 3%, and NGLs production decreased 2%. Including derivatives settled, average oil prices increased 6% to $59.94 per barrel, average natural gas prices decreased 15% to $1.86 per Mcf, and NGLs prices decreased 44% to $12.52 per barrel.
Oil and natural gas operating costs increased $3.8 million or 12% between the comparative second quarters of 2019 and 2018 primarily due to higher lease operating expenses (LOE) and salt water disposal expenses.
Depreciation, depletion, and amortization (DD&A) increased $7.2 million or 23% due primarily to a 25% increase in the DD&A rate partially offset by an 1% decrease in equivalent production. The increase in our DD&A rate in the second quarter of 2019 compared to the second quarter of 2018 resulted primarily from the cost of wells drilled in the last six months of 2018 and the first six months of 2019.
Contract Drilling
Drilling revenues decreased $3.9 million or 8% in the second quarter of 2019 versus the second quarter of 2018. The decrease was due primarily to an 11% decrease in the average number of drilling rigs in use partially offset by a 7% increase in the average dayrate. Average drilling rig utilization decreased from 32.2 drilling rigs in the second quarter of 2018 to 28.6 drilling rigs in the second quarter of 2019.
Drilling operating costs decreased $2.6 million or 8% between the comparative second quarters of 2019 and 2018. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased $0.2 million or 2% in the second quarter of 2019 versus the second quarter of 2018 also due to less drilling rigs operating and the transfer of 41 drilling rigs to assets held for sale partially offset by accelerated depreciation on drilling rigs stacked more than 49 months.
Mid-Stream
Our mid-stream revenues decreased $9.8 million or 18% in the second quarter of 2019 as compared to the second quarter of 2018 due primarily to lower gas, NGLs, and condensate prices. Gas processed volumes per day increased 3% between the comparative quarters primarily due to additional wells connected mainly to our Cashion gathering system. Gas gathered volumes per day increased 19% between the comparative quarters due to connecting additional wells to our gathering and processing facilities primarily in Pennsylvania and Oklahoma.
Operating costs decreased $7.2 million or 18% in the second quarter of 2019 compared to the second quarter of 2018 primarily due to lower gas and purchase prices. Depreciation and amortization increased $0.9 million, or 8%, primarily due to new capital assets placed in service.
Gain on Disposition of Assets
There was a $0.4 million gain on disposition of assets in the second quarter of 2019 which was primarily related to assets held for sale that were sold which consisted of miscellaneous drilling rig components. For the second quarter of 2018, we had a gain of $0.2 million for the disposition of assets primarily due to the sale of drilling rig components and vehicles.
Other Income (Expense)
Interest expense, net of capitalized interest, increased $0.9 million between the comparative second quarters of 2019 and 2018 due primarily to a 13% increase in average long-term debt outstanding in the second quarter of 2019 partially offset by a lower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for the second quarter of 2019 was $4.2 million compared to $4.3 million in the second quarter of 2018, and was netted against our gross interest of $13.2 million and $12.4 million for the second quarters of 2019 and 2018, respectively. Our average interest rate decreased from 6.7% in the second quarter of 2018 to 6.5% in the second quarter of 2019 and our average debt outstanding was $84.3 million higher in the second quarter of 2019 as compared to the second quarter of 2018 primarily due to additional capital expenditures over the last 12 months.
Gain (Loss) on Derivatives
Gain (loss) on derivatives increased by $22.4 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax (Benefit) Expense
Income tax expense went from an expense of $2.0 million to a benefit of $1.9 million between the comparative second quarters of 2019 and 2018 primarily due to decreased pre-tax income. Our effective tax rate was 18.9% for the second quarter of 2019 compared to 19.9% for the second quarter of 2018. The rate change was primarily due to decreased pre-tax income in relation to permanent tax differences. There was no current income tax expense or benefit in the second quarter of 2019 or 2018. We paid no income taxes in the second quarter of 2019.
Six Months Ended June 30, 2019 versus Six Months Ended June 30, 2018
Provided below is a comparison of selected operating and financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
Percent
Change
(1)
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
(In thousands unless otherwise specified)
|
|
|
|
|
|
Total revenue
|
|
$
|
354,837
|
|
$
|
408,435
|
|
(13)
|
%
|
|
Net income (loss)
|
|
$
|
(10,299)
|
|
$
|
16,015
|
|
(164)
|
%
|
|
Net income attributable to non-controlling interest
|
|
$
|
1,714
|
|
$
|
2,362
|
|
(27)
|
%
|
|
Net income (loss) attributable to Unit Corporation
|
|
$
|
(12,013)
|
|
$
|
13,653
|
|
(188)
|
%
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas:
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
163,910
|
|
$
|
205,417
|
|
(20)
|
%
|
|
Operating costs excluding depreciation, depletion, and amortization
|
|
$
|
68,956
|
|
$
|
68,380
|
|
1
|
%
|
|
Depreciation, depletion, and amortization
|
|
$
|
74,518
|
|
$
|
62,337
|
|
20
|
%
|
|
|
|
|
|
|
|
|
|
Average oil price received (Bbl)
|
|
$
|
58.16
|
|
$
|
55.76
|
|
4
|
%
|
|
Average NGLs price received (Bbl)
|
|
$
|
14.11
|
|
$
|
21.65
|
|
(35)
|
%
|
|
Average natural gas price received (Mcf)
|
|
$
|
2.18
|
|
$
|
2.40
|
|
(9)
|
%
|
|
Oil production (Bbl)
|
|
1,414,000
|
|
1,429,000
|
|
(1)
|
%
|
|
NGLs production (Bbl)
|
|
2,417,000
|
|
2,425,000
|
|
—
|
%
|
|
Natural gas production (Mcf)
|
|
26,659,000
|
|
27,237,000
|
|
(2)
|
%
|
|
Depreciation, depletion, and amortization rate (Boe)
|
|
$
|
8.64
|
|
$
|
7.08
|
|
22
|
%
|
|
|
|
|
|
|
|
|
|
Contract Drilling:
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
94,192
|
|
$
|
92,915
|
|
1
|
%
|
|
Operating costs excluding depreciation
|
|
$
|
60,709
|
|
$
|
63,561
|
|
(4)
|
%
|
|
Depreciation
|
|
$
|
26,203
|
|
$
|
27,038
|
|
(3)
|
%
|
|
|
|
|
|
|
|
|
|
Percentage of revenue from daywork contracts
|
|
100
|
%
|
|
100
|
%
|
|
—
|
%
|
|
Average number of drilling rigs in use
|
|
30.0
|
|
31.9
|
|
(6)
|
%
|
|
Average dayrate on daywork contracts
|
|
$
|
18,412
|
|
$
|
17,184
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
Mid-Stream:
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
96,735
|
|
$
|
110,103
|
|
(12)
|
%
|
|
Operating costs excluding depreciation and amortization
|
|
$
|
71,846
|
|
$
|
81,307
|
|
(12)
|
%
|
|
Depreciation and amortization
|
|
$
|
23,828
|
|
$
|
22,228
|
|
7
|
%
|
|
|
|
|
|
|
|
|
|
Gas gathered—Mcf/day
|
|
457,859
|
|
382,005
|
|
20
|
%
|
|
Gas processed—Mcf/day
|
|
163,725
|
|
155,799
|
|
5
|
%
|
|
Gas liquids sold—gallons/day
|
|
681,070
|
|
627,305
|
|
9
|
%
|
|
|
|
|
|
|
|
|
|
Corporate and Other:
|
|
|
|
|
|
|
|
General and administrative expense
|
|
$
|
19,805
|
|
$
|
19,474
|
|
2
|
%
|
|
Other depreciation
|
|
$
|
3,869
|
|
$
|
3,836
|
|
1
|
%
|
|
Gain (loss) on disposition of assets
|
|
$
|
(1,193)
|
|
$
|
322
|
|
NM
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
44
|
|
$
|
411
|
|
(89)
|
%
|
|
Interest expense, net
|
|
$
|
(17,577)
|
|
(18,144)
|
|
(3)
|
%
|
|
Gain (loss) on derivatives
|
|
$
|
995
|
|
$
|
(21,223)
|
|
NM
|
|
|
Other
|
|
$
|
11
|
|
$
|
11
|
|
—
|
%
|
|
Income tax (benefit) expense
|
|
$
|
(2,318)
|
|
$
|
5,636
|
|
(141)
|
%
|
|
Average long-term debt outstanding
|
|
$
|
710,494
|
|
$
|
733,487
|
|
(3)
|
%
|
|
Average interest rate
|
|
6.5
|
%
|
|
6.4
|
%
|
|
2
|
%
|
_________________________
2.
NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
Oil and Natural Gas
Oil and natural gas revenues decreased $41.5 million or 20% in the first six months 2019 as compared to the first six months of 2018 primarily due to lower commodity prices and production volumes. In the first six months of 2019, as compared to the first six months of 2018, oil production decreased 1%, natural gas production decreased 2%, and NGLs production was essentially unchanged. Average oil prices increased 4% to $58.16 per barrel, average natural gas prices decreased 9% to $2.18 per Mcf, and NGLs prices decreased 35% to $14.11 per barrel.
Oil and natural gas operating costs increased $0.6 million or 1% between the comparative first six months of 2019 and 2018 due to higher saltwater disposal, general and administrative expenses, and gross production tax partially offset by lower LOE.
DD&A increased $12.2 million or 20% due primarily to a 22% increase in our DD&A rate partially offset by an 1% decrease in equivalent production. The increase in our DD&A rate in the first six months of 2019 compared to the first six months of 2018 resulted primarily from the cost of wells drilled in the last six months of 2018 and the first six months of 2019.
Contract Drilling
Drilling revenues increased $1.3 million or 1% in the first six months of 2019 versus the first six months of 2018. The increase was due primarily to a 7% increase in the average dayrate partially offset by a 6% decrease in the average number of drilling rigs in use. We also received $4.8 million in contract early termination fees during the first six months of 2019. Average drilling rig utilization decreased from 31.9 drilling rigs in the first six months of 2018 to 30.0 drilling rigs in the first six months of 2019.
Drilling operating costs decreased $2.9 million or 4% between the comparative first six months of 2019 and 2018. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased $0.8 million or 3% between the comparative first six months of 2019 and 2018. The decrease was also due to less drilling rigs operating and the transfer of 41 drilling rigs to assets held for sale partially offset by accelerated depreciation on drilling rigs stacked more than 49 months.
Mid-Stream
Our mid-stream revenues decreased $13.4 million or 12% in the first six months of 2019 as compared to the first six months of 2018 due due primarily to lower gas, NGLs, and condensate prices. Gas processed volumes per day increased 5% between the comparative periods primarily due to connecting new wells at the Cashion processing facilities. Gas gathered volumes per day increased 20% between the comparative periods primarily due to connecting new wells at our Cashion and Pittsburgh Mills facilities.
Operating costs decreased $9.5 million or 12% in the first six months of 2019 compared to the first six months of 2018 primarily due lower purchase prices. Depreciation and amortization increased $1.6 million, or 7%, primarily due to new capital assets placed into service.
General and Administrative
Corporate general and administrative expenses increased $0.3 million or 2% in the first six months of 2019 compared to the first six months of 2018 primarily due to higher employee costs and computer network costs.
Gain (Loss) on Disposition of Assets
There was an $1.2 million loss on disposition of assets in the first six months of 2019. Of this amount, $0.2 million was related to assets held for sale that were sold which consisted of three drilling rigs and other drilling components. The other $1.0 million was related to the sales of other drilling rig components and vehicles. For the first six months of 2018, we had a gain of $0.3 million for the disposition of assets primarily due to the sale of drilling rig components and vehicles.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased $0.6 million between the comparative first six months of 2019 and 2018 due primarily to a 3% decrease in the average long-term debt outstanding and an increase in interest capitalized partially offset by a higher average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems.
Capitalized interest for the first six months of 2019 was $8.4 million compared to $7.9 million in the first six months of 2018, and was netted against our gross interest of $26.0 million and $26.1 million for the first six months of 2019 and 2018, respectively. Our average interest rate increased from 6.4% to 6.5% and our average debt outstanding was $23.0 million lower in the first six months of 2019 as compared to the first six months of 2018 primarily due to the pay down of our Unit credit agreement in the second quarter of 2018.
Gain (Loss) on Derivatives
Gain (loss) on derivatives increased $22.2 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax (Benefit) Expense
Income tax expense went from an expense of $5.6 million to a benefit of $2.3 million between the comparative first six months of 2019 and 2018 primarily due to decreased pre-tax income. Our effective tax rate was 18.4% for the first six months of 2019 compared to 26.0% for the first six months of 2018. The decrease was again primarily due to decreased pre-tax income in relation to permanent tax differences. There was no current income tax expense or benefit in the first six months of 2019 or 2018. We paid no income taxes in the first six months of 2019.
Safe Harbor Statement
This report, including information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases, and oral statements issued by or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events, or developments which we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements.
These forward-looking statements include, among others, things as:
•
the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
•
prices for oil, NGLs, and natural gas;
•
demand for oil, NGLs, and natural gas;
•
our exploration and drilling prospects;
•
the estimates of our proved oil, NGLs, and natural gas reserves;
•
oil, NGLs, and natural gas reserve potential;
•
development and infill drilling potential;
•
expansion and other development trends of the oil and natural gas industry;
•
our business strategy;
•
our plans to maintain or increase production of oil, NGLs, and natural gas;
•
the number of gathering systems and processing plants we plan to construct or acquire;
•
volumes and prices for natural gas gathered and processed;
•
expansion and growth of our business and operations;
•
demand for our drilling rigs and drilling rig rates;
•
our belief that the final outcome of legal proceedings involving us will not materially affect our financial results;
•
our ability to timely secure third-party services used in completing our wells;
•
our ability to transport or convey our oil or natural gas production to established pipeline systems;
•
impact of federal and state legislative and regulatory initiatives relating to hydrocarbon fracturing impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;
•
our projected production guidelines for the year;
•
our anticipated capital budgets;
•
our financial condition and liquidity (including our ability to refinance our senior subordinated notes);
•
the number of wells our oil and natural gas segment plans to drill or rework during the year; and
•
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.
These statements are based on certain assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:
•
the risk factors discussed in this report and in the documents we incorporate by reference;
•
general economic, market, or business conditions;
•
the availability of and nature of (or lack of) business opportunities that we pursue;
•
demand for our land drilling services;
•
changes in laws or regulations;
•
changes in the current geopolitical situation;
•
risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
•
risks associated with future weather conditions;
•
decreases or increases in commodity prices;
•
putative class action lawsuits that may result in substantial expenditures and divert management's attention; and
•
other factors, most of which are beyond our control.
You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this report to reflect the occurrence of unanticipated events.
A more thorough discussion of forward-looking statements with the possible impact of some of these risks and uncertainties is provided in our Annual Report on Form 10-K filed with the SEC. We encourage you to get and read that document.