|
| | | | |
Type of Reserves | | Nature of Available Data | | Degree of Accuracy |
| | | | |
Proved undeveloped | | Data from offsetting wells, seismic data | | Less accurate |
| | | | |
Proved developed non-producing | | The above and logs, core samples, well tests, pressure data | | More accurate |
| | | | |
Proved developed producing | | The above and production history, pressure data over time | | Most accurate |
Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in estimating these reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that point when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves is greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on different assumptions. Companies, like ours, using full cost accounting use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.
We compute DD&A on a units-of-production method. Each quarter, we use these formulas to compute the provision for DD&A for our producing properties:
DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production
Provision for DD&A = DD&A Rate x Current Period Production
Unamortized cost includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service.
Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve estimates are revised upward, the DD&A rate will decrease. Based on our 2017 production level of 16.0 MMBoe, a decrease in our 2017 oil, NGLs, and natural gas reserves by 5% would increase our DD&A rate by $0.36 per Boe and would decrease pre-tax income by $5.8 million annually. Conversely, an increase in our 2017 oil, NGLs, and natural gas reserves by 5% would decrease our DD&A rate by $0.30 per Boe and would increase pre-tax income by $4.8 million annually.
The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities adjusted for period production.
We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess amount. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and results in lower DD&A expense in future periods. Once incurred, a write-down cannot be reversed.
The risk we will be required to write-down the carrying value of our oil and natural gas properties increases when the prices for oil, NGLs, and natural gas are depressed or if we have large downward revisions in our estimated proved oil, NGLs, and natural gas reserves. Application of these rules during periods of relatively low prices, even if temporary, increases the
chance of a ceiling test write-down. At December 31, 2017, our reserves were calculated based on applying 12-month 2017 average unescalated prices of $51.34 per barrel of oil, $31.83 per barrel of NGLs, and $2.98 per Mcf of natural gas (then adjusted for price differentials) over the estimated life of each of our oil and natural gas properties. We had no ceiling test write-down for 2017.
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 December 31, 2017 and only adjust the 12-month average price to an estimated first quarter ending average (holding February 2018 prices constant for the remaining one month of the first quarter of 2018), our forward looking expectation is that we will not recognize an impairment in the first quarter of 2018. But commodity prices (and other factors) remain volatile and they could negatively affect the 12-month average price resulting in the potential for an impairment in the first quarter.
We use the sales method for recording natural gas sales. This method allows for the recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all wells as incurred. The expenses relating to the wells in which we have a production imbalance are not material.
Costs Withheld from Amortization. Costs associated with unproved properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and related seismic data, wells drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred.
Our decision to withhold costs from amortization and the timing of transferring those costs into the amortization base involve significant judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. In December 2015, December 2016, and December 2017, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $114.4 million, $7.6 million, and $10.5 million in 2015, 2016, and 2017, respectively of costs being added to the total of our capitalized costs being amortized. At December 31, 2017, we had approximately $296.8 million of costs excluded from the amortization base of our full cost pool.
Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.
Accounting for Impairment of Long-Lived Assets. Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed.We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment.Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding
future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could cause materially different carrying values of our assets.
On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be spare equipment. The remaining components of these rigs are retired. During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax. No impairments were recorded in 2016 or 2017.
In 2015, our mid-stream segment incurred a $27.0 million pre-tax write-down of its systems, Bruceton Mills, Spring Creek, and Midwell due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. No impairments were recorded in 2016 or 2017.
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded at December 31, 2017, 2016, or 2015. Based on our impairment test performed as of December 31, 2017, the fair value of our drilling segment exceeded its carrying value by 41%. A period of sustained reduced commodity prices resulting in further reductions in the number of our drilling rigs working and the rates we charge for them could cause a non-cash goodwill impairment in future periods.
Turnkey and Footage Drilling Contracts. Because our contract drilling operations do not bear the risk of completion of a well being drilled under a “daywork” contract, we recognize revenues and expense generated under “daywork” contracts as the services are performed. Under “footage” and “turnkey” contracts we bear the risk of completion of the well, so revenues and expenses are recognized when the well is substantially completed. Substantial completion is determined when the well bore reaches the depth specified in the contract. The entire amount of any loss is recorded when the loss can be reasonably determined, however, any profit is recorded only at the time the well is finished. The costs of drilling contracts uncompleted at the end of the reporting period (which includes expenses incurred on “footage” or “turnkey” contracts) are included in other current assets. We drilled no wells under turnkey or footage contracts in 2017, 2016, or 2015.
Accounting for Value of Stock Compensation Awards. To account for stock-based compensation, compensation cost is measured at the grant date based on the fair value of an award and is recognized over the service period, which is usually the vesting period. We elected to use the modified prospective method, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. Determining the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and performance vesting criteria assumptions. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee.
Accounting for Derivative Instruments and Hedging. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) along with any derivatives settled are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
New Accounting Standards
Compensation—Stock Compensation. The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms of a share-based payment award. The amendment is effective for reporting periods beginning after December 15, 2017. 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.
Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendment should help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendment is effective for annual periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. This amendment will not have a material impact on our financial statements.
Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are evaluating the impact this amendment will have on our financial statements and currently evaluating a plan for implementation.
Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This standard affects any entity using U.S. GAAP that either contracts with customers to transfer goods or services or enters into contracts for transferring nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which is codified in the new Topic 606, effective January 1, 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We adopted this standard January 1, 2018 using the modified retrospective approach, which resulted in a cumulative effect adjustment upon adoption for our mid-stream segment. This adjustment related to the timing of revenue on certain demand fees which was not material to the company. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment.
The application of Topic 606 will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but additional footnote disclosures are required with respect to revenue. In our oil and natural gas segment, the classification of certain costs as either a deduction from revenue or an expense will be determined based on when control of the commodity transfers to the customer, which would impact total revenue recognized, but will not affect gross profit.
Part of our review included evaluation of these issues:
Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees collectible during a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.
Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires these arrangements represent variable consideration related to the sale of the commodity, and requires that we include an
estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue when it is not expected to be subject to a significant reversal.
Our internal control framework did not materially change, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.
Adopted Standards
Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations must classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment requires current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.
Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendment should improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment primarily affects classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.
Financial Condition and Liquidity
Summary.
Our financial condition and liquidity primarily depends on the cash flow from our operations and borrowings under our credit agreement. The principal factors determining our cash flow are:
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 have sufficient cash flow and liquidity to meet our obligations and remain in compliance with our debt covenants for the next twelve months. Our ability to meet our debt covenants (under our credit agreement and our Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which in turn will be affected by financial, business, economic, regulatory, and other factors. For example, lower oil, natural gas, and NGLs prices since the last redetermination under our credit agreement could cause a redetermination of the borrowing base to a lower level and therefore reduce or limit our ability to borrow funds. We monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work with the lenders under our credit agreement to address any of those issues ahead of time.
Below is a summary of certain financial information for the years ended December 31:
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| | (In thousands) | |
| Net cash provided by operating activities | $ | 279,588 |
| | $ | 240,130 |
| | $ | 446,944 |
| |
| Net cash used in investing activities | (306,998 | ) | | (110,971 | ) | | (549,778 | ) | |
| Net cash provided by (used in) financing activities | 27,218 |
| | (129,101 | ) | | 102,620 |
| |
| Net increase (decrease) in cash and cash equivalents | $ | (192 | ) | | $ | 58 |
| | $ | (214 | ) | |
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, NGL, and natural gas we produce, settlements of derivative contracts, third-party demand for our drilling rigs and mid-stream services, and the rates we can charge for those services. Our cash flows from operating activities are also affected by changes in working capital.
Net cash provided by operating activities during 2017 increased by $39.5 million from 2016 due primarily to higher revenues due to higher commodity prices and higher drilling rig utilization partially offset by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.
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 $196.0 million in 2017 compared to 2016. The change was due primarily to an increase in capital expenditures due to an oil and gas property acquisition, the restarting of our drilling program in 2017, the construction of a new BOSS drilling rig, and a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities increased by $156.3 million in 2017 compared to 2016. The increase was primarily due to proceeds from the ATM common stock program coupled with an increase in net borrowing after paying down long-term debt in 2016.
At December 31, 2017, we had unrestricted cash totaling $0.7 million and had borrowed $178.0 million of the $475.0 million we have available under our credit agreement.
Below is a summary of certain financial information as of December 31, and for the years ended December 31:
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| | (In thousands) | |
| Working capital | $ | (62,264 | ) | | $ | (43,719 | ) | | $ | (10,633 | ) | |
Long-term debt (1) | $ | 820,276 |
| | $ | 800,917 |
| | $ | 918,995 |
| |
Shareholders’ equity (2) | $ | 1,345,560 |
| | $ | 1,194,070 |
| | $ | 1,313,580 |
| |
Net income (loss) (2) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) | |
_________________________
| |
(1) | Long-term debt is net of unamortized discount and debt issuance costs. |
| |
(2) | In 2016 and 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million, and $1.6 billion pre-tax ($100.6 million and $1.0 billion, net of tax), respectively. In 2015, we incurred a non-cash write-down associated with the removal of 31 drilling rigs from our fleet along with certain other equipment and drill pipe of $8.3 million pre-tax ($5.1 million, net of tax). In December 2015, we incurred a non-cash write-down associated with the reduction in the carrying value of three mid-stream segment gathering systems of $27.0 million pre-tax ($16.8 million, net of tax). The write-downs affected our shareholders’ equity, ratio of long-term debt to total capitalization, and net income (loss) for 2015. There was no impact on our compliance with the covenants in our credit agreement. |
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 $62.3 million, $43.7 million, and $10.6 million as of December 31, 2017, 2016, and 2015, respectively. This is primarily due to increased accounts payable due to increased activity in our drilling program and increased drilling rig utilization and the reclassification of the current deferred tax asset to long-term asset per ASU 2015-17 partially offset by increased accounts receivable from increased revenues and the change in the value of outstanding derivatives. Our credit agreement is used primarily for working capital and capital expenditures. At December 31, 2017, we had borrowed $178.0 million of the $475.0 million available to us under our credit agreement. The effect of our derivatives decreased working capital by $7.1 million as of December 31, 2017, and increased working capital by $21.6 million and $10.2 million as of December 31, 2016 and 2015, respectively.
This table summarizes certain operating information for the years ended December 31:
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| Oil and Natural Gas: | | | | | | |
| Oil production (MBbls) | 2,715 |
| | 2,974 |
| | 3,783 |
| |
| Natural gas liquids production (MBbls) | 4,737 |
| | 5,014 |
| | 5,274 |
| |
| Natural gas production (MMcf) | 51,260 |
| | 55,735 |
| | 65,546 |
| |
| Average oil price per barrel received | $ | 49.44 |
| | $ | 40.50 |
| | $ | 50.79 |
| |
| Average oil price per barrel received excluding derivatives | $ | 48.98 |
| | $ | 39.05 |
| | $ | 45.04 |
| |
| Average NGLs price per barrel received | $ | 18.35 |
| | $ | 11.26 |
| | $ | 10.12 |
| |
| Average NGLs price per barrel received excluding derivatives | $ | 18.35 |
| | $ | 11.26 |
| | $ | 10.12 |
| |
| Average natural gas price per mcf received | $ | 2.46 |
| | $ | 2.07 |
| | $ | 2.63 |
| |
| Average natural gas price per mcf received excluding derivatives | $ | 2.49 |
| | $ | 1.98 |
| | $ | 2.25 |
| |
| Contract Drilling: | | | | | | |
| Average number of our drilling rigs in use during the period | 30.0 |
| | 17.4 |
| | 34.7 |
| |
| Total drilling rigs available for use at the end of the period | 95 |
| | 94 |
| | 94 |
| |
| Average dayrate | $ | 16,256 |
| | $ | 17,784 |
| | $ | 19,455 |
| |
| Mid-Stream: | | | | | | |
| Gas gathered—Mcf/day | 385,209 |
| | 419,217 |
| | 353,771 |
| |
| Gas processed—Mcf/day | 137,625 |
| | 155,461 |
| | 182,684 |
| |
| Gas liquids sold—gallons/day | 534,140 |
| | 536,494 |
| | 577,513 |
| |
| Number of natural gas gathering systems | 24 |
| | 25 |
| | 25 |
| (1) |
| Number of processing plants | 13 |
| | 13 |
| | 13 |
| |
_________________________
| |
(1) | In 2015, our mid-stream segment transferred 11 natural gas gathering systems to our oil and natural gas segment. |
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. Domestic oil prices are primarily influenced by world oil market developments. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.
Based on our 2017 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 $410,000 per month ($4.9 million annualized) change in our pre-tax operating cash flow. Our 2017 average natural gas price was $2.46 compared to an average natural gas price of $2.07 for 2016 and $2.63 for 2015. A $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $217,000 per month ($2.6 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 $380,000 per month ($4.6 million annualized) change in our pre-tax operating cash flow based on our production in 2017. Our 2017 average oil price per barrel was $49.44 compared with an average oil price of $40.50 in 2016 and $50.79 in 2015, and our 2017 average NGLs price per barrel was $18.35 compared with an average NGLs price of $11.26 in 2016 and $10.12 in 2015.
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 December 31, 2017, the 12-month average unescalated prices were $51.34 per barrel of oil, $31.83 per barrel of NGLs, and $2.98 per Mcf of natural gas, and then are adjusted for price differentials. We did not have to take a write down in 2017.
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 December 31, 2017 and only adjust the 12-month average price to an estimated first quarter ending average (holding February 2018 prices constant for the remaining
one month of the first quarter of 2018), our forward looking expectation is that we will not recognize an impairment in the first quarter of 2018. Commodity prices remain volatile and they could negatively affect the 12-month average price and the potential for an impairment in the first quarter.
Our natural gas production is sold to intrastate and interstate pipelines, to independent marketing firms and gatherers under contracts with terms generally 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 have 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.
Competition to keep qualified labor continues. We increased compensation for some rig personnel in the third quarter of 2017 and again during the first quarter of 2018.
During 2017, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes 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 2017, our average dayrate was $16,256 per day compared to $17,784 and $19,455 per day for 2016 and 2015, respectively. Our average number of drilling rigs used (utilization %) in 2017 was 30.0 (32%) compared with 17.4 (19%) and 34.7 (38%) in 2016 and 2015, respectively.Based on the average utilization of our drilling rigs during 2017, 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 associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our statement of operations, 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. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.
Mid-Stream Operations
This segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 13 processing plants, 24 gathering systems, and approximately 1,455 miles of pipeline. Its operations are in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. This segment enhances our ability to gather and market not only our own natural gas and NGLs but also that owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During 2017, 2016, and 2015 this segment purchased $63.2 million, $42.7 million, and $57.6 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $6.7 million, $9.2 million, and $7.6 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 consolidated financial statements.
Our mid-stream segment gathered an average of 385,209 Mcf per day in 2017 compared to 419,217 Mcf per day in 2016 and 353,771 Mcf per day in 2015. It processed an average of 137,625 Mcf per day in 2017 compared to 155,461 Mcf per day in 2016 and 182,684 Mcf per day in 2015, and sold NGLs of 534,140 gallons per day in 2017 compared to 536,494 gallons per day in 2016 and 577,513 gallons per day in 2015. Gas gathering volumes per day in 2017 decreased primarily due to lower volumes from our fee-based Appalachian systems. Volumes processed decreased primarily due to lower purchased volumes and fewer new wells connected to our processing systems in 2017. NGLs sold decreased primarily due to lower purchased volumes and continuing to operate most of our systems in ethane rejection mode.
At-the-Market (ATM) Common Stock Program
On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions we may impose).
We do not have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
Since entering into the Agreement through February 13, 2018, we have sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the fourth quarter of 2017. Approximately $81.0 million remain available for sale under the program.
Our Credit Agreement and Senior Subordinated Notes
Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to time) 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 $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. With the new amendment, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.
The lenders under our credit agreement and their respective participation interests are:
|
| | |
Lender | Participation
Interest
|
BOK (BOKF, NA, dba Bank of Oklahoma) | 17 | % |
Compass Bank | 17 | % |
BMO Harris Financing, Inc. | 15 | % |
Bank of America, N.A. | 15 | % |
Comerica Bank | 8 | % |
Wells Fargo Bank, N.A. | 8 | % |
Canadian Imperial Bank of Commerce | 8 | % |
Toronto Dominion (New York), LLC | 8 | % |
The Bank of Nova Scotia | 4 | % |
| 100 | % |
The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves and on our cash flows from our mid-stream segment. The October 2017 redetermination did not result in any changes. 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 credit agreement.
At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% 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 credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At December 31, 2017 and February 13, 2018, we had $178.0 million and $173.8 million, respectively, outstanding borrowings under our credit agreement.
We can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes.
The 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; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except for our lenders.
The 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.
Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:
a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.
Beginning with the quarter ending June 30, 2019, and for each quarter ending thereafter, the credit agreement requires:
a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.
As of December 31, 2017, we were in compliance with the covenants in the credit agreement.
6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021. In issuing the Notes, we incurred $14.7 million of fees 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 and providing for issuing the Notes. The Guarantors are our direct and indirect subsidiaries. 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 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 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through dividends, loans, advances or otherwise.
We may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, 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, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, 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 December 31, 2017.
Capital Requirements
Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward growth. Any decision 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, which provide us flexibility in deciding when and if to incur these costs. We completed drilling 70 gross wells (25.71 net wells) in 2017 compared to 21 gross wells (9.67 net wells) in 2016, and 58 gross wells (34.99 net wells) in 2015.
On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition included 13 potential horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction.
Capital expenditures for oil and gas properties on the full cost method for 2017 by this segment, excluding a $4.0 million reduction in the ARO liability and $59.0 million in acquisitions (including associated ARO), totaled $215.4 million compared to 2016 capital expenditures of $119.9 million (excluding a $30.9 million reduction in the ARO liability and $0.6 million in acquisitions), and 2015 capital expenditures of $273.5 million (excluding an $5.7 million reduction in the ARO liability and $0.2 million in acquisitions).
For 2018, we plan to participate in drilling approximately 75 to 85 gross wells and estimate our total capital expenditures (excluding any possible acquisitions) for our oil and natural gas segment will be approximately $272.0 million. Whether we drill all of those wells depends on several factors, many of which are beyond our control and include 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.
We sold non-core oil and natural gas assets, net of related expenses, for $18.6 million, $67.2 million, and $1.9 million during 2017, 2016, and 2015, respectively. Proceeds from those dispositions reduced the net book value of our full cost pool with no gain or loss recognized.
Contract Drilling Dispositions, Acquisitions, and Capital Expenditures. During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax.
During 2015, five BOSS drilling rigs were constructed and placed into service for third-party operators.
During December 2016, we sold an idle 1500 HP SCR drilling rig to an unaffiliated third party. We also fabricated and placed into service our ninth new BOSS drilling rig for a third party operator. This new BOSS rig was constructed using the long lead time components purchased in prior years.
During 2017, we built our tenth BOSS drilling rig and placed it into service for a third party operator under a long term contract. We also returned to service 14 SCR drilling rigs that had been previously stacked.
Our anticipated 2018 capital expenditures for this segment is approximately $47.0 million. We spent $36.1 million for capital expenditures during 2017 compared to $19.1 million in 2016, and $84.8 million in 2015.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At our Cashion processing facility in central Oklahoma, our total throughput volume for the fourth quarter of 2017 averaged approximately 37.3 MMcf per day and our total production of natural gas liquids increased to approximately 198,600 gallons per day. The total processing capacity at this facility is approximately 45 MMcf per day. During 2017, we connected 12 new wells to this system from three producers. We are continuing a pipeline extension project for a producer scheduled to actively drill in the Cashion area in 2018. We have already connected four new wells from this producer and anticipate connecting several more wells throughout 2018. As volume increases on this system, we will evaluate the need to add additional processing capacity. If volume continues to increase, we may need to add an additional processing plant in the Cashion area.
At our Hemphill processing facility in the Texas panhandle, our average gathered volume for the fourth quarter of 2017 was approximately 68.5 MMcf per day and our total production of natural gas liquids increased to 188,600 gallons per day. During 2017, we connected six new wells to this processing system with several more wells scheduled to be connected in the first part of 2018. We have completed construction of the pipeline to connect the next well pad and we are upgrading our compression facilities to handles the expected additional volume.
At our Bellmon processing facility in the Mississippian play in north central Oklahoma, during 2017 we connected 14 new wells to this system. Our total throughput volume for the fourth quarter of 2017 averaged approximately 27 MMcf per day. We have two processing skids available that provide total processing capacity of 90 MMcf per day.
At our Segno gathering facility in Southeast Texas, our average gathered volume for the fourth quarter of 2017 was approximately 86.4 MMcf per day. The gathering and dehydration capacity for this facility is approximately 120 MMcf per day. During 2017, we connected three new wells to this gathering system along with additional volume from recompletion activity in the area around our system.
In the Appalachian region, at our Pittsburgh Mills gathering system, we continue to connect new well pads to this system. During 2017, we connected one new well pad with five new wells to this gathering system. By adding these new wells our average gathered volume for the fourth quarter was approximately 117.2 MMcf per day. We are constructing a new pipeline to connect the next well pad to this system. Most of the preliminary environmental and permitting activities have been completed and right of way has been obtained. In the first quarter of 2018, we will start the construction of the pipeline with an expected completion date in the third quarter of 2018. This new well pad is expected to have seven wells drilled and we anticipate receiving gas from this pad at the end of 2018. This well pad is on the south end of our system and will be connected to our Kissick compressor station. And we have been notified by the producer they will drill seven infill wells on already existing pads in 2018.
During 2017, our mid-stream segment incurred $22.2 million in capital expenditures as compared to $16.8 million in 2016, and $63.5 million, in 2015. For 2018, our estimated capital expenditures is approximately $32.0 million.
Contractual Commitments
At December 31, 2017, we had these contractual obligations:
|
| | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| | Total | | Less Than 1 Year | | 2-3 Years | | 4-5 Years | | After 5 Years |
| | (In thousands) |
Long-term debt (1) | $ | 986,931 |
| | $ | 49,133 |
| | $ | 271,871 |
| | $ | 665,927 |
| | $ | — |
|
Operating leases (2) | 3,878 |
| | 2,717 |
| | 1,024 |
| | 137 |
| | — |
|
Capital lease interest and maintenance (3) | 7,048 |
| | 2,324 |
| | 4,172 |
| | 552 |
| | — |
|
Drill pipe, drilling components, and equipment purchases (4) | 3,887 |
| | 3,887 |
| | — |
| | — |
| | — |
|
| Total contractual obligations | $ | 1,001,744 |
| | $ | 58,061 |
| | $ | 277,067 |
| | $ | 666,616 |
| | $ | — |
|
_________________________
| |
(1) | See previous discussion in MD&A regarding our long-term debt. This obligation is presented under the Notes and credit agreement and includes interest calculated using our December 31, 2017 interest rates of 6.625% for the Notes and 3.4% for the credit agreement. |
| |
(2) | We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. And, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. |
| |
(3) | Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining are $5.9 million and $1.2 million, respectively. |
| |
(4) | We have committed to purchase approximately $3.9 million of new drilling rig components over the next year. |
At December 31, 2017, we also had these 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) | $ | 5,390 |
| | Unknown |
| | Unknown |
| | Unknown |
| | Unknown |
|
Separation benefit plans (2) | $ | 6,524 |
| | $ | 657 |
| | Unknown |
| | Unknown |
| | Unknown |
|
ARO liability (3) | $ | 69,444 |
| | $ | 1,726 |
| | $ | 42,409 |
| | $ | 3,908 |
| | $ | 21,401 |
|
Gas balancing liability (4) | $ | 3,283 |
| | Unknown |
| | Unknown |
| | Unknown |
| | Unknown |
|
Repurchase obligations (5) | $ | — |
| | Unknown |
| | Unknown |
| | Unknown |
| | Unknown |
|
Workers’ compensation liability (6) | $ | 13,340 |
| | $ | 6,775 |
| | $ | 1,712 |
| | $ | 917 |
| | $ | 3,936 |
|
Capital lease obligations (7) | $ | 15,224 |
| | $ | 3,844 |
| | $ | 8,164 |
| | $ | 3,216 |
| | $ | — |
|
| Derivative liabilities—commodity hedges | $ | 7,763 |
| | $ | 7,763 |
| | $ | — |
| | $ | — |
| | $ | — |
|
_________________________
| |
(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 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 with us is involuntarily terminated or with 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. 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 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 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were also dissolved. The Partnerships were formed to conduct 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 made repurchases of approximately $2,900, $5,000, and $118,000 in 2017, 2016, and 2015, respectively. |
| |
(6) | We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment. |
| |
(7) | This amount includes commitments under capital lease arrangements for compressors in our mid-stream segment. |
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. Any change in the fair value of all our derivatives are reflected in the statement of operations.
Commodity Derivatives. Our commodity derivatives should 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. As of December 31, 2017, based on our fourth quarter 2017 average daily production, the approximated percentages of our production under derivative contracts are as follows:
|
| | | | | | | | | | | |
| | Mark-to-Market |
| | 2018 |
| | Q1 | | Q2 | | Q3 | | Q4 |
| Daily oil production | 70 | % | | 63 | % | | 63 | % | | 63 | % |
| Daily natural gas production | 53 | % | | 33 | % | | 33 | % | | 29 | % |
| Daily NGLs production | — | % | | 7 | % | | 7 | % | | — | % |
Regarding the commodities subject to derivative contracts, those contracts 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.
Using derivative transactions has the risk that the counterparties may not meet their financial obligations under the transactions. Based on our evaluation at December 31, 2017, we believe the risk of non-performance by our counterparties is not material. At December 31, 2017, the fair values of the net assets (liabilities) we had with each of the counterparties to our commodity derivative transactions are:
|
| | | |
| | December 31, 2017 |
| | (In millions) |
| Canadian Imperial Bank of Commerce | $ | 0.7 |
|
| Bank of America Merrill Lynch | (2.5 | ) |
| Bank of Montreal | (5.3 | ) |
| Total assets (liabilities) | $ | (7.1 | ) |
If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our Consolidated Balance Sheets. At December 31, 2017, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.7 million and current derivative liabilities of $7.8 million. At December 31, 2016, we recorded the fair value of our commodity derivatives on our balance sheet as non-current derivative assets of $0.4 million and current and non-current derivative liabilities of $21.6 million and $0.4 million, respectively.
All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
These gains (losses) are as follows at December 31: |
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Gain (loss) on derivatives, included are amounts settled during the period of $173, $9,658, and $46,615, respectively | $ | 14,732 |
| | $ | (22,813 | ) | | $ | 26,345 |
|
Stock and Incentive Compensation
During 2017, we granted awards covering 708,276 shares of restricted stock. These awards were granted as retention incentive awards. These stock awards had an estimated fair value as of the grant date of $17.4 million. Compensation expense will be recognized over the awards' three year vesting period. During 2017, we recognized $7.0 million in additional compensation expense and capitalized $1.1 million for these awards. During 2016, we granted awards covering 736,451 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three year vesting period. During 2015, we granted awards covering 750,290 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over their two and three year vesting periods. No SAR awards were made during 2017, 2016, or 2015.
During 2017, we recognized compensation expense of $13.3 million for our restricted stock grants and capitalized $1.8 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 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 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 the same 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 and 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. During 2017, 2016, and 2015, the total we received for these fees was $0.2 million, $0.3 million, and $0.4 million, respectively. Our proportionate share of assets, liabilities, and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements.
Effects of Inflation
The effect of inflation in the oil and natural gas industry is primarily driven by the prices for oil, NGLs, and natural gas. Increases in these prices increase the demand for our contract drilling rigs and services. This increase in demand affects the dayrates we can obtain for our contract drilling services. During periods of higher demand for our drilling rigs we have experienced increases in labor costs and the costs of services to support our drilling rigs. Historically, during this same period, when oil, NGLs, and natural gas prices declined, labor rates did not come back down to the levels existing before the increases. If commodity prices increase substantially for a long period, shortages in support equipment (like drill pipe, third party services, and qualified labor) can cause additional increases in our material and labor costs. Increases in dayrates for drilling rigs also increase the cost of our oil and natural gas properties. Commodity prices also can affect our fracking and completion costs. How inflation will affect us in the future will depend on increases, if any, realized in our drilling rig rates, the prices we receive for our oil, NGLs, and natural gas, and the rates we receive for gathering and processing natural gas. Due to increased demand for drilling rigs and the need to maintain qualified labor, we increased pay for some of our drilling personnel in the fourth quarter of 2017 and again in the first quarter of 2018.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we are subject to various contractual commitments.
Results of Operations
2017 versus 2016
|
| | | | | | | | | | |
| | 2017 | | 2016 | | Percent Change (1) |
| | (In thousands unless otherwise specified) | | |
| Total operating revenue | $ | 739,640 |
| | $ | 602,177 |
| | 23 | % |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | 187 | % |
| | | | | | |
| Oil and Natural Gas: | | | | | |
| Revenue | $ | 357,744 |
| | $ | 294,221 |
| | 22 | % |
| Operating costs excluding depreciation, depletion, amortization, and impairment | $ | 130,789 |
| | $ | 120,184 |
| | 9 | % |
| Depreciation, depletion, and amortization | $ | 101,911 |
| | $ | 113,811 |
| | (10 | )% |
| Impairment of oil and gas properties | $ | — |
| | $ | 161,563 |
| | (100 | )% |
| | | | | | |
| Average oil price received (Bbl) | $ | 49.44 |
| | $ | 40.50 |
| | 22 | % |
| Average NGL price received (Bbl) | $ | 18.35 |
| | $ | 11.26 |
| | 63 | % |
| Average natural gas price received (Mcf) | $ | 2.46 |
| | $ | 2.07 |
| | 19 | % |
| Oil production (MBbls) | 2,715 |
| | 2,974 |
| | (9 | )% |
| NGLs production (MBbls) | 4,737 |
| | 5,014 |
| | (6 | )% |
| Natural gas production (MMcf) | 51,260 |
| | 55,735 |
| | (8 | )% |
| Depreciation, depletion, and amortization rate (Boe) | $ | 6.00 |
| | $ | 6.24 |
| | (4 | )% |
| | | | | | |
| Contract Drilling: | | | | | |
| Revenue | $ | 174,720 |
| | $ | 122,086 |
| | 43 | % |
| Operating costs excluding depreciation | $ | 122,600 |
| | $ | 88,154 |
| | 39 | % |
| Depreciation | $ | 56,370 |
| | $ | 46,992 |
| | 20 | % |
| | | | | | |
| Percentage of revenue from daywork contracts | 100 | % | | 100 | % | | — | % |
| Average number of drilling rigs in use | 30.0 |
| | 17.4 |
| | 72 | % |
| Average dayrate on daywork contracts | $ | 16,256 |
| | $ | 17,784 |
| | (9 | )% |
| | | | | | |
| Mid-Stream: | | | | | |
| Revenue | $ | 207,176 |
| | $ | 185,870 |
| | 11 | % |
| Operating costs excluding depreciation and amortization | $ | 155,483 |
| | $ | 137,609 |
| | 13 | % |
| Depreciation and amortization | $ | 43,499 |
| | $ | 45,715 |
| | (5 | )% |
| | | | | | |
| Gas gathered—Mcf/day | 385,209 |
| | 419,217 |
| | (8 | )% |
| Gas processed—Mcf/day | 137,625 |
| | 155,461 |
| | (11 | )% |
| Gas liquids sold—gallons/day | 534,140 |
| | 536,494 |
| | — | % |
| | | | | | |
| Corporate and other: | | | | | |
| General and administrative expense | $ | 38,087 |
| | $ | 33,337 |
| | 14 | % |
| Other depreciation | $ | 7,477 |
| | $ | 1,835 |
| | NM |
|
| Gain on disposition of assets | $ | 327 |
| | $ | 2,540 |
| | (87 | )% |
| Other income (expense): | | | | | |
| Interest expense, net | $ | (38,334 | ) | | $ | (39,829 | ) | | (4 | )% |
| Gain (loss) on derivatives | $ | 14,732 |
| | $ | (22,813 | ) | | 165 | % |
| Other | $ | 21 |
| | $ | 307 |
| | (93 | )% |
| Income tax benefit | $ | (57,678 | ) | | $ | (71,194 | ) | | 19 | % |
| Average interest rate | 6.0 | % | | 5.7 | % | | 5 | % |
| Average long-term debt outstanding | $ | 810,734 |
| | $ | 868,332 |
| | (7 | )% |
_________________________ | |
(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 increased $63.5 million or 22% in 2017 as compared to 2016 due primarily to higher commodity prices partially offset by a decrease in production. Oil production decreased 9%, NGLs production decreased 6%, and natural gas production decreased 8%. Average oil prices between the comparative years increased 22% to $49.44 per barrel, NGLs prices increased 63% to $18.35 per barrel, and natural gas prices increased 19% to $2.46 per Mcf.
Oil and natural gas operating costs increased $10.6 million or 9% between the comparative years of 2017 and 2016 primarily due to higher LOE and gross production taxes partially offset by lower saltwater disposal expense.
DD&A decreased $11.9 million or 10% primarily due to a 4% decrease in our DD&A rate and by the effect of a 7% decrease in equivalent production. The decrease in our DD&A rate in 2017 compared to 2016 resulted primarily from the effect of the ceiling test write-downs throughout 2016. Our DD&A expense on our oil and natural properties is calculated each quarter using period end reserve quantities adjusted for period production.
During 2016, we recorded non-cash ceiling test write-downs of our oil and natural gas properties totaling $161.6 million pre-tax ($100.6 million net of tax). We did not have a non-cash ceiling test write-down in 2017. The write-downs were due primarily from the reduction of the 12-month average commodity prices during 2016.
Contract Drilling
Drilling revenues increased $52.6 million or 43% in 2017 as compared to 2016. The increase was due primarily to a 72% increase in the average number of drilling rigs in use partially offset by a 9% decrease in the average dayrate compared to 2016. Average drilling rig utilization increased from 17.4 drilling rigs in 2016 to 30.0 drilling rigs in 2017.
Drilling operating costs increased $34.4 million or 39% in 2017 compared to 2016. The increase was due primarily to more drilling rigs operating. Contract drilling depreciation increased $9.4 million or 20% also due primarily to more drilling rigs operating.
Mid-Stream
Our mid-stream revenues increased $21.3 million or 11% in 2017 as compared to 2016 primarily due to increased NGLs and condensate sales. Gas processing volumes per day decreased 11% between the comparative years primarily due to fewer new well connections to our processing systems. Gas gathering volumes per day decreased 8% primarily due to declining volumes in the Appalachian region.
Operating costs increased $17.9 million or 13% in 2017 compared to 2016 primarily due to increased natural gas, NGLs, and condensate prices. Depreciation and amortization decreased $2.2 million or 5% primarily due to less capital expenditures this year while older assets became fully depreciated.
General and Administrative
General and administrative expenses increased $4.8 million or 14% in 2017 compared to 2016 primarily due to higher employee costs.
Other Depreciation
Other depreciation increased $5.6 million in 2017 compared to 2016 primarily due to the depreciation on the new ERP system and the corporate office facility.
Gain on Disposition of Assets
Gain on disposition of assets decreased $2.2 million in 2017 compared to 2016. The gain in 2017 was primarily for the sale of a corporate aircraft and vehicles, while the pre-tax gain of $3.2 million in 2016 was primarily for the sale of one drilling rig, various drilling rig components, vehicles, and other equipment somewhat offset by losses from our oil and natural gas and mid-stream segments in 2016.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased $1.5 million between the comparative years of 2017 and 2016. We capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2017 was $15.9 million compared to $15.3 million in 2016, and was netted against our gross interest of $54.2 million and $55.1 million for 2017 and 2016, respectively. Our average interest rate increased from 5.7% to 6.0% and our average debt outstanding was $57.6 million lower in 2017 as compared to 2016 primarily due to the decrease in our outstanding borrowings under our credit agreement over the comparative periods.
Gain (loss) on derivatives increased from a loss of $22.8 million in 2016 to a gain of $14.7 million in 2017 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Benefit
Income tax benefit decreased $13.5 million in 2017 compared to 2016 primarily. During the fourth quarter of 2017, the U.S. government enacted the Tax Cuts and Jobs Act (the Tax Act). Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. As a result of the Tax Act, the Company recorded a tax benefit of $81.3 million due to a revaluation of our net deferred tax liability. Without this income tax benefit charge, income tax expense would have been $23.6 million in 2017 compared to an income tax benefit of $71.2 million in 2016 or an increase of $94.8 million which is commensurate with the increase in pre-tax income for 2017 compared to 2016.
Our effective tax rate was (95.9%) for 2017 compared to 34.4% for 2016. The effective tax rate for the current year was dramatically lower due to the Tax Act and revaluation of our net deferred tax liability. Without the $81.3 million income tax benefit, our effective tax rate for 2017 would have been 39.3% The rate change without consideration of deferred tax liability revaluation was primarily due to increased deferred income tax expense related to our restricted stock vestings in both years whereby the increase in 2017 increased our deferred income tax expense and the increase in 2016 decreased our income tax benefit. We did not pay any income taxes during 2017.
2016 versus 2015
|
| | | | | | | | | | |
| | 2016 | | 2015 | | Percent Change (1) |
| | (In thousands unless otherwise specified) | | |
| Total operating revenue | $ | 602,177 |
| | $ | 854,231 |
| | (30 | )% |
| Net loss | $ | (135,624 | ) | | $ | (1,037,361 | ) | | 87 | % |
| | | | | | |
| Oil and Natural Gas: | | | | | |
| Revenue | $ | 294,221 |
| | $ | 385,774 |
| | (24 | )% |
| Operating costs excluding depreciation, depletion, amortization, and impairment | $ | 120,184 |
| | $ | 166,046 |
| | (28 | )% |
| Depreciation, depletion, and amortization | $ | 113,811 |
| | $ | 251,944 |
| | (55 | )% |
| Impairment of oil and natural gas properties | $ | 161,563 |
| | $ | 1,599,348 |
| | (90 | )% |
| | | | | | |
| Average oil price received (Bbl) | $ | 40.50 |
| | $ | 50.79 |
| | (20 | )% |
| Average NGLs price received (Bbl) | $ | 11.26 |
| | $ | 10.12 |
| | 11 | % |
| Average natural gas price received (Mcf) | $ | 2.07 |
| | $ | 2.63 |
| | (21 | )% |
| Oil production (MBbls) | 2,974 |
| | 3,783 |
| | (21 | )% |
| NGLs production (MBbls) | 5,014 |
| | 5,274 |
| | (5 | )% |
| Natural gas production (MMcf) | 55,735 |
| | 65,546 |
| | (15 | )% |
| Depreciation, depletion, and amortization rate (Boe) | $ | 6.24 |
| | $ | 12.30 |
| | (49 | )% |
| | | | | | |
| Contract Drilling: | | | | | |
| Revenue | $ | 122,086 |
| | $ | 265,668 |
| | (54 | )% |
| Operating costs excluding depreciation and impairment | $ | 88,154 |
| | $ | 156,408 |
| | (44 | )% |
| Depreciation | $ | 46,992 |
| | $ | 56,135 |
| | (16 | )% |
| Impairment of contract drilling equipment | $ | — |
| | $ | 8,314 |
| | (100 | )% |
| | | | | | |
| Percentage of revenue from daywork contracts | 100 | % | | 100 | % | | — | % |
| Average number of drilling rigs in use | 17.4 |
| | 34.7 |
| | (50 | )% |
| Average dayrate on daywork contracts | $ | 17,784 |
| | $ | 19,455 |
| | (9 | )% |
| | | | | | |
| Mid-Stream: | | | | | |
| Revenue | $ | 185,870 |
| | $ | 202,789 |
| | (8 | )% |
| Operating costs excluding depreciation, amortization, and impairment | $ | 137,609 |
| | $ | 161,556 |
| | (15 | )% |
| Depreciation and amortization | $ | 45,715 |
| | $ | 43,676 |
| | 5 | % |
| Impairment of gas gathering and processing systems | $ | — |
| | $ | 26,966 |
| | (100 | )% |
| | | | | | |
| Gas gathered—Mcf/day | 419,217 |
| | 353,771 |
| | 18 | % |
| Gas processed—Mcf/day | 155,461 |
| | 182,684 |
| | (15 | )% |
| Gas liquids sold—gallons/day | 536,494 |
| | 577,513 |
| | (7 | )% |
| | | | | | |
| Corporate and other: | | | | | |
| General and administrative expense | $ | 33,337 |
| | $ | 34,358 |
| | (3 | )% |
| Other depreciation | $ | 1,835 |
| | $ | 987 |
| | 86 | % |
| Gain (loss) on disposition of assets | $ | 2,540 |
| | $ | (7,229 | ) | | 135 | % |
| Other income (expense): | | | | | |
| Interest expense, net | $ | (39,829 | ) | | $ | (31,963 | ) | | 25 | % |
| Gain (loss) on derivatives | $ | (22,813 | ) | | $ | 26,345 |
| | (187 | )% |
| Other | $ | 307 |
| | $ | 45 |
| | NM |
|
| Income tax benefit | $ | (71,194 | ) | | $ | (626,948 | ) | | 89 | % |
| Average interest rate | 5.7 | % | | 5.4 | % | | 6 | % |
| Average long-term debt outstanding | $ | 868,332 |
| | $ | 897,391 |
| | (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 $91.6 million or 24% in 2016 as compared to 2015 due primarily to lower oil and natural gas prices and a decrease in production. Oil production decreased 21%, NGLs production decreased 5%, and natural gas production decreased 15%. Average oil prices between the comparative years decreased 20% to $40.50 per barrel, NGLs prices increased 11% to $11.26 per barrel, and natural gas prices decreased 21% to $2.07 per Mcf.
Oil and natural gas operating costs decreased $45.9 million or 28% between the comparative years of 2016 and 2015 due to lower LOE, saltwater disposal, and general and administrative expense.
DD&A decreased $138.1 million or 55% primarily due to a 49% decrease in our DD&A rate and by the effect of a 14% decrease in equivalent production. The decrease in our DD&A rate in 2016 compared to 2015 resulted primarily from the effect of the ceiling test write-downs during 2015 and 2016. Our DD&A expense on our oil and natural properties is calculated each quarter using period end reserve quantities adjusted for period production.
During 2016, we recorded non-cash ceiling test write-downs of our oil and natural gas properties totaling $161.6 million pre-tax ($100.6 million, net of tax) compared to a non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion net of tax) in 2015. These write-downs were due primarily from the reduction of the 12-month average commodity prices during each year.
Contract Drilling
Drilling revenues decreased $143.6 million or 54% in 2016 as compared to 2015. The decrease was due primarily to a 50% decrease in the average number of drilling rigs in use, a 9% decrease in the average dayrate, and $25.9 million less received for fees on contracts terminated early in 2016 compared to 2015. Average drilling rig utilization decreased from 34.7 drilling rigs in 2015 to 17.4 drilling rigs in 2016.
Drilling operating costs decreased $68.3 million or 44% in 2016 compared to 2015. The decrease was due primarily to fewer drilling rigs operating. Contract drilling depreciation decreased $9.1 million or 16% also due primarily to fewer drilling rigs operating. During the second quarter of 2015, we recorded an impairment of approximately $8.3 million on 31 drilling rigs and other equipment sold at auction during the third quarter.
Mid-Stream
Our mid-stream revenues decreased $16.9 million or 8% in 2016 as compared to 2015 due primarily to gas sold per day decreasing 16% and NGLs sold per day decreasing 7%. Gas processing volumes per day decreased 15% between the comparative years primarily from fewer well connections near our processing systems. Gas gathering volumes per day increased 18% primarily from new well connections in the Appalachian region.
Operating costs decreased $23.9 million or 15% in 2016 compared to 2015 primarily due to a 6% decrease in prices paid for natural gas purchased and a 15% decrease in purchase volumes. Depreciation and amortization increased $2.0 million or 5% primarily due to capital expenditures for upgrades and well connects.
In December 2015, our mid-stream segment had a $27.0 million pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems.
Due to continued depressed NGLs prices, we were operating most of our processing facilities in full ethane rejection mode which reduced the liquids sold throughout 2016. Our mid-stream segment also experienced a reduction in processed volumes in 2016 due to the low pricing environment and reduced drilling activity around our systems.
General and Administrative
General and administrative expenses decreased $1.0 million or 3% in 2016 compared to 2015 primarily due to lower employee costs.
Other Depreciation
Other depreciation increased $0.8 million or 86% in 2016 compared to 2015 primarily due to the depreciation on the corporate office facility.
Gain (loss) on Disposition of Assets
Gain (loss) on disposition of assets increased $9.8 million in 2016 compared to 2015 primarily due to the gain of $3.2 million pre-tax on the sale of one drilling rig, various drilling rig components, vehicles, and other equipment somewhat offset by losses from our oil and natural gas and mid-stream segments, compared to a loss of $7.3 million pre-tax on the sale of 31 drilling rigs and other drilling equipment somewhat offset by the gains on the sale of one gathering system, various drilling rig components, vehicles, and a drilling rig during 2015.
Other Income (Expense)
Interest expense, net of capitalized interest, increased $7.9 million between the comparative years of 2016 and 2015. We capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2016 was $15.3 million compared to $21.7 million in 2015, and was netted against our gross interest of $55.1 million and $53.7 million for 2016 and 2015, respectively. Our average interest rate increased from 5.4% to 5.7% and our average debt outstanding was $29.1 million lower in 2016 as compared to 2015 primarily due to the decrease in our outstanding borrowings under our credit agreement over the comparative periods.
Gain (loss) on derivatives decreased from a gain of $26.3 million in 2015 to a loss of $22.8 million in 2016 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Benefit
Income tax benefit decreased $555.8 million in 2016 compared to 2015 primarily due to a lower pre-tax loss from a reduction in non-cash ceiling test write-downs in 2016 compared to 2015. Our effective tax rate was 34.4% for 2016 and 37.7% for 2015. This decrease was primarily due to increased deferred tax expense in 2016 related to our restricted stock vestings in 2016 after the exhaustion of our remaining accumulated excess tax benefits. The current income tax benefit was minimal in 2016 compared to a current income tax benefit of $20.6 million for 2015. The $20.6 million current income tax benefit in 2015 was primarily due to an anticipated alternative minimum tax (AMT) net operating loss (NOL) carryback refund claim. We paid $42,000 in income taxes during 2016.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Our operations are exposed to market risks primarily because of changes in the prices for natural gas and oil and interest rates.
Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. Those prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, these prices have fluctuated and they will probably continue to do so. The price of oil, NGLs, and natural gas also affects both the demand for our drilling rigs and the amount we can charge for our drilling rigs. Based on our 2017 production, a $0.10 per Mcf change in what we are paid for our natural gas production would cause a corresponding $410,000 per month ($4.9 million annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our oil price would have a $217,000 per month ($2.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices would have a $380,000 per month ($4.6 million annualized) change in our pre-tax cash flow.
We use derivative transactions to manage the risk associated with price volatility. 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. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading purposes.
At December 31, 2017, these non-designated hedges were outstanding:
|
| | | | | | | | |
Term | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps
| | Contracted Market |
Jan’18 – Dec’18 | | Natural gas – swap | | 20,000 MMBtu/day | | $3.013 | | IF – NYMEX (HH) |
Apr'18 – Oct'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.990 | | IF – NYMEX (HH) |
Jan’18 – Mar'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.208) | | IF – NYMEX (HH) |
Nov’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.208) | | IF – NYMEX (HH) |
Jan’18 – Mar'18 | | Natural gas – three-way collar | | 60,000 MMBtu/day | | $3.29 - $2.63 - $4.07 | | IF – NYMEX (HH) |
Apr’18 – Dec'18 | | Natural gas – three-way collar | | 20,000 MMBtu/day | | $3.00 - $2.50 - $3.51 | | IF – NYMEX (HH) |
Jan’18 – Dec'18 | | Crude oil – swap | | 3,000 Bbl/day | | $51.36 | | WTI – NYMEX |
Jan’18 – Mar'18 | | Crude oil – collar | | 500 Bbl/day | | $55.00 - $59.50 | | WTI – NYMEX |
Jan’18 – Dec'18 | | Crude oil – three-way collar | | 2,000 Bbl/day | | $47.50 - $37.50 - $56.08 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids (Propane) – swap | | 1,000 Bbl/day | | $31.16 | | MONT BELVIEU |
After December 31, 2017, these non-designated hedges were entered into:
|
| | | | | | | | |
Term | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps | | Contracted Market |
Apr’18 – Sep'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.925 | | IF – NYMEX (HH) |
Apr’18 – Sep'18 | | Natural gas – collar | | 30,000 MMBtu/day | | $2.67 - $2.97 | | IF – NYMEX (HH) |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.678) | | PEPL |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.568) | | NGPL MIDCON |
Apr’18 – Oct'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.190) | | NGPL TEXOK |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.728) | | PEPL |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.625) | | NGPL MIDCON |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.273) | | NGPL TEXOK |
Jan'20 – Dec'20 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.280) | | NGPL TEXOK |
Apr'18 – Dec'18 | | Crude oil – swap | | 1,000 Bbl/day | | $60.00 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids – swap | | 500 Bbl/day | | $34.10 | | MONT BELVIEU |
Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreement and the Notes. The credit agreement, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a variable rate in 2017, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $1.6 million. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year).
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Unit Corporation and Subsidiaries
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Management’s Report on Internal Control over Financial Reporting
Management of the company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
The company’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2017. In making this assessment, the company’s management used the criteria set forth in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on their assessment, the company’s management concluded that, as of December 31, 2017, the company’s internal control over financial reporting was effective based on those criteria.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Report of Independent Registered Public Accounting Firm
ToBoard of Directors and Shareholders of Unit Corporation:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Unit Corporationand its subsidiariesas of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 27, 2018
We have served as the Company’s auditor since 1989.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In thousands except share and par value amounts) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 701 |
| | $ | 893 |
|
| Accounts receivable (less allowance for doubtful accounts of $2,450 and $3,773 at December 31, 2017 and 2016, respectively) | 111,512 |
| | 83,954 |
|
| Materials and supplies | 505 |
| | 3,340 |
|
| Current derivative asset (Note 12) | 721 |
| | — |
|
| Current deferred tax asset (Note 8) | — |
| | 25,211 |
|
| Prepaid expenses and other | 6,233 |
| | 7,798 |
|
| Total current assets | 119,672 |
| | 121,196 |
|
| Property and equipment: | | | |
| Oil and natural gas properties, on the full cost method: | | | |
| Proved properties | 5,712,813 |
| | 5,446,305 |
|
| Unproved properties not being amortized | 296,764 |
| | 314,867 |
|
| Drilling equipment | 1,593,611 |
| | 1,565,268 |
|
| Gas gathering and processing equipment | 726,236 |
| | 705,859 |
|
| Saltwater disposal systems | 62,618 |
| | 60,638 |
|
| Corporate land and building | 59,080 |
| | 59,066 |
|
| Transportation equipment | 29,631 |
| | 32,842 |
|
| Other | 53,439 |
| | 48,590 |
|
| | 8,534,192 |
| | 8,233,435 |
|
| Less accumulated depreciation, depletion, amortization, and impairment | 6,151,450 |
| | 5,952,330 |
|
| Net property and equipment | 2,382,742 |
| | 2,281,105 |
|
| Goodwill (Note 2) | 62,808 |
| | 62,808 |
|
| Non-current derivative asset (Note 12) | — |
| | 377 |
|
| Other assets | 16,230 |
| | 13,817 |
|
| Total assets | $ | 2,581,452 |
| | $ | 2,479,303 |
|
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In thousands except share and par value amounts) |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 112,648 |
| | $ | 88,793 |
|
| Accrued liabilities (Note 5) | 48,523 |
| | 39,651 |
|
| Current derivative liabilities (Note 12) | 7,763 |
| | 21,564 |
|
| Current portion of other long-term liabilities (Note 6) | 13,002 |
| | 14,907 |
|
| Total current liabilities | 181,936 |
| | 164,915 |
|
| Long-term debt less unamortized discount and debt issuance costs (Note 6) | 820,276 |
| | 800,917 |
|
| Non-current derivative liabilities (Note 12) | — |
| | 415 |
|
| Other long-term liabilities (Note 6) | 100,203 |
| | 103,064 |
|
| Deferred income taxes (Note 8) | 133,477 |
| | 215,922 |
|
| Commitments and contingencies (Note 14) | — |
| | — |
|
| Shareholders’ equity: | | | |
| Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued | — |
| | — |
|
| Common stock, $0.20 par value, 175,000,000 shares authorized, 52,880,134 and 51,494,318 shares issued as of December 31, 2017 and 2016, respectively | 10,280 |
| | 10,016 |
|
| Capital in excess of par value | 535,815 |
| | 502,500 |
|
| Accumulated other comprehensive income (net of tax of $39 at December 31, 2017) (Note 15) | 63 |
| | — |
|
| Retained earnings | 799,402 |
| | 681,554 |
|
| Total shareholders’ equity | 1,345,560 |
| | 1,194,070 |
|
| Total liabilities and shareholders’ equity | $ | 2,581,452 |
| | $ | 2,479,303 |
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands except per share amounts) |
| Revenues: | | | | | |
| Oil and natural gas | $ | 357,744 |
| | $ | 294,221 |
| | $ | 385,774 |
|
| Contract drilling | 174,720 |
| | 122,086 |
| | 265,668 |
|
| Gas gathering and processing | 207,176 |
| | 185,870 |
| | 202,789 |
|
| Total revenues | 739,640 |
| | 602,177 |
| | 854,231 |
|
| Expenses: | | | | | |
| Operating costs: | | | | | |
| Oil and natural gas | 130,789 |
| | 120,184 |
| | 166,046 |
|
| Contract drilling | 122,600 |
| | 88,154 |
| | 156,408 |
|
| Gas gathering and processing | 155,483 |
| | 137,609 |
| | 161,556 |
|
| Total operating costs | 408,872 |
| | 345,947 |
| | 484,010 |
|
| | | | | | |
| Depreciation, depletion, and amortization | 209,257 |
| | 208,353 |
| | 352,742 |
|
| Impairments | — |
| | 161,563 |
| | 1,634,628 |
|
| General and administrative | 38,087 |
| | 33,337 |
| | 34,358 |
|
| (Gain) loss on disposition of assets | (327 | ) | | (2,540 | ) | | 7,229 |
|
| Total expenses | 655,889 |
| | 746,660 |
| | 2,512,967 |
|
| Income (loss) from operations | 83,751 |
| | (144,483 | ) | | (1,658,736 | ) |
| Other income (expense): | | | | | |
| Interest, net | (38,334 | ) | | (39,829 | ) | | (31,963 | ) |
| Gain (loss) on derivatives | 14,732 |
| | (22,813 | ) | | 26,345 |
|
| Other | 21 |
| | 307 |
| | 45 |
|
| Total other income (expense) | (23,581 | ) | | (62,335 | ) | | (5,573 | ) |
| Income (loss) before income taxes | 60,170 |
| | (206,818 | ) | | (1,664,309 | ) |
| Income tax expense (benefit): | | | | | |
| Current | 5 |
| | 15 |
| | (20,616 | ) |
| Deferred | (57,683 | ) | | (71,209 | ) | | (606,332 | ) |
| Total income taxes | (57,678 | ) | | (71,194 | ) | | (626,948 | ) |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
| Net income (loss) per common share: | | | | | |
| Basic | $ | 2.31 |
| | $ | (2.71 | ) | | $ | (21.12 | ) |
| Diluted | $ | 2.28 |
| | $ | (2.71 | ) | | $ | (21.12 | ) |
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
| | | | | | | | | | | |
| | For Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
| Other comprehensive income, net of taxes: | | | | | |
| Unrealized appreciation on securities, net of tax of $39, $0, and $0 | 63 |
| | — |
| | — |
|
| Comprehensive income (loss) | $ | 117,911 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year Ended December 31, 2015, 2016, and 2017
|
| | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Capital In Excess of Par Value | | Accumulated Other Comprehensive Income | | Retained Earnings | | Total |
| | (In thousands except per share amounts) |
| Balances, January 1, 2015 | $ | 9,732 |
| | $ | 468,123 |
| | $ | — |
| | $ | 1,854,539 |
| | $ | 2,332,394 |
|
| Net loss | — |
| | — |
| | — |
| | (1,037,361 | ) | | (1,037,361 | ) |
| Activity in employee compensation plans (819,289 shares) | 99 |
| | 18,448 |
| | — |
| | — |
| | 18,547 |
|
| Balances, December 31, 2015 | 9,831 |
| | 486,571 |
| | — |
| | 817,178 |
| | 1,313,580 |
|
| Net loss | — |
| | — |
| | — |
| | (135,624 | ) | | (135,624 | ) |
| Activity in employee compensation plans (1,081,217 shares) | 185 |
| | 15,929 |
| | — |
| | — |
| | 16,114 |
|
| Balances, December 31, 2016 | 10,016 |
| | 502,500 |
| | — |
| | 681,554 |
| | 1,194,070 |
|
| Net income | — |
| | — |
| | — |
| | 117,848 |
| | 117,848 |
|
| Other comprehensive income (net of tax $39) | — |
| | — |
| | 63 |
| | — |
| | 63 |
|
| Total comprehensive income | | | | | | | | | 117,911 |
|
| Proceeds from sale of stock (787,547 shares) | 158 |
| | 18,465 |
| | — |
| | — |
| | 18,623 |
|
| Activity in employee compensation plans (598,269 shares) | 106 |
| | 14,850 |
| | — |
| | — |
| | 14,956 |
|
| Balances, December 31, 2017 | $ | 10,280 |
| | $ | 535,815 |
| | $ | 63 |
| | $ | 799,402 |
| | $ | 1,345,560 |
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| OPERATING ACTIVITIES: | | | | | |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
| Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: | | | | | |
| Depreciation, depletion, and amortization | 209,257 |
| | 208,353 |
| | 352,742 |
|
| Impairments (Note 2) | — |
| | 161,563 |
| | 1,634,628 |
|
| Amortization of debt issuance costs and debt discount | 2,159 |
| | 2,122 |
| | 2,088 |
|
| (Gain) loss on derivatives | (14,732 | ) | | 22,813 |
| | (26,345 | ) |
| Cash receipts on derivatives settled | 173 |
| | 9,658 |
| | 46,615 |
|
| (Gain) loss on disposition of assets | (327 | ) | | (3,127 | ) | | 7,229 |
|
| Deferred tax benefit | (57,683 | ) | | (71,209 | ) | | (606,332 | ) |
| Employee stock compensation plans | 17,747 |
| | 13,812 |
| | 21,468 |
|
| Bad debt expense | 348 |
| | 785 |
| | 1,191 |
|
| ARO liability accretion | 2,886 |
| | 2,779 |
| | 3,453 |
|
| Other, net | (865 | ) | | (6,037 | ) | | (1,517 | ) |
| Changes in operating assets and liabilities increasing (decreasing) cash: | | | | | |
| Accounts receivable | (32,073 | ) | | (11,796 | ) | | 105,426 |
|
| Materials and supplies | 2,835 |
| | 225 |
| | 1,507 |
|
| Prepaid expenses and other | 1,527 |
| | 2,585 |
| | 7,134 |
|
| Accounts payable | 21,824 |
| | 27,400 |
| | (20,306 | ) |
| Accrued liabilities | 6,996 |
| | (4,388 | ) | | (22,920 | ) |
| Income taxes | 38 |
| | 20,903 |
| | (21,482 | ) |
| Contract advances | 1,630 |
| | (687 | ) | | (274 | ) |
| Net cash provided by operating activities | 279,588 |
| | 240,130 |
| | 446,944 |
|
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (269,185 | ) | | (186,149 | ) | | (561,453 | ) |
| Producing property and other acquisitions | (58,026 | ) | | (564 | ) | | (179 | ) |
| Proceeds from disposition of property and equipment | 21,713 |
| | 74,823 |
| | 11,854 |
|
| Other | (1,500 | ) | | 919 |
| | — |
|
| Net cash used in investing activities | (306,998 | ) | | (110,971 | ) | | (549,778 | ) |
| FINANCING ACTIVITIES: | | | | | |
| Borrowings under line of credit | 343,900 |
| | 251,398 |
| | 618,500 |
|
| Payments under line of credit | (326,700 | ) | | (371,600 | ) | | (503,500 | ) |
| Payments on capitalized leases | (3,694 | ) | | (3,694 | ) | | (3,549 | ) |
| Proceeds from common stock issued, net of issue costs (Note 15) | 18,623 |
| | — |
| | — |
|
| Tax expense from stock compensation | — |
| | (376 | ) | | (3,207 | ) |
| Decrease in book overdrafts (Note 2) | (4,911 | ) | | (4,829 | ) | | (5,624 | ) |
| Net cash provided by (used in) financing activities | 27,218 |
| | (129,101 | ) | | 102,620 |
|
| Net increase (decrease) in cash and cash equivalents | (192 | ) | | 58 |
| | (214 | ) |
| Cash and cash equivalents, beginning of year | 893 |
| | 835 |
| | 1,049 |
|
| Cash and cash equivalents, end of year | $ | 701 |
| | $ | 893 |
| | $ | 835 |
|
| Supplemental disclosure of cash flow information: | | | | | |
| Cash paid during the year for: | | | | | |
| Interest paid (net of capitalized) | $ | 33,931 |
| | $ | 35,690 |
| | $ | 30,910 |
|
| Income taxes | $ | — |
| | $ | 42 |
| | $ | 3,540 |
|
| Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment | $ | (6,942 | ) | | $ | 21,190 |
| | $ | 105,157 |
|
| Non-cash reductions to oil and natural gas properties related to asset retirement obligations | $ | 3,613 |
| | $ | 30,897 |
| | $ | 5,694 |
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION
Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like terms refer to Unit Corporation and its subsidiaries.
We are primarily engaged in the exploration, development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are principally in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.
Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company, we explore, develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, Montana, New Mexico, North Dakota, Utah, and Wyoming.
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, we drill onshore oil and natural gas wells for our own account and for a wide range of other oil and natural gas companies. Our drilling operations are mainly in Oklahoma, Texas, Wyoming, North Dakota, and to a lesser extent in Louisiana and Kansas.
Mid-Stream. Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements.
Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity.
Accounting Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Drilling Contracts. We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2017, all of our contracts were daywork contracts of which nine were multi-well and had durations which ranged from six months to two years, eight of which expire in 2018 and one expiring in 2019. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.
Cash Equivalents and Book Overdrafts. We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2017 and 2016, book overdrafts were $12.4 million and $17.3 million, respectively.
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.
Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues:
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Oil and Natural Gas: | | | | | |
| Sunoco Logistics Partners L.P. | 10 | % | | 24 | % | | 19 | % |
| Valero Energy Corporation | 9 | % | | 11 | % | | 15 | % |
| Drilling: | | | | | |
| QEP Resources, Inc. | 26 | % | | 28 | % | | 25 | % |
| Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) | 7 | % | | 18 | % | | 7 | % |
| Mid-Stream: | | | | | |
| ONEOK, Inc. | 36 | % | | 30 | % | | 29 | % |
| Range Resources Corporation | 9 | % | | 10 | % | | 5 | % |
| Koch Energy Services, LLC | 8 | % | | 11 | % | | 9 | % |
| Tenaska Resources, LLC | 6 | % | | 10 | % | | 18 | % |
| Laclede Group, Inc. | 1 | % | | 9 | % | | 12 | % |
We had a concentration of cash of $11.4 million and $8.3 million at December 31, 2017 and 2016, respectively with one bank.
The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance risk in our derivative valuation at December 31, 2017 and determined there was no material risk at that time. At December 31, 2017, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below:
|
| | | |
| | December 31, 2017 |
| | (In millions) |
| Canadian Imperial Bank of Commerce | $ | 0.7 |
|
| Bank of America Merrill Lynch | (2.5 | ) |
| Bank of Montreal | (5.3 | ) |
| Total assets (liabilities) | $ | (7.1 | ) |
Property and Equipment. Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment.Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. The use of different estimates and assumptions could cause materially different carrying values of our assets.
On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. Our contract drilling segment had no impairments in either 2016 or 2017. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.
In 2015, our mid-stream segment incurred a $27.0 million, pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. Our mid-stream segment had no impairments in either 2016 or 2017.
We record an asset and a liability equal to the present value of the expected future ARO associated with our oil and gas properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense.
Capitalized Interest. During 2017, 2016, and 2015, interest of approximately $15.9 million, $15.3 million, and $21.7 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2017, 2016, or 2015. There were no additions to goodwill in 2017, 2016, or 2015. Based on our impairment test performed as of December 31, 2017, the fair value of our drilling segment exceeded its carrying value by 41%. Goodwill of $0.7 million is deductible for tax purposes.
Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
on proved oil and natural gas reserves. Directly related overhead costs of $14.8 million, $15.4 million, and $19.2 million were capitalized in 2017, 2016, and 2015, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $6.00, $6.24, and $12.30 per Boe in 2017, 2016, and 2015, respectively. The calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. Our unproved properties and wells in progress totaling $296.8 million are excluded from the DD&A calculation.
No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved.
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.
Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $114.4 million, $7.6 million, and $10.5 million in 2015, 2016, and 2017, respectively of costs being added to the total of our capitalized costs being amortized. In 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion net of tax) primarily due to the reduction of the 12-month average commodity prices during the year. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million net of tax) due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We had no non-cash ceiling test write-downs during 2017.
Our contract drilling segment provides drilling services for our exploration and production segment. Depending on the timing of the drilling services performed on our properties those services may be deemed, for financial reporting purposes, to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for these services are eliminated in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties. The contracts for these services are issued under the similar terms and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.
ARO. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.
Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms.
Insurance. We are self-insured for certain losses relating to workers’ compensation, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately 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.
Derivative Activities. All derivatives are recognized on the balance sheet and measured at fair value with the exception of normal purchase and normal sales which are expected to result in physical delivery. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
We document our risk management strategy and do not engage in derivative transactions for speculative purposes.
Limited Partnerships. Unit Petroleum Company is a general partner in 13 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.
Income Taxes. During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. The change in tax law required the Company to remeasure existing net deferred tax liabilities using the lower rate in the period of enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.
The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2017 balancing position to be approximately 3.7 Bcf on under-produced properties and approximately 3.8 Bcf on over-produced properties. We have recorded a receivable of $2.4 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.3 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.
Employee and Director Stock Based Compensation. We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants is based on the closing stock price on the date of the grants.
New Accounting Standards
Compensation—Stock Compensation. The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms of a share-based payment award. The amendment is effective for reporting periods beginning after December 15, 2017. 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
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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.
Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendment should help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendment is effective for annual periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. This amendment will not have a material impact on our financial statements.
Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are evaluating the impact this amendment will have on our financial statements and currently evaluating a plan for implementation.
Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This standard affects any entity using U.S. GAAP that either contracts with customers to transfer goods or services or enters into contracts for transferring nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which is codified in the new Topic 606, effective January 1, 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We adopted this standard January 1, 2018 using the modified retrospective approach, which resulted in a cumulative effect adjustment upon adoption for our mid-stream segment. This adjustment related to the timing of revenue on certain demand fees which was not material to the company. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment.
The application of Topic 606 will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but additional footnote disclosures are required with respect to revenue. In our oil and natural gas segment, the classification of certain costs as either a deduction from revenue or an expense will be determined based on when control of the commodity transfers to the customer, which would impact total revenue recognized, but will not affect gross profit.
Part of our review included evaluation of these issues:
Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees collectible during a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.
Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires these arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue when it is not expected to be subject to a significant reversal.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Our internal control framework did not materially change, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.
Adopted Standards
Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations must classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment requires current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.
Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendment should improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment primarily affects classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.
NOTE 3 – ACQUISITIONS AND DIVESTITURES
Acquisitions
On April 3, 2017, we closed on an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million.
As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction.
We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed.
|
| | | |
| Final Adjusted Purchase Price | |
| Total consideration given | $ | 54,332 |
|
| | |
| Final Adjusted Allocation of Purchase Price | |
| Oil and natural gas properties included in the full cost pool: | |
| Proved oil and natural gas properties | $ | 43,745 |
|
| Undeveloped oil and natural gas properties | 8,650 |
|
Total oil and natural gas properties included in the full cost pool (1) | 52,395 |
|
| Gas gathering equipment and other | 2,340 |
|
| Asset retirement obligation | (403 | ) |
| Fair value of net assets acquired | $ | 54,332 |
|
| |
(1) | We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The pro forma effects of this acquired business are immaterial to the results of operations.
For 2017, we had approximately $4.7 million in other acquisitions.
Divestitures
Oil and Natural Gas
We had non-core asset sales with proceeds, net of related expenses, of $18.6 million, $67.2 million, and $1.9 million, in 2017, 2016, and 2015, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
Contract Drilling
During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax.
During December 2016, we sold one idle 1500 HP SCR drilling rig to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $1.7 million net book value of the drilling rig, resulting in a gain of $1.6 million.
We did not have any divestitures in 2017.
NOTE 4 – EARNINGS (LOSS) PER SHARE
The following data shows the amounts used in computing earnings (loss) per share:
|
| | | | | | | | | | |
| | Income (Loss) (Numerator) | | Weighted Shares (Denominator) | | Per-Share Amount |
| | (In thousands except per share amounts) |
| For the year ended December 31, 2015: | | | | | |
| Basic loss per common share | $ | (1,037,361 | ) | | 49,110 |
| | $ | (21.12 | ) |
| Effect of dilutive stock options, restricted stock, and SARs | — |
| | — |
| | — |
|
| Diluted loss per common share | $ | (1,037,361 | ) | | 49,110 |
| | $ | (21.12 | ) |
| For the year ended December 31, 2016: | | | | | |
| Basic loss per common share | $ | (135,624 | ) | | 50,029 |
| | $ | (2.71 | ) |
| Effect of dilutive stock options, restricted stock, and SARs | — |
| | — |
| | — |
|
| Diluted loss per common share | $ | (135,624 | ) | | 50,029 |
| | $ | (2.71 | ) |
| For the year ended December 31, 2017: | | | | | |
| Basic earnings per common share | $ | 117,848 |
| | 51,113 |
| | $ | 2.31 |
|
| Effect of dilutive restricted stock | — |
| | 635 |
| | (0.03 | ) |
| Diluted earnings per common share | $ | 117,848 |
| | 51,748 |
| | $ | 2.28 |
|
Due to the net loss for the years ended December 31, 2016 and 2015, approximately 509,000 and 186,000, respectively, weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share calculation above.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Options and SARs | 87,500 |
| | 199,755 |
| | 261,270 |
|
| Average exercise price | $ | 51.34 |
| | $ | 48.79 |
| | $ | 50.34 |
|
NOTE 5 – ACCRUED LIABILITIES
Accrued liabilities consisted of the following as of December 31:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| Employee costs | $ | 19,521 |
| | $ | 15,394 |
|
| Lease operating expenses | 11,819 |
| | 10,075 |
|
| Interest payable | 6,745 |
| | 6,524 |
|
| Taxes | 3,404 |
| | 2,219 |
|
| Third-party credits | 2,240 |
| | 2,998 |
|
| Other | 4,794 |
| | 2,441 |
|
| Total accrued liabilities | $ | 48,523 |
| | $ | 39,651 |
|
NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
Long-term debt consisted of the following as of December 31:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| Credit agreement with average interest rates of 3.4% and 2.8% at December 31, 2017 and 2016, respectively | $ | 178,000 |
| | $ | 160,800 |
|
| 6.625% senior subordinated notes due 2021 | 650,000 |
| | 650,000 |
|
| Total principal amount | $ | 828,000 |
| | $ | 810,800 |
|
| Less: unamortized discount | (2,234 | ) | | (2,804 | ) |
| Less: debt issuance costs, net | (5,490 | ) | | (7,079 | ) |
| Total long-term debt | $ | 820,276 |
| | $ | 800,917 |
|
Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to time) 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 $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. With the new amendment, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.
The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves and on our cash flows from our mid-stream segment. The October 2017 redetermination did not cause any changes. 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 set forth in the credit agreement.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% 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 credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At December 31, 2017, we had $178.0 million outstanding borrowings under our credit agreement.
We can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes.
The 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; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except for our lenders.
The 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.
Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:
a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.
Beginning with the quarter ending June 30, 2019, and for each quarter ending thereafter, the credit agreement requires:
a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.
As of December 31, 2017, we were in compliance with the covenants contained in the credit agreement.
6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees 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 and providing for issuing the Notes. The Guarantors are our direct and indirect subsidiaries. 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 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 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through dividends, loans, advances or otherwise.
We may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, 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 December 31, 2017.
Other Long-Term Liabilities
Other long-term liabilities consisted of the following as of December 31:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| ARO liability | $ | 69,444 |
| | $ | 70,170 |
|
| Capital lease obligations | 15,224 |
| | 18,918 |
|
| Workers’ compensation | 13,340 |
| | 15,163 |
|
| Separation benefit plans | 6,524 |
| | 4,943 |
|
| Deferred compensation plan | 5,390 |
| | 4,578 |
|
| Gas balancing liability | 3,283 |
| | 3,789 |
|
| Other | — |
| | 410 |
|
| | 113,205 |
| | 117,971 |
|
| Less current portion | 13,002 |
| | 14,907 |
|
| Total other long-term liabilities | $ | 100,203 |
| | $ | 103,064 |
|
Estimated annual principal payments under the terms of debt and other long-term liabilities from 2018 through 2022 are $13.0 million, $45.6 million, $184.7 million, $655.9 million, and $2.1 million, respectively.
Capital Leases
During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $3.8 million is included in current portion of other long-term liabilities and the non-current portion of $11.4 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2017. These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $5.9 million and $1.2 million, respectively at December 31, 2017. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
Future payments required under the capital leases at December 31, 2017 are as follows:
|
| | | | |
| | | Amount |
| Ending December 31, | | (In thousands) |
| 2018 | | $ | 6,168 |
|
| 2019 | | 6,168 |
|
| 2020 | | 6,168 |
|
| 2021 | | 3,768 |
|
| Total future payments | | 22,272 |
|
| Less payments related to: | | |
| Maintenance | | 5,874 |
|
| Interest | | 1,174 |
|
| Present value of future minimum payments | | $ | 15,224 |
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 7 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets (AROs). Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to plugging costs associated with our oil and gas wells.
The following table shows certain information about our AROs for the periods indicated:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| ARO liability, January 1: | $ | 70,170 |
| | $ | 98,297 |
|
| Accretion of discount | 2,886 |
| | 2,779 |
|
| Liability incurred | 1,948 |
| | 584 |
|
| Liability settled | (2,694 | ) | | (1,215 | ) |
| Liability sold | (1,735 | ) | | (10,882 | ) |
Revision of estimates (1) | (1,131 | ) | | (19,393 | ) |
| ARO liability, December 31: | 69,444 |
| | 70,170 |
|
| Less current portion | 1,726 |
| | 2,906 |
|
| Total long-term ARO liability | $ | 67,718 |
| | $ | 67,264 |
|
_________________________
| |
(1) | Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments and changes in estimated timing of cash flows. |
NOTE 8 – INCOME TAXES
During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among its many provisions, the Tax Act reduces the federal corporate tax rate from 35% to 21%, effective January 1, 2018. The change in tax law required the Company to revalue its existing net deferred tax liability using the lower rate in the period of enactment resulting in the recognition of an income tax benefit of $81.3 million for the year ended December 31, 2017 related to that revaluation. As a result, the Company recognized an overall income tax benefit of $57.7 million for the year ended December 31, 2017.
Also during the fourth quarter of 2017, the SEC issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. While we were able to make reasonable estimates of the impact of the reduction in corporate rate, bonus depreciation expensing provisions, and impact of Sec 162(m) to our existing restricted stock grants, the final impact of the Tax Act may differ from these estimates, due to, among other things, changes in our interpretations and assumptions, additional guidance that may be issued by the IRS, and actions we may take.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Income tax expense (benefit) computed by applying the statutory rate | $ | 21,059 |
| | $ | (72,386 | ) | | $ | (582,508 | ) |
| State income tax expense (benefit), net of federal benefit | 1,655 |
| | (5,687 | ) | | (45,768 | ) |
Deferred tax liability revaluation (1) | (81,307 | ) | | — |
| | — |
|
| Restricted stock shortfall | 1,867 |
| | 5,465 |
| | — |
|
| Statutory depletion and other | (952 | ) | | 1,414 |
| | 1,328 |
|
| Income tax benefit | $ | (57,678 | ) | | $ | (71,194 | ) | | $ | (626,948 | ) |
__________________________
| |
(1) | In 2017, the revaluation from the Tax Act. |
For the periods indicated, the total provision for income taxes consisted of the following:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Current taxes: | | | | | |
| Federal | $ | — |
| | $ | — |
| | $ | (20,612 | ) |
| State | 5 |
| | 15 |
| | (4 | ) |
| | 5 |
| | 15 |
| | (20,616 | ) |
| Deferred taxes: | | | | | |
| Federal | (62,788 | ) | | (62,923 | ) | | (535,691 | ) |
| State | 5,105 |
| | (8,286 | ) | | (70,641 | ) |
| | (57,683 | ) | | (71,209 | ) | | (606,332 | ) |
| Total provision | $ | (57,678 | ) | | $ | (71,194 | ) | | $ | (626,948 | ) |
Deferred tax assets and liabilities are comprised of the following at December 31:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| Deferred tax assets: | | | |
| Allowance for losses and nondeductible accruals | $ | 32,242 |
| | $ | 53,967 |
|
| Net operating loss carryforward | 153,746 |
| | 190,603 |
|
| Alternative minimum tax and research and development tax credit carryforward | 5,409 |
| | 5,409 |
|
| | 191,397 |
| | 249,979 |
|
| Deferred tax liability: | | | |
| Depreciation, depletion, amortization, and impairment | (324,874 | ) | | (440,690 | ) |
| Net deferred tax liability | (133,477 | ) | | (190,711 | ) |
| Current deferred tax asset | — |
| | 25,211 |
|
| Non-current—deferred tax liability | $ | (133,477 | ) | | $ | (215,922 | ) |
Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced. At December 31, 2017, we have federal net operating loss carryforwards of approximately $587.9 million which expire from 2021 to 2037.
We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal tax examinations for years before 2016 or state income tax examinations by state taxing authorities for years before 2014. During 2014, we recognized a tax benefit relating to a research and development tax credit carryforward in conjunction with our BOSS
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
drilling rig activities. Due to the nature and subjectivity surrounding the research and development credit and historical challenges by the IRS against companies who claim the credit, it was our belief that the full amount of the credit may not have been eventually allowed by the IRS once we were no longer in an AMT tax paying position. During 2017, our U.S federal tax returns for 2013, 2014, and 2015 were examined by the IRS and no additional tax was found to be due and the research and development tax credit carryforward was allowed in full. Accordingly, we no longer have any unrecognized tax benefits as of December 31, 2017.
NOTE 9 – EMPLOYEE BENEFIT PLANS
Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. We made discretionary contributions under the plan of 155,822, 630,039, and 235,104 shares of common stock and recognized expense of $4.4 million, $4.0 million, and $6.2 million in 2017, 2016, and 2015, respectively.
We provide a salary deferral plan (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. The liability recorded under the Deferral Plan at December 31, 2017 and 2016 was $5.4 million and $4.6 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral.
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 up to a maximum of 104 weeks. To receive payments, the recipient must waive any 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 Unit 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. 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.
On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments, and the circumstances under which employees become eligible to receive benefits. On December 8, 2015, we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $2.7 million, $3.1 million, and $3.0 million in 2017, 2016, and 2015, respectively, for benefits associated with anticipated payments from these separation plans.
We have entered into key employee change of control contracts with three of our current executive officers. These severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, unless a notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive’s terms and conditions for employment (including position, work location, compensation, and benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an additional three years.
The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 10 – TRANSACTIONS WITH RELATED PARTIES
Unit Petroleum Company serves as the general partner of 13 oil and gas limited partnerships (the employee partnerships) which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. Previously, there were three non-employee partnerships, one that was formed in 1984 and two formed in 1986 (investments by third parties). Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were also dissolved.
The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed. The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one percent.
Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general partner are as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Well supervision and other fees | $ | 172 |
| | $ | 254 |
| | $ | 423 |
|
| General and administrative expense reimbursement | — |
| | 6 |
| | 18 |
|
Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by management to be reasonable.
As of December 31, 2016, John Nikkel retired as director and chairman of Unit's board and is no longer considered a related party. As of 2016, Mr. Nikkel was a 25.8% owner of Rampart Holdings, Inc. which owned 100% of Toklan Oil and Gas Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son, Robert Nikkel is Toklan's President, and he owned 20.0% of the company. In 2015, there was one well drilled for Toklan with no activity in 2016. Under its usual standard dayrate contract terms available generally to all similarly-situated customers at that time and in the same general drilling area, the Company recognized revenue from Toklan of approximately $0.5 million in 2015. During 2015, we received payments of $0.9 million with no accounts receivable balance at December 31, 2015. There were no material revenues in 2016. There were no material royalties to disclose for 2015 or 2016. Also in 2015, Toklan paid $0.5 million for the North Custer Gathering System, an inactive (since 2009) gathering system owned by our mid-stream segment. We determined that the capital required to re-activate that system would not provide adequate returns based on future cash flow potential. Toklan operates the North Custer Gathering System under its affiliate, West Thomas Field Services, LLC (West Thomas), a company in which Mr. John Nikkel held an approximate 25.0% ownership interest and in which Mr. Robert Nikkel held ownership interest of approximately 20.0%. West Thomas entered into a gas purchase agreement with our exploration and production segment in November of 2015. Payments from West Thomas under that contract amounted to $0.4 million and $0.1 million for 2016 and 2015 volumes purchased, respectively. Additionally, on March 10, 2016, Mr. Nikkel purchased in the open market $0.4 million in aggregate principal amount of our outstanding 6.625% senior subordinated notes due 2021. The notes pay interest semi-annually in cash in arrears on May 15 and November 15 of each year. For 2016, interest payments for May and November were approximately $4,800 and $13,250, respectively.
One of our directors, G. Bailey Peyton IV, also serves as Manager of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. The Company in the ordinary course of business, paid royalties or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr. Peyton, members of Mr. Peyton's
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.7 million, $0.5 million, and $0.8 million during 2017, 2016, and 2015, respectively.
Our Audit Committee and the board, in accordance with our related party transaction policy, have determined that these arrangements are in the best interest of the Company.
NOTE 11 – STOCK-BASED COMPENSATION
For restricted stock awards, we had:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Recognized stock compensation expense | $ | 13.3 |
| | $ | 9.6 |
| | $ | 15.3 |
|
| Capitalized stock compensation cost for our oil and natural gas properties | 1.8 |
| | 2.1 |
| | 3.5 |
|
| Tax benefit on stock based compensation | 5.0 |
| | 3.6 |
| | 5.8 |
|
The remaining unrecognized compensation cost related to unvested awards at December 31, 2017 is approximately $12.8 million of which $1.3 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of a year.
The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. A total of 7,230,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that can be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following:
incentive stock options under Section 422 of the Internal Revenue Code;
non-qualified stock options;
performance shares;
performance units;
restricted stock;
restricted stock units;
stock appreciation rights;
cash based awards; and
other stock-based awards.
This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in the award agreement.
Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States Treasury Strips rate using the term over which it is anticipated the grant will be exercised.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
SARs
Activity pertaining to SARs granted under the amended plan is as follows:
|
| | | | | | |
| | Number of Shares | | Weighted Average Price |
| Outstanding at January 1, 2015 | 131,770 |
| | $ | 46.60 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | — |
| | — |
|
| Outstanding at December 31, 2015 | 131,770 |
| | 46.60 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (40,515 | ) | | 51.76 |
|
| Outstanding at December 31, 2016 | 91,255 |
| | 44.31 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (91,255 | ) | | 44.31 |
|
| Outstanding at December 31, 2017 | — |
| | $ | — |
|
There were no SARs granted or vested during 2017, 2016, or 2015. There were no SARs exercised in 2017. The SARs expired after 10 years from the date of the grant, and there were no outstanding shares at December 31, 2017.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Restricted Stock
Activity pertaining to restricted stock awards granted under the amended plan is as follows:
|
| | | | | | | | | | | | |
| Employees | Number of Time Vested Shares | | Number of Performance Vested Shares | | Total Number of Shares | | Weighted Average Price |
| Nonvested at January 1, 2015 | 724,766 |
| | 175,520 |
| | 900,286 |
| | $ | 50.81 |
|
| Granted | 576,361 |
| | 148,081 |
| | 724,442 |
| | 34.06 |
|
| Vested | (343,657 | ) | | (39,245 | ) | | (382,902 | ) | | 49.69 |
|
| Forfeited | (20,808 | ) | | (7,196 | ) | | (28,004 | ) | | 45.33 |
|
| Nonvested at December 31, 2015 | 936,662 |
| | 277,160 |
| | 1,213,822 |
| | 41.29 |
|
| Granted | 494,078 |
| | 152,373 |
| | 646,451 |
| | 5.62 |
|
| Vested | (425,195 | ) | | — |
| | (425,195 | ) | | 43.47 |
|
| Forfeited | (75,808 | ) | | (57,405 | ) | | (133,213 | ) | | 36.87 |
|
| Nonvested at December 31, 2016 | 929,737 |
| | 372,128 |
| | 1,301,865 |
| | 23.32 |
|
| Granted | 485,799 |
| | 173,373 |
| | 659,172 |
| | 26.07 |
|
| Vested | (455,570 | ) | | (62,119 | ) | | (517,689 | ) | | 29.87 |
|
| Forfeited | (44,408 | ) | | (34,953 | ) | | (79,361 | ) | | 38.87 |
|
| Nonvested at December 31, 2017 | 915,558 |
| | 448,429 |
| | 1,363,987 |
| | $ | 21.25 |
|
|
| | | | | | |
| Non-Employee Directors | Number of Shares | | Weighted Average Price |
| Nonvested at January 1, 2015 | 35,136 |
| | $ | 50.08 |
|
| Granted | 25,848 |
| | 34.04 |
|
| Vested | (18,920 | ) | | 46.51 |
|
| Forfeited | — |
| | — |
|
| Nonvested at December 31, 2015 | 42,064 |
| | $ | 41.83 |
|
| Granted | 90,000 |
| | 12.02 |
|
| Vested | (20,248 | ) | | 43.46 |
|
| Forfeited | — |
| | — |
|
| Nonvested at December 31, 2016 | 111,816 |
| | $ | 17.21 |
|
| Granted | 49,104 |
| | 17.92 |
|
| Vested | (43,206 | ) | | 21.24 |
|
| Forfeited | — |
| | — |
|
| Nonvested at December 31, 2017 | 117,714 |
| | $ | 16.03 |
|
The time vested restricted stock awards granted are being recognized over a three year vesting period. During 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at December 31, 2017, the participants are estimated to receive 82% of the 2017, 159% of the 2016, and 100% of the 2015 performance based shares. The CFTA performance measurement at December 31, 2017 for the one-third vesting in 2018 was assessed to vest at 131%. The CFTA performance measurement for future years was assessed to vest at target or 100%.
The fair value of the restricted stock granted in 2017, 2016, and 2015 at the grant date was $17.4 million, $4.5 million, and $24.5 million, respectively. The aggregate intrinsic value of the 560,895 shares of restricted stock that vested in 2017 on
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
their vesting date was $12.3 million. The aggregate intrinsic value of the 1,481,701 shares of restricted stock outstanding subject to vesting at December 31, 2017 was $32.6 million with a weighted average remaining life of 0.9 of a year.
Employee Stock Option Plan
The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In 2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further awards were made under this plan. During 2015, the remaining options expired.
Activity pertaining to the Stock Option Plan is as follows:
|
| | | | | | |
| | Number of Shares | | Weighted Average Exercise Price |
| Outstanding at January 1, 2015 | 9,500 |
| | $ | 37.69 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (9,500 | ) | | 37.69 |
|
| Outstanding at December 31, 2015 | — |
| | — |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | — |
| | — |
|
| Outstanding at December 31, 2016 | — |
| | — |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | — |
| | — |
|
| Outstanding at December 31, 2017 | — |
| | $ | — |
|
As of December 31, 2015, there were no further options outstanding or exercisable in this plan.
Non-Employee Directors' Stock Option Plan
Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The option price for each stock option was the fair market value of the common stock on the date the stock options were granted. The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six months of its term except in case of death. On May 2, 2012, our stockholders approved the amended plan which succeeds this plan, the remaining available shares were transferred over to the new plan and no further awards were made under the non-employee director option plan.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Activity pertaining to the Directors’ Plan is as follows:
|
| | | | | | |
| | Number of Shares | | Weighted Average Exercise Price |
| Outstanding at January 1, 2015 | 150,500 |
| | $ | 54.18 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (21,000 | ) | | 54.35 |
|
| Outstanding at December 31, 2015 | 129,500 |
| | 54.15 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (21,000 | ) | | 62.40 |
|
| Outstanding at December 31, 2016 | 108,500 |
| | 52.56 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (21,000 | ) | | 57.63 |
|
| Outstanding at December 31, 2017 | 87,500 |
| | $ | 51.34 |
|
There were no options exercised in 2017.
|
| | | | | | | | |
| | Outstanding and Exercisable
Options at December 31, 2017 |
| Weighted Average Exercise Price | Number of Shares | | Weighted Average Remaining
Contractual Life | | Weighted Average
Exercise Price |
| $31.30 - $41.21 | 38,500 |
| | 1.9 years | | $ | 37.58 |
|
| $53.81 - $73.26 | 49,000 |
| | 2.1 years | | $ | 62.15 |
|
There was no aggregate intrinsic value of the shares outstanding subject to options at December 31, 2017. The remaining weighted average remaining contractual term is 2.0 years.
NOTE 12 – DERIVATIVES
Commodity Derivatives
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of December 31, 2017, our derivative transactions consisted of the following types of hedges:
Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Basis Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis swaps to hedge the price risk between NYMEX and its physical delivery points.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put) and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price.
We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative purposes. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
At December 31, 2017, the following non-designated hedges were outstanding:
|
| | | | | | | | |
Term | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps
| | Contracted Market |
Jan’18 – Dec’18 | | Natural gas – swap | | 20,000 MMBtu/day | | $3.013 | | IF – NYMEX (HH) |
Apr'18 – Oct'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.990 | | IF – NYMEX (HH) |
Jan’18 – Mar'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.208) | | IF – NYMEX (HH) |
Nov’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.208) | | IF – NYMEX (HH) |
Jan’18 – Mar'18 | | Natural gas – three-way collar | | 60,000 MMBtu/day | | $3.29 - $2.63 - $4.07 | | IF – NYMEX (HH) |
Apr’18 – Dec'18 | | Natural gas – three-way collar | | 20,000 MMBtu/day | | $3.00 - $2.50 - $3.51 | | IF – NYMEX (HH) |
Jan’18 – Dec'18 | | Crude oil – swap | | 3,000 Bbl/day | | $51.36 | | WTI – NYMEX |
Jan’18 – Mar'18 | | Crude oil – collar | | 500 Bbl/day | | $55.00 - $59.50 | | WTI – NYMEX |
Jan’18 – Dec'18 | | Crude oil – three-way collar | | 2,000 Bbl/day | | $47.50 - $37.50 - $56.08 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids (Propane) – swap | | 1,000 Bbl/day | | $31.16 | | MONT BELVIEU |
After December 31, 2017, the following non-designated hedges were entered into:
|
| | | | | | | | |
Term | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps | | Contracted Market |
Apr’18 – Sep'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.925 | | IF – NYMEX (HH) |
Apr’18 – Sep'18 | | Natural gas – collar | | 30,000 MMBtu/day | | $2.67 - $2.97 | | IF – NYMEX (HH) |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.678) | | PEPL |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.568) | | NGPL MIDCON |
Apr’18 – Oct'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.190) | | NGPL TEXOK |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.728) | | PEPL |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.625) | | NGPL MIDCON |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.273) | | NGPL TEXOK |
Jan'20 – Dec'20 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.280) | | NGPL TEXOK |
Apr'18 – Dec'18 | | Crude oil – swap | | 1,000 Bbl/day | | $60.00 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids – swap | | 500 Bbl/day | | $34.10 | | MONT BELVIEU |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31:
|
| | | | | | | | | | |
| | | | | Derivative Assets Fair Value |
| | | Balance Sheet Location | | 2017 | | 2016 |
| | | | | (In thousands) |
| Commodity derivatives: | | | | | | |
| Current | | Current derivative assets | | $ | 721 |
| | $ | — |
|
| Long-term | | Non-current derivative assets | | — |
| | 377 |
|
| Total derivative assets | | | | $ | 721 |
| | $ | 377 |
|
|
| | | | | | | | | | |
| | | | | Derivative Liabilities Fair Value |
| | | Balance Sheet Location | | 2017 | | 2016 |
| | | | | (In thousands) |
| Commodity derivatives: | | | | | | |
| Current | | Current derivative liabilities | | $ | 7,763 |
| | $ | 21,564 |
|
| Long-term | | Non-current derivative liabilities | | — |
| | 415 |
|
| Total derivative liabilities | | | | $ | 7,763 |
| | $ | 21,979 |
|
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Consolidated Balance Sheets.
Effect of derivative instruments on the Consolidated Statements of Operations for the year ended December 31:
|
| | | | | | | | | | |
| Derivatives Instruments | | Location of Gain or (Loss) Recognized in Income on Derivative | | Amount of Gain or (Loss) Recognized in Income on Derivative |
| | | 2017 | | 2016 |
| | | | | (In thousands) |
| Commodity derivatives | | Gain (loss) on derivatives (1) | | $ | 14,732 |
| | $ | (22,813 | ) |
| Total | | | | $ | 14,732 |
| | $ | (22,813 | ) |
_________________________
| |
(1)
| Amount settled during the period are gains of $173 and $9,658, respectively. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 13 – FAIR VALUE MEASUREMENTS
The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:
|
| | | | | | | | | | | | | | | | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Estimated Fair Value |
| | | (In thousands) |
| Equity Securities: | | |
| December 31, 2017 | | $ | 830 |
| | $ | 102 |
| | $ | — |
| | $ | 932 |
|
| December 31, 2016 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. These securities would be classified as Level 2.
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:
Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.
Level 2—significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.
Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal data.
The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.
The following tables set forth our recurring fair value measurements:
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Level 2 | | Level 3 | | Effect of Netting | | Total |
| | (In thousands) |
| Financial assets (liabilities): | | | | | | | |
| Commodity derivatives: | | | | | | | |
| Assets | $ | 2,137 |
| | $ | 3,344 |
| | $ | (4,760 | ) | | $ | 721 |
|
| Liabilities | (8,973 | ) | | (3,550 | ) | | 4,760 |
| | (7,763 | ) |
| | $ | (6,836 | ) | | $ | (206 | ) | | $ | — |
| | $ | (7,042 | ) |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Level 2 | | Level 3 | | Effect of Netting | | Total |
| | (In thousands) |
| Financial assets (liabilities): | | | | | | | |
| Commodity derivatives: | | | | | | | |
| Assets | $ | 878 |
| | $ | 43 |
| | $ | (544 | ) | | $ | 377 |
|
| Liabilities | (15,358 | ) | | (7,165 | ) | | 544 |
| | (21,979 | ) |
| | $ | (14,480 | ) | | $ | (7,122 | ) | | $ | — |
| | $ | (21,602 | ) |
All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of December 31, 2017.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).
Level 2 Fair Value Measurements
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.
Level 3 Fair Value Measurements
Commodity Derivatives. The fair values of our natural gas and crude oil collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.
The following tables are reconciliations of our level 3 fair value measurements:
|
| | | | | | | |
| | Net Derivatives |
| | For the Year Ended, |
| | December 31, 2017 | | December 31, 2016 |
| | (In thousands) |
| Beginning of period | $ | (7,122 | ) | | $ | 9,094 |
|
| Total gains or losses: | | | |
Included in earnings (1) | 7,791 |
| | (9,042 | ) |
| Settlements | (875 | ) | | (7,174 | ) |
| End of period | $ | (206 | ) | | $ | (7,122 | ) |
| Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period | $ | 6,916 |
| | $ | (16,216 | ) |
_________________________
| |
(1) | Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2017:
|
| | | | | | |
Commodity (1) | Fair Value | Valuation Technique | Unobservable Input | Range |
| | (In thousands) | | | |
| Oil collars | $ | (77 | ) | Discounted cash flow | Forward commodity price curve | $0.00 - $2.48 |
| Oil three-way collar | (3,473 | ) | Discounted cash flow | Forward commodity price curve | $0.00 - $5.96 |
| Natural gas three-way collar | 3,344 |
| Discounted cash flow | Forward commodity price curve | $0.00 - $0.68 |
_________________________
| |
(1) | The commodity contracts detailed in this category include non-exchange-traded crude oil collars and crude and natural gas three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period. |
Based on our valuation at December 31, 2017, we determined that the non-performance risk with regard to our counterparties was immaterial.
Fair Value of Other Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
At December 31, 2017, the carrying values on the consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature.
Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement at December 31, 2017 approximates its fair value. This debt would be classified as Level 2.
The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Consolidated Balance Sheets at December 31, 2017 and December 31, 2016 were $642.3 million and $640.1 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2017 and December 31, 2016 were $649.7 million and $649.9 million, respectively. These Notes would be classified as Level 2.
Fair Value of Non-Financial Instruments
The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented in Note 7 – Asset Retirement Obligations.
Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2016 and 2015, we recorded non-cash impairment charges discussed further in Note 2 – Summary of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as Level 3.
NOTE 14 – COMMITMENTS AND CONTINGENCIES
We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.Future minimum rental payments under the terms of the leases are approximately $2.7 million, $0.6 million, $0.4 million, and $0.1 million in 2018 through 2021, respectively. Total rent expense incurred was $8.8 million, $11.1 million, and $12.9 million in 2017, 2016, and 2015, respectively.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. Future capital lease payments under the terms are approximately $6.2 million each year through 2020 and approximately $3.8 million in 2021. Total maintenance and interest remaining related to these leases are $5.9 million and $1.2 million, respectively at December 31, 2017. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
The employee oil and gas limited partnerships 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. These repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of approximately $2,900, $5,000, $118,000 in 2017, 2016, and 2015, respectively.
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.
We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well.
For 2018, we have committed to purchase approximately $3.9 million of new drilling rig components.
We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matter, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our results of operations, financial position, or cash flows.
NOTE 15 – EQUITY
At-the-Market (ATM) Common Stock Program
On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms and conditions of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).
We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
As of December 31, 2017, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the fourth quarter of 2017.
Accumulated Other Comprehensive Income
Components of accumulated other comprehensive income were as follows for the years ended December 31:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Unrealized appreciation on securities, before tax | $ | 102 |
| | $ | — |
| | $ | — |
|
| Tax expense | (39 | ) | | — |
| | — |
|
| Unrealized appreciation on securities, net of tax | $ | 63 |
| | $ | — |
| | $ | — |
|
Changes in accumulated other comprehensive income by component, net of tax, for the years ended December 31 are as follows:
|
| | | | | | | | | | | |
| | Net Gains on Equity Securities |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Balance at January 1: | $ | — |
| | $ | — |
| | $ | — |
|
| Unrealized appreciation before reclassifications | 63 |
| | — |
| | — |
|
| Amounts reclassified from accumulated other comprehensive income | — |
| | — |
| | — |
|
| Net current-period other comprehensive income | 63 |
| | — |
| | — |
|
| Balance at December 31: | $ | 63 |
| | $ | — |
| | $ | — |
|
NOTE 16 – INDUSTRY SEGMENT INFORMATION
We have three main business segments offering different products and services:
Oil and natural gas,
Contract drilling, and
Mid-stream
The oil and natural gas segment is engaged in the development, acquisition, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs.
We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. Our oil and natural gas production outside the United States is not significant.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table provides certain information about the operations of each of our segments:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2017 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-stream | | Other | | Eliminations | | Total Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | | | |
| Oil and natural gas | | $ | 357,744 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 357,744 |
|
| Contract drilling | | — |
| | 188,172 |
| | — |
| | — |
| | (13,452 | ) | | 174,720 |
|
| Gas gathering and processing | | — |
| | — |
| | 277,049 |
| | — |
| | (69,873 | ) | | 207,176 |
|
| Total revenues | | 357,744 |
| | 188,172 |
| | 277,049 |
| | — |
| | (83,325 | ) | | 739,640 |
|
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 135,532 |
| | — |
| | — |
| | — |
| | (4,743 | ) | | 130,789 |
|
| Contract drilling | | — |
| | 134,432 |
| | — |
| | — |
| | (11,832 | ) | | 122,600 |
|
| Gas gathering and processing | | — |
| | — |
| | 220,613 |
| | — |
| | (65,130 | ) | | 155,483 |
|
| Total operating costs | | 135,532 |
| | 134,432 |
| | 220,613 |
| | — |
| | (81,705 | ) | | 408,872 |
|
| Depreciation, depletion, and amortization | | 101,911 |
| | 56,370 |
| | 43,499 |
| | 7,477 |
| | — |
| | 209,257 |
|
| Total expenses | | 237,443 |
| | 190,802 |
| | 264,112 |
| | 7,477 |
| | (81,705 | ) | | 618,129 |
|
Total operating income (loss) (1) | | 120,301 |
| | (2,630 | ) | | 12,937 |
| | (7,477 | ) | | (1,620 | ) | | |
| General and administrative expense | | — |
| | — |
| | — |
| | (38,087 | ) | | — |
| | (38,087 | ) |
| Gain (loss) on disposition of assets | | 228 |
| | (776 | ) | | 25 |
| | 850 |
| | — |
| | 327 |
|
| Gain on derivatives | | — |
| | — |
| | — |
| | 14,732 |
| | — |
| | 14,732 |
|
| Interest expense, net | | — |
| | — |
| | — |
| | (38,334 | ) | | — |
| | (38,334 | ) |
| Other | | — |
| | — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Income (loss) before income taxes | | $ | 120,529 |
| | $ | (3,406 | ) | | $ | 12,962 |
| | $ | (68,295 | ) | | $ | (1,620 | ) | | $ | 60,170 |
|
| | | | | | | | | | | | | |
| Identifiable assets: | | | | | | | | | | | | |
Oil and natural gas (2) | | $ | 1,127,900 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,127,900 |
|
| Contract drilling | | — |
| | 933,063 |
| | — |
| | — |
| | — |
| | 933,063 |
|
| Gas gathering and processing | | — |
| | — |
| | 438,571 |
| | — |
| | — |
| | 438,571 |
|
Total identifiable assets (3) | | 1,127,900 |
| | 933,063 |
| | 438,571 |
| | — |
| | — |
| | 2,499,534 |
|
| Corporate land and building | | — |
| | — |
| | — |
| | 56,854 |
| | — |
| | 56,854 |
|
Other corporate assets (4) | | — |
| | — |
| | — |
| | 25,064 |
| | — |
| | 25,064 |
|
| Total assets | | $ | 1,127,900 |
| | $ | 933,063 |
| | $ | 438,571 |
| | $ | 81,918 |
| | $ | — |
| | $ | 2,581,452 |
|
| | | | | | | | | | | | | |
| Capital expenditures: | | $ | 270,443 |
| | $ | 36,148 |
| | $ | 22,168 |
| | $ | 3,521 |
| | $ | — |
| | $ | 332,280 |
|
_______________________
| |
(1) | Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income, or income taxes. |
| |
(2) | Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. |
| |
(3) | Identifiable assets are those used in Unit’s operations in each industry segment. |
| |
(4) | Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2016 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-stream | | Other | | Eliminations | | Total Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | | | |
| Oil and natural gas | | $ | 294,221 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 294,221 |
|
| Contract drilling | | — |
| | 122,086 |
| | — |
| | — |
| | — |
| | 122,086 |
|
| Gas gathering and processing | | — |
| | — |
| | 237,785 |
| | — |
| | (51,915 | ) | | 185,870 |
|
| Total revenues | | 294,221 |
| | 122,086 |
| | 237,785 |
| | — |
| | (51,915 | ) | | 602,177 |
|
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 126,739 |
| | — |
| | — |
| | — |
| | (6,555 | ) | | 120,184 |
|
| Contract drilling | | — |
| | 88,154 |
| | — |
| | — |
| | — |
| | 88,154 |
|
| Gas gathering and processing | | — |
| | — |
| | 182,969 |
| | — |
| | (45,360 | ) | | 137,609 |
|
| Total operating costs | | 126,739 |
| | 88,154 |
| | 182,969 |
| | — |
| | (51,915 | ) | | 345,947 |
|
| Depreciation, depletion and amortization | | 113,811 |
| | 46,992 |
| | 45,715 |
| | 1,835 |
| | — |
| | 208,353 |
|
Impairments (1) | | 161,563 |
| | — |
| | — |
| | — |
| | — |
| | 161,563 |
|
| Total expenses | | 402,113 |
| | 135,146 |
| | 228,684 |
| | 1,835 |
| | (51,915 | ) | | 715,863 |
|
Total operating income (loss) (2) | | (107,892 | ) | | (13,060 | ) | | 9,101 |
| | (1,835 | ) | | — |
| | |
| General and administrative expense | | — |
| | — |
| | — |
| | (33,337 | ) | | — |
| | (33,337 | ) |
| Gain (loss) on disposition of assets | | (324 | ) | | 3,184 |
| | (302 | ) | | (18 | ) | | — |
| | 2,540 |
|
| Loss on derivatives | | — |
| | — |
| | — |
| | (22,813 | ) | | — |
| | (22,813 | ) |
| Interest expense, net | | — |
| | — |
| | — |
| | (39,829 | ) | | — |
| | (39,829 | ) |
| Other | | — |
| | — |
| | — |
| | 307 |
| | — |
| | 307 |
|
| Income (loss) before income taxes | | $ | (108,216 | ) | | $ | (9,876 | ) | | $ | 8,799 |
| | $ | (97,525 | ) | | $ | — |
| | $ | (206,818 | ) |
| | | | | | | | | | | | | |
| Identifiable assets: | | | | | | | | | | | | |
Oil and natural gas (3) | | $ | 965,159 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 965,159 |
|
| Contract drilling | | — |
| | 941,676 |
| | — |
| | — |
| | — |
| | 941,676 |
|
| Gas gathering and processing | | — |
| | — |
| | 461,600 |
| | — |
| | — |
| | 461,600 |
|
Total identifiable assets (4) | | 965,159 |
| | 941,676 |
| | 461,600 |
| | — |
| | — |
| | 2,368,435 |
|
| Corporate land and building | | — |
| | — |
| | — |
| | 58,188 |
| | — |
| | 58,188 |
|
Other corporate assets (5) | | — |
| | — |
| | — |
| | 52,680 |
| | — |
| | 52,680 |
|
| Total assets | | $ | 965,159 |
| | $ | 941,676 |
| | $ | 461,600 |
| | $ | 110,868 |
| | $ | — |
| | $ | 2,479,303 |
|
| | | | | | | | | | | | | |
| Capital expenditures: | | $ | 89,562 |
| | $ | 19,134 |
| | $ | 16,796 |
| | $ | 16,663 |
| | $ | — |
| | $ | 142,155 |
|
_______________________
| |
(1) | We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax). |
| |
(2) | Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes. |
| |
(3) | Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. |
| |
(4) | Identifiable assets are those used in Unit’s operations in each industry segment. |
| |
(5) | Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2015 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-stream | | Other | | Eliminations | | Total Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | | | |
| Oil and natural gas | | $ | 385,774 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 385,774 |
|
| Contract drilling | | — |
| | 287,767 |
| | — |
| | — |
| | (22,099 | ) | | 265,668 |
|
| Gas gathering and processing | | — |
| | — |
| | 268,012 |
| | — |
| | (65,223 | ) | | 202,789 |
|
| Total revenues | | 385,774 |
| | 287,767 |
| | 268,012 |
| | — |
| | (87,322 | ) | | 854,231 |
|
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 170,831 |
| | — |
| | — |
| | — |
| | (4,785 | ) | | 166,046 |
|
| Contract drilling | | — |
| | 174,757 |
| | — |
| | — |
| | (18,349 | ) | | 156,408 |
|
| Gas gathering and processing | | — |
| | — |
| | 221,994 |
| | — |
| | (60,438 | ) | | 161,556 |
|
| Total operating costs | | 170,831 |
| | 174,757 |
| | 221,994 |
| | — |
| | (83,572 | ) | | 484,010 |
|
| Depreciation, depletion and amortization | | 251,944 |
| | 56,135 |
| | 43,676 |
| | 987 |
| | — |
| | 352,742 |
|
Impairments (1) | | 1,599,348 |
| | 8,314 |
| | 26,966 |
| | — |
| | — |
| | 1,634,628 |
|
| Total expenses | | 2,022,123 |
| | 239,206 |
| | 292,636 |
| | 987 |
| | (83,572 | ) | | 2,471,380 |
|
Total operating income (loss) (2) | | (1,636,349 | ) | | 48,561 |
| | (24,624 | ) | | (987 | ) | | (3,750 | ) | | |
| General and administrative expense | | — |
| | — |
| | — |
| | (34,358 | ) | | — |
| | (34,358 | ) |
| Gain (loss) on disposition of assets | | (147 | ) | | (7,516 | ) | | 465 |
| | (31 | ) | | — |
| | (7,229 | ) |
| Gain on derivatives | | — |
| | — |
| | — |
| | 26,345 |
| | — |
| | 26,345 |
|
| Interest expense, net | | — |
| | — |
| | — |
| | (31,963 | ) | | — |
| | (31,963 | ) |
| Other | | — |
| | — |
| | — |
| | 45 |
| | — |
| | 45 |
|
| Income (loss) before income taxes | | $ | (1,636,496 | ) | | $ | 41,045 |
| | $ | (24,159 | ) | | $ | (40,949 | ) | | $ | (3,750 | ) | | $ | (1,664,309 | ) |
| | | | | | | | | | | | | |
| Identifiable assets: | | | | | | | | | | | | |
Oil and natural gas (3) | | $ | 1,218,036 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,218,036 |
|
| Contract drilling | | — |
| | 993,015 |
| | — |
| | — |
| | — |
| | 993,015 |
|
| Gas gathering and processing | | — |
| | — |
| | 478,661 |
| | — |
| | — |
| | 478,661 |
|
Total identifiable assets (4) | | 1,218,036 |
| | 993,015 |
| | 478,661 |
| | — |
| | — |
| | 2,689,712 |
|
| Corporate land and building | | — |
| | — |
| | — |
| | 49,890 |
| | — |
| | 49,890 |
|
Other corporate assets (5) | | — |
| | — |
| | — |
| | 60,240 |
| |
|
| | 60,240 |
|
| Total assets | | $ | 1,218,036 |
| | $ | 993,015 |
| | $ | 478,661 |
| | $ | 110,130 |
| | $ | — |
| | $ | 2,799,842 |
|
| | | | | | | | | | | | | |
| Capital expenditures: | | $ | 267,944 |
| | $ | 84,802 |
| | $ | 63,476 |
| | $ | 38,065 |
| | $ | — |
| | $ | 454,287 |
|
_______________________
| |
(1) | We incurred non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). Impairment for contract drilling equipment includes an $8.3 million pre-tax write-down for 30 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek. |
| |
(2) | Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes. |
| |
(3) | Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. |
| |
(4) | Identifiable assets are those used in Unit’s operations in each industry segment. |
| |
(5) | Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 17 – SELECTED QUARTERLY FINANCIAL INFORMATION
Summarized unaudited quarterly financial information is as follows:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | |
| | March 31 | | June 30 | | September 30 | | December 31 | |
| | (In thousands except per share amounts) | |
| 2016 | | | | | | | | |
| Revenues | $ | 136,184 |
| | $ | 138,305 |
| | $ | 153,408 |
| | $ | 174,280 |
| |
Gross income (loss) (1) | $ | (49,745 | ) | | $ | (73,830 | ) | | $ | (26,893 | ) | | $ | 36,782 |
| |
| Net income (loss) | $ | (41,149 | ) | | $ | (72,136 | ) | | $ | (24,022 | ) | | $ | 1,683 |
| |
| Net income (loss) per common share: | | | | | | | | |
Basic (2) | $ | (0.83 | ) | | $ | (1.44 | ) | | $ | (0.48 | ) | | $ | 0.03 |
| |
Diluted (2) | $ | (0.83 | ) | | $ | (1.44 | ) | | $ | (0.48 | ) | | $ | 0.03 |
| |
| 2017 | | | | | | | | |
| Revenues | $ | 175,724 |
| | $ | 170,581 |
| | $ | 188,488 |
| | $ | 204,847 |
| |
Gross income (1) | $ | 32,657 |
| | $ | 24,462 |
| | $ | 27,181 |
| | $ | 37,211 |
| |
| Net income | $ | 15,929 |
| | $ | 9,059 |
| | $ | 3,705 |
| | $ | 89,155 |
| |
| Net income per common share: | | | | | | | | |
| Basic | $ | 0.32 |
| | $ | 0.18 |
| | $ | 0.07 |
| | $ | 1.74 |
| |
Diluted (2) | $ | 0.31 |
| | $ | 0.17 |
| | $ | 0.07 |
| | $ | 1.71 |
| |
_________________________
| |
(1) | Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on derivatives, income taxes, and other income (loss). |
| |
(2) | The earnings (loss) per share for the year's four quarters does not equal annual income (loss) per share. |
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
Our oil and gas operations are substantially located in the United States. The capitalized costs at year end and costs incurred during the year were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Capitalized costs: | | | | | |
| Proved properties | $ | 5,712,813 |
| | $ | 5,446,305 |
| | $ | 5,401,618 |
|
| Unproved properties | 296,764 |
| | 314,867 |
| | 337,099 |
|
| | 6,009,577 |
| | 5,761,172 |
| | 5,738,717 |
|
| Accumulated depreciation, depletion, amortization, and impairment | (4,996,696 | ) | | (4,900,304 | ) | | (4,631,404 | ) |
| Net capitalized costs | $ | 1,012,881 |
| | $ | 860,868 |
| | $ | 1,107,313 |
|
| Cost incurred: | | | | | |
| Unproved properties acquired | $ | 47,029 |
| | $ | 21,675 |
| | $ | 41,777 |
|
| Proved properties acquired | 47,638 |
| | 564 |
| | 179 |
|
| Exploration | 14,811 |
| | 17,325 |
| | 19,222 |
|
| Development | 160,941 |
| | 80,582 |
| | 208,845 |
|
| Asset retirement obligation | (3,613 | ) | | (30,906 | ) | | (5,693 | ) |
| Total costs incurred | $ | 266,806 |
| | $ | 89,240 |
| | $ | 264,330 |
|
The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2017, by the year in which such costs were incurred:
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 and Prior | | Total |
| | (In thousands) |
| Unproved properties acquired and wells in progress | $ | 50,447 |
| | $ | 22,092 |
| | $ | 40,254 |
| | $ | 183,971 |
| | $ | 296,764 |
|
Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.
The results of operations for producing activities are as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Revenues | $ | 347,285 |
| | $ | 282,742 |
| | $ | 371,335 |
|
| Production costs | (107,332 | ) | | (108,822 | ) | | (152,560 | ) |
| Depreciation, depletion, amortization, and impairment | (96,392 | ) | | (268,901 | ) | | (1,844,726 | ) |
| | 143,561 |
| | (94,981 | ) | | (1,625,951 | ) |
| Income tax (expense) benefit | (56,376 | ) | | 32,696 |
| | 612,496 |
|
| Results of operations for producing activities (excluding corporate overhead and financing costs) | $ | 87,185 |
| | $ | (62,285 | ) | | $ | (1,013,455 | ) |
Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:
|
| | | | | | | | | | | |
| | Oil Bbls | | NGLs Bbls | | Natural Gas Mcf | | Total MBoe |
| | (In thousands) |
| 2015 | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | |
| Beginning of year | 22,667 |
| | 48,529 |
| | 646,961 |
| | 179,023 |
|
Revision of previous estimates (1) | (3,954 | ) | | (9,367 | ) | | (139,514 | ) | | (36,573 | ) |
| Extensions and discoveries | 1,208 |
| | 1,948 |
| | 20,974 |
| | 6,651 |
|
| Infill reserves in existing proved fields | 670 |
| | 1,861 |
| | 22,641 |
| | 6,304 |
|
| Purchases of minerals in place | — |
| | — |
| | — |
| | — |
|
| Production | (3,783 | ) | | (5,274 | ) | | (65,546 | ) | | (19,981 | ) |
| Sales | (73 | ) | | (10 | ) | | (648 | ) | | (191 | ) |
| End of year | 16,735 |
| | 37,687 |
| | 484,868 |
| | 135,233 |
|
| Proved developed reserves: | | | | | | | |
| Beginning of year | 17,448 |
| | 35,850 |
| | 500,950 |
| | 136,790 |
|
| End of year | 14,679 |
| | 31,218 |
| | 416,395 |
| | 115,296 |
|
| Proved undeveloped reserves: | | | | | | | |
| Beginning of year | 5,219 |
| | 12,679 |
| | 146,011 |
| | 42,233 |
|
| End of year | 2,056 |
| | 6,469 |
| | 68,473 |
| | 19,937 |
|
| 2016 | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | |
| Beginning of year | 16,735 |
| | 37,687 |
| | 484,868 |
| | 135,233 |
|
Revision of previous estimates (1) | (549 | ) | | (2,473 | ) | | (31,670 | ) | | (8,300 | ) |
| Extensions and discoveries | 1,816 |
| | 1,588 |
| | 13,720 |
| | 5,690 |
|
| Infill reserves in existing proved fields | 663 |
| | 2,724 |
| | 24,704 |
| | 7,504 |
|
| Purchases of minerals in place | 114 |
| | 43 |
| | 630 |
| | 262 |
|
| Production | (2,974 | ) | | (5,014 | ) | | (55,735 | ) | | (17,277 | ) |
| Sales | (109 | ) | | (73 | ) | | (30,938 | ) | | (5,338 | ) |
| End of year | 15,696 |
| | 34,482 |
| | 405,579 |
| | 117,774 |
|
| Proved developed reserves: | | | | | | | |
| Beginning of year | 14,679 |
| | 31,218 |
| | 416,395 |
| | 115,296 |
|
| End of year | 12,724 |
| | 28,502 |
| | 347,121 |
| | 99,079 |
|
| Proved undeveloped reserves: | | | | | | | |
| Beginning of year | 2,056 |
| | 6,469 |
| | 68,473 |
| | 19,937 |
|
| End of year | 2,972 |
| | 5,980 |
| | 58,458 |
| | 18,695 |
|
| 2017 | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | |
| Beginning of year | 15,696 |
| | 34,482 |
| | 405,579 |
| | 117,774 |
|
| Revision of previous estimates | 730 |
| | 4,325 |
| | 38,330 |
| | 11,444 |
|
| Extensions and discoveries | 2,235 |
| | 4,520 |
| | 49,321 |
| | 14,975 |
|
| Infill reserves in existing proved fields | 1,632 |
| | 5,779 |
| | 52,270 |
| | 16,123 |
|
| Purchases of minerals in place | 2,019 |
| | 1,197 |
| | 15,313 |
| | 5,768 |
|
| Production | (2,715 | ) | | (4,737 | ) | | (51,260 | ) | | (15,996 | ) |
| Sales | (84 | ) | | (80 | ) | | (903 | ) | | (314 | ) |
| End of year | 19,513 |
| | 45,486 |
| | 508,650 |
| | 149,774 |
|
| Proved developed reserves: | | | | | | | |
| Beginning of year | 12,724 |
| | 28,502 |
| | 347,121 |
| | 99,079 |
|
| End of year | 14,862 |
| | 33,358 |
| | 388,446 |
| | 112,961 |
|
| Proved undeveloped reserves: | | | | | | | |
| Beginning of year | 2,972 |
| | 5,980 |
| | 58,458 |
| | 18,695 |
|
| End of year | 4,651 |
| | 12,128 |
| | 120,204 |
| | 36,813 |
|
_________________________ | |
(1) | Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices. |
Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.
The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Future cash flows | $ | 3,347,396 |
| | $ | 2,030,925 |
| | $ | 2,475,898 |
|
| Future production costs | (1,308,244 | ) | | (861,625 | ) | | (1,017,777 | ) |
| Future development costs | (369,560 | ) | | (173,446 | ) | | (228,445 | ) |
| Future income tax expenses | (234,152 | ) | | (141,752 | ) | | (230,544 | ) |
| Future net cash flows | 1,435,440 |
| | 854,102 |
| | 999,132 |
|
| 10% annual discount for estimated timing of cash flows | (628,270 | ) | | (335,892 | ) | | (409,646 | ) |
| Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves | $ | 807,170 |
| | $ | 518,210 |
| | $ | 589,486 |
|
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (239,953 | ) | | $ | (173,920 | ) | | $ | (218,115 | ) |
| Net changes in prices and production costs | 236,126 |
| | (94,026 | ) | | (1,356,333 | ) |
| Revisions in quantity estimates and changes in production timing | 87,239 |
| | (51,979 | ) | | (213,945 | ) |
| Extensions, discoveries, and improved recovery, less related costs | 102,965 |
| | 84,738 |
| | 95,671 |
|
| Changes in estimated future development costs | (5,194 | ) | | 70,976 |
| | 227,857 |
|
| Previously estimated cost incurred during the period | 36,044 |
| | 16,602 |
| | 59,117 |
|
| Purchases of minerals in place | 51,686 |
| | 2,652 |
| | — |
|
| Sales of minerals in place | (1,447 | ) | | (17,248 | ) | | (3,338 | ) |
| Accretion of discount | 57,517 |
| | 69,069 |
| | 209,979 |
|
| Net change in income taxes | (33,389 | ) | | 44,241 |
| | 562,838 |
|
| Other—net | (2,634 | ) | | (22,381 | ) | | (209,989 | ) |
| Net change | 288,960 |
| | (71,276 | ) | | (846,258 | ) |
| Beginning of year | 518,210 |
| | 589,486 |
| | 1,435,744 |
|
| End of year | $ | 807,170 |
| | $ | 518,210 |
| | $ | 589,486 |
|
Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes
that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.
The December 31, 2017, future cash flows were computed by applying the unescalated 12-month average prices of $51.34 per barrel for oil, $31.83 per barrel for NGLs, and $2.98 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves.
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
| |
(a) | Evaluation of Disclosure Controls and Procedures |
We maintain “disclosure controls and procedures,” as that term is defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934 (the Exchange Act), that are designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, our management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Our disclosure controls and procedures have been designed to meet, and our management believes that they meet, reasonable assurance standards. Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our Chief Executive Officer and Chief Financial Officer have concluded that, subject to the limitations noted above, the company’s disclosure controls and procedures were effective.
| |
(b) | Management’s Report on Internal Control Over Financial Reporting |
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Our management, including our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this report.
| |
(c) | Changes in Internal Control Over Financial Reporting |
In January 2017, we implemented a new ERP accounting and reporting system designed to upgrade our technology and improve the timeliness and quality of our financial and operational information. This new ERP system was not implemented in response to any material weakness in our internal control over financial reporting (ICFR). The implementation of the ERP system has affected the processes that constitute part of our ICFR and requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our ICFR. There were no changes in ICFR during the quarter ended December 31, 2017, that materially affected our ICFR or are reasonably likely to materially affect it.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers, and Corporate Governance
In accordance with Instruction G(3) of Form 10-K, the information required by this item is incorporated in this report by reference to the Proxy Statement, except for the information regarding our executive officers which is presented below. The Proxy Statement will be filed before our annual shareholders’ meeting scheduled to be held on May 2, 2018.
Information About Our Code of Ethics and Business Conduct applies to all directors, officers, and employees, including our Chief Executive Officer, our Chief Financial Officer, and our Controller. You can find our Code of Ethics and Business Conduct on our internet website, www.unitcorp.com. We will post any amendments to the Code of Ethics and Business Conduct, and any waivers that are required to be disclosed by the rules of either the SEC or the NYSE, on our internet website.
Because our common stock is listed on the NYSE, our Chief Executive Officer was required to make, and he has made, an annual certification to the NYSE stating that he was not aware of any violation by us of the NYSE corporate governance listing standards. Our Chief Executive Officer made his annual certification to that effect to the NYSE as of May 5, 2017. In addition, we have filed, as exhibits to this Annual Report on Form 10-K, the certifications of our Chief Executive Officer and Chief Financial Officer required under Section 302 of the Sarbanes-Oxley Act of 2002 to be filed with the SEC regarding the quality of our public disclosure.
Executive Officers
The table below and accompanying text sets forth certain information as of February 13, 2018April 22, 2020 concerning each of our executive officers and certain officers of our subsidiaries. There were no arrangements or understandings between any of the officers and any other person(s) under which the officers were elected.
|
| | | | | | | |
| NAME | AGE | AGE | | POSITION HELD |
Larry D. Pinkston | | 63 |
| | Chief Executive Officer since April 1, 2005, Director since January 15, 2004, President since August 1, 2003, Chief Operating Officer from February 24, 2004 to August 28, 2017, Vice President and Chief Financial Officer from May 1989 to February 24, 2004 |
Mark E. Schell | | 60 |
| | Senior Vice President since December 2002, General Counsel and Corporate Secretary since January 1987 |
| David T. Merrill | 59 | 57 |
| | President and Chief Executive Officer from April 1, 2020, Chief Operating Officer sincefrom August 28, 2017 until April 1, 2020, Senior Vice President from May 2, 2012 to November 27, 2017, Chief Financial Officer and Treasurer from February 24, 2004 to November 27, 2017, Vice President of Finance from August 2003 to February 24, 2004 |
| Mark E. Schell | 63 | Senior Vice President since December 2002, General Counsel and Corporate Secretary since January 1987 |
| G. Les Austin | | 52 |
| 54 | Senior Vice President and Chief Financial Officer since November 27, 2017 |
| David P. Dunham | | 38 |
| 40 | Senior Vice President of Business Development since August 28, 2017, Vice President of Corporate Planning from January 2012 to August 28, 2017, Director of Corporate Planning from November 2007 to January 2012 |
| John H. Cromling | | 70 |
| 72 | Executive Vice President, Unit Drilling Company since April 15, 2005 |
| Robert H. Parks Jr. | 65 | 63President, Superior Pipeline Company, L.L.C. June 1996 to March 31, 2020 |
| Micheal L. Hicks |
54 | | Manager and President, Superior Pipeline Company, L.L.C. since June 1996April 1, 2020 |
| Frank Q. Young | 50 | 48 |
| | SeniorExecutive Vice President Exploration and Production Midcontinent of Unit Petroleum Company since 2017, Senior Vice President of Unit Petroleum Company 2012 - 2017, Vice President - Central Division from June 2007, when he joined Unit Petroleum Company, until 2012. |
Mr. Pinkston joined the company in December 1981. He had served as Corporate Budget Director and Assistant Controller before being appointed Controller in February, 1985. In December, 1986 he was elected Treasurer of the company and was elected to the position of Vice President and Chief Financial Officer in May, 1989. In August, 2003, he was elected to the position of President. He was elected a director of the company by the Board in January, 2004. In February, 2004, in addition to his position as President, he was elected to the office of Chief Operating Officer. In April 2005, he also began serving as Chief Executive Officer. Mr. Pinkston holds the offices of President and Chief Executive Officer. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma.
Mr. Schell joined the company in January 1987, as its Secretary and General Counsel. In 2003, he was promoted to Senior Vice President. From 1979 until joining Unit Corporation, Mr. Schell was Counsel, Vice President, and a member of the Board of Directors of C & S Exploration Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa College of Law. He is a member of the Oklahoma Bar Association. Mr. Schell is a director of the Oklahoma Oil and Gas Association. In addition, he is the Chairman and a director of the Oklahoma Injury Benefit Coalition, an Oklahoma non-profit association advocating for improvements to Oklahoma's Workers' Compensation system. He is also a member of the State Chamber of Oklahoma board of directors and serves on the board of advisors for the Greater Oklahoma City Chamber.
Mr. Merrill joined the company in August 2003 and served as its Vice President of Finance until February 2004 when he was elected to the position of Chief Financial Officer and Treasurer. In May 2012, he was promoted to Senior Vice President, a position he held until November 2017. In August 2017, he was promoted to Chief Operating Officer. In April, 2020, he was promoted to President and Chief Executive Officer. From May 1999 through August 2003, Mr. Merrill served as Senior Vice President, Finance with TV Guide Networks, Inc. From July 1996 through May 1999 he was a Senior Manager with Deloitte & Touche LLP. From July 1994 through July 1996 he was Director of Financial Reporting and Special Projects for MAPCO, Inc. He began his career as an auditor with Deloitte, Haskins & Sells in 1983. Mr. Merrill received a Bachelor of Business Administration Degree in Accounting from the University of Oklahoma and is a Certified Public Accountant.
Mr. Schell joined the company in January 1987, as its Secretary and General Counsel. In 2003, he was promoted to Senior Vice President. From 1979 until joining Unit Corporation, Mr. Schell was Counsel, Vice President, and a member of the Board of Directors of C & S Exploration Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa College of Law. He is a member of the Oklahoma Bar Association. He is also a member of the State Chamber of Oklahoma board of directors, a director of the Petroleum Alliance of Oklahoma, and serves on the board of advisors for the Greater Oklahoma City Chamber.
Mr. Austin joined the company in November 2017 as Senior Vice President and Chief Financial Officer of the company. Prior to coming to Unit, he served as Senior Vice President and Chief Financial Officer of Cypress Energy Partners, L.P..L.P. From 2008 to 2011, he was the Senior Vice President and Chief Financial Officer of Ram Energy Resources, Inc. In 2011, he was promoted to Chief Operating Officer where he served until its sale in 2012. Before joining Ram Energy Resources, Inc., Mr. Austin was the Vice President of Finance and Chief Financial Officer of Matrix Service Company. He has also held various managerial and financial positions at Flint Energy Construction Co. and Ernst & Young, LLP. Mr. Austin has a bachelor's degree in accounting from Oklahoma State University and is a Certified Public Accountant.
Mr. Dunham joined the company in November 2007 as its Director of Corporate Planning. He was promoted to Vice President of Corporate Planning in January 2012. In August 2017, he was promoted to Senior Vice President of Business Development. From 2004 to November 2007, Mr. Dunham worked for Williams Power, serving as Manager of Structured
Products. He worked for Leggett & Platt from 2003 to 2004, serving as a Mergers & Acquisitions Analyst. He received his Bachelor of Arts degree in Psychology from Northwestern University, his Master of Science in Finance degree from the University of Tulsa, and his MBAM.B.A. from the Wharton School of the University of Pennsylvania.
Mr. Cromling joined Unit Drilling Company in 1997 as a Vice-President and Division Manager. In April 2005, he was promoted to the position of Executive Vice-President of Drilling for Unit Drilling Company. In 1980, he formed Cromling Drilling Company which managed and operated drilling rigs until 1987. From 1987 to 1997, Cromling Drilling Company provided engineering consulting services and generated and drilled oil and natural gas prospects. Prior to this, he was employed by Big Chief Drilling for 11 years and served as Vice-President. Mr. Cromling graduated from the University of Oklahoma with a degree in Petroleum Engineering. Mr. Cromling has given the company notice of his intent to retire, effective July 31, 2020.
Mr. Parks founded Superior Pipeline Company, L.L.C. in 1996.1996 and retired as its President on March 31, 2020. When Superior was acquired by the company in July 2004, he continued with Superior as one of its managers and as its President. From April 1992 through April 1996 Mr. Parks served as Vice-President—Gathering and Processing for Cimarron Gas Companies. From December 1986 through March 1992, he served as Vice-President—Business Development for American Central Gas Companies. Mr. Parks began his career as an engineer with Cities Service Company in 1978. He received a Bachelor of Science degree in Chemical Engineering from Rice University and his M.B.A. from the University of Texas at Austin.
Mr. Hicksjoined Superior Pipeline Company, L.L.C. in April 2013 as Vice President of Operations. In December 2014, he was promoted to Senior Vice President of Operations and Engineering. In June 2019, he was promoted to the position of Chief Operating Officer, and effective April 1, 2020, he became President. Prior to joining Superior, Mr. Hicks worked as the Executive Vice President - Operations for Aka Energy Group from 2011 to 2013. From 2007 to 2011, he was the President of Frontier Field Services and Lumen Midstream Services, both owned by the Aka Energy Group, which is part of the Southern Ute Growth Fund. From 2005 to 2007, he was President of Frontier only. From 2003 to 2005, he was the Director of Operations for Frontier Energy, a privately owned, private equity based company. He was the Director of Operations and Engineering from 2000 to 2003 for CMS Field Services. He began his career in 1988 until 2000 as a plant engineer, maintenance engineer, process and project engineer, operations supervisor, plant manager, and area manager for Warren Petroleum (1988 - 1997) and Dynegy (1997 - 2000), after Dynegy bought Warren from Chevron. Mr. Hicks earned a Bachelor of Science in Chemical Engineering from the University of Tulsa.
Mr. Young joined Unit Petroleum Company in June 2007 as Vice President - Central Division. In 2012, he was promoted to Senior Vice President of Exploration and Production over Unit’s Midcontinent assets.assets and, in 2017, to Executive Vice President over Unit Petroleum Company. Before joining Unit, Mr. Young was employed by Anadarko Petroleum Corporation. He began his career with Anadarko in 1991 as a Production Engineer and, in 1994, began working as a Reservoir Engineer. In 1996, he was promoted to a Senior Asset Engineering role responsible for delineation and development of Anadarko’s North African oil fields. In 1999, he was moved into a Senior Completions / Operations Engineering role responsible for development of gas fields in East Texas. In 2000, he was promoted to Division Engineer responsible for operations within Anadarko’s Permian Division in West Texas. In 2002, he was promoted to Planning Manager for North America. In 2004, he was promoted to General Manager of Central Gulf of Mexico responsible for delineation and development of various Deepwater fields. Mr. Young holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University and a Master of Business Administration degree from Texas A&M University.
Information About Our Board of Directors
The table below and accompanying text sets forth certain information as of April 22, 2020 concerning each member of our Board of Directors (the "board"). Former board member and member of the Audit and Compensation Committees, Mr. Gary R. Christopher, passed away on April 21, 2020.
| | | | | | | | | | | | | | | | | | | | |
| NAME | AGE | DIRECTOR | | COMMITTEES OF THE BOARD | TERM EXPIRES MAY OF | PRIMARY OCCUPATION |
| | SINCE | CLASS | | | |
| J. Michael Adcock | 71 | 1997 | III | Audit
Compensation | 2020 | Board Chair, Unit Corporation, Tulsa, Oklahoma |
| Steven B. Hildebrand | 65 | 2008 | III | Audit (Chair)
Compensation | 2020 | Investments, Tulsa, Oklahoma |
| Carla S. Mashinski | 57 | 2015 | II | Audit
Compensation (Chair) | 2022 | Chief Financial and Administrative Officer, Cameron LNG, Houston, Texas |
| William B. Morgan | 75 | 1988 | II | Audit
Compensation
Nominating & Governance (Chair) | 2022 | Investments, Scottsdale, Arizona |
| Larry C. Payne | 72 | 2011 | III | Audit
Nominating & Governance | 2020 | President and Chief Executive Officer, LESA and Associates, LLC, Tulsa, Oklahoma |
| G. Bailey Peyton IV | 64 | 2011 | III | None | 2020 | President, Peyton Holdings, Canadian, Texas |
| Larry D. Pinkston | 65 | 2004 | II | None | 2022 | Director and retired CEO, Unit Corporation, Tulsa, Oklahoma |
| Robert J. Sullivan Jr. | 74 | 2005 | I | Nominating & Governance | 2021 | Manager, Sullivan and Company LLC, Tulsa, Oklahoma |
Biographical information for our directors is set forth below:
Mr. Adcock was elected as our Board Chair effective December 31, 2016. He has been a licensed attorney since 1974, and has served since 1997 as co-trustee of the Don Bodard Trust, a private business trust dealing in real estate, oil and natural gas investments, and other equity investments. Since January 2018, Mr. Adcock has been a member of the board of the privately-held Arvest Bank, Oklahoma City. He served as Chairman of the Board of Arvest Bank, Shawnee, Oklahoma from October 1997 until January 2018, when it became part of Arvest Bank, Oklahoma City. He has also served as a member of the Board of the nonprofit Avedis Foundation (successor to Community Health Partners, Inc.) for more than five years, and served as its Chairman of the Board from 2015 until his retirement from the Avedis Board in June 2018. Mr. Adcock has been a co-owner of Central Disposal, LLC, a solid waste management company with operations in central Oklahoma, since 2009, and was elected as Chairman of the Board in 2014. Between 1997 and September 1998, Mr. Adcock served as Chairman of the Board of Ameribank and President and CEO of American National Bank and Trust Company of Shawnee, Oklahoma, and Chairman of AmeriTrust Corporation, Tulsa, Oklahoma. Before 1997, Mr. Adcock was engaged in the private practice of law and served as General Counsel for Ameribank Corporation. Mr. Adcock holds a B.S. degree in business administration from Oklahoma State University, and a juris doctorate from the University of Oklahoma College of Law. Attributes, experience, and qualifications for board and committee service: many years of experience in banking, investment, and energy operations; expertise in tax, banking, and SEC/regulatory compliance law; executive leadership experience as CEO of two companies, one of which was a publicly-traded international energy company with exploration and production, pipeline, trading, and co-generation subsidiaries; extensive history and familiarity with the company and the industry in which it operates; demonstrated commitment to boardroom excellence evidenced by completion of the NACD’s comprehensive program for certification as a Corporate Directors Leadership Fellow.
Mr. Hildebrand has been engaged in personal investments since March 2008. He retired in 2008 from Dollar Thrifty Automotive Group, Inc. (NYSE: DTG), a car rental business, where he had served as Executive Vice President and Chief Financial Officer since 1997. Prior to that, Mr. Hildebrand served as Executive Vice President and Chief Financial Officer of Thrifty Rent-A-Car System, Inc., a subsidiary of Dollar Thrifty. Mr. Hildebrand joined Thrifty Rent-A-Car System, Inc. in 1987 as Vice President and Treasurer and became Chief Financial Officer in 1989. Mr. Hildebrand was with Franklin Supply Company, an oilfield supply business, from 1980 to 1987 where he held several positions including Controller and Vice President of Finance. From 1976 to 1980, Mr. Hildebrand was with the accounting firm Coopers & Lybrand, most recently as Audit Supervisor. Mr. Hildebrand earned a B.S.B.A. degree in accounting from Oklahoma State University, and he is a certified public accountant. Attributes, experience, and qualifications for board and committee service: experience and expertise in accounting and finance, including many years of experience as a CPA; qualifications as an audit committee financial expert;
executive leadership experience at a public company, including experience with strategic planning, SEC reporting, Sarbanes Oxley compliance, investor relations, enterprise risk management, executive compensation, corporate compliance, internal audit, bank facilities, private placement debt transactions and working with ratings agencies.
Ms. Mashinski joined the Board of Directors in August 2015. Ms. Mashinski serves as Chief Financial Officer of Cameron LNG, a natural gas liquefaction terminal near the Gulf of Mexico, a position she has had since July 2015; effective February 2017, her title was expanded to that of Chief Financial and Administrative Officer. From 2014 to July 2015, she served as Chief Financial Officer and Vice President of Finance and Information Management for the North America Operation of SASOL, an international integrated energy company. From 2008 to 2014, Ms. Mashinski was employed by SBM Offshore, Inc., a provider of leased floating production systems for the offshore energy industry, serving as Vice President of Finance and Administration, U.S. Chief Financial Officer from 2008 to February 2014, and as Commercial and Contracts Manager from February to August 2014. She served as Vice President and Chief Accounting Officer and Controller of Gulfmark Offshore from 2004 to 2008. Prior to that, Ms. Mashinski held various finance and accounting positions for Duke Energy (1999-2004) and Shell Oil Company (1985-1998) or affiliated companies. Ms. Mashinski is a certified public accountant, certified management accountant, and a certified project management professional with a B.S. degree in accounting from the University of Tennessee, Knoxville and an Executive M.B.A. from the University of Texas, Dallas. She is a National Association of Corporate Directors (NACD) Governance Fellow and a recipient of the CERT Certificate in Cybersecurity Oversight issued by Carnegie Mellon University. Since January 2019, Ms. Mashinski has served as a director for publicly-traded Carbo Ceramics Inc., where she serves on the compensation, audit, and nominating and corporate governance committees. Since March 2019, she has served as a director of publicly-traded Primoris Services Corporation, where she serves on the audit committee. Attributes, experience, and qualifications for board and committee service: executive level experience with corporate financial, human resources, and information management activities, including budgeting and forecasting, treasury, financial reporting, Sarbanes Oxley compliance, and tax management; industry experience in strategic planning, risk management, compensation, mergers and acquisitions, joint ventures, and financial leadership; international industry experience; accounting and financial expertise as a certified public accountant, certified management accountant, and project management professional; demonstrated commitment to boardroom excellence evidenced by completion of NACD’s comprehensive program of study for directors and corporate governance professionals; cybersecurity oversight training.
Mr. Morgan is engaged in personal investments and has been since he retired in June 2007 from his position as Executive Vice President and General Counsel of St. John Health System, Inc., Tulsa, Oklahoma, where he was also President of its principal for-profit subsidiary Utica Services, Inc., positions he had held since 1995. He currently serves as an Arbitrator for the Financial Industry Regulatory Authority (FINRA) and has done so on a part-time basis for more than five years. Prior to joining St. John, Mr. Morgan was engaged in the private practice of law at the Tulsa, Oklahoma firm of Doerner, Saunders, Daniel & Anderson, and he served as an adjunct law professor at the University of Tulsa, where he taught securities law. In 1968 and 1969, Mr. Morgan served as a United States Army Officer in Vietnam. He has an undergraduate degree from Muhlenberg College, Allentown, Pennsylvania and a juris doctorate from the University of Tulsa College of Law. Attributes, experience,and qualifications for board and committee service: background as a licensed attorney with over 40 years’ of business and legal experience; expertise in complex corporate finance, business, and securities and regulatory law; executive leadership experience; analytical skills; extensive history and familiarity with the company and the industry in which it operates.
Mr. Payne is President and Chief Executive Officer of LESA and Associates, LLC, a private investment and consulting firm, a position he has held since he started that firm in June of 2011. From December 1, 2012 to September 8, 2013, Mr. Payne also served as Interim President of Magnum NGLs, LLC, a private company engaged in natural gas liquids storage in Delta, Utah. From April 2010 to April 2011, Mr. Payne served as President and Chief Operating Officer of Lansing NGL Services Natural Gas Liquids Division, a division of Lansing Trade Group, LLC, a commodities trading company located in Overland Park, Kansas. From August 2009 to April 2010, Mr. Payne provided energy consulting services to private clients interested in the midstream energy business. From 2003 until August 2009, Mr. Payne served as President and Chief Operating Officer of SemStream, L.P., a midstream energy company engaged in natural gas liquids supply and marketing. Before joining SemStream, Mr. Payne served as Vice President of Commodity Management for Williams Midstream Marketing and Risk Management, LLC., and before that he served as Vice President of Natural Gas Liquids Supply, Trading and Risk Management for Texaco NGL. During his earlier years of service, Mr. Payne held numerous other positions in the energy industry including executive positions with Enterprise Products, Aux Sable Liquid Products, and Ferrellgas. Mr. Payne received a B.S. in Business Administration from Grambling State University, and an M.B.A. from Texas Southern University with a concentration in Finance and Economics. Mr. Payne served on the board of directors and audit committee of Buckeye Partners GP, LLC, general partner of the NYSE-listed limited partnership Buckeye Partners, LP, from September 29, 2014 to November 1, 2019. He also serves on the boards of three nonprofit organizations. Attributes, experience, and qualifications for board and committee service: executive and strategic experience in the midstream energy business; extensive background in commodity risk
management; expertise in oil and natural gas component marketing; extensive operational experience including management of assets such as product terminals, pipelines, fractionators, storage facilities, and transportation equipment.
Mr. Peyton has been President of Peyton Holdings Corporation (formerly Peyton Oil and Gas), a Canadian, Texas company he formed in 1985 for purposes of buying land, minerals, and royalties. Since 2009, Mr. Peyton has owned and served as President and managing member of Perryton Feeders, LLC, a cattle feeding business in Perryton, Texas. Also since 2009, Mr. Peyton has owned and served as President of Cuatro Cattle Company, a cattle ranching operation in Canadian, Texas. Since 2007, Mr. Peyton has served as President and co-owner of Upland Resources, LLC, a Canadian, Texas oil and gas exploration company that began actively drilling in the Texas Panhandle in 2012. From 1984 to 2007, Mr. Peyton served as President of Upland Resources, Inc., an oil and natural gas exploration company he founded and later sold. Mr. Peyton currently serves on the board of directors of Happy State Bank in Amarillo, Texas. Mr. Peyton is a past President of the Panhandle Association of Landmen, Amarillo, Texas. Mr. Peyton holds a B.S. degree in ranch management from Texas Christian University. Attributes, experience, and qualifications for board service: extensive operations experience in exploration and production as well as mineral leasing and oil and gas property management; executive experience; entrepreneurial expertise.
Mr. Pinkston joined the company in December 1981 and retired from his position as Chief Executive Officer and President on March 31, 2020. He had served as Corporate Budget Director and Assistant Controller before being appointed Controller in February, 1985. In December, 1986 he was elected Treasurer of the company and was elected to the position of Vice President and Chief Financial Officer in May, 1989. In August, 2003, he was elected to the position of President. He was elected a director of the company by the Board in January, 2004. In February, 2004, in addition to his position as President, he was elected to the office of Chief Operating Officer and held this position until August 2017. In April 2005, he also began serving as Chief Executive Officer. Mr. Pinkston held the offices of President and Chief Executive Officer until March 31, 2020. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma. Attributes, experience,and qualifications for board service: extensive familiarity with the company and the industry; operational experience; accounting and financial expertise; management and leadership skills.
Mr. Sullivan is, and since 1975 has been, a Principal with Sullivan and Company LLC, a family-owned independent oil and natural gas exploration and production company founded in 1958, and he has served as a manager of that company since approximately 1995. He is also the Founder (1989) of Lumen Energy Corporation, serving as its Chairman and CEO from inception to the time of its sale in 2004. Mr. Sullivan was appointed to Oklahoma Governor Frank Keating’s Cabinet as Secretary of Energy in March 2002. He received a B.B.A. from the University of Notre Dame, and a M.B.A. from the University of Michigan. Attributes, experience, and qualifications for board and committee service: extensive energy industry expertise; entrepreneurial expertise in founding and operating a 3D seismic company and a midstream natural gas transportation company.
Corporate Governance and Board Matters
General Governance Matters
We are committed to having sound corporate governance principles. Our Corporate Governance Guidelines and Code of Business Conduct and Ethics are available on our website http://www.unitcorp.com/investor/governance.html and copies of these documents may also be obtained, without charge, on request, from our corporate secretary. These provisions apply to our directors, employees, and officers, including our principal executive officer, principal financial officer, and principal accounting officer. We will post any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed by the rules of either the SEC or the NYSE on our website.
Each year, our directors and executive officers are asked to complete a director and officer questionnaire which requires disclosure of any transactions with us in which the director or executive officer, or any member of his or her immediate family, have a direct or indirect material interest. Our CEO and general counsel are charged with resolving any conflict of interests not otherwise resolved under one of our other policies.
Role of our Board in Risk Management Process
Oversight of risk management committee. Our board’s oversight of our risk management activities is delegated to our audit committee. The audit committee manages this responsibility by maintaining regular contact with our senior vice president of business development, who oversees our company’s risk management committee. The risk management committee, staffed by employees of our executive and operations management team, conducts an annual risk analysis. The objective of the analysis is
to identify and analyze factors that might pose a significant risk to the company as a whole. As necessary and feasible, remediation plans are developed for the highest priority risks. The senior vice president of business development provides periodic progress reports directly to the audit committee, which provides input and direction that is communicated back to the risk management committee. Similarly, the director of information technology reports regularly to the audit committee on the company’s cybersecurity initiatives. During 2017, the company conducted an in-depth company-wide cybersecurity risk assessment and received Phase 1 and Phase 2 reports from the cybersecurity consulting firm conducting that risk assessment. Cybersecurity risk assessment and attendant system enhancements continued during fiscal year 2018 and in fiscal year 2019 and beyond. The audit committee keeps the full board updated on the company’s ongoing risk management activities, including updating it on the cybersecurity initiatives, and reports any significant findings to the board. In addition, management discusses its highest priority risks and remediation plans with the full board.
Oversight of hedging activities. We hedge some of our oil, natural gas, and natural gas liquids production. The objective of our hedging program is to manage, to a degree, our exposure to changes in commodity prices. Any risk to our company from our hedging activities is overseen by our board. The board defines the scope of our permissible hedging or derivatives activities. The audit committee (and, ultimately, the board) monitors our hedging activities on an ongoing basis.
Board Structure and Committees
Our board is structured so the principal executive officer (our CEO) and board chair positions are separate. Our Corporate Governance Guidelines provide that the board has no policy regarding separation of these positions. Our board believes that the decision to combine or separate these positions should be made based on the qualities of the individuals being considered to fill them. Our board’s oversight of risk management has not affected our leadership structure. Our leadership structure results from specific facts and circumstances and not a specific governance policy. Mr. Adcock, an independent director, serves as the board’s Chair, continuing with our most recent practice of separating the Chair and CEO positions. Mr. Adcock has presided over executive sessions of the board for several years, has an extensive history with and knowledge about the company, and has public company executive experience and experience serving as a board chair for private and non-profit organizations. The board believes that Mr. Adcock is very qualified to hold the position of Chair of the Board. Our board further believes that, at this time and based on the individuals involved, continuing to maintain the separation of the CEO and Chair positions is the most appropriate leadership structure. As our independent chair, Mr. Adcock presides over the executive sessions of the board.
Our board currently has eight directors and these three standing committees: audit; compensation; and nominating and governance.
The board is divided into three classes. Classes I and II are each structured to be composed of three directors (although there are currently two vacancies in Class I), and Class III is structured to be composed of four directors. Directors serve for a three-year term. Each standing committee operates under a written charter adopted by the committee. Each committee’s charter is available at our website at http://www.unitcorp.com/investor/governance.html. In addition, copies of these charters may also be obtained from our corporate secretary.
During 2019, the board held nine meetings, seven regularly-scheduled and two special telephonic meetings. In 2019, all of our directors attended 100% of both the board meetings and any committee meetings held by committees on which he or she then served. Directors are encouraged to attend our annual meeting of stockholders. All directors who were board members on the date of our last annual stockholders meeting attended that annual meeting. Besides meetings, the board and its committees may occasionally act by unanimous consent.
This table identifies the current membership of each standing committee, and the number of meetings each committee held during 2019:
| | | | | | | | | | | |
| DIRECTOR | | COMMITTEE | |
| Audit | Compensation | Nominating and Governance |
| J. Michael Adcock | x | x | |
| Steven B. Hildebrand | x* | x | |
| Carla S. Mashinski | x | x* | |
| William B. Morgan | x | x | x* |
| Larry C. Payne | x | | x |
| Robert J. Sullivan Jr. | | | x |
| Number of meetings | 9 | 5 | 3 |
* Designates the chair of the committee.
Audit Committee. The committee’s responsibilities include:
•selecting our independent registered public accounting firm;
•approving all audit engagement fees and terms;
•pre-approving all audit and non-audit services to be rendered by our independent registered public accounting firm;
•reviewing and approving our annual and quarterly financial statements;
•overseeing our relationship with our independent registered public accounting firm, including the evaluation of their qualifications, performance, and independence;
•overseeing our internal audit functions;
•reviewing with our independent registered public accounting firm and our internal audit department and management any significant matters regarding internal controls over financial reporting that may come to their attention during the conduct of their audit;
•recommending to our board whether the financial statements should be included in our annual report on Form 10-K;
•reviewing our earnings press releases, and our policies regarding the publication of our earnings and other financial information;
•monitoring our ongoing risk assessment and management activities, including those related to cybersecurity; and
•monitoring our hedging activities on an ongoing basis.
This committee has the authority to form and delegate authority to subcommittees, to delegate authority to one or more of its members, and to obtain advice and assistance and receive appropriate funding from the company for outside legal, accounting, or other advisors, as the committee deems necessary or appropriate to carry out its duties. The committee has established procedures for the receipt, retention, and treatment (on a confidential basis) of complaints received by the company, the board, or the audit committee, regarding accounting, internal accounting controls or auditing matters, and the confidential, anonymous submissions by employees of concerns regarding questionable accounting or auditing matters. These procedures are described in the Accounting and Auditing Complaint Procedures posted on our website.
Each member of the committee is independent, financially literate, knowledgeable, and qualified to review financial statements. The board has determined that Steven B. Hildebrand, Gary R. Christopher, Larry C. Payne, and Carla S. Mashinski qualify as “audit committee financial experts” under the rules of the SEC and NYSE listing standards.
Compensation Committee. Our compensation committee has overall responsibility for approving and evaluating director and executive officer compensation plans, policies, and programs. In carrying out these responsibilities the committee:
•annually reviews and approves any corporate goals and objectives relevant to our CEO’s compensation, and makes recommendations to the board on our CEO’s compensation;
•recommends to our board the compensation of our other executive officers and certain key employees;
•reviews the severance arrangements, change-in-control agreements, and any special or supplemental benefits or plans (if any) applicable to our NEOs;
•administers any director and employee compensation plans, policies and programs, and discharges its duties under those plans;
•annually evaluates the risk associated with our compensation programs and practices;
•recommends director compensation;
•reviews and approves the “compensation discussion and analysis” included in our proxy statement; and
•retains and approves the fees for any compensation consultants or other advisors that assist the committee in its evaluation of director, CEO, or executive officer compensation, and assesses the independence of any such advisors.
This committee has the authority to form and delegate authority to subcommittees and to delegate authority to one or more of its members. For additional information on the operations of the committee, see “Compensation Discussion and Analysis – Administration of our executive compensation program – overview of the process.” The compensation committee report is included at page 16.
Nominating and Governance Committee. This committee’s responsibilities include:
•advising the board on corporate governance matters;
•advising the board on the size and composition of the board;
•identifying those individuals qualified to become board members, consistent with any criteria approved by the board;
•recommending a slate of nominees for election to the board and recommending membership to each board committee;
•reviewing the continuing qualification of our directors to serve on the board and its committees;
•reviewing any candidates recommended by our stockholders;
•leading the board and its committees in an annual self-assessment;
•considering and resolving questions of possible conflicts of interest of board members or the company’s senior executives; and
•identifying best practices and recommending corporate governance principles, including giving proper attention and making effective responses to stockholder concerns regarding corporate governance.
Material Changes to Procedures for Nominating Directors
There have been no material changes to the procedures by which security holders may recommend nominees to our board of directors since our last proxy statement filed March 26, 2019 disclosing those procedures.
Director Qualifications
General director qualifications. Our Corporate Governance Guidelines contain the criteria our nominating and governance committee uses in evaluating nominees it may recommend for a position on our board. Under these criteria, nominees should meet the board’s qualifications as independent (as applicable) and should have enough time to carry out their duties and provide guidance beneficial to the company’s success. Their service on other boards of public companies should be limited to a number that permits them, given their individual circumstances, to perform responsibly all director duties. Each director must represent the interests of the company and its stockholders.
Directors’ specific qualifications. Each current director possesses a combination of attributes that qualifies him or her for service on our board. These attributes can include (but are not limited to): business experience (in general or specific to our industry), knowledge based on specialized education (such as technical industry training, legal, or accounting), and leadership abilities (civic, work-related, or both). We believe the qualifications of our directors, individually and collectively, have made our board an effective and productive one.
At its February 2020 meeting, our nominating and governance committee reviewed the individual qualifications of each of our board members and determined that all directors continue to be qualified for board service and service on the committees of the board on which they serve. Following each of our directors’ biographies beginning on page 6, we have listed the unique attributes that we believe qualifies them for service on our board and its committees.
Identifying and evaluating nominees for directors; diversity policy. The nominating and governance committee uses various means to identify and evaluate individuals being considered for a position on our board. The committee assesses the appropriate size of the board (within the size limits in our corporate charter), and whether any vacancies on the board are expected due to retirement or otherwise. If vacancies are anticipated (or otherwise arise), the committee undertakes to identify those potential candidates it believes will make good decisions and be able to contribute to the company in a meaningful way. Candidates may come to the attention of the committee through board members, professional search firms, stockholders, or other persons. Candidates are evaluated at regular or special meetings of the committee and may be considered at any point during the year. It is the committee’s responsibility to consider any properly-submitted stockholder nominations for candidates for the board, verify the stockholder status of persons proposing candidates, and then submit its recommendations to the full board.
Our Corporate Governance Guidelines set forth our position regarding diversity. Our board is committed to inclusiveness in selecting candidates for board membership. Within the context of our fiduciary duties, applicable law and regulations, and the membership of the board at the time, our nominating and governance committee will try to include women, minority candidates, and candidates from non-traditional environments (such as government, academia, and non-profit organizations) in the pool from which board nominees are chosen. Although there is no specific implementation plan, achievement of our diversity goals is evaluated annually as part of our board self-evaluations.
Executive Sessions
Our board met in regularly scheduled executive sessions of non-management directors during 2019, one of which was attended only by independent directors of the board. The sessions were scheduled and presided over by our board chair Mr. J. Michael Adcock. As independent board chair, Mr. Adcock schedules and presides over executive sessions. Any non-management director can request that an executive session be scheduled.
Any interested party may communicate directly with the chair by writing to:
Mr. J. Michael Adcock
c/o Corporate Secretary
Unit Corporation
8200 S. Unit Drive
Tulsa, Oklahoma 74132
Contacting our Board
Individuals may communicate with our board by submitting an e-mail to the board in care of the company’s corporate secretary at mark.schell@unitcorp.com or sending a letter to the Board of Directors, c/o Corporate Secretary, at: Unit Corporation, 8200 S. Unit Drive, Tulsa, Oklahoma 74132.
The chair of the nominating and governance committee has been designated as the person to receive communications directed to non-management directors. Our stockholders may write to the chair of this or any other board committee or to the outside directors as a group c/o Mark E. Schell, Senior Vice President and General Counsel, at: Unit Corporation, 8200 S. Unit Drive, Tulsa, Oklahoma 74132.
Stockholder communications are distributed to the board, or to the appropriate individual director or directors, depending on the facts and circumstances of the communication. However, at the request of the board, certain items not related to the duty and responsibilities of the board are excluded, such as advertisements, junk mail, mass mailings, spam, and surveys.
Board and Committee Evaluations
Each year the board evaluates its performance and effectiveness. Each director completes a board evaluation form to solicit feedback on specific aspects of the board’s role, organization, and meetings. The collective ratings and comments are compiled by or for the chair of the nominating and governance committee, and presented by him to and discussed with the full board. Additionally, each of the three standing board committees annually evaluates its performance through a committee evaluation form, and a report summarizing the results is distributed to and discussed by each committee.
Delinquent Section 16(a) Reports
Mr. Adcock failed to file a report required by Section 16(a) of the Exchange Act on a timely basis one time in fiscal year 2019. His purchase of 2,000 shares of our common stock on May 28, 2019 was not reported on Form 4 until June 12, 2019.
Item 11. Executive Compensation
Directors' 2019 Compensation - Overview
Our compensation committee reviews director compensation annually. In October 2019, the committee reviewed the directors’ 2018 compensation relative to the 2018 compensation of the 2019 peer group directors. That review reflected that for 2018 the peer group directors’ average total compensation was $267,769 compared to the company’s average total director compensation of $209,062. The committee also reviewed market-based survey information about director compensation for medium-size companies (with revenues of $1.0 billion to $2.5 billion) as reported in the 2018 - 2019 Director Compensation Report of the National Association of Corporate Directors (NACD). The NACD report contained director compensation information for the fiscal year ending between February 1, 2017 and January 31, 2018, and reflected median total annual director compensation of $195,438 for companies in the medium-size revenue group during that period. Based on its review, the committee determined that director compensation should not increase and that 2019 compensation should remain at 2018 compensation levels. In early 2020, the compensation committee recommended and the board approved reducing fees for telephonic board and committee fees by half, to $750 per meeting, effective January 1, 2020. Other than this fee reduction, there have been no changes to the rate of director compensation since 2012.
Directors' 2019 Cash Compensation
Only non-employee directors receive compensation for serving as a director. The various components of the 2019 cash compensation paid to our non-employee directors are as follows:
| | | | | |
| Annual retainer (paid quarterly) | $ | 60,000 | |
| Annual retainer for each committee a board member serves on (paid quarterly) | $ | 3,500 | |
Each board or committee meeting attended in person (1) | $ | 1,500 | |
Each board or committee meeting attended by telephone (1) | $ | 1,500 | |
| Additional compensation for service as board chair | $ | 25,000 | |
| Additional compensation for service as chair of the audit committee | $ | 15,000 | |
| Additional compensation for service as chair for each of the compensation committee and nominating and governance committee | $ | 6,000 | |
| Reimbursement for expenses incurred attending stockholder, board, and committee meetings | Yes |
| Range of total cash compensation (excluding expense reimbursement) earned by directors for 2019 | $73,500 - $129,500 |
_________________________
1.Effective January 1, 2020, fees for special (not-regularly-scheduled) telephonic board or committee meetings are $750 per meeting. Also in 2020, fees for regularly-scheduled board or committee meetings held telephonically due to COVID-19 are paid at the full rate of $1,500 per meeting.
Directors' 2019 Equity Awards
Under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan (the “stock plan”), we may make annual equity awards to our non-employee directors. Under the stock plan, the annual maximum number of awards to any one non-employee director are: for Options and SARS: 80,000; for Restricted Stock and Restricted Stock Units: 50,000; for Performance Shares and Performance Units: 50,000; for Cash-Based Awards: $500,000; and for Stock Awards: 50,000. Annual director equity awards are typically granted the day after the annual organizational board meeting and the awards are based on the lesser of 10,000 shares or a number of shares valued at $110,000 based on the NYSE closing common stock price on the grant date. Based on the closing price of our common stock on the NYSE on the day after our 2019 annual meeting, each non-employee director received 9,098 shares of restricted stock as the equity component of his or her 2019 director compensation. The 2019 awards vest in three equal annual installments on May 14th in each of 2020, 2021, and 2022. If a director’s service terminates before all shares have vested, the unvested shares will be forfeited unless the termination of service is due to death, disability, a change of control, or, unless the committee specifically determines otherwise on a director’s retirement, in which case all unvested shares will accelerate and vest 100% as of the date of death, disability, change of control, or retirement. Shares that are issued under the stock plan can be clawed back in the event of specified instances of misconduct.
Before 2012, we made annual equity grants to our non-employee directors under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan (the “option plan”). As of April 15, 2020, 42,000 shares are subject to outstanding options held by current non-employee directors. Previously, under the option plan, each non-employee director automatically received an option to purchase 3,500 shares of our common stock on the first business day following each annual meeting of our stockholders. The option exercise price was the NYSE closing price of our common stock on that date. Payment of the
exercise price can be made in cash or in shares of common stock held by the director for at least one year. No stock option can be exercised during the first six months of its term except in the case of death. Each option has a ten-year term. No future awards will be made under the option plan.
Director Compensation Table
This table shows the total compensation received in 2019 by each of our non-employee directors:
| | | | | | | | | | | | | | | | | | | | | | | |
| DIRECTOR COMPENSATION FOR 2019 | | | | | | | |
| Name | Fees Earned or Paid in Cash (1) ($) | Stock Awards (2) ($) | Option Awards (2) ($) | Non-Equity
Incentive
Plan
Compensation
($) | Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($) | All Other
Compensation
($) | Total
($) |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) |
| J. Michael Adcock | 129,500 | 110,000 | n/a | n/a | n/a | — | 239,500 |
Gary R. Christopher (3) | 104,500 | 110,000 | n/a | n/a | n/a | — | 214,500 |
| Steven B. Hildebrand | 119,500 | 110,000 | n/a | n/a | n/a | — | 229,500 |
| Carla S. Mashinski | 110,500 | 110,000 | n/a | n/a | n/a | — | 220,500 |
| William B. Morgan | 118,500 | 110,000 | n/a | n/a | n/a | — | 228,500 |
| Larry C. Payne | 100,000 | 110,000 | n/a | n/a | n/a | — | 210,000 |
| G. Bailey Peyton IV | 73,500 | 110,000 | n/a | n/a | n/a | — | 183,500 |
| Robert J. Sullivan Jr. | 81,500 | 110,000 | n/a | n/a | n/a | — | 191,500 |
_________________________
1.Represents cash compensation for board and committee meeting attendance, retainers, and service as a board or committee chair.
2.On May 2, 2019, each director was granted a restricted stock award for 9,098 shares with a grant date fair value of $110,000. The amounts included for each director in the “Stock Awards” column are the aggregate grant date fair value computed under FASB ASC Topic 718 based on a stock price of $12.09, reflecting the fair market value on the date of grant. The non-employee directors have the following aggregate number of shares subject to stock and option awards outstanding at December 31, 2019:
| | | | | | | | |
| Name | Stock Awards | Options |
| J. Michael Adcock | 14,836 | 7,000 |
Gary R. Christopher (3) | 14,836 | 7,000 |
| Steven B. Hildebrand | 14,836 | 7,000 |
| Carla S. Mashinski | 14,836 | — |
| William B. Morgan | 14,836 | 7,000 |
| Larry C. Payne | 14,836 | 3,500 |
| G. Bailey Peyton IV | 14,836 | 3,500 |
| Robert J. Sullivan Jr. | 14,836 | 7,000 |
3. Mr. Christopher passed away on April 21, 2020.
Executive Compensation
Overview of NEOs’ 2019 Compensation
This table summarizes the major components of our NEOs’ 2019 compensation:
| | | | | | | | | | | | | | | | | |
| OVERVIEW OF NEOs’ 2019 COMPENSATION | | | | | |
| Name | Salary | Cash Bonus | | Shares of Restricted Stock (1) | |
| | Performance Based | Discretionary | Performance Based | Time Vested |
| Larry D. Pinkston | $887,500 | $330,613 | — | 123,808 | 82,539 |
| David T. Merrill | $545,000 | $142,117 | — | 62,530 | 41,686 |
| Mark E. Schell | $492,000 | $128,296 | — | 56,454 | 37,636 |
| John H. Cromling | $466,000 | $134,850 | — | 53,464 | 35,642 |
| G. Les Austin | $370,000 | $96,483 | — | 41,371 | 27,581 |
_________________________
1.Amounts shown as performance-based stock awards are target amounts.
Protecting the Integrity of Our Compensation Practices
The following compensation practices are included in our compensation program:
•Clawback rights – Our Second Amended and Restated Stock and Incentive Compensation Plan includes a mandatory clawback provision. We have the right to “clawback” long-term or short-term incentive compensation paid to any participant, including our NEOs and directors, who commits acts of fraud or dishonesty, including those that result in a financial restatement.
•Performance metrics – For 2019, sixty percent (based on target) of our NEOs’ long-term incentive awards were granted subject to performance metrics. Sixty percent (based on target) of our NEOs’ 2019 short-term incentive cash bonus was based on pre-established objective performance measures and forty percent (based on target) was based on subjective performance goals and potential discretion.
•Stock ownership and retention guidelines for directors and NEOs – We have stock ownership and retention guidelines applicable to our NEOs and directors. Within five years of election, and subject to the requirement that 50% of net shares awarded be held until the assigned levels are met, our CEO must hold shares valued at five times base salary, our other NEOs must hold shares valued at three times base salary, and our directors must hold shares valued at three times annual retainer. Required holdings are calculated on the later of the adoption of the policy or election as an officer or director and as more particularly described in our stock ownership policy, appended to our corporate governance guidelines, available on our website at http://www.unitcorp.com/investor/governance.html. All of our directors and all NEOs except Mr. Austin (who became subject to holding requirements in 2017 and has until 2022 to become compliant) hold shares above required holding levels.
•Hedging and Pledging Policy – We have a policy prohibiting our directors and NEOs (and any other officers filing Section 16 reports with the SEC) from hedging or pledging our common stock. The policy specifically prohibits the purchase, sale, or writing of “calls, puts, or other options or derivative instruments.” Based on their answers to our most recent directors and officers questionnaires, no directors or NEOs have hedged or pledged company stock. Non-Section 16 officers and all other employees are subject to a policy that strongly discourages engaging in “hedging or monetization transactions, such as zero-cost collars and forward sales contracts” and requires any proposed hedging transactions to be pre-cleared by our General Counsel. No employees requested clearance from the General Counsel for hedging transactions in 2019.
•Ongoing compensation risk assessment – Our compensation committee conducts a formal annual compensation risk assessment. The committee has determined that there are adequate design features and controls in place to ensure that our compensation plans and practices do not encourage unnecessary risk-taking and are not reasonably likely to have a material adverse effect on us.
•Minimum vesting requirements on equity awards – We have minimum vesting requirements for all awards (other than SARs or options) under our stock and incentive compensation plan, which provides that for other than SARs and options, awards under the plan will be subject to a minimum three-year vesting period unless performance-based, in
which case the vesting period will be at least one year, subject to the right of the committee to grant up to five percent of shares available for grant under the plan free of these restrictions.
•Prohibition of Option Repricing – Except in connection with corporate transactions involving the company (like dividends, stock splits, reorganizations, mergers, etc.), the terms of outstanding awards may not be amended to reduce the exercise price of outstanding options or SARs or cancel outstanding options or SARs in exchange for cash, other awards, options or SARs without stockholder approval.
Compensation Committee Report
The compensation committee has reviewed and discussed with our management the following compensation discussion and analysis. Following that review and discussion, the compensation committee recommended to our board that the compensation discussion and analysis be included in this annual report on Form 10-K for fiscal year 2019.
The members of the compensation committee are:
| | | | | | | | | | | |
| Carla S. Mashinski – Chair | | | |
| William B. Morgan | | |
| J. MichaelAdcock | | |
| Steven B. Hildebrand | | |
Compensation Discussion and Analysis
To assist you in reviewing our compensation discussion and analysis, we have arranged our discussion into these sections, each of which may have its own subsections:
•Our general compensation objectives
•Elements of our compensation program
•Our compensation policies and program as they relate to risk management
•Effect of stockholder say-on-pay vote on compensation decisions
•Administration of our executive compensation program – overview of the process
•Role of compensation consultant
•Role of CEO
•Peer group
•2019 salaries
•2019 long-term incentive awards
•2019 annual cash bonus awards
•2019 compensation decisions pertaining to 2020 compensation
•Performance-based stock awards vesting during or for fiscal year 2019
•Stock ownership policy
•Policy on hedging and pledging our securities
•No backdating, spring-loading, or repricing of options
•Non-employee director compensation
•Tax considerations
•Employment agreements
Our general compensation objectives. Our goals are to attract, motivate, reward, and retain qualified employees. We try to satisfy those goals in a way that aligns our employees’ interests with both our business and financial objectives, as well as the interests of our stockholders. So we:
•offer a competitive compensation mix comprising competitive salaries, short-term and long-term incentives, and certain additional benefits;
•reward performance that achieves our business objectives and enhances the performance of our common stock; and
•link executive compensation to our stockholders’ interests both generally through equity awards as components of executive and non-executive compensation, and more specifically by tying a significant portion of both long- and short-term incentive compensation for our executives to various performance goals.
Elements of our compensation program. Our executive compensation program includes salary, annual cash bonus (also called “short-term incentive awards”), and certain forms of equity awards (also called “long-term incentive awards”). We also make available health, disability and life insurance, certain indemnification protection, 401(k) retirement benefits, separation benefits, and certain limited perquisites. Each element of our compensation program is viewed as a necessary component of the mix required to attract and retain talented executives, reward them for quality performance, and motivate them to focus on both the company’s short- and long-term performance. We believe a competitive salary is required to attract and retain qualified executives. When authorized, annual cash bonuses provide executives with potential earnings based on annual financial and operating results and reward them for short-term successes. Long-term incentive awards are used to motivate both long- and short-term results and aid in the retention of our executives. Compensating our executives for company performance in both the short term and the long term aligns our executives’ compensation with the interests of our stockholders. Indemnification protections, retirement and separation benefits, and general perquisites are commonly included in executive compensation packages offered by our competitors, and providing them helps achieve our compensation goals.
The following chart provides further details about the elements of compensation and benefits that we pay (or offer) our executives and why we do so:
| | | | | | | | | | | |
Form of compensation
or benefit | Description | Purpose and
what it rewards | Interaction with other elements of
compensation or benefits |
| Base Salary | Regular cash income, paid semi-monthly. | Provides competitive and predictable regular compensation and rewards core competence and experience. | Is a fundamental or foundation component of our overall competitive pay mix; serves as a short-term feature to balance long-term incentives. |
Cash Bonus
(or
“short-term incentive
compensation”) | Part objectively performance-based cash awards and part discretionary or subjectively performance-based cash awards under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan. | Provides an annual incentive award in cash based on the attainment of designated objective and subjective performance measures, as well as based on committee discretion. | Serves as a short-term incentive to balance long-term incentives; rewards short-term performance, aligning executives’ interests with those of the stockholders in the short term. |
| Long-term Incentives | We generally used awards of restricted common stock as our form of long-term incentive compensation. Pay-out is generally staggered over a vesting period, although we have in the past also awarded retention shares structured to have a one-time “cliff” vesting feature. We tie a significant part of this award to attainment of certain performance criteria. | Provides long-term incentive to contribute to company performance and rewards corporate performance and continued service with company. | Balances the short-term features of our mix and motivates our executives to enhance corporate performance, further aligning executive interest with stockholder interests. |
| Indemnification | We indemnify our officers and directors to the fullest extent permitted by law. This is required by our charter, bylaws, and certain contracts. | We include this as a compensation element because it is commonly provided by peer organizations and is valued by our executives. We believe it allows our executives to be free from undue concern about personal liability for their service to the company and it rewards willingness to serve in positions that carry exposure to liability. | Represents a significant component of a competitive executive compensation package. |
| Medical, Dental, and Life Insurance | Available to full-time company employees through our benefit plans. The value of these is not included in the Summary Compensation Table, since they are available on a company-wide basis. | We include this as a compensation element as it is commonly provided by our competitors and it encourages the health of our employees, and adds to employee productivity and loyalty. | Represents a significant component of a competitive executive compensation package. |
| Executive Disability Insurance | This is a paid disability insurance premium benefit offered only to executive level employees. | We include this because it is a standard executive level benefit believed necessary to stay competitive in the market. | Works with other elements to create a competitive compensation package. |
| Other Paid Time-off Benefits | We provide vacation and other paid holidays to full-time employees, including the NEOs. | Rewards continuity of service and is a standard benefit comparable to the vacation benefits provided by competitors. | Works with other elements to create a competitive compensation package. |
| Unit Corporation Employees’ Thrift Plan [401(k) plan] | Tax-qualified retirement savings plan under which participating employees can contribute up to 99% of their pre-tax compensation, a portion of which the company can match. | A 401(k) plan is a standard corporate benefit and our match to the participants is a competitive feature of our plan. This benefit rewards continuity of service. | Works with our other executive pay components to create a competitive overall executive compensation package. |
Unit Corporation Salary Deferral Plan
[Non-qualified plan] | Our non-qualified plan allows designated participants to defer salary and cash bonus for tax purposes until actual distribution at termination, death, in service, or under defined hardship. We do not make matching contributions to this plan. | This element of compensation is a standard benefit at executive levels, and is a component of our program that contributes to our competitiveness. This rewards continuity of service. | Works with our other executive pay components to create a competitive overall executive compensation package. |
| Separation Benefits | We provide payments to salaried full-time employees in cases of involuntary termination, change-in-control, or on retirement after 20 years of service with the company. | This component of our program contributes to our competitiveness, and helps retain our employees. This benefit rewards length and continuity of service. | Works with our other executive pay components to create a competitive overall executive compensation package. |
| Perquisites | We provide a car allowance to our NEOs and pay for certain club memberships. | Compensating with certain perquisites adds to the general attractiveness and competitiveness of our compensation mix, and helps attract and retain the executive talent we value. | Works with our other executive pay components to create a competitive executive compensation program. |
Our compensation policies and program as they relate to risk management. The compensation committee conducted an annual compensation risk assessment at its October 2019 meeting. It received information about our compensation policies and programs for both executive and non-executive employees for 2019, including the structure of awards then outstanding under those programs. Based on its review, the committee concluded that our compensation policies and practices did not encourage
unreasonable or inappropriate risk taking, nor were they reasonably likely to have a material adverse effect on the company. The committee believes that the following factors help control or mitigate any potential compensation-related risks:
•We use a mix of fixed and variable, short-term and long-term compensation;
•Total payouts under all incentive award scenarios are not believed to be excessive based on compensation surveys and peer compensation level analyses, and are consistent with our financial resources;
•NEO incentive compensation is subject to clawback under specified circumstances;
•Controls are in place to enhance the integrity of recorded results on any objective performance measures;
•Our NEOs generally have substantial levels of stock ownership, reflecting alignment with our stockholders and providing a continuing incentive to align risk towards increasing stockholder value; and
•The NEOs’ performance-based awards have certain risk-mitigating features, including capped maximum payouts; appropriately tiered goals/performance metrics; and overlapping multi-year vesting terms for restricted stock awards.
Effect of stockholder say-on-pay vote on compensation decisions. The committee reviews the results of the previous year’s say-on-pay vote in making its executive compensation decisions. The voting results from the 2019 annual meeting of stockholders reflected that approximately 96.6% of shares voting on that item approved our 2018 executive compensation detailed in our 2019 proxy statement. The committee views the 96.6% approval rating as affirmation of its general approach to executive compensation and continues setting executive compensation as it has previously done, attempting to gauge competitive practices and authorizing compensation within the range of what is deemed competitive and appropriate in our industry. Based on the vote of our stockholders, we provide our stockholders an annual say-on-pay vote.
Administration of our executive compensation program – overview of the process. Our executive compensation program is administered by our compensation committee. The chair of the compensation committee, our CEO, and our vice president of human resources meet several times during the year to analyze the compensation packages for our executive and non-executive employees. Our CEO will usually make recommendations regarding salaries and any short- or long-term incentives awards for the NEOs besides himself. (See “Role of CEO” for greater detail on the role of the CEO.) None of our NEOs has a role in recommending his or her own compensation.
Each December the committee considers the CEO’s salary recommendations for non-CEO NEOs, along with any peer and market information presented to the committee, and decides the appropriate salary for the CEO and the other NEOs. The committee then presents its salary determination to the full board. Salaries that are adjusted from the previous year are effective starting January 1st of the new year. No action is taken regarding annual short-term incentive awards until sometime after the start of the year following the year to which the bonuses relate. This allows time for the complete financial and performance results for the prior year to be considered. Once that information is available any annual bonus awards for the prior year are determined. Long-term incentive awards are made prospectively, usually in the first quarter of the year to which they relate, and peer and performance information is considered at the time the awards are granted. So, for 2019, salary determinations were made in December 2018 effective January 1, 2019, long-term incentive awards were determined in February 2019, and short-term incentive awards were determined in February 2020 based on performance metrics and discretionary goals selected in early 2019. Equity awards are effective on the date of the committee’s approval of the award.
Generally, once the committee approves the NEOs’ compensation, the only adjustments that might be made before the committee’s next annual review would be those deemed necessary or useful due to a change in circumstances (e.g., a promotion or material increase in responsibility, or if a severe downturn in our industry occurs). It is possible, however, that the committee may make adjustments in the future based on changed circumstances, and those changes would be on an ad hoc basis and could affect any element of compensation based on the actual circumstances.
In selecting our NEOs’ overall compensation package, the committee considers the financial and operating results of the company or its segments, including:
•the growth in each segment of the company;
•net income, cash flow, asset base growth, and return on invested capital;
•long-term debt levels;
•any acquisitions made during the year;
•the attainment of any designated business objectives; and
•our compensation practices compared to those of other companies.
The committee may also consider any significant changes in or to our industry, and general economic conditions. Individual NEO contributions are noted in the context of considering our overall financial and operating results and in evaluating outcomes on any specific performance-based short- and long-term incentive awards. When performance-based awards are granted, the designated performance measures are selected in advance and certified by the committee early in the performance period. Performance goals or measures may change from year to year. Decisions on pay not tied to performance-based incentive awards are made at the committee’s discretion, with subjective goals sometimes attached. In those cases there is no weighting of assessed factors, no formulaic modeling of how to tie company or individual achievement to awards, no fixed position on whether prior compensation should be considered in making compensation decisions, or whether or how to incorporate any other criteria-based measures into the compensation-setting process.
Role of compensation consultant. The committee used Villareal Associates (Villareal), a Tulsa, Oklahoma-based compensation consultant, to assist it in determining the types and amounts of the compensation paid to our executives for 2019. The committee has used the services of Villareal as its independent compensation consultant since 2009. Villareal provided peer and survey information used in determining all components of our NEOs’ reported compensation. Villareal also worked with our management and the vice president of our human resources department to create the metrics used in our performance-based incentive awards.
In 2019, we incurred fees of $29,175 from Villareal, all of which was for executive compensation services. The committee’s selection of Villareal was not based on a recommendation by our management, but was based on the committee’s preferences. At its February 2020 meeting, the committee reviewed the compensation consultant independence questionnaire completed by Villareal. Based on Villareal’s answers to the questionnaire and committee discussion, the committee determined there is no conflict of interest created by Villareal’s work for either the committee or the company.
Role of CEO. Before those meetings when it decides our NEOs’ compensation, committee members receive and review the recommendations (and any information on which they are based) made by our CEO, regarding the salary and incentive-based compensation for the other NEOs. Our CEO does not evaluate or make a recommendation regarding his salary or incentive compensation. Our CEO also meets with the committee and discusses his recommendations. The executives subject to the CEO’s recommendations are not present during these deliberations. The compensation committee has the authority to accept, reject, or adjust the CEO’s recommendations or those made by any other person. After the committee has decided on the NEOs’ compensation, its determinations are then submitted to the full board. The board then ratifies (and approves, if required) the committee’s determinations. The board (acting through its independent directors only) has the authority to make any changes it feels are appropriate to the recommendations of the committee.
Peer group. The peer group we used in evaluating the executive compensation decisions being reported in this proxy statement is composed of companies we feel are the best match for us in industry and revenues, and, to a lesser degree, market capitalization. It is the committee’s view that annual revenues as opposed to market capitalization represent a better criterion to use in identifying energy companies for the peer group because revenue size is more stable over time and is more commonly used to evaluate compensation. Adjusted from our 2018 peer group by removal of Cabot Oil & Gas Corporation, Cimarex Energy Co., Newfield Exploration Company, and Parker Drilling Company (due to merger, bankruptcy or corporate restructuring) and the addition of Extraction Oil & Gas, Inc., Gulfport Energy Corporation, Precision Drilling Corporation, and SRC Energy, Inc. (companies deemed peer-appropriate in terms of revenues, market capitalization and line of business), our 2019 peer group includes the following companies (the “2019 peer group”):
| | | | | | | | | | | | | | |
| • | Carrizo Oil and Gas, Inc. | | • | Patterson – UTI Energy, Inc. |
| • | Denbury Resources, Inc. | | • | PDC Energy, Inc. |
| • | Extraction Oil & Gas, Inc. | | • | Pioneer Energy Services Corporation |
| • | Gulfport Energy Corporation | | • | Precision Drilling Corporation |
| • | Helmerich & Payne, Inc. | | • | SM Energy Company |
| • | Laredo Petroleum, Inc. | | • | SRC Energy, Inc. |
| • | Oasis Petroleum, Inc. | | • | Whiting Petroleum Corporation |
| | | • | WPX Energy, Inc. |
| | | | |
| | | | |
2019 salaries. Our NEOs’ salaries were determined at the compensation committee’s December 2018 meeting. At the committee’s October 2018 meeting, our vice president of human resources presented compensation survey data that indicated that industry-wide salary increases for 2019 would be between 3% and 3.3%. At the December 2018 meeting, Mr. Pinkston recommended NEO salary increases of 3% for all NEOs other than Mr. Austin. For Mr. Austin, who had received no 2018 salary increase due to his late 2017 start date, Mr. Pinkston recommended a 5.7% salary increase. Mr. Pinkston made no recommendation as to his own 2019 salary. In addition to the information provided by the vice president of human resources, along with the CEO’s recommendations, the committee reviewed total compensation information provided by our compensation consultant Villareal.
Villareal’s December 2018 materials included 2017 executive compensation market information obtained from SEC filings for the company’s executive compensation peer group consisting at that time of Cabot Oil & Gas Corporation, Carrizo Oil & Gas, Inc., Cimarex Energy Company, Denbury Resources, Inc., Helmerich & Payne, Inc., Laredo Petroleum, Inc., Newfield Exploration Company, Oasis Petroleum, Inc., Parker Drilling Company, Patterson - UTI Energy, Inc., PDC Energy, Inc., Pioneer Energy Services Corporation, SM Energy Company, Whiting Petroleum and WPX Energy, Inc. (the “2018 peer group”). The Villareal materials also included 2018 market compensation information based on survey data for executives with positions comparable to the NEOs, obtained from the 2018 Mercer Survey for energy companies with a $1.0 to $3.0 billion revenue range; the 2018 ECI Survey for energy companies and company divisions of size comparable to Unit; and Economic Research Institute’s Executive Compensation Assessor, providing data covering 2,000 industries and over 500 top management/executive positions, including energy companies of comparable size to Unit.
The Villareal materials reflected that overall, total cash compensation paid to our named executive officers for 2018 was 12% above the survey-based market as measured by the average total compensation for comparable executive positions (applying a 15% upward adjustment to market data for the General Counsel to better reflect his additional responsibilities), and that based on salary alone they were above the survey group by approximately 15%. However, the named executive officers’ 2018 total compensation was below market by 33% compared to the 2017 total compensation of the 2018 peer group according to proxy filings.
After review of the various materials provided to it at the December 2018 meeting, the committee approved a 5.7% increase for Mr. Austin and a 3.0% increase for all other NEOs as well as the CEO, determining the increases to be reasonable and competitive in the then-current market.
2019 long-term incentive awards. The NEOs’ 2019 long-term incentive awards were determined at the committee’s February 2019 meeting. Materials for the meeting included the 2018 segment highlights, substantially in the form that was included in our Annual Report on Form 10-K filed with the SEC on February 26, 2019, which listed various achievements by the company’s business segments during 2018. The committee also reviewed the CEO Performance Assessment Survey for 2019 performance completed by the non-employee directors. That survey indicated that on the whole the directors felt that the CEO was performing at a skilled or highly-skilled level.
The committee also reviewed and discussed materials prepared by Villareal. Referring to the companies in the 2019 peer group, Villareal’s February materials reflected the following:
•For the peer group NEOs for fiscal year 2017, the most recently-completed year for which proxy information was available as of the meeting date, average total compensation was $17 million and median total compensation was $16.5 million, while total 2017 compensation for the company’s NEOs (as set forth in its 2018 proxy statement) was $11.5 million;
•Mr. Pinkston’s total 2017 compensation was $4.2 million, compared to the $7 million average of the highest-paid positions for the peer group for 2017, and the company’s non-CEO NEOs’ average total compensation was $1.8 million, compared to the $2.5 million average total compensation paid to the second through fifth most highly-compensated peer group executives during 2017;
•For the period 2014 - 2017, the average ratio of NEO total long-term incentive awards to company cash flow (the “NEO LTI-to-cash-flow ratio”) for the peer group was 1.82%, compared to a NEO LTI-to-cash-flow ratio of 1.94% for the company;
•For the period 2014 - 2017, the average ratio of NEO total short-term incentive compensation to company cash flow (the “NEO STI-to-cash-flow ratio”) for the peer group was 0.69%, compared to a NEO STI-to-cash-flow ratio of 0.30% for the company; and
•For 2017, Mr. Pinkston received a total bonus of $0.72 million or 91.8% of salary compared to an average bonus to the highest paid peer group executives of $1.3 million or 173.9% of salary. Mr. Pinkston’s 2017
long-term incentive award was valued at $2.7 million or 340.5% of salary compared to an average long-term incentive for the highest paid peer group executives of $4.4 million or 575.8% of salary. The company’s 2017 group of non-CEO NEOs received an average bonus of $0.28 million or 63.9% of salary compared to an average bonus for the second through fifth most highly paid executives in the peer group of $0.54 million or 131.7% of salary, and the value of their long-term incentive awards averaged 244.2% of their salaries, compared to the average value of the comparable peer group employees’ long-term incentives at 374.6% of salaries.
Targets for NEO long-term incentive awards, which were set by the committee in February 2013 and continue to be used by the committee because they are believed to continue to represent market targets, were 329% of salary for the non-CEO NEOs and 400% of salary for the CEO. The committee decided that to pay competitively with the market, awards should be granted at 100% of target based on recent stock prices. The committee further decided that 60% of the stock awards should be performance based and 40% time vested. Half of the performance-based component (the “TSR Award”) would cliff vest at the end of a three-year performance period in an amount determined based on the company’s TSR for that period compared to the TSR of the peer companies during that time, and the other half (the “CFTA Award”) would vest in three annual installments in an amount determined based on the company’s consolidated cash-flow-to-assets ratio relative to the actual cash-flow-to-assets ratios of the 2019 peer companies for each of 2019, 2020, and 2021. The committee chose this award structure because it believes that TSR is a readily understood and commonly used measure of corporate performance aligning our management with our stockholders, that the cash-flow-to-assets ratio is a meaningful way to quantify the efficiency of the company’s use of its assets, and that comparing our performance on those measures to peer performance on the same measures provides additional meaningful performance information.
TSR award. The target number of shares for the TSR award is 30% of the total shares awarded each NEO for their 2019 long-term incentive awards (half the performance-based award), but the actual number of shares that vest could be more or less than target, depending on performance results. TSR for both the company and the 2019 peer group will be determined using this formula:
TSR = Ending stock price – Beginning stock price + Dividends
Beginning stock price
For the formula, the ending and beginning common stock price uses the average of the closing price of our common stock on the NYSE for the 15-trading-day period ending on the start and end of the designated performance period (February 19, 2019 to February 19, 2022) and the 2019 peer group stock prices are determined in the same manner. Based on application of the above formula, the number of performance-based shares that will ultimately vest for the NEOs will be determined by the TSR of the company relative to the TSR of the 2019 peer group at the end of the performance period, as follows:
| | | | | |
Company’s Performance
Percentile Rank
(Unit TSR vs. Peer TSR) | Vesting
(% that will vest) |
| >90 | 200% |
| 90 (Outstanding) | 200% |
| 75 | 150% |
| 60 (Target) | 100% |
| 50 | 75% |
| 40 (Threshold) | 50% |
| <40 | —% |
Straight line interpolation will determine the percentage of the awards that will vest when performance falls between the percentile ranks in the table above.
CFTA award. The CFTA award will vest annually in three installments beginning March 9, 2020. The target number of shares for each installment of the CFTA award are one third of the total CFTA award, which was 30% of the entire long-term incentive award (half the performance-based award), but the final number of shares that vest could be more or less, based on actual performance. For the award, cash flow is defined as cash flow before changes in assets and liabilities. The performance period is the three-year period consisting of fiscal years 2019, 2020, and 2021. The number of shares that vest will be determined by the percentile rank of the company’s actual consolidated cash-flow-to-assets ratio for each year in the
performance period relative to the actual consolidated cash-flow-to-assets ratio of the 2019 peer companies for each of those years (2019 for the first installment, 2020 for the second installment, and 2021 for the third installment), as follows:
| | | | | |
Company’s Performance
Percentile Rank
(Unit consolidated cash-flow-to-assets ratio vs.
Peer cash-flow-to-assets ratio) | Vesting
(% of each installment that will vest) |
| >90 | 200% |
| 90 (Outstanding) | 200% |
| 75 | 150% |
| 60 (Target) | 100% |
| 50 | 75% |
| 40 (Threshold) | 50% |
| <40 | —% |
Straight line interpolation will determine the percentage of the awards that will vest when performance falls between the percentile ranks in the table above.
2019 annual cash bonus awards. Our NEOs’ 2019 annual cash bonus short-term incentive awards (STIs) were made under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan based on performance goals determined early in the performance period. The awards certified for payment by the committee were determined based on the company’s objective performance on a "financial performance" award and a "scorecard" award (set forth at the end of this section). The committee considered the company’s financial circumstances and the conditions in the industry and chose not to make any discretionary cash bonus awards for 2019, despite recognizing the NEOs’ efforts toward accomplishing the four subjective goals tied to the discretionary component of the award (continued enhancement of cybersecurity measures, completion of a formal midstream strategic plan, implementation of corporate-culture-survey-related policy enhancements, and implementation of employee training/development and coaching programs).The percentage-of-salary targets chosen for the NEOs’ 2019 STIs were set at approximately 100% of the STI targets originally established for the NEOs in 2013 based on prevailing peer and competitor practices. The maximum possible payout for outstanding performance on the combined performance-based and discretionary short-term incentive award is 200% of salary for the CEO, and 140% of salary for the other NEOs.
The committee certified 2019 STIs as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2019 Short-term Incentive Cash Bonus Awards | | | | | | | | | | |
| Performance-based Component | %
of
Target | %
of
Salary | | Discretionary/ Subjective Goals Component | %
of
Target | %
of
Salary | | Total Cash Bonus | %
of
Salary |
| Mr. Pinkston | $330,613 | 62.1% | 37.25% | | — | — | — | | $330,613 | 37.25% |
| Mr. Merrill | $142,117 | 62.1% | 26.08% | | — | — | — | | $142,117 | 26.08% |
| Mr. Schell | $128,296 | 62.1% | 26.08% | | — | — | — | | $128,296 | 26.08% |
| Mr. Cromling | $134,850 | 68.9% | 28.94% | | — | — | — | | $134,850 | 28.94% |
| Mr. Austin | $96,483 | 62.1% | 26.08% | | — | — | — | | $96,483 | 26.08% |
The performance-based short-term incentives comprised two separate awards, a “financial performance award,” and a “scorecard award.” The financial performance award was computed in the same manner for all segments of the company, but weighted more heavily for Messrs. Pinkston, Schell, Merrill, and Austin, the corporate NEOs (60% of the total performance-based bonus amount), and less heavily for Mr. Cromling and the other heads of our business operating segments who participate in the performance award program (20% of the total performance-based bonus amount). The total performance-based incentives available to the NEOs for 2019 were multipliers of their salaries that were based on the level of performance achieved, as detailed in the scorecard tables at the end of this section. Amounts payable for performance falling between two performance levels is determined by straight line interpolation.
For purposes of the financial performance award, NEO performance was measured in terms of the company’s actual 2019 adjusted EBITDA, defined as “earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for non-cash gain or loss on derivatives, stock compensation expense, gain or loss on disposition of assets, impairments, and other
non-cash items (primarily debt related).” For an explanation of how the company calculated adjusted EBITDA for 2019 and a reconciliation of adjusted EBITDA to the measures the company believes to be the most directly comparable to those measures under GAAP, please see “Reconciliation of Adjusted EBITDA” on page 12 of our press release filed on Form 8-K on March 16, 2020 in which fourth quarter and year end 2019 results were announced. Adjusted EBITDA was selected as the performance measure for this component because it is believed to be a commonly-used and meaningful measure of performance both to stockholders and to the NEOs.
The scorecard component of the 2019 short-term incentive award was based on the performance of our three primary operating segments, and the performance metrics differed for each segment. The scorecard award for Messrs. Pinkston, Merrill, Schell, and Austin, our corporate-level NEOs, is referred to as the “corporate scorecard award.” The scorecard award for Mr. Cromling, Executive Vice President of Unit Drilling Company (UDC), is referred to as the “drilling segment scorecard award.” We have two additional operating subsidiaries, the heads of which participate in our performance award program: Unit Petroleum Company (UPC), our exploration and production segment, and Superior Pipeline Company, L.L.C. (SPC), our midstream segment. UPC’s Executive Vice President and SPC’s President are not named as NEOs and their compensation is not covered in this proxy statement, but the scorecards for their respective segments factor into the corporate scorecard award and are detailed in the footnotes to the scorecard table for Mr. Pinkston.
The goals selected for the operating segment heads were initially selected by our CEO in consultation with the individual segment heads, and they were submitted to and approved by the committee. Each year the CEO and the committee review and make changes to the goals as circumstances change. Each goal was chosen because it was believed to relate to an important and measurable financial, operating, or strategic goal of that operating segment. The process for setting the threshold, target and outstanding levels for each metric is dependent upon the metric. For many of the metrics, the “target” performance level is set based on the budget for the coming year and the “threshold” and “outstanding” numbers are then chosen within a reasonable range of the “target.” For other metrics, the “threshold” is set at a level that creates economic value for the company and its stockholders while the “target” and “outstanding” levels are set as significant improvements to the “threshold” level. The committee strives to maintain vigorous targets which may increase or decrease from the prior year's targets after considering the impact of industry conditions, commodity prices, capital spending budgets, segment objectives, and other factors.
2019 corporate scorecard award. The scorecard for Messrs. Pinkston, Merrill, Schell, and Austin was a composite of the scorecards of the three business segments. The segments were weighted 70% for the oil and natural gas segment, 15% for the drilling segment, and 15% for the midstream segment. This weighting was initially based on the relative expected cash flow contribution of each operating segment as projected at the time the awards were established, and then adjusted to ensure each segment’s weighting would be high enough to be relevant to the overall measurement. The incentive range for these awards is 40% of the performance based incentive opportunity range for the corporate NEOs, reflecting the weighting of the corporate scorecard award relative to the financial performance award for those NEOs.
2019 drilling segment scorecard award. The incentive range for the scorecard award as a whole was 80% of the total incentive opportunity range for this performance-based incentive award for the segment head. The drilling segment's scorecard award was determined based on the segment’s performance on four factors: (1) accidents per 200,000 man-hours; (2) cash flow per rig per day; (3) number of rigs operating; and (4) rig down-time.
The committee believes that safety is a paramount concern in the oil and gas drilling industry, and incentives tied to improved safety performance, such as reduced accidents per man hours worked, are believed to be in the best interests of that segment. Cash flow is a commonly-used financial measure in all areas of business, and the committee believes that for the drilling business, cash flow per rig per day is a valuable measure of financial performance. The number of rigs operating and rig down-time both reflect the operating efficiency of the organization and impact the bottom line of the business, so increased rig utilization and decreased rig downtime are worthwhile performance goals approved by the committee.
2019 exploration and production segment scorecard award. The incentive range for the scorecard award as a whole was 80% of the total incentive opportunity range for this performance-based incentive award for the segment head. For the head of our exploration and production segment, the performance measures approved were: (1) production replacement with new reserves; (2) rate of return for new wells drilled; (3) oil production growth; and (4) operating costs.
Rates of return and operating costs were selected as metrics because both will have measurable impact on the financial performance of the segment. Production growth and production replacement with new reserves were selected as metrics because they are both good measures of added value to the exploration and production segment.
2019 midstream segment scorecard award. The incentive range for the scorecard award as a whole was 80% of the incentive opportunity range for this performance-based incentive award for the segment head. This segment's scorecard performance was determined based on the segment's performance on these three factors: (1) volumes gathered; (2) return on invested capital; and (3) segment EBITDA.
Metrics tied to segment EBITDA and return on invested capital were selected because they are commonly used financial measures believed to provide meaningful measures of midstream segment performance and efficiency. Metrics tied to volumes gathered relates to an operational goal that enhances the midstream segment’s revenue and bottom line.
The amounts paid to the participating NEOs for the performance-based components of the 2019 cash bonus awards are set forth in the scorecard tables that follow.
John Cromling:
| | | | | | | | | | | | | | | | | | | | |
| A. Drilling Segment Scorecard Award | | | | | | |
Performance
Measure
(each weighted at 20%) | Threshold
(pays 16.80% of salary/4.20% per factor) | Target
(pays 33.60% of salary/8.40% per factor) | Outstanding
(pays 67.20% of salary/16.80% per factor) | Actual | % Salary Payable(1) | Bonus
Payable |
Accidents (2) | 1.63 | 1.45 | 1.09 | 2.10 | 0.00 | |
Cash Flow per Rig per Day (3) | $5,449.00 | $5,763.00 | $6,200.00 | $6,009.69 | 13.14 | |
Number of Rigs Operating (4) | 28.00 | 32.00 | 39.00 | 24.60 | 0.00 | |
Rig Down-time (5) | 0.83% | 0.75% | 0.64% | 0.71% | 11.45 | |
| Scorecard Total | | | | | 24.60 | |
| B. Financial Performance Award | | | | | | |
| | | | | | |
| Threshold
(4.20% of Salary) | Target
(8.40% of Salary) | Outstanding
(16.80% of Salary) | Actual | % Salary Payable | |
Unit Corporation Adjusted EBITDA (6) | $284,274,000 | $355,826,000 | $435,113,000 | $285,558,000 | 4.34 | |
| Financial Performance Award Total | | | | | 4.34 | |
| | | | | | |
| Total Objective Performance-based Bonus Award (A + B) for Mr. Cromling | | | | | | $ | 134,850 | |
_________________________
1.Decimals truncated so total is slightly off due to rounding.
2.Defined as number of recordable accidents per 200,000 man-hours worked.
3.Defined as average daily cash flow generated per rig in 2019.
4.Defined as average number of rigs operating per day in 2019.
5.Defined as total rig hours available but not billed as a ratio of total rig hours available.
6.Defined as 2019 earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for non-cash gain or loss on derivatives, stock compensation expense, gain or loss on disposition of assets, impairments and other non-cash items (primarily debt-related).
Larry Pinkston:
| | | | | | | | | | | | | | | | | | | | |
A. Corporate Scorecard Award (1) | | | | | | |
Performance Measure - Segment Scorecards (2) | Threshold | Target | Outstanding | Actual | % Salary Payable (3) | Bonus
Payable |
| UPC Scorecard | 16.80%
(8.40% of salary) | 33.60%
(16.80% of salary) | 67.20%
(33.60% of salary) | 27.73% | 13.87 | |
| UDC Scorecard | 16.80%
(1.80% of salary) | 33.60%
(3.60% of salary) | 67.20%
(7.20% of salary) | 24.60% | 2.64 | |
| SPC Scorecard | 15.00%
(1.80% of salary) | 30.00%
(3.60% of salary) | 60.00%
(7.20% of salary) | 17.88% | 2.15 | |
| Scorecard Total | | | | | 18.65 | |
B. Financial Performance Award (4) | | | | | | |
| Threshold
(18.00% of salary) | Target
(36.00% of salary) | Outstanding
(72.00% of salary) | Actual | % Salary Payable | |
Unit Corporation Adjusted EBITDA (5) | $284,274,000 | $355,826,000 | $435,113,000 | $285,558,000 | 18.61 | |
| Financial Performance Award Total | | | | | 18.61 | |
| | | | | | |
| Total Objective Performance-based Bonus Award (A + B) for Mr. Pinkston | | | | | | $ | 330,613 | |
_________________________
1.40% of total award opportunity, weighted by segment scorecards as follows: UPC - 70%, UDC - 15%, SPC - 15%.
2.Expressed as a percentage of salary payable to each division head for the Scorecard Award for his respective business segment. The UDC Scorecard entry corresponds to the “Scorecard Total” for Part A. of the table for Mr. Cromling, above. The UPC Scorecard entry is based on actual performance of our exploration and production segment, which is the “Scorecard Total” set forth in the following table:
| | | | | | | | | | | | | | | | | |
| Exploration & Production Segment Scorecard | | | | | |
| Threshold
(totals 16.8% of salary/4.20% per factor) | Target
(totals 33.60% of salary/8.40% per factor) | Outstanding
(totals 67.20% of salary/16.80% per factor) | Actual | % Salary Payable (a) |
Reserves Replacement (b) | 120.00% | 150.00% | 200.00% | (204.00)% | 0.00 |
Rate of Return - New Wells Drilled (c) | 18.00% | 21.00% | 26.00% | 1.30% | 0.00 |
Oil Production Growth (d) | 9.00% | 11.00% | 13.00% | 11.60% | 10.93 |
Operating Costs (e) | $1.44 | $1.33 | $1.22 | 1.21% | 16.80 |
| Scorecard Total | | | | | 27.73 |
_________________________
a.Decimals truncated so total is slightly off due to rounding.
b.Defined as percentage of 2018 reserves replaced through 2019 drilling activity.
c.Defined as overall rate of return on new wells drilled and PUDs converted in 2019.
d.Defined as percentage growth in number of barrels oil produced in 2019 compared to 2018.
e.Defined as total operating costs divided by total production in terms of MCF-equivalent amounts.
The SPC Scorecard entry is based on actual performance of our midstream segment, which is the “Scorecard Total” set forth in the following table:
| | | | | | | | | | | | | | | | | |
| Midstream Segment Scorecard | | | | | |
| Threshold
(totals 15.00% of salary/5.00% per factor) | Target
(totals 30.00% of salary/10.00% per factor) | Outstanding
(totals 60.00% of salary/20.00% per factor) | Actual | % Salary Payable (a) |
Volumes Gathered (b) | 144,161 MMCF | 159,778 MMCF | 180,201 MMCF | 159,011 MMCF | 9.75 |
Return on Invested Capital (c) | 7.00% | 7.50% | 8.50% | 6.67% | 0.00 |
Segment EBITDA (d) | $45,560,000 | $57,192,000 | $68,824,000 | $52,843,000 | 8.13 |
| Scorecard Total | | | | | 17.88 |
_________________________
a.Decimals truncated so total is slightly off due to rounding.
b.Defined as total volumes gathered for 2019
c.Defined as business unit EBITDA divided by the average invested capital for 2019.
d.Defined a business unit EBITDA for 2019.
3.Decimals truncated so total is slightly off due to rounding.
4.60% of total award opportunity.
5.Defined as 2019 earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for non-cash gain or loss on derivatives, stock compensation expense, gain or loss on disposition of assets, impairments and other non-cash items (primarily debt-related).
David Merrill:
| | | | | | | | | | | | | | | | | | | | |
A. Corporate Scorecard Award (1) | | | | | | |
Performance Measure - Segment Scorecards (2) | Threshold | Target | Outstanding | Actual | % Salary Payable (3) | Bonus
Payable |
| UPC Scorecard | 16.80%
(5.88% of salary) | 33.60%
(11.76% of salary) | 67.20%
(23.52% of salary) | 27.73% | 9.71 | |
| UDC Scorecard | 16.80%
(1.26% of salary) | 33.60%
(2.52% of salary) | 67.20%
(5.04% of salary) | 24.60% | 1.85 | |
| SPC Scorecard | 15.00%
(1.26% of salary) | 30.00%
(2.52% of salary) | 60.00%
(5.04% of salary) | 17.88% | 1.50 | |
| Scorecard Total | | | | | 13.05 | |
B. Financial Performance Award (4) | | | | | | |
| Threshold
(12.60% of salary) | Target
(25.20% of salary) | Outstanding
(50.40% of salary) | Actual | % Salary Payable | |
Unit Corporation Adjusted EBITDA (5) | $284,274,000 | $355,826,000 | $435,113,000 | $285,558,000 | 13.02 | |
| Financial Performance Award Total | | | | | 13.02 | |
| | | | | | |
| Total Objective Performance-based Bonus Award (A + B) for Mr. Merrill | | | | | | $ | 142,117 | |
_________________________
1.40% of total award opportunity, weighted by segment scorecards as follows: UPC - 70%, UDC - 15%, SPC - 15%.
2.Expressed as a percentage of salary payable to each division head for the Scorecard Award for his respective business segment. The UDC Scorecard entry corresponds to the “Scorecard Total” for Part A. of the table for Mr. Cromling, above. The UPC Scorecard entry and the SPC Scorecard entry are based on actual performance of our exploration and production and midstream segments, which are detailed in the respective “Scorecard Totals” set forth in the footnoted tables following Mr. Pinkston’s scorecard, above.
3.Decimals truncated so total is slightly off due to rounding.
4.60% of total award opportunity.
5.Defined as 2019 earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for non-cash gain or loss on derivatives, stock compensation expense, gain or loss on disposition of assets, impairments and other non-cash items (primarily debt-related).
Mark Schell:
| | | | | | | | | | | | | | | | | | | | |
A. Corporate Scorecard Award (1) | | | | | | |
Performance Measure - Segment Scorecards (2) | Threshold | Target | Outstanding | Actual | % Salary Payable (3) | Bonus
Payable |
| UPC Scorecard | 16.80%
(5.88% of salary) | 33.60%
(11.76% of salary) | 67.20%
(23.52% of salary) | 27.73% | 9.71 | |
| UDC Scorecard | 16.80%
(1.26% of salary) | 33.60%
(2.52% of salary) | 67.20%
(5.04% of salary) | 24.60% | 1.85 | |
| SPC Scorecard | 15.00%
(1.26% of salary) | 30.00%
(2.52% of salary) | 60.00%
(5.04% of salary) | 17.88% | 1.50 | |
| Scorecard Total | | | | | 13.05 | |
B. Financial Performance Award (4) | | | | | | |
| Threshold
(12.60% of salary) | Target
(25.20% of salary) | Outstanding
(50.40% of salary) | Actual | % Salary Payable | |
Unit Corporation Adjusted EBITDA (5) | $284,274,000 | $355,826,000 | $435,113,000 | $285,558,000 | 13.02 | |
| Financial Performance Award Total | | | | | 13.02 | |
| | | | | | |
| Total Objective Performance-based Bonus Award (A + B) for Mr. Schell | | | | | | $ | 128,296 | |
_________________________
1.40% of total award opportunity, weighted by segment scorecards as follows: UPC - 70%, UDC - 15%, SPC - 15%.
2.Expressed as a percentage of salary payable to each division head for the Scorecard Award for his respective business segment. The UDC Scorecard entry corresponds to the “Scorecard Total” for Part A. of the table for Mr. Cromling, above. The UPC Scorecard entry and the SPC Scorecard entry are based on actual performance of our exploration and production and midstream segments, which are detailed in the respective “Scorecard Totals” set forth in the footnoted tables following Mr. Pinkston’s scorecard, above.
3.Decimals truncated so total is slightly off due to rounding.
4.60% of total award opportunity.
5.Defined as 2019 earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for non-cash gain or loss on derivatives, stock compensation expense, gain or loss on disposition of assets, impairments and other non-cash items (primarily debt-related).
Les Austin:
| | | | | | | | | | | | | | | | | | | | |
A. Corporate Scorecard Award (1) | | | | | | |
Performance Measure - Segment Scorecards (2) | Threshold | Target | Outstanding | Actual | % Salary Payable (3) | Bonus
Payable |
| UPC Scorecard | 16.80%
(5.88% of salary) | 33.60%
(11.76% of salary) | 67.20%
(23.52% of salary) | 27.73% | 9.71 | |
| UDC Scorecard | 16.80%
(1.26% of salary) | 33.60%
(2.52% of salary) | 67.20%
(5.04% of salary) | 24.60% | 1.85 | |
| SPC Scorecard | 15.00%
(1.26% of salary) | 30.00%
(2.52% of salary) | 60.00%
(5.04% of salary) | 17.88% | 1.50 | |
| Scorecard Total | | | | | 13.05 | |
B. Financial Performance Award (4) | | | | | | |
| Threshold
(12.60% of salary) | Target
(25.20% of salary) | Outstanding
(50.40% of salary) | Actual | % Salary Payable | |
Unit Corporation Adjusted EBITDA (5) | $284,274,000 | $355,826,000 | $435,113,000 | $285,558,000 | 13.02 | |
| Financial Performance Award Total | | | | | 13.02 | |
| | | | | | |
| Total Objective Performance-based Bonus Award (A + B) for Mr. Austin | | | | | | $ | 96,483 | |
_________________________
1.40% of total award opportunity, weighted by segment scorecards as follows: UPC - 70%, UDC - 15%, SPC - 15%.
2.Expressed as a percentage of salary payable to each division head for the Scorecard Award for his respective business segment. The UDC Scorecard entry corresponds to the “Scorecard Total” for Part A. of the table for Mr. Cromling, above. The UPC Scorecard entry and the SPC Scorecard entry are based on actual performance of our exploration and production and midstream segments, which are detailed in the respective “Scorecard Totals” set forth in the footnoted tables following Mr. Pinkston’s scorecard, above.
3.Decimals truncated so total is slightly off due to rounding.
4.60% of total award opportunity.
5.Defined as 2019 earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for non-cash gain or loss on derivatives, stock compensation expense, gain or loss on disposition of assets, impairments and other non-cash items (primarily debt-related).
2019 compensation decisions pertaining to 2020 compensation. The following is provided as supplemental information beneficial to stockholders. It provides additional context to our fiscal year 2019 compensation decisions. This information will be analyzed in greater detail in our proxy statement for our 2021 annual meeting, since the information in this section relates to 2020 compensation.
At the December 10, 2019 compensation committee meeting, management recommended and the compensation committee and the board agreed that the NEOs should receive no salary increase for 2020. As determined at that time, annual salaries for the NEOs’ for 2020 were:
•Mr. Pinkston – $887,500
•Mr. Merrill – $545,000
•Mr. Schell – $492,000
•Mr. Cromling – $466,000
•Mr. Austin – $370,000
In February 2020 Mr. Pinkston announced that he would retire as Chief Executive Officer and President effective March 31, 2020. Also in February 2020, Mr. Merrill was elected by the board to replace Mr. Pinkston in those positions.
Performance-based stock awards vesting during or for fiscal year 2019. Vesting during 2019, for prior years’ performance: The three-year performance period for 2016 performance-based long-term incentive awards for Messrs. Pinkston, Merrill, Schell, and Cromling ended in February 2019, and the awards vested on March 9, 2019 at 200% of target based on the company’s actual performance at the 100th percentile of the 2016 peer group. Also vesting on March 9, 2019 for Messrs. Pinkston, Merrill, Schell and Cromling, the third tranche of the 2016 CFTA award vested at 100% of target for performance at the 50th percentile of the 2016 peer group, and the second tranche of the 2017 CFTA award vested at 75% of target for performance at the 50th percentile of the 2017 peer group. The first tranche of the 2018 CFTA award vested on March 9, 2019 for all NEOs at 57% of target for performance at the 42.80 percentile of the 2018 peer group.
•Mr. Pinkston – 84,516 shares
•Mr. Merrill – 37,454 shares
•Mr. Schell – 36,992 shares
•Mr. Cromling – 36,565 shares
•Mr. Austin – 3,230 shares
Awards scheduled to vest during 2020, for 2019 performance: No performance awards scheduled to vest March 9, 2020 for 2019 performance vested since all reflected below-threshold performance. Performance on the third tranche of the 2017 CFTA award was at the 30th percentile of the peer group. Performance on the 2017 TSR award was at the 38.4th percentile of the peer group. Performance for the second tranche of the 2018 CFTA award was at the 23rd percentile of the peer group. Performance on the first tranche of the 2019 CFTA award was at the 25th percentile of the peer group.
Stock ownership policy. All directors and NEOs are subject to our stock ownership and retention policy. As determined on the date of the policy’s original adoption (for officers and directors holding their positions at that time) or the date of election (for anyone not an officer or director at the time the policy was adopted), the policy requires non-employee directors to hold shares valued at three times the value of their annual retainer, the CEO to hold shares valued at five times the value of his or her base salary, and all remaining NEOs to hold shares valued at three times their base salaries. All covered officers and directors have five years from implementation of the policy or becoming a covered officer or director to become compliant with the policy and must hold 50% of all net shares received because of the exercise, vesting, or payment of any equity awards granted to them until they meet required holding levels. This summary of the policy is subject to the policy’s specific terms, a copy of which is set forth in our Corporate Governance Guidelines, available on our website at http://www.unitcorp.com/investor/governance.html. All of our non-employee directors and our NEOs other than Mr. Austin satisfy the ownership guidelines. Mr. Austin joined the company in November 2017 and has until November 2022 to meet the ownership guidelines set for him.
Policy on hedging and pledging our securities. We have a policy prohibiting our directors and NEOs (and any other officers filing Section 16 reports with the SEC) from hedging or pledging our common stock. The policy specifically prohibits the purchase, sale, or writing of “calls, puts, or other options or derivative instruments.” Based on their answers to our most recent directors and officers questionnaires, no directors or NEOs have hedged or pledged company stock. Non-Section 16 officers and all other employees are subject to a policy that strongly discourages engaging in “hedging or monetization transactions, such as zero-cost collars and forward sales contracts” and requires any proposed hedging transactions to be pre-cleared by our General Counsel. No employees requested clearance from the General Counsel for hedging transactions in 2019.
No backdating, spring-loading, or repricing of options. We do not backdate options, grant options retroactively, or reprice existing options. In addition, we do not coordinate grants of options to be made before announcement of favorable information, or after announcement of unfavorable information. Option and stock awards are granted at fair market value on the date the award is approved. Our general practice is to grant awards only on an annual grant basis, although sometimes grants have been made on other dates, such as for a newly-hired employee or special employee retention restricted stock awards.
Non-employee director compensation. The compensation committee recommends the form and amount of compensation for our non-employee directors to the board and the board makes the final determination. In deciding its recommendation, the compensation committee considers those factors it deems appropriate, including historical compensation information, level of compensation necessary to attract and retain non-employee directors meeting our desired qualifications, and market data from published surveys and from peer company proxy statements.
Tax considerations. Section 162(m). Section 162(m) of the Internal Revenue Code generally limits to $1 million annually the federal income tax deduction that a publicly-held corporation may claim for compensation payable to certain of its respective current and former executive officers, but that deduction limitation historically did not apply to performance-based compensation that met certain requirements. As part of the tax reform legislation passed in December 2017, Section 162(m) was amended, effective for taxable years beginning after December 31, 2017, to expand the scope of executive officers subject to the deduction limitation and to eliminate the performance-based compensation exception. Our compensation committee has not made any significant changes to our executive compensation program due to the loss of Section 162(m) deductibility.
Employment agreements. We do not have contracts with any of our NEOs governing the terms of their employment, but three of our NEOs have key employee contracts that address their rights in the limited event of a change of control of the company. Additional information regarding key employee contracts is contained in the discussion under the heading “Potential payments on termination or change in control.”
Summary Compensation Table For 2019
The following table sets forth information regarding the compensation paid, distributed, or earned by or for our NEOs for the stated fiscal years.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SUMMARY COMPENSATION TABLE | | | | | | | | | |
| Name and Principal Position | Year | Salary ($) (1) | Bonus ($) (1) (2) | Stock Awards ($) (3) | Option Awards
($) | Non- Equity Incentive Plan Compensation ($) (4) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (5) | All Other Compensation ($) (6) | Total
($) |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) |
| Larry D. Pinkston, President and CEO | 2019 | 887,500 | — | 2,701,661 | — | 330,613 | — | 31,089 | 3,950,863 |
| 2018 | 861,500 | 411,539 | 2,430,448 | — | 409,621 | — | 26,805 | 4,139,913 |
| 2017 | 780,500 | 376,209 | 2,657,873 | — | 340,163 | — | 26,454 | 4,181,199 |
David T. Merrill,
COO | 2019 | 545,000 | — | 1,364,477 | — | 142,117 | — | 43,357 | 2,094,951 |
| 2018 | 529,000 | 178,379 | 1,315,463 | — | 177,548 | — | 35,540 | 2,235,930 |
| 2017 | 481,036 | 171,696 | 1,147,684 | — | 155,244 | — | 34,525 | 1,990,185 |
Mark E. Schell,
Sr. V.P., Secretary, and
General Counsel | 2019 | 492,000 | — | 1,231,901 | — | 128,296 | — | 35,341 | 1,887,538 |
| 2018 | 477,600 | 161,047 | 1,187,388 | — | 160,296 | — | 27,848 | 2,014,179 |
| 2017 | 463,600 | 154,980 | 1,147,684 | — | 140,131 | — | 27,376 | 1,933,771 |
John H. Cromling,
Executive V.P. - Drilling | 2019 | 466,000 | — | 1,166,644 | — | 134,850 | — | 36,935 | 1,804,429 |
| 2018 | 452,300 | 152,516 | 1,068,808 | — | 153,065 | — | 30,565 | 1,857,254 |
| 2017 | 417,300 | 125,834 | 1,147,684 | — | 115,604 | — | 32,144 | 1,838,566 |
G. Les Austin
Sr. V.P. and CFO | 2019 | 370,000 | — | 902,782 | — | 96,483 | — | 42,242 | 1,411,507 |
| 2018 | 350,000 | 118,020 | 896,443 | — | 117,470 | — | 36,057 | 1,517,990 |
| 2017 | 34,551 | — | 203,900 | — | — | — | 567 | 239,018 |
_________________________
1.Compensation deferred at the election of an executive is included in the year earned.
2.Amounts in column (d) reflect the bonus amount earned in the year without regard to when those amounts were actually paid, and do not include amounts, if any, earned in prior years but paid in the stated year. All amounts listed were awarded and paid during the subsequent fiscal year, but are compensation for the year listed, and were paid at the discretion of the compensation committee in view of its assessment of performance on four subjective performance goals.
3.For 2019, the amounts included in the “Stock Awards” column for the performance-based awards ($1,323,260 for Mr. Pinkston, $668,321 for Mr. Merrill, $603,380 for Mr. Schell, $571,423 for Mr. Cromling, and $442,179 for Mr. Austin) are the aggregate grant date fair value of these awards based on a probability analysis projecting a 28% payout on the TSR award for performance at the 17.90 percentile of the peer group and 100% payout on the CFTA award for performance at the 60th percentile of the peer group, as computed in accordance with FASB ASC Topic 718 “Stock Compensation,” which excludes the effect of estimated forfeitures. For a discussion of the valuation assumptions used in calculating these values for 2019, see Notes 2 and 12 to our Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2019. The amount shown does not represent amounts paid to the NEOs. If performance had been at its highest level, the award payout for the performance-based component of the restricted stock awards included in the “Stock Awards” column would be at 200%, and would be as follows:
| | | | | | | | | | | |
| Name | 2019 | 2018 | 2017 |
| Larry D. Pinkston | $4,135,187 | $3,734,364 | $3,087,547 |
| David T. Merrill | $2,088,502 | $2,021,219 | $1,333,266 |
| Mark E. Schell | $1,885,564 | $1,855,030 | $1,333,266 |
| John H. Cromling | $1,785,698 | $1,642,235 | $1,333,266 |
| G. Les Austin | $1,381,791 | $1,377,356 | N/A |
4.Reflects component of cash bonuses paid based on objective performance metrics set in advance by the compensation committee under the company’s Stock and Incentive Compensation Plan.
5.We do not provide for preferential or above-market earnings on deferred compensation.
6.The table below shows the components of this column for the last fiscal year:
| | | | | | | | | | | | | | | | | |
| Name | Executive Disability Insurance Premium
($) | 401(k) Match ($) (a) | Personal Car
Allowance
($) | Club
Membership
($) | Total “All
Other
Compensation”
($) |
| Larry D. Pinkston | 3,933 | 19,656 | 7,500 | — | 31,089 |
| David T. Merrill | 7,596 | 19,656 | 6,000 | 10,105 | 43,357 |
| Mark E. Schell | 7,122 | 19,656 | 7,500 | 1,063 | 35,341 |
| John H. Cromling | 2,799 | 19,656 | 5,325(b) | 9,155 | 36,935 |
| G. Les Austin | 5,912 | 19,656 | 6,000 | 10,674 | 42,242 |
_________________________
a.Match was made in cash.
b.Represents imputed taxable value attributed to Mr. Cromling’s use of a company vehicle.
Grants of Plan-Based Awards for 2019
In 2019, the NEOs received the following plan-based awards:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| GRANTS OF PLAN-BASED AWARDS FOR 2019 | | | | | | | | | | | | |
| Name | Grant
Date | Approval Date | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | | | Estimated Future Payouts Under Equity Incentive Plan Awards (2) | | | All Other Stock Awards: Number of Shares of Stock or Units (3) (#) | All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#) | Exercise or
Base Price
of Option
Awards
($/sh) | Grant Date Fair Value of Stock and Option Awards (4) ($) |
| | | Threshold
($) | Target
($) | Maxi-mum
($) | Thresh-
old
(#
shares) | Target
(#
shares) | Maxi-
mum
(# shares) | | | | |
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | (i) | (j) | (k) | (l) | (m) |
| Larry D. Pinkston | 2/19/19 | 2/19/19 | | | | 61,904 | | 123,808 | | 247,616 | | | | | 1,323,260 | |
| 2/19/19 | 2/19/19 | | | | | | | 82,539 | | | | 1,378,401 | |
| | | 266,250 | | 532,500 | | 1,065,000 | | | | | | | | |
| David T. Merrill | 2/19/19 | 2/19/19 | | | | 31,625 | | 62,530 | | 125,060 | | | | | 668,321 | |
| 2/19/19 | 2/19/19 | | | | | | | 41,686 | | | | 696,156 | |
| | | 114,450 | | 228,900 | | 457,800 | | | | | | | | |
| Mark E. Schell | 2/19/19 | 2/19/19 | | | | 28,227 | | 56,454 | | 112,908 | | | | | 603,380 | |
| 2/19/19 | 2/19/19 | | | | | | | 37,636 | | | | 628,521 | |
| | | 103,320 | | 206,640 | | 413,280 | | | | | | | | |
| John H. Cromling | 2/19/19 | 2/19/19 | | | | 26,732 | | 53,464 | | 106,928 | | | | | 571,423 | |
| 2/19/19 | 2/19/19 | | | | | | | 35,642 | | | | 595,221 | |
| | | 97,860 | | 195,720 | | 391,440 | | | | | | | | |
| G. Les Austin | 2/19/19 | 2/19/19 | | | | 20,686 | | 41,371 | | 82,742 | | | | | 442,179 | |
| 2/19/19 | 2/19/19 | | | | | | | 27,581 | | | | 460,603 | |
| | | 77,700 | | 155,400 | | 310,800 | | | | | | | | |
_________________________
1.Reflects threshold, target, and maximum payout levels possible for each NEO on the non-discretionary component of the 2019 short-term incentive award (the financial performance and scorecard awards) if certain performance objectives were achieved between January 1, 2019 and December 31, 2019. Actual awards were paid in February 2020, and were: for Mr. Pinkston, $330,613 (62.1% of target); for Mr. Merrill, $142,117 (62.1% of target); for Mr. Schell, $128,296 (62.1% of target); for Mr. Cromling, $134,850 (68.9% of target); and for Mr. Austin, $96,483 (62.1% of target).
2.Reflects threshold, target, and maximum vesting levels for performance-based restricted stock granted under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan. Actual vesting amounts will be determined based on performance outcomes during the three-year performance period that ends February 19, 2022. Half of the stated amount (the “CFTA Award”) will vest in annual increments in each of 2020, 2021, and 2022 in amounts determined based on the company’s cash-flow-to-assets ratio relative to the cash-flow-to-assets ratios of the companies in the 2019 peer group for each of those years. The other half of the stated amount (the “TSR Award”) will vest based on the company’s three-year TSR relative to the three-year TSR of the companies in the 2019 peer group. For both the CFTA Award and the TSR Award, Threshold payout requires performance at the 40th percentile, Target payout requires performance at the 60th percentile, and Maximum payout requires performance at the 90th percentile of the 2019 peer group. Performance between levels will be determined based on interpolation for both the CFTA Award and the TSR Award.
3.Represents time-vested shares of restricted stock granted under the Second Amended and Restated Stock and Incentive Compensation Plan. Shares will vest in three equal annual installments on March 9th of each year 2020 through 2022.
4.Grant date fair value of the performance-based restricted stock awards granted February 19, 2019, as follows: for the CFTA Award, reflects vesting at 100% of target level for performance at the 60th percentile of the peer group, and for the TSR Award reflects vesting at 28% of target for performance at the 17.90 percentile of the 2019 peer group, both based on the probable outcome of performance conditions on the date of grant as determined under FASB ASC 718.
Material factors necessary to an understanding of the information in the table above are discussed at length in our Compensation Discussion and Analysis under the captions "2019 long-term incentive awards" and "2019 annual cash bonus awards."
For 2019, 32% of our NEOs’ total compensation consisted of salaries and annual bonuses and 66.1% consisted of restricted stock awards. For 2018, 40% of our NEOs’ total compensation consisted of salaries and annual bonuses and 58.6% consisted of restricted stock awards. For 2017, 35.8% of our NEOs’ total compensation consisted of salaries and annual bonuses and 63.6% consisted of restricted stock awards.
Of the 562,711 shares of restricted stock granted to our NEOs in 2019, 337,627 shares are subject to performance-based conditions (calculated assuming that vesting occurs at the target level), and the remaining 225,084 shares are subject to the condition that the recipient must be employed with us on the vesting date to receive the shares. If a change-in-control occurs, any unvested shares immediately vest in the recipient. The recipient of each restricted stock award has the rights of a holder of shares of our common stock, including the right to vote those shares and to receive any cash dividends paid on them. The compensation committee may, however, determine that cash dividends be automatically reinvested in additional shares which become shares of restricted stock and have the same restrictions and other terms of the award. To date, we have not issued dividends on our common stock.
Outstanding Equity Awards at End of 2019
This table shows outstanding equity awards at December 31, 2019 for each of the NEOs:
| | | | | | | | | | | | | | |
| OUTSTANDING EQUITY AWARDS AT END OF 2019 | | | | |
| Stock Awards | | | |
| Name | Number of Shares or Units of Stock That Have Not Vested (1) (#) | Market Value of Shares or Units of Stock That Have Not Vested (2) ($) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (1) (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (2) ($) |
| (a) | (g) | (h) | (i) | (j) |
| Larry D. Pinkston | 136,533 | 95,573 | 82,308 | 57,616 |
| David T. Merrill | 69,483 | 48,638 | 42,683 | 29,878 |
| Mark E. Schell | 63,275 | 44,293 | 38,533 | 26,973 |
| John H. Cromling | 59,282 | 41,497 | 35,787 | 25,051 |
| G. Les Austin | 46,022 | 32,215 | 28,570 | 19,999 |
_________________________
1.Vesting dates for unvested time-vesting restricted stock and unvested and unearned performance-based restricted stock are shown in the table that follows. The number of shares of performance-based restricted stock shown to vest on March 9, 2020 reflects actual payout at 0% of target for performance at the 38.4th percentile of the peer group on the 2017 TSR award and the third tranche of the 2017 CFTA award; actual payout at 0% of target for performance at the 23rd percentile of the peer group on the second tranche of the 2018 CFTA award, and actual payout at 0% of target for performance at the 25th percentile of the peer group on the first tranche of the 2019 CFTA award. The number of shares of performance-based stock shown to vest on March 9, 2021 reflect projected threshold payout at 50% of target for performance at the 40th percentile of the peer group on the 2018 TSR award, the third tranche of the 2018 CFTA award, and the second tranche of the 2019 CFTA award. The number of shares of performance-based stock shown to vest on March 9, 2022 reflect projected threshold payout at 50% of target for performance at the 40th percentile of the peer group for the 2019 TSR award and the third tranche of the 2019 CFTA award.
| | | | | | | | | | | | | | |
| Unvested Restricted Stock | | Unvested and Unearned
Performance-based
Restricted Stock | |
| Name | # Shares | Vesting Date | # Shares | Vesting Date |
| Larry D. Pinkston | 61,027 | 3/9/20 | — | 3/9/20 |
| 47,993 | 3/9/21 | 41,039 | 3/9/21 |
| 27,513 | 3/9/22 | 41,269 | 3/9/22 |
| David T. Merrill | 30,609 | 3/9/20 | — | 3/9/20 |
| 24,979 | 3/9/21 | 21,839 | 3/9/21 |
| 13,895 | 3/9/22 | 20,844 | 3/9/22 |
| Mark E. Schell | 28,180 | 3/9/20 | — | 3/9/20 |
| 22,550 | 3/9/21 | 19,714 | 3/9/21 |
| 12,545 | 3/9/22 | 18,819 | 3/9/22 |
| John H. Cromling | 26,515 | 3/9/20 | — | 3/9/20 |
| 20,887 | 3/9/21 | 17,966 | 3/9/21 |
| 11,880 | 3/9/22 | 17,821 | 3/9/22 |
| G. Les Austin | 16,748 | 3/9/20 | — | 3/9/20 |
| 3,333 | 11/27/20 | 14,779 | 3/9/21 |
| 16,748 | 3/9/21 | 13,791 | 3/9/22 |
| 9,193 | 3/9/22 | | |
2.Market value is determined based on a market value of our common stock of $0.70, the closing price of our common stock on the NYSE on December 31, 2019, the last trading day of the year.
Option Exercises and Stock Vested Table for 2019
The table below shows information regarding options and stock awards exercised and vested, respectively, for the NEOs in 2019:
| | | | | | | | | | |
| OPTION EXERCISES AND STOCK VESTED FOR 2019 | | | | |
| Name | | | Stock Awards | |
| | | Number of
Shares
Acquired
on Vesting
(#) | Value Realized on Vesting ($) (1) |
| (a) | | | (d) | (e) |
| Larry D. Pinkston | | | 105,203 | 1,471,790 |
| David T. Merrill | | | 47,669 | 666,889 |
| Mark E. Schell | | | 46,590 | 651,794 |
| John H. Cromling | | | 45,591 | 637,818 |
| G. Les Austin | | | 10,887 | 152,309 |
_________________________
1.Value realized equals fair market value of the stock on the date of vesting times the number of shares acquired.
Non-qualified Deferred Compensation for 2019
We permit the NEOs and certain other employees to elect to receive a portion of their compensation on a deferred basis under our salary deferral plan (an unsecured, non-qualified, deferred compensation plan).
Under this plan, each participant may elect to defer up to 100% of his or her salary and any cash bonuses he or she may have earned. Deferrals (including earnings) are credited with investment gains and losses until the amounts are paid out. Account balances are deemed invested in phantom investments selected by the executive from an array of investment options
that are similar to the funds in our 401(k) plan, subject to restrictions established by the plan administrator. To date, we have not provided matching contributions under this plan.
At the participant’s election, the plan balance may be paid as a lump sum, annual, or monthly installments over a period of up to 10 years. Despite the foregoing, a participant may elect to receive a lump sum distribution from the plan in the event of certain severe financial hardships. The amount of any hardship distribution may not exceed the amount necessary to satisfy the hardship.
The following table shows the NEOs’ contributions, earnings and account balances in our non-qualified plan as of December 31, 2019.
| | | | | | | | | | | | | | | | | |
| NON-QUALIFIED DEFERRED COMPENSATION FOR 2019 | | | | | |
| Name | Executive Contributions in Last Fiscal Year (1) ($) | Registrant Contributions in Last Fiscal Year (2) ($) | Aggregate
Earnings in
Last Fiscal Year
($) | Aggregate
Withdrawals/
Distributions
($) | Aggregate Balance at End of Last Fiscal Year (1) (3) ($) |
| (a) | (b) | (c) | (d) | (e) | (f) |
| Larry D. Pinkston | — | — | 76,046 | — | 1,311,556 |
| David T. Merrill | — | — | 108,514 | — | 466,372 |
| Mark E. Schell | 24,600 | — | 328,033 | — | 1,249,659 |
| John H. Cromling | — | — | — | — | — |
| G. Les Austin | — | — | — | — | — |
_________________________
1.Only Mr. Schell contributed to the non-qualified deferred compensation plan in 2019. Column (b) amounts are those designated by the NEOs for deferral from 2019 compensation to their respective non-qualified deferred compensation accounts. Amounts that appear in both the Non-Qualified Deferred Compensation Table for 2019 and the Summary Compensation Table for 2019 are set forth in the table below. The table below also quantifies the amounts in the “Aggregate Balance” column (column (f) above)) that represent salary or bonus reported in the Summary Compensation Tables for proxy statements in prior years.
| | | | | | | | |
| Name | Amount included in both
Non-qualified Deferred
Compensation Table and
Summary Compensation Table
for Last Completed Fiscal Year
($) | Amount included in
Non-qualified Deferred
Compensation Table
previously reported in
prior years’ Summary
Compensation Tables
($) |
| Larry D. Pinkston | — | 706,831 |
| David T. Merrill | — | 155,642 |
| Mark E. Schell | 24,600 | 329,266 |
| John H. Cromling | — | — |
| G. Les Austin | — | — |
2.We do not make employer contributions to our non-qualified deferral plan.
3.The aggregate balances represent 2019 executive contributions and associated earnings, as well as amounts that the NEOs earned but elected to defer, plus earnings or losses from prior years’ participation in this plan.
CEO Pay Ratio Disclosure
In accordance with Instruction G(3)Section 953(b) of Form 10-K,the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we calculated a reasonable estimate of the ratio of the annual total compensation of Mr. Pinkston, our CEO, compared to that of our median employee in 2019.
We identified our median employee as of December 31, 2019, using the methodology and the material assumptions and estimates described below:
•We calculated the total annual compensation for all employees using full fiscal year salary, 2019 stock awards valued on the grant date, bonuses paid during fiscal year 2019, and "other compensation" data such as perquisites and company 401(k) thrift plan matches;
•We did not take a cost-of-living adjustment for identifying the median employee in 2019;
•No sampling or "de minimus" exceptions were used to exclude any employees; and
•Compensation for part-time employees as well as any newly-hired employees who had worked less than a year was annualized in determining our median employee.
Our CEO Mr. Pinkston had annual total compensation for 2019 of $3,950,863 as reflected in the Summary Compensation Table. Our median employee’s annual total compensation for 2019 was $102,374. As a result, we estimate that Mr. Pinkston’s 2019 annual total compensation was approximately 38.6 times that of our median employee.
Potential Payments on Termination or Change in Control
The discussion below summarizes the plans and contracts under which our NEOs would be entitled to certain compensation if that executive’s employment terminates.
Single-trigger provisions in the plans apply equally to all salaried full-time employees, including all of our NEOs (see Separation Benefit Plan and Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan, as described below). The key employee contracts that apply to three of our NEOs contain double-trigger provisions. It is our belief that our plans’ change-in-control provisions benefit the company by enhancing the quality and stability of our workforce, as those benefits serve as incentives to our employees to remain with the company. The single-trigger provision in the broader-based plans should avoid the potential ambiguity or confusion that might result on the part of the participants in those plans should a change in control occur.
The amounts actually paid out can only be determined on the NEO’s separation from service, and may well be different than the figures set forth below. This discussion is qualified entirely by the applicable plan documents.
Separation Benefit Plan
On December 20, 1996, effective as of January 1, 1997, our board adopted the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries. This plan is generally applicable to all of our full-time salaried employees and to the salaried employees of our subsidiaries who have been with their employer for at least one year. Subject to the terms of the plan, any eligible employee whose employment is terminated may receive a separation benefit in an amount calculated by dividing the eligible employee’s highest annual base salary in effect during the five-year period before the employee’s separation by 52 to determine a weekly separation benefit amount. The number of weekly separation benefit payments then payable to an eligible employee is calculated based on the employee’s years of service under a schedule in the plan. Employees who voluntarily leave their employment are not entitled to receive a separation benefit unless they have completed at least 20 years of service. Any eligible employee who has completed 20 years of service or more is vested in his or her separation benefit, subject to fulfilling the other requirements of the plan. Separation benefit payments are limited to a maximum of 104 weekly payments. The plan also provides that, unless otherwise determined by our board before a change in control of the company, as defined in the plan, all eligible employees vest in their separation benefit as of the date of the change in control based on their years of service. As a condition to receiving the separation benefits, employees must sign a separation agreement waiving certain claims the employee may have against the company or its subsidiaries.
This table identifies the amounts due to each of our NEOs if those amounts were determined as of December 31, 2019.
| | | | | |
| Estimated Benefit Amounts as of December 31, 2019 | |
| Name | Amount Due Under Plan ($) (1) |
| Larry D. Pinkston | 1,775,000 |
| David T. Merrill | 670,769 |
| Mark E. Schell | 984,000 |
| John H. Cromling | 788,616 |
| G. Les Austin | 59,923 |
_________________________
1.Assumes for this disclosure only that the amount shown has either vested under the plan or that a change in control of the company (as defined in the plan) has occurred.
Change-in-Control Arrangements
Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan. Unless the successor company assumes or replaces them (and there is no termination of employment within twelve months of a change of control), the restricted shares of stock awarded under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan vest immediately if a change in control of the company occurs. Under that plan, a change in control is generally defined as:
1.Any individual, entity or group acquiring beneficial ownership of 20% or more of either the outstanding shares of the company’s common stock or the combined voting power of the outstanding voting securities of the company entitled to vote generally for the election of directors;
2.Individuals who constitute the board on the date thereof ceasing to constitute a majority of the board (provided that an individual whose election or nomination as a director is approved by a vote of at least a majority of the directors as of the date thereof will be deemed a member of the incumbent board);
3.Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all the assets of the company or acquiring assets of another entity, unless following the business combination:
•all or substantially all the beneficial owners of the company’s then outstanding common stock before the business combination own over 70% of the outstanding common stock of the company resulting from the business combination;
•no person, entity or group owns 25% or more of the outstanding voting securities of the company resulting from the business combination; and
•at least a majority of the board of the company resulting from the business combination were members of the company’s board before the business combination; or
4.Approval by our stockholders of a complete liquidation or dissolution of the company.
Key Employee Contracts. We have entered into key employee change-in-control contracts with Messrs. Pinkston, Schell, and Merrill. These contracts have an initial three-year term automatically extended for one year on each anniversary, unless a notice not to extend is given by us. If a change in control of the company (as defined below) occurs during the term of the contract, then the contract becomes operative for a fixed three-year period. The contracts generally provide that the executive’s terms and conditions of employment (including position, work location, compensation and benefits) will not be adversely changed during the three-year period after a change in control. If the executive’s employment is terminated by the company (other than for cause, death, or disability) during the three-year period, the executive terminates for good reason during the three-year period, or the executive terminates employment during the 30-day period following the first anniversary of the change in control, and on certain terminations of employment in connection with or in anticipation of a change in control, the executive is generally entitled to receive the following from the company in a lump sum:
•earned but unpaid compensation;
•three times the executive’s base salary plus annual bonus (based on historic annual bonus); and
•the company matching contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for an additional three years.
In addition, the contract provides for a continuation of various medical, dental, disability and life insurance plans for a period of three years, outplacement services and the payment of all legal fees and expenses incurred by the executive in enforcing any right or benefit provided by the contract. The contract provides that the executive will receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under the Internal Revenue Code. The executive must agree to retain in confidence any and all confidential information known to him about the company and its business if the information requiredis not otherwise publicly disclosed.
For these contracts, a change in control is generally defined as:
1.Any individual, entity or group acquiring beneficial ownership of 15% or more of either the outstanding shares of the company’s common stock or the combined voting power of the outstanding voting securities of the company entitled to vote generally for the election of directors;
2.Individuals who constitute the board on the date thereof cease to constitute a majority of the board, provided that an individual whose election or nomination as a director is approved by this Item is incorporated into this reporta vote of at least a majority of the directors as of the date thereof will be deemed a member of the incumbent board;
3.Approval by referenceour stockholders of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the company or acquiring assets of another entity, unless following the business combination:
•all or substantially all of the beneficial owners of our outstanding common stock before the business combination own over 60% of the outstanding common stock of the corporation resulting from the business combination;
•no person, entity or group owns 15% or more of the outstanding voting securities of the corporation resulting from the business combination; and
•at least a majority of the board of the company resulting from the business combination were members of the company’s board prior to the Proxy Statement (see Item 10 above)business combination; or
4.Approval by our stockholders of a complete liquidation or dissolution of the company.
Payments on Termination or Change-in-Control Table
This table sets forth quantitative information regarding potential payments to be made to our NEOs or their beneficiaries on termination under various circumstances, assuming termination on December 31, 2019. The potential payments are based on the plans maintained by us and the negotiated contractual terms of certain agreements we have made with some of the NEOs. For a more detailed description, see the discussion of each plan and agreement above. These disclosed amounts are estimates only and do not necessarily reflect the actual amounts that would be paid to the executive. Actual amounts would only be known when they would become due under the plan(s) or agreement. The amounts in the table below are additional to each of the NEO’s deferred compensation noted in the “Non-Qualified Deferred Compensation for 2019” table.
| | | | | | | | | | | | | | | | | | | | | | | |
| TYPE OF TRIGGERING EVENT | | | | | | | |
Named Executive
Officer | Death or
Disability
$ | Voluntary
Termination
or
Retirement
$ | Change in
Control
Without
Termination
$ | Termination
by Company
for Cause
$ | Termination
by Company
Without Cause
Unrelated to
Change in
Control
$ | Termination
by Company
or by
Executive
for Good
Reason After
Change in
Control
$ | Termination
by Executive
Without Good
Reason After
Change in
Control
$ |
| Larry D. Pinkston | | | | | | | |
| Key Employee Contract Payments: | | | | | | | |
Salary under contract formula (1) | — | — | — | — | — | 2,662,500 | — |
Bonus under contract formula (1) | — | — | — | — | — | 2,463,480 | — |
| Previously-earned but unpaid bonus amounts | — | — | — | — | — | — | — |
| Tax Gross-up | — | — | — | — | — | — | — |
| 36 months 401(k) company match | — | — | — | — | — | 58,968 | — |
Health Insurance (2) | — | — | — | — | — | 32,808 | — |
Disability Insurance (2) | — | — | — | — | — | 14,026 | — |
| Life and AD&D Insurance | — | — | — | — | — | 2,930 | — |
| Outplacement Services | — | — | — | — | — | 30,000 | — |
Stock Awards (3) | 325,276 | — | 325,276 | — | — | 325,276 | 325,276 |
| Option and SARs Awards | — | — | — | — | — | — | — |
| Separation Benefit Plan Payment | 1,775,000 | 1,775,000 | — | — | 1,775,000 | 1,775,000 | 1,775,000 |
| 2,100,276 | 1,775,000 | 325,276 | — | 1,775,000 | 7,364,988 | 2,100,276 |
| | | | | | | | | | | | | | | | | | | | | | | |
| TYPE OF TRIGGERING EVENT | | | | | | | |
Named Executive
Officer | Death or
Disability
$ | Voluntary
Termination
or
Retirement
$ | Change in
Control
Without
Termination
$ | Termination
by Company
for Cause
$ | Termination
by Company
Without Cause
Unrelated to
Change in
Control
$ | Termination
by Company
or by
Executive
for Good
Reason After
Change in
Control
$ | Termination
by Executive
Without Good
Reason After
Change in
Control
$ |
| David T. Merrill | | | | | | | |
| Key Employee Contract Payments: | | | | | | | |
Salary under contract formula (1) | — | — | — | — | — | 1,635,000 | — |
Bonus under contract formula (1) | — | — | — | — | — | 1,067,781 | — |
| Previously-earned but unpaid bonus amounts | — | — | — | — | — | — | — |
| Tax Gross-up | — | — | — | — | — | — | — |
| 36 months 401(k) company match | — | — | — | — | — | 58,968 | — |
Health Insurance (2) | — | — | — | — | — | 36,860 | — |
Disability Insurance (2) | — | — | — | — | — | 25,016 | — |
| Life and AD&D Insurance | — | — | — | — | — | 2,930 | — |
| Outplacement Services | — | — | — | — | — | 30,000 | — |
Stock Awards (3) | 164,593 | — | 164,593 | — | — | 164,593 | 164,593 |
| Option and SARs Awards | — | — | — | — | — | — | — |
| Separation Benefit Plan Payment | 670,769 | — | — | — | 670,769 | 670,769 | 670,769 |
| 835,362 | — | 164,593 | — | 670,769 | 3,691,917 | 835,362 |
| Mark E. Schell | | | | | | | |
| Key Employee Contract Payments: | | | | | | | |
Salary under contract formula (1) | — | — | — | — | — | 1,476,000 | — |
Bonus under contract formula (1) | — | — | — | — | — | 1,110,333 | — |
| Previously-earned but unpaid bonus amounts | — | — | — | — | — | — | — |
| Tax Gross-up | — | — | — | — | — | — | — |
| 36 months 401(k) company match | — | — | — | — | — | 58,968 | — |
Health Insurance (2) | — | — | — | — | — | 52,366 | — |
Disability Insurance (2) | — | — | — | — | — | 23,596 | — |
| Life and AD&D Insurance | — | — | — | — | — | 2,930 | — |
| Outplacement Services | — | — | — | — | — | 30,000 | — |
Stock Awards (3) | 150,123 | — | 150,123 | — | — | 150,123 | 150,123 |
| Option and SARs Awards | — | — | — | — | — | — | — |
| Separation Benefit Plan Payment | 984,000 | 984,000 | — | — | 984,000 | 984,000 | 984,000 |
| 1,134,123 | 984,000 | 150,123 | — | 984,000 | 3,888,316 | 1,134,123 |
| John H. Cromling | | | | | | | |
Stock Awards (3) | 141,117 | | — | | 141,117 | | — | | — | | 141,117 | | 141,117 | |
| Option and SARs Awards | — | | — | | — | | — | | — | | — | | — | |
| Separation Benefit Plan Payment | 788,616 | | 788,616 | | — | | — | | 788,616 | | 788,616 | | 788,616 | |
| 929,733 | | 788,616 | | 141,117 | | — | | 788,616 | | 929,733 | | 929,733 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| TYPE OF TRIGGERING EVENT | | | | | | | |
Named Executive
Officer | Death or
Disability
$ | Voluntary
Termination
or
Retirement
$ | Change in
Control
Without
Termination
$ | Termination
by Company
for Cause
$ | Termination
by Company
Without Cause
Unrelated to
Change in
Control
$ | Termination
by Company
or by
Executive
for Good
Reason After
Change in
Control
$ | Termination
by Executive
Without Good
Reason After
Change in
Control
$ |
| G. Les Austin | | | | | | | |
Stock Awards (3) | 101,690 | | — | | 101,690 | | — | | — | | 101,690 | | 101,690 | |
| Separation Benefit Plan Payment | 56,923 | | — | | — | | — | | 56,923 | | 56,923 | | 56,923 | |
| 158,613 | | — | | 101,690 | | — | | 56,923 | | 158,613 | | 158,613 | |
_________________________
1.It is assumed for purposes of these calculations that all year-to-date accrued salary, bonus and vacation pay is current as of December 31, 2019. This calculation represents the product of three and the sum of:
(i) the executive officer’s annual base salary, as defined, and
(ii) the highest annual bonus (as determined under the agreement).
2.The amount for health and disability coverage was determined by assuming that the rate of cost increases for coverage equals the discount rate applicable to reduce the amount to present value as of December 31, 2019.
3.The value of restricted stock assumes a fair market value for our common stock of $00.70, the closing price of our common stock on the NYSE on December 31, 2019, the last trading day of the year. All performance-based restricted stock has been assumed to vest at target.
Compensation Committee Interlocks and Insider Participation
These directors (none of whom was or had been an officer or employee of the company or any of its subsidiaries) served on the compensation committee during the full course of fiscal year 2019: Carla S. Mashinski, William B. Morgan, Steven B. Hildebrand, and J. Michael Adcock. There were no related party transactions between Ms. Mashinski or Messrs. Adcock, Morgan, or Hildebrand or their affiliated companies and the company or its subsidiaries during 2019. There were no committee interlocks with other companies within the meaning of the SEC’s rules during 2019.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The followingOwnership of Our Common Stock by Beneficial Owners and Management
Directors and Executive Officers
This table provides information forshows the number of shares of our common stock beneficially owned by each current director, each NEO, and all equity compensation planscurrent directors and executive officers as a group as of the fiscal year ended December 31, 2017, under which our equity securities were authorized for issuance:April 15, 2020, with all shares directly owned unless otherwise noted:
|
| | | | | | | | | | |
| Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted Average
Exercise Price of
Outstanding
Options,
Warrants and Rights
(b) | | Number of Securities
Remaining
Available for
Future Issuance Under Equity
Compensation
Plans (Excluding Securities Reflected in Column (a)) (c) | |
Equity compensation plans approved by security holders (1) | 87,500 |
| (2) | $ | 51.34 |
| | 3,641,494 |
| (3) |
| Equity compensation plans not approved by security holders | — |
| | — |
| | — |
| |
| Total | 87,500 |
| | $ | 51.34 |
| | 3,641,494 |
| |
| | | | | | | | | | | | | | |
STOCK OWNED BY OUR DIRECTORS, NOMINEES, AND EXECUTIVE OFFICERS AS OF APRIL 15, 2020 | | | | |
Name of Beneficial
Owner | Common Stock (1)(2)
(a) | Options Exercisable within 60 days (3)
(b) | Unvested Common Stock (4)
(c) | Total
(d) |
| J. Michael Adcock | 46,157 | 7,000 | 14,836 | 67,993 |
Gary R. Christopher (5) | 48,266 | 7,000 | 14,836 | 70,102 |
| Steven B. Hildebrand | 33,266 | 7000 | 14,836 | 55,102 |
| Carla S. Mashinski | 15,939 | — | 14,836 | 30,775 |
| William B. Morgan | 33,766 | 7,000 | 14,836 | 55,602 |
| Larry C. Payne | 28,266 | 3,500 | 14,836 | 46,602 |
| G. Bailey Peyton IV | 65,816 | 3,500 | 14,836 | 84,152 |
| Robert J. Sullivan Jr. | 26,266 | 7,000 | 14,836 | 48,102 |
| Larry D. Pinkston | 360,214 | — | — | 360,214 |
| David T. Merrill | 167,862 | — | 135,321 | 303,183 |
| Mark E. Schell | 323,800 | — | 122,163 | 445,963 |
| John H. Cromling | 190,314 | — | 113,345 | 303,659 |
| G. Les Austin | 32,701 | — | 93,964 | 126,665 |
All directors and executive officers as a group (6) (16 people) | 1,653,050 | 42,000 | 773,130 | 2,468,180 |
_________________________
| |
(1) | Shares awarded under all above plans may be newly issued, from our treasury, or acquired in the open market. |
| |
(2) | This number includes 87,500 stock options outstanding under the Non-Employee Directors’ Stock Option Plan. |
| |
(3) | This number reflects the shares available for issuance under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan). The amended plan allows us to grant stock-based compensation to our employees and non-employee directors. A total of 7,230,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan. No more than 2,000,000 of the shares available under the amended plan may be issued as “incentive stock options” and all of the shares available under this plan may be issued as restricted stock. In addition, shares related to grants that are forfeited, terminated, canceled, expire unexercised, or settled in such manner that all or some of the shares are not issued to a participant shall immediately become available for issuance. |
1.Includes these shares of common stock held under our 401(k) thrift plan: Mr. Pinkston, 12,800 shares; Mr. Merrill, 26,163 shares; Mr. Schell, 155,717 shares; Mr. Austin, 12,316 shares; and Mr. Cromling, 21,638 shares; and directors and executive officers as a group, 399,758 shares. Reflects these shares held jointly with spouses: Mr. Pinkston, 347,414 shares; Mr. Schell, 168,083 shares; Mr. Cromling, 168,676 shares; Mr. Christopher, 29,266 shares; and Mr. Peyton, 65,816 shares. Excludes unvested restricted stock, which is set forth separately in column (c).
In accordance with Instruction G(3)2.Of the shares listed as being beneficially owned, these individuals disclaim any beneficial interest in shares held by spouses, trusts, or for the benefit of Form 10-K,family members: Mr. Adcock, 17,891 shares and Mr. Hildebrand, 7,000 shares.
3.The options have all vested, but have not been exercised.
4.Represents unvested shares of restricted stock over which the named executive officer or director has voting power but not investment power. Amounts include 85,362 shares for Mr. Merrill; 77,062 shares for Mr. Schell; 71,572 shares for Mr. Cromling; 57,136 for Mr. Austin, and 409,137 shares for our executive officers (including the NEOs) as a group that have voting rights and vest based on performance criteria (based on target levels).
5.Mr. Christopher passed away on April 21, 2020.
6.As of April 15, 2020, each of our named directors and officers individually owns less than one percent of our outstanding shares of common stock and collectively the directors and officers own 4.50%. To calculate this percentage ownership, the total number of shares outstanding includes the shares issued and outstanding (which includes the “Unvested” restricted stock identified in column (c)) plus the number of shares that any named owner may acquire within 60 days.
Stockholders Owning More Than 5% of Our Common Stock
This table sets forth information requiredabout the beneficial ownership of our common stock by this Itemstockholders who own over five percent of our common stock.
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| STOCKHOLDERS WHO OWN MORE THAN 5% OF OUR COMMON STOCK | | |
| Name and Address | Amount and Nature of Beneficial Ownership (1) | Percent of Class (2) |
FMR LLC
245 Summer Street
Boston, MA 02210 | 6,926,460 | 12.65% |
Dimensional Fund Advisors LP
Building One
6300 Bee Cave Road
Austin, TX 78746 | 4,403,416 | 8.04% |
Black Rock, Inc.
55 East 52nd Street
New York, NY 10055 | 3,867,297 | 7.06% |
The Vanguard Group
100 Vanguard Blvd.
Malvern, PA 19355 | 2,944,138 | 5.38% |
_________________________
1.Beneficial ownership is incorporated into this reportbased on the Schedule 13G, 13G/A, or 13D most recently filed by referencethe stockholder or other information provided to us. Beneficial ownership may under certain circumstances include both voting power and investment power. Information is provided for reporting purposes only and should not be construed as an admission of actual beneficial ownership.
2. Based on the Proxy Statement (see Item 10 above)number of issued and outstanding shares of our common stock as of April 15, 2020.
Item 13. Certain Relationships and Related Transactions, and Director Independence
InOur Related Person Transaction Policy
Our board has adopted a policy and procedures for the review, approval, or ratification of related person transactions (as defined below) which is set forth in our Policy and Procedures with Respect to Related Person Transactions (the “Policy”).
Under the Policy, a “related person transaction” is a transaction, arrangement, or relationship (or any series of similar transactions, arrangements, or relationships) in which the company (including any of its subsidiaries) was, is or will be a participant and in which any Related Person (as defined below) had, has or will have a direct or indirect material interest, other than (1) transactions in which the amount involved does not exceed $120,000, (2) transactions available to employees generally, or (3) transactions involving compensation approved by the board’s compensation committee.
Under the Policy, a “related person” means (1) any person who is, or since the beginning of the company’s last fiscal year was, a director or executive officer of the company or a nominee to become a director of the company, (2) any person who is known to be the beneficial owner of over 5% of our voting securities, (3) any immediate family member of any of the above persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law of the director, executive officer, nominee or over 5% beneficial owner, and any person (other than a tenant or employee) sharing the household of such director, executive officer, nominee or over 5% beneficial owner, and (4) any firm, corporation or other entity in which any of the foregoing persons is employed or is a general partner or principal or in a similar position or in which such person has a 5% or greater ownership or economic interest.
Our audit committee is responsible for reviewing and approving (or prohibiting) any transaction determined by our general counsel to constitute a related person transaction. The audit committee will consider the relevant facts and circumstances available to it, including (if applicable) but not limited to (1) the benefits to the company, (2) the impact on a director’s independence if the related person is a director, an immediate family member of a director or an entity in which a director is a partner, stockholder or executive officer, (3) the availability of other sources for comparable products or services, (4) the terms of the transaction, and (5) the terms available to unrelated third parties or to employees generally. No member of the audit committee will participate in any review, consideration or approval of any related person transaction regarding which such member or any of his or her immediate family members is the related person. The audit committee will approve only those related person transactions in, or are not inconsistent with, the best interests of the company and its stockholders, as the audit committee determines in good faith.
Certain Transactions Between the Company and Its Officers, Directors, Nominees for Directors and Their Associates
One of our directors, G. Bailey Peyton IV, also serves as Manager and 99.5% owner of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells owned or operated by the company in several states. The company in the ordinary course of business, paid royalties or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.4 million, $0.9 million, and $0.7 million during 2019, 2018, and 2017, respectively. The transactions have been ratified and approved by the audit committee and the board.
Director Independence Criteria
Our director independence standards are available on our website at http://www.unitcorp.com/investor/governance.html. Our board has defined an independent director as a director who the board has determined has no material relationship with the company, either directly, or as a partner, stockholder, or executive officer of an organization that has a relationship with the company. A relationship is “material” if, in the judgment of the board, the relationship would interfere with the director’s independent judgment. Based on the materiality guidelines adopted by the board, a director is not independent if:
•the director, or the director’s immediate family member received as direct compensation any payment from the company in excess of $120,000 during any twelve-month period within the last three years, other than compensation for board service and pension or other forms of deferred compensation for prior service with the company, except that compensation received by an immediate family member for service as an employee of the company (other than as an executive officer) need not be considered in determining independence;
•the director is an executive officer or employee of, or his or her immediate family member, is an executive officer of, a company, or other for profit entity, to which the company made, or from which the company received for property or services (other than those arising solely from investments in the company’s securities), payments in excess of the greater of $1 million or 2% of that company’s consolidated gross revenues in any of the last three fiscal years;
•or the director serves as an executive officer of any tax exempt organization which received contributions from the company in any of the preceding three fiscal years in an aggregate amount that exceeded the greater of $1 million or 2% of that tax exempt organization’s consolidated gross revenues.
Any person who, or whose immediate family member(s), has within the last three years had any of the following relationships with the company does not qualify as an independent director:
•Former employees. No director will be independent if he or she is currently, or was at any time within the last three years, an employee of the company.
•Interlocking directorships. No director, and no immediate family member of a director, may currently be, or have been within the last three years, employed as an executive officer of another company where any of our present executive officers at the same time serves or served on that company’s compensation committee.
•Former executive officers of the company. No director will be independent if he or she has any immediate family member that is currently, or was at any time within the last three years, an executive officer of the company.
•Former auditor. No director will be independent if (i) he or she or an immediate family member is a current partner of a firm that is the company’s internal or external auditor; (ii) the director is a current employee of such a firm; (iii) the director has an immediate family member who is a current employee of such a firm, and who participates in the firm’s audit, assurance or tax compliance (but not tax planning) practice; or (iv) the director or an immediate family member was at any time within the last three years but is no longer a partner or employee of such a firm and personally worked on the company’s audit within that time.
Additional requirements for audit committee members. A director is not considered independent for purposes of serving on the audit committee, and may not serve on the audit committee, if the director:
•receives directly or indirectly any consulting, advisory, or compensatory fee from the company, other than fees for service as a director or fixed amounts of compensation under a retirement plan (including deferred compensation) for
prior service with the company (provided that such compensation is not contingent in any way on continued service); or
•is an affiliated person of the company or its subsidiaries, as determined in accordance with Instruction G(3)SEC regulations. In this regard, audit committee members are prohibited from owning or controlling more than 10% of Form 10-K,any class of the informationcompany’s voting securities or such lower amount as may be established by the SEC.
Additional requirements for compensation committee members. A director is not considered independent for purposes of serving on the compensation committee, and may not serve on the compensation committee, if the director:
•receives directly or indirectly any remuneration as specified for purposes of Section 162(m) of the Internal Revenue Code;
•has ever been an officer of the company;
•has a direct or indirect material interest in any transaction, arrangement or relationship or any series of similar transactions, arrangements or relationships required to be disclosed under SEC Regulation S-K Item 404(a) and involving, generally, amounts in excess of $120,000; or
•otherwise has a relationship that is material to that director’s ability to be independent from management in connection with the duties of a compensation committee member.
Director Independence Determinations
The board has determined that at the present time J. Michael Adcock, Steven B. Hildebrand, William B. Morgan, Carla S. Mashinski, Larry C. Payne, and Robert J. Sullivan Jr. have no material relationship with the company (either directly or as a partner, stockholder, or officer of an organization that has a relationship with the company) and is independent. There were no transactions between the company and the independent directors that required consideration by this Itemthe board in making its independence determination, and with respect to G. Bailey Peyton IV, our one outside director who was not categorized as independent, the board considered ordinary course business transactions between the director and the company or its operating subsidiaries. The board has also determined that each of the current members of its three standing committees has no material relationship with the company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the company) and is incorporated into this report by reference to“independent” within the Proxy Statement (see Item 10 above).meaning of both our director independence standards and those of the NYSE and SEC, as currently in effect.
Item 14. Principal Accounting Fees and Services
Fees Incurred for PricewaterhouseCoopers LLP
This table shows the fees for professional audit services provided by PricewaterhouseCoopers LLP for the audit of the company’s annual financial statements for the years ended December 31, 2019 and 2018, and fees billed for other services during those years.
| | | | | | | | |
| Type of Service | 2019 | 2018 |
Audit Fees (1) | $1,771,975 | $1,508,175 |
Audit-Related Fees (2) | 49,000 | 47,350 |
Tax Fees (3) | 32,000 | 7,500 |
| All Other Fees | — | — |
| Total | $1,852,975 | $1,563,025 |
_________________________
1.Audit fees represent fees for professional services for the audit of our financial statements and review of our quarterly financial statements and audit services provided for the issuance of consents and assistance with review of documents filed with the SEC.
2.In accordance2019 and 2018 fees related to review of special filings and transactions.
3.For tax compliance fees.
Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor
Consistent with Instruction G(3)SEC policies regarding auditor independence, the audit committee has responsibility for appointing, setting compensation, and overseeing the work of Form 10-K, the information requiredindependent registered public accounting firm. In recognition of this
responsibility, the audit committee has established a policy to pre-approve all audit and permissible non-audit services provided by this Item is incorporated into this report by referencethe independent registered public accounting firm.
Before incurring the following, management will submit to the Proxy Statement (see Item 10 above).audit committee for approval a list of services and related fees expected to be rendered by our independent registered public accounting firm during that year within these four categories of services:
(1) Audit services include audit work performed on the financial statements, internal control over financial reporting, and work that generally only the independent registered public accounting firm can reasonably be expected to provide, including comfort letters, statutory audits, and discussions surrounding the proper application of financial accounting and reporting standards.
PART IV(2) Audit-related services are for assurance and related services traditionally performed by the independent registered public accounting firm, including due diligence related to mergers and acquisitions, employee benefit plan audits, and special procedures required to meet certain regulatory requirements.
(3) Tax services include all services, except those services specifically related to the audit of the financial statements performed by the independent registered public accounting firm’s tax personnel, including tax analysis; assisting with coordination of execution of tax related activities, primarily in corporate development; supporting other tax related regulatory requirements; and tax compliance and reporting.
(4) Other Fees are those associated with services not captured in the other categories.
The audit committee pre-approves the independent registered public accounting firm’s services within each category. The fees are budgeted and the audit committee requires the independent registered public accounting firm and management to report actual fees versus the budget periodically throughout the year. Circumstances may arise when it may become necessary to engage the independent registered public accounting firm for additional services not contemplated in the original pre-approval categories. In those instances (subject to certain de minimus exceptions), the audit committee requires specific pre-approval before engaging the independent registered public accounting firm.
The audit committee may (and has at various times in the past) delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the audit committee at its next scheduled meeting.
Item 15. Exhibits, Financial Statement Schedules
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements:
Included in Part IIThe following financial statements are filed as part of this report:Unit’s Annual Report on Form 10-K filed March 16, 2020 under Item 8-Financial Statements and Supplementary Data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 20172019 and 20162018
Consolidated Statements of Operations for the years ended December 31, 2017, 2016,2019, 2018, and 20152017
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016,2019, 2018, and 20152017
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2015, 2016,2017, 2018, and 20172019
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016,2019, 2018, and 20152017
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Included in Part IV of this reportUnit’s Annual Report on Form 10-K filed March 16, 2020 for the years ended December 31, 2017, 2016,2019, 2018, and 2015:2017:
Schedule II—Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
3. Exhibits:
The exhibit numbers in the following list correspond to the numbers assigned such exhibits in the Exhibit Table of Item 601 of Regulation S-K.
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3.1.23.1.1 | | | |
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10.2.1 | | Unit 1979 Oil and Gas Program Agreement of Limited Partnership (filed as Exhibit I to Unit Drilling and Exploration Company’s Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which is incorporated herein by reference). |
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10.2.3* | | |
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10.2.5* | | Unit Corporation Employees’ Thrift Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein by reference). |
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10.2.6 | | Unit Consolidated Employee Oil and Gas Limited Partnership Agreement (filed as an Exhibit to Unit’s Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). |
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| 10.10 | | | Unit Corporation Employees’ Thrift Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein by reference). |
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| 10.20 | | | Unit Consolidated Employee Oil and Gas Limited Partnership Agreement (filed as an Exhibit to Unit’s Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). |
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| 101.INS | | | XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the inline XBRL document. |
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| 101.SCH | | | XBRL Taxonomy Extension Schema Document. |
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| 101.CAL | | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.DEF | | | XBRL Taxonomy Extension Definition Linkbase Document. |
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| 101.LAB | | | XBRL Taxonomy Extension Labels Linkbase Document. |
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| 101.PRE | | | XBRL Taxonomy Extension Presentation Linkbase Document. |
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| 104 | | | Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101) |
* Indicates a management contract or compensatory plan identified under the requirements of Item 15 of Form 10-K.
Item 16. Form 10-K Summary
Not applicable.
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
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| Description | Balance at Beginning of Period | | Additions
Charged to
Costs &
Expenses | | Deductions & Net Write-Offs | | Balance at End of Period |
| | (In thousands) |
| Year ended December 31, 2017 | $ | 3,773 |
| | $ | 348 |
| | $ | (1,671 | ) | | $ | 2,450 |
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| Year ended December 31, 2016 | $ | 5,199 |
| | $ | 785 |
| | $ | (2,211 | ) | | $ | 3,773 |
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| Year ended December 31, 2015 | $ | 5,039 |
| | $ | 1,191 |
| | $ | (1,031 | ) | | $ | 5,199 |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | UNIT CORPORATION |
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| DATE: | April 29, 2020 | By: | UNIT CORPORATION/s/ DAVID T. MERRILL |
| | | DAVID T. MERRILL |
DATE: | February 27, 2018 | By: | /s/ LARRY D. PINKSTON
|
| | | LARRY D. PINKSTON |
| | | President and Chief Executive Officer (Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 27th day of February, 2018.
EXHIBIT INDEX
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| Exhibit No. | | Description |
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Name | | Title |
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/s/ J. MICHAEL ADCOCK
| | Chairman of the Board and Director |
J. Michael Adcock | | |
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/s/ LARRY D. PINKSTON
| | President and Chief Executive Officer and Director
(Principal Executive Officer)
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Larry D. Pinkston | | |
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/s/ LES AUSTIN
| | Senior Vice President, Chief Financial Officer (Principal Financial Officer) |
Les Austin | | |
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/s/ DON A. HAYES
| | Vice President, Controller
(Principal Accounting Officer)
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Don A. Hayes | | |
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/s/ GARY CHRISTOPHER
| | Director |
Gary Christopher | | |
| 101.INS | | XBRL Instance Document. |
/s/ STEVEN B. HILDEBRAND
| | Director |
Steven B. Hildebrand101.SCH | | XBRL Taxonomy Extension Schema Document. |
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/s/ CARLA S. MASHINSKI
101.CAL | | DirectorXBRL Taxonomy Extension Calculation Linkbase Document. |
Carla S. Mashinski | | |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document. |
/s/ WILLIAM B. MORGAN
| | Director |
William B. Morgan101.LAB | | XBRL Taxonomy Extension Labels Linkbase Document. |
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/s/ LARRY C. PAYNE
101.PRE | | Director |
Larry C. Payne | | |
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/s/ G. BAILEY PEYTON IV
| | Director |
G. Bailey Peyton IV | | |
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/s/ ROBERT SULLIVAN, JR.
| | Director |
Robert Sullivan, Jr. | | XBRL Taxonomy Extension Presentation Linkbase Document. |
