Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Apr. 13, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | PNRG | ||
Entity Registrant Name | PRIMEENERGY CORP | ||
Entity Central Index Key | 56,868 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Common Stock, Shares Outstanding | 2,097,777 | ||
Entity Public Float | $ 48,199,855 |
Consolidated Balance Sheet
Consolidated Balance Sheet - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | $ 8,438 | $ 10,111 |
Accounts receivable, net | 16,961 | 7,400 |
Prepaid obligations | 756 | 412 |
Other current assets | 476 | 160 |
Total Current Assets | 26,631 | 18,083 |
Property and Equipment | ||
Oil and gas properties at cost | 476,570 | 417,821 |
Less: Accumulated depletion and depreciation | (263,569) | (230,331) |
Oil and gas properties, Net | 213,001 | 187,490 |
Field and office equipment at cost | 26,241 | 26,902 |
Less: Accumulated depreciation | (19,267) | (18,024) |
Field and office equipment, net | 6,974 | 8,878 |
Total Property and Equipment, Net | 219,975 | 196,368 |
Other Assets | 159 | 203 |
Total Assets | 246,765 | 214,654 |
Current Liabilities | ||
Accounts payable | 24,615 | 11,965 |
Accrued liabilities | 16,294 | 8,184 |
Current portion of long-term debt | 2,378 | 2,949 |
Current portion of asset retirement and other long-term obligations | 2,309 | 1,563 |
Derivative liability short-term | 1,509 | 2,547 |
Due to Related Parties | 65 | |
Total Current Liabilities | 47,170 | 27,208 |
Long-Term Bank Debt | 48,459 | 66,316 |
Asset Retirement Obligations | 21,269 | 15,943 |
Derivative Liability Long-Term | 1,913 | 1,092 |
Deferred Income Taxes | 24,962 | 37,500 |
Other Long-Term Obligations | 553 | 715 |
Total Liabilities | 144,326 | 148,774 |
Commitments and Contingencies | ||
Equity | ||
Common stock, $.10 par value; 2017 and 2016: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2017: 2,169,370 shares; 2016: 2,283,503 shares | 383 | 383 |
Paid-in capital | 8,729 | 8,313 |
Retained earnings | 138,320 | 96,322 |
Accumulated other comprehensive loss, net | 0 | 0 |
Treasury stock, at cost; 2017: 1,667,027 shares; 2016: 1,552,894 shares | (52,123) | (46,473) |
Total Stockholders' Equity-PrimeEnergy | 95,309 | 58,545 |
Non-controlling interest | 7,130 | 7,335 |
Total Equity | 102,439 | 65,880 |
Total Liabilities and Equity | $ 246,765 | $ 214,654 |
Consolidated Balance Sheet (Par
Consolidated Balance Sheet (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common stock, par value | $ 0.10 | $ 0.10 |
Common stock, shares authorized | 4,000,000 | 4,000,000 |
Common stock, shares issued | 3,836,397 | 3,836,397 |
Common stock, shares outstanding | 2,169,370 | 2,283,503 |
Treasury stock, shares | 1,667,027 | 1,552,894 |
Consolidated Statement of Opera
Consolidated Statement of Operations - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues | ||
Oil and gas sales | $ 66,883 | $ 38,306 |
Realized loss on derivative instruments, net | (155) | (16) |
Field service income | 15,704 | 15,432 |
Administrative overhead fees | 6,158 | 6,567 |
Unrealized gain (loss) on derivative instruments | 547 | (3,582) |
Other income | 173 | 59 |
Total Revenues | 89,310 | 56,766 |
Costs and Expenses | ||
Lease operating expense | 30,880 | 27,544 |
Field service expense | 11,990 | 12,549 |
Depreciation, depletion, amortization and accretion on discounted liabilities | 36,068 | 30,174 |
General and administrative expense | 9,646 | 7,849 |
Total Costs and Expenses | 88,584 | 78,116 |
Gain on Sale and Exchange of Assets | 41,258 | 32,378 |
Income from Operations | 41,984 | 11,028 |
Other Income and Expenses | ||
Less: Interest expense | 2,310 | 3,507 |
Add: Interest income | 7 | 1 |
Income Before Provision (Benefit) for Income Taxes | 39,681 | 7,522 |
Provision (Benefit) for Income Taxes | (7,753) | 2,100 |
Net Income | 47,434 | 5,422 |
Less: Net Income Attributable to Non-Controlling Interest | 5,436 | 1,978 |
Net Income Attributable to PrimeEnergy | $ 41,998 | $ 3,444 |
Basic Income Per Common Share | $ 18.99 | $ 1.50 |
Diluted Income Per Common Share | $ 14.18 | $ 1.13 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Net income | $ 47,434 | $ 5,422 |
Other Comprehensive Income, net of taxes: | ||
Changes in fair value of hedge positions, net of taxes of $0 and $(2), respectively | 5 | |
Total other comprehensive income | 5 | |
Comprehensive income | 47,434 | 5,427 |
Less: Comprehensive income attributable to non-controlling interest | 5,436 | 1,978 |
Comprehensive Income attributable to PrimeEnergy | $ 41,998 | $ 3,449 |
Consolidated Statement of Comp6
Consolidated Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | ||
Changes in fair value of hedge positions, tax | $ 0 | $ (2) |
Consolidated Statement of Equit
Consolidated Statement of Equity - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Treasury Stock [Member] | Total Stockholders' Equity - PrimeEnergy [Member] | Non-Controlling Interest [Member] |
Balance at Dec. 31, 2015 | $ 62,901 | $ 383 | $ 7,854 | $ 92,878 | $ (5) | $ (45,380) | $ 55,730 | $ 7,171 |
Balance, shares at Dec. 31, 2015 | 3,836,397 | |||||||
Purchase shares of common stock | (1,093) | (1,093) | (1,093) | |||||
Net income | 5,422 | 3,444 | 3,444 | 1,978 | ||||
Other comprehensive income, net of taxes | 5 | $ 5 | 5 | |||||
Purchase of non-controlling interest | (224) | 459 | 459 | (683) | ||||
Distributions to non-controlling interest | (1,131) | (1,131) | ||||||
Balance at Dec. 31, 2016 | $ 65,880 | $ 383 | 8,313 | 96,322 | (46,473) | 58,545 | 7,335 | |
Balance, shares at Dec. 31, 2016 | 3,836,397 | 3,836,397 | ||||||
Purchase shares of common stock | $ (5,650) | (5,650) | (5,650) | |||||
Net income | 47,434 | 41,998 | 41,998 | 5,436 | ||||
Purchase of non-controlling interest | (308) | 416 | 416 | (724) | ||||
Distributions to non-controlling interest | (4,917) | (4,917) | ||||||
Balance at Dec. 31, 2017 | $ 102,439 | $ 383 | $ 8,729 | $ 138,320 | $ (52,123) | $ 95,309 | $ 7,130 | |
Balance, shares at Dec. 31, 2017 | 3,836,397 | 3,836,397 |
Consolidated Statement of Equi8
Consolidated Statement of Equity (Parenthetical) - shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Purchase of common stock, shares | 114,133 | 21,181 |
Treasury Stock [Member] | ||
Purchase of common stock, shares | 114,133 | 21,181 |
Total Stockholders' Equity - PrimeEnergy [Member] | ||
Purchase of common stock, shares | 114,133 | 21,181 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Cash Flows from Operating Activities: | ||
Net income | $ 47,434 | $ 5,422 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, depletion, amortization and accretion on discounted liabilities | 36,068 | 30,174 |
Gain on sale of properties | (41,258) | (32,378) |
Unrealized (gain) loss on derivative instruments | (547) | 3,582 |
(Benefit) Provision for deferred income taxes | (12,538) | 147 |
Changes in assets and liabilities: | ||
(Increase) Decrease in accounts receivable | (9,561) | 2,143 |
Increase (Decrease) in due from related parties | 101 | (25) |
(Increase) Decrease in inventories | (9) | 61 |
(Increase) Decrease in prepaid expenses and other assets | (344) | 207 |
Increase (Decrease) in accounts payable | 12,650 | (390) |
Increase in accrued liabilities | 8,111 | 2,062 |
Net Cash Provided by Operating Activities | 40,107 | 11,005 |
Cash Flows from Investing Activities: | ||
Capital expenditures, including exploration expense | (59,361) | (20,843) |
Proceeds from sale of properties and equipment | 46,231 | 35,226 |
Net Cash (Used in) Provided by Investing Activities | (13,130) | 14,383 |
Cash Flows from Financing Activities: | ||
Purchase of stock for treasury | (5,650) | (1,093) |
Purchase of non-controlling interests | (308) | (224) |
Increase in long-term bank debt and other long-term obligations | 64,853 | 13,500 |
Repayment of long-term bank debt and other long-term obligations | (82,628) | (39,910) |
Distribution to non-controlling interest | (4,917) | (843) |
Net Cash Used in Financing Activities | (28,650) | (28,570) |
Net Decrease in Cash and Cash Equivalents | (1,673) | (3,182) |
Cash and Cash Equivalents at the Beginning of the Year | 10,111 | 13,293 |
Cash and Cash Equivalents at the End of the Year | 8,438 | 10,111 |
Supplemental Disclosures: | ||
Income taxes paid during the year | 414 | 120 |
Interest paid during the year | $ 2,339 | $ 3,476 |
Description of Operations and S
Description of Operations and Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Description of Operations and Significant Accounting Policies | 1. Description of Operations and Significant Accounting Policies Nature of Operations: PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing non-operating Consolidation and Presentation: The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements. Reclassifications: Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions. Subsequent Events: Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure other than as stated in footnote 2 to these financial statements. Use of Estimates: The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. Property and Equipment: The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production Capitalization of Interest: Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. Impairment of Long-Lived Assets: The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. Fair Value: The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability. The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Asset Retirement Obligation: The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations. Income Taxes: The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2017, and 2016, we had no valuation allowance. The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. General and Administrative Expenses: General and administrative expenses represent cost and expenses associated with the operation of the Company. Earnings Per Common Share: Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. Statements of Cash Flows: For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents. Concentration of Credit Risk: The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. Hedging: The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2016, the entire other comprehensive income amount is comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations. Recently Issued Accounting Standards: The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue recognition 932-605. Extractivies – Oil and Gas Revenue Recognition. The FASB issued ASU 2016-02, Leases (Topic 842 right-of-use In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, 2016-15 2016-15 In January 2017, the FASB issued ASU No. 2017-03, |
Acquisitions and Dispositions
Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | 2. Acquisitions and Dispositions Historically, the Company has repurchased the non-controlling non-controlling In May of 2017, we acquired 118 net mineral acres in one and a half sections in Upton County, Texas for $596,600 directly offsetting Company acreage. This purchase increased Prime’s leasehold in a core area of expected future development. During the first quarter of 2018, the Company acquired 1,640 gross (464 net) mineral acres, along with 16.6% to 33.4% working interest ownership in 53 oil and gas wells and one commercial salt water disposal well operated by the Company, all located in Reagan County, Texas, for $6,080,000. During 2017 the Company also sold or farmed-out leasehold rights through six separate transactions, receiving gross proceeds of approximately $46 million. In West Texas we sold approximately 2,096 net mineral acres for $37.4 million, primarily located in Martin County, and in Oklahoma we farmed-out approximately 1,554 net mineral acres primarily in Canadian County for $8.6 million and will retain an over-riding royalty interest and potential reversionary interests. These sales were of non-cash flowing mineral interests. The Company has entered into agreements and closed on the sale of additional non-core During 2016, the Company sold or farmed out interests in certain non-core undeveloped oil and natural gas properties through a number of separate, individually negotiated transactions in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements were $34.4 million. |
Additional Balance Sheet Inform
Additional Balance Sheet Information | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Additional Balance Sheet Information | 3. Additional Balance Sheet Information Accounts receivable at December 31, 2017 and 2016 consisted of the following: December 31, (Thousands of dollars) 2017 2016 Joint interest billings $ 3,173 $ 2,345 Trade receivables 941 1,070 Oil and gas sales 12,941 4,078 Other 4 204 17,059 7,697 Less: Allowance for doubtful accounts (98 ) (297 ) Total $ 16,961 $ 7,400 Accounts payable at December 31, 2017 and 2016 consisted of the following: December 31, (Thousands of dollars) 2017 2016 Trade $ 14,317 $ 3,967 Royalty and other owners 7,073 5,909 Partner advances 1,268 592 Prepaid drilling deposits 67 83 Other 1,890 1,414 Total $ 24,615 $ 11,965 Accrued liabilities at December 31, 2017 and 2016 consisted of the following: December 31, (Thousands of dollars) 2017 2016 Compensation and related expenses $ 2,449 $ 2,295 Property costs 9,141 3,317 Income tax 4,180 1,988 Other 524 584 Total $ 16,294 $ 8,184 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 4. Long-Term Debt Bank Debt: Effective July 30, 2010 the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement had a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility was secured by substantially all of the Company’s oil and gas properties. The credit facility was subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “2017 Credit Agreement”) with a maturity date of February 15, 2021. The Second Amended and Restated Credit Agreement and subsequent amendments were amended and restated by the 2017 Credit Agreement. Pursuant to the terms and conditions of the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships. On December 22, 2017, the Company and its lenders entered into a First Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes the addition of a new lender and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $85 million. At December 31, 2017, the Company had a total of $47.7 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.21% and $37.3 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 4.97% for the year ended December 31, 2017 as compared to 3.93% for year ended December 31, 2016. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates. The Company entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commenced in January 2014, related to $75 million of the Company’s bank debt resulting in a LIBO fixed rate of 0.563% and terminated in January 2016. The Company recorded interest expense and paid $7,000 related to the settlement of interest rate swaps for the twelve months ended December 31, 2016. Equipment Loans: On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by a portion of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of December 31, 2017, the Company had a total of $1.267 million outstanding on this Equipment Loan. On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw of an additional $0.5 million on this facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan, with a rate of 3.50% and requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of December 31, 2017, the Company had a total of $1.870 million outstanding on the Additional Equipment Loans. On January 12, 2018, the Company made a principal payment towards the third interim loan in the amount of $20,858. Effective with the payment due of January 26, 2018 the required monthly payments (principal and interest) on this loan changed to $7,986 with a continuing effective rate of 3.50% and a final maturity of June 26, 2020. The Company determined these loans are Level 3 liabilities in the fair-value hierarchy and estimated their fair value as $3,110 million and $6,147 million at December 31, 2017 and 2016, respectively, using a discounted cash flow model. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments | 5. Commitments Operating Leases: The Company has several non-cancelable (Thousands of dollars) Operating 2018 $ 486 2019 172 Total minimum payments $ 658 Rent expense for office space for the years ended December 31, 2017 and 2016 was $659,000 and $892,000, respectively. Asset Retirement Obligation: A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2017 and 2016 is as follows: Year Ended December 31, (Thousands of dollars) 2017 2016 Asset retirement obligation at beginning of period $ 17,505 $ 11,737 Liabilities incurred 45 68 Liabilities settled (676 ) (288 ) Accretion expense 768 498 Revisions in estimated liabilities 5,936 5,490 Asset retirement obligation at end of period $ 23,578 $ 17,505 The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. During 2017 revisions in estimated liabilities for asset retirement obligations resulted from increased field costs resulting in shorter productive life of marginal wells and the Company’s acceleration of the schedule for plugging various marginal non-core |
Contingent Liabilities
Contingent Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities | 6. Contingent Liabilities The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations. From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. |
Stock Options and Other Compens
Stock Options and Other Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock Options and Other Compensation | 7. Stock Options and Other Compensation In May 1989, non-statutory |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 8. Income Taxes The components of the provision (benefit) for income taxes for the years ended December 31, 2017 and 2016 are as follows: Year Ended December 31, (Thousands of dollars) 2017 2016 Current: Federal $ 4,522 $ 1,789 State 262 164 Total current 4,784 1,953 Deferred: Federal (13,226 ) 117 State 689 30 Total deferred (12,537 ) 147 Total income tax provision (benefit) $ (7,753 ) $ 2,100 At December 31, (Thousands of dollars) 2017 2016 Deferred Tax Assets: Accrued liabilities $ 349 $ 550 Allowance for doubtful accounts 22 152 Derivative Contracts 684 1,273 Alternative minimum tax credits 9,919 6,612 Net operating loss carry-forwards 528 586 Percentage depletion carry-forwards 727 3,025 Total deferred tax assets 12,229 12,198 Deferred Tax Liabilities: Basis differences relating to managed partnerships 3,193 6,211 Depletion and depreciation 33,998 43,487 Total deferred tax liabilities 37,191 49,698 Net deferred tax liabilities $ 24,962 $ 37,500 The total provision for income taxes for the years ended December 31, 2017 and 2016 varies from the federal statutory tax rate as a result of the following: Year Ended December 31, (Thousands of dollars) 2017 2016 Expected tax expense $ 11,643 $ 1,885 Revaluation of deferred tax attributes (20,204 ) — State income tax, net of federal benefit 717 194 Percentage depletion (89 ) (84 ) IRS settlement — 75 Other, net 180 30 Total income tax provision (benefit) $ (7,753 ) $ 2,100 Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. On December 22, 2017, the U.S. enacted into law the Tax Cuts and Jobs Act (“2017 Tax Act”). For the year ended December 31, 2017, the Company recorded a tax benefit of $20.204 million directly related to the effect of the 2017 Tax Act, based on the remeasurement of deferred tax assets and liabilities at the lower corporate tax rate. The Company has $9.918 million in alternative minimum tax (“AMT”) credits at December 31, 2017. Under the 2017 Tax Act, the Company may fully offset any regular tax liability in future years. In addition, a portion of the minimum tax credit which exceeds the regular tax liability is refundable in future years. The refundable portion is 50% of any excess credit in the years 2018 through 2020 and 100% in 2021. The Company will therefore expect to receive credits against regular tax and refunds of previously paid taxes in the amount of $9.918 million over the next four years. The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate. The Company is allowed a credit against the Texas Franchise Tax based on net operating losses incurred in prior periods. The credits allowed are $89 thousand in the years 2018 through 2026. Any credits not utilized in a given year due to the allowable credit exceeding the tax liability may be carried forward. No credit may be carried forward past 2026. The value of the credit is calculated net of the federal income tax effect. In 2016, the Company paid $75 thousand in settlement of an audit of its 2014 federal income tax return. The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, 2009 and 2014 federal income tax returns have been audited by the Internal Revenue Service. The 2015 through 2017 returns are currently open for examination by the IRS. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. State returns for the years 2014 through 2017 remain open for examination by the relevant taxing authorities. |
Segment Information and Major C
Segment Information and Major Customers | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Information and Major Customers | 9. Segment Information and Major Customers The Company operates in one industry – oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States. The Company sells its oil and gas production to a number of direct purchasers under direct contracts or through other operators under joint operating agreements. Listed below are the percent of the Company’s total oil and gas sales made which represented more than 10% of the Company’s oil and gas sales in the year 2017. Oil Purchasers: Apache Corporation 28 % Plains All American Inc. 23 % Sunoco, Inc. 16 % Shell Trading Company 10 % Gas Purchasers: Targa Pipeline Mid-Continent 25 % Apache Corporation 12 % Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers. |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Financial Instruments | (10). Financial Instruments Fair Value Measurements: Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2017 and December 31, 2016: December 31, 2017 Quoted Prices in Significant Significant Balance at (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 388 $ 388 Total assets $ — $ — $ 388 $ 388 Liabilities Commodity derivative contracts $ — $ — $ (3,422 ) $ (3,422 ) Total liabilities $ — $ — $ (3,422 ) $ (3,422 ) December 31, 2016 Quoted Prices in Significant Significant Balance at (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 57 $ 57 Total assets $ — $ — $ 57 $ 57 Liabilities Commodity derivative contract $ — $ — $ (3,639 ) $ (3,639 ) Total liabilities $ — $ — $ (3,639 ) $ (3,639 ) The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 2017. (Thousands of dollars) Net Liabilities — December 31, 2016 $ (3,582 ) Total realized and unrealized (gains) losses: Included in earnings (a) 392 Purchases, sales, issuances and settlements 156 Net Liabilities — December 31, 2017 $ (3,034 ) (a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. Derivative Instruments: The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings. Interest rate swap derivatives are treated as cash-flow hedges and are used to fix our floating interest rates on existing debt. Settlements of the swaps, which began in January 2014 and concluded in January 2016, was recognized within interest expense. There were no remaining interest rate swaps as of December 31, 2017 and December 31, 2016. The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax. The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2017 and 2016: Fair Value (Thousands of dollars) Balance Sheet Location December 31, December 31, Asset Derivatives: Derivatives not designated as cash-flow hedging instruments: Natural gas commodity contracts Other Current Assets $ 344 $ — Natural gas commodity contracts Other Assets 44 57 Total $ 388 $ 57 Liability Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contracts Derivative liability short-term (1,504 ) (1,065 ) Natural gas commodity contracts Derivative liability short-term (4 ) (1,482 ) Natural gas commodity contracts Derivative liability long-term (4 ) (463 ) Crude oil commodity contracts Derivative liability long-term (1,910 ) (629 ) Total $ (3,422 ) $ (3,639 ) Total derivative instruments $ (3,034 ) $ (3,582 ) The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2017 and 2016: Location of gain/loss recognized in income Amount of gain/loss (Thousands of dollars) 2017 2016 Derivative designated as cash-flow hedge instruments: Interest rate swap contracts Interest expense $ — $ (7 ) Derivatives not designated as cash-flow hedge instruments: Natural gas commodity contracts Unrealized gain (loss) on derivative instruments, net 2,267 (1,888 ) Crude oil commodity contracts Unrealized (loss) gain on derivative instruments, net (1,720 ) (1,694 ) Natural gas commodity contracts Realized (loss) gain on derivative instruments, net (9 ) 20 Crude oil commodity contracts Realized loss on derivative instruments, net (146 ) (36 ) $ 392 $ (3,605 ) |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 11. Related Party Transactions The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in an amount totaling $308,000 during 2017 and $224,000 during 2016. Treasury stock purchases in any reported period may include shares from a related party, which may include members of the Company’s Board of Directors. In 2017 and 2016, the Company purchased 10,000 shares from a related party. Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors. Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses. |
Salary Deferral Plan
Salary Deferral Plan | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Salary Deferral Plan | 12. Salary Deferral Plan The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions, of which $374,000 and $465,000 were made in 2017 and 2016, respectively. |
Earnings per Share
Earnings per Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings per Share | 13. Earnings per Share Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements: Year Ended December 31, 2017 2016 Net Income Weighted Per Share Net Income Weighted Per Share Basic $ 41,998 2,211,985 $ 18.99 $ 3,444 2,293,688 $ 1.50 Effect of dilutive securities: Options 750,803 751,563 Diluted (a) $ 41,998 2,962,788 $ 14.18 $ 3,444 3,045,251 $ 1.13 |
Shareholder's Equity
Shareholder's Equity | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Shareholder's Equity | 14. Shareholder’s Equity The Company has in place a stock repurchase program whereby it may purchase outstanding shares of its common stock from time-to-time, |
Supplementary Information
Supplementary Information | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Supplementary Information | PRIMEENERGY CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION OIL AND GAS PRODUCING ACTIVITIES Years Ended December 31, 2017 and 2016 (Unaudited) As of December 31, (Thousands of dollars) 2017 2016 Proved Developed oil and gas properties $ 476,570 $ 417,824 Proved Undeveloped oil and gas properties — — Total Capitalized Costs 476,570 417,824 Accumulated depreciation, depletion and valuation allowance 263,569 230,333 Net Capitalized Costs $ 213,001 $ 187,491 EXPLORATION AND DEVELOPMENT ACTIVITIES Years Ended December 31, 2017 and 2016 (Unaudited) Year Ended December 31, (Thousands of dollars) 2017 2016 Development Costs $ 59,361 $ 20,843 NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES Years Ended December 31, 2017 and 2016 (Unaudited) As of December 31, (Thousands of dollars) 2017 2016 Future cash inflows $ 384,198 $ 221,542 Future production costs (175,099 ) (115,091 ) Future development costs (34,798 ) (31,870 ) Future income tax expenses (20,884 ) (7,883 ) Future Net Cash Flows 153,417 66,698 10% annual discount for estimated timing of cash flows (46,503 ) (14,461 ) Standardized Measure of Discounted Future Net Cash Flows $ 106,914 $ 52,237 See accompanying Notes to Supplementary Information NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES Years Ended December 31, 2017 and 2016 (Unaudited) The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2017 and 2016: Year Ended December 31, (Thousands of dollars) 2017 2016 Sales of oil and gas produced, net of production costs $ (36,003 ) $ (10,762 ) Net changes in prices and production costs 12,432 (6,895 ) Extensions, discoveries and improved recovery 76,694 27,706 Revisions of previous quantity estimates 19,808 (5,214 ) Net change in development costs (5,199 ) (26,953 ) Reserves sold (21 ) — Reserves purchased 1,372 — Accretion of discount 5,224 5,880 Net change in income taxes (13,001 ) (2,600 ) Changes in production rates (timing) and other (6,628 ) 12,273 Net change 54,677 (6,565 ) Standardized measure of discounted future net cash flow: Beginning of year 52,237 58,802 End of year $ 106,914 $ 52,237 See accompanying Notes to Supplementary Information PRIMEENERGY CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION Years Ended December 31, 2017 and 2016 (Unaudited) As of December 31, 2017 2016 Oil NGLs Gas Oil NGLs Gas Proved Developed Reserves: Beginning of year 3,107 1,265 13,001 4,579 1,673 23,275 Extensions, discoveries and improved recovery 2,263 488 3,253 577 176 1,136 Revisions of previous estimates 496 89 3,846 (1,425 ) (527 ) (7,342 ) Converted from undeveloped reserves 383 103 476 46 14 65 Reserves sold (2 ) — (13 ) — (1 ) (7 ) Reserve purchased 90 41 220 — — — Production (1,004 ) (282 ) (3,640 ) (670 ) (70 ) (4,126 ) End of year 5,333 1,704 17,143 3,107 1,265 13,001 Proved Undeveloped Reserves: Beginning of year 643 159 2,003 52 12 55 Extensions, discoveries and improved recovery 298 118 335 635 157 1,994 Revisions of previous estimates (53 ) (18 ) (1,153 ) 2 4 19 Converted to developed reserves (383 ) (103 ) (476 ) (46 ) (14 ) (65 ) End of year 505 156 709 643 159 2,003 Total Proved Reserves at the End of the Year 5,838 1,860 17,852 3,750 1,424 15,004 Years Ended December 31, 2017 and 2016 (Unaudited) Year Ended December 31, (Thousands of dollars) 2017 2016 Revenue: Oil and gas sales $ 66,883 $ 38,306 Costs and Expenses: Lease operating expenses 30,880 27,544 Depreciation, depletion and accretion 34,006 27,534 Income tax (benefit) expense (7,753 ) (5,870 ) Total Costs and Expenses 57,133 49,208 Results of Operations from Producing Activities (excluding corporate overhead and interest costs) $ 9,750 $ (10,902 ) See accompanying Notes to Supplementary Information PRIMEENERGY CORPORATION AND SUBSIDIARIES (Unaudited) 1. Presentation of Reserve Disclosure Information Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling 2. Determination of Proved Reserves The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs. Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. 3. Results of Operations from Oil and Gas Producing Activities The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities. 4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles. Future cash inflows are computed as described in Note 2 by applying current prices to year-end Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, year-end Future income tax expenses are calculated by applying the 2018 U.S. tax rate to future pre-tax Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end 5. Changes in Reserves The 2017 and 2016 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent |
Description of Operations and25
Description of Operations and Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Nature of Operations | Nature of Operations: PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing non-operating |
Consolidation and Presentation | Consolidation and Presentation: The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements. |
Reclassifications | Reclassifications: Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions. |
Subsequent Events | Subsequent Events: Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure other than as stated in footnote 2 to these financial statements. |
Use of Estimates | Use of Estimates: The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. |
Property and Equipment | Property and Equipment: The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production |
Capitalization of Interest | Capitalization of Interest: Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets: The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. |
Fair Value | Fair Value: The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability. The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. |
Asset Retirement Obligation | Asset Retirement Obligation: The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations. |
Income Taxes | Income Taxes: The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2017, and 2016, we had no valuation allowance. The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. |
General and Administrative Expenses | General and Administrative Expenses: General and administrative expenses represent cost and expenses associated with the operation of the Company. |
Earnings Per Common Share | Earnings Per Common Share: Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. |
Statements of Cash Flows | Statements of Cash Flows: For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents. |
Concentration of Credit Risk | Concentration of Credit Risk: The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. |
Hedging | Hedging: The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2016, the entire other comprehensive income amount is comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards: The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue recognition 932-605. Extractivies – Oil and Gas Revenue Recognition. The FASB issued ASU 2016-02, Leases (Topic 842 right-of-use In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, 2016-15 2016-15 In January 2017, the FASB issued ASU No. 2017-03, |
Presentation of Reserve Disclosure Information | 1. Presentation of Reserve Disclosure Information Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling |
Determination of Proved Reserves | 2. Determination of Proved Reserves The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs. Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. |
Results of Operations from Oil and Gas Producing Activities | 3. Results of Operations from Oil and Gas Producing Activities The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities. |
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves | 4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles. Future cash inflows are computed as described in Note 2 by applying current prices to year-end Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, year-end Future income tax expenses are calculated by applying the 2018 U.S. tax rate to future pre-tax Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end |
Changes in Reserves | 5. Changes in Reserves The 2017 and 2016 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent |
Additional Balance Sheet Info26
Additional Balance Sheet Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Components of Balance Sheet Amounts | Accounts receivable at December 31, 2017 and 2016 consisted of the following: December 31, (Thousands of dollars) 2017 2016 Joint interest billings $ 3,173 $ 2,345 Trade receivables 941 1,070 Oil and gas sales 12,941 4,078 Other 4 204 17,059 7,697 Less: Allowance for doubtful accounts (98 ) (297 ) Total $ 16,961 $ 7,400 Accounts payable at December 31, 2017 and 2016 consisted of the following: December 31, (Thousands of dollars) 2017 2016 Trade $ 14,317 $ 3,967 Royalty and other owners 7,073 5,909 Partner advances 1,268 592 Prepaid drilling deposits 67 83 Other 1,890 1,414 Total $ 24,615 $ 11,965 Accrued liabilities at December 31, 2017 and 2016 consisted of the following: December 31, (Thousands of dollars) 2017 2016 Compensation and related expenses $ 2,449 $ 2,295 Property costs 9,141 3,317 Income tax 4,180 1,988 Other 524 584 Total $ 16,294 $ 8,184 |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of Future Minimum Lease Payments for Non-Cancelable Operating Leases | The Company has several non-cancelable (Thousands of dollars) Operating 2018 $ 486 2019 172 Total minimum payments $ 658 |
Reconciliation of Liability for Plugging and Abandonment Costs | A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2017 and 2016 is as follows: Year Ended December 31, (Thousands of dollars) 2017 2016 Asset retirement obligation at beginning of period $ 17,505 $ 11,737 Liabilities incurred 45 68 Liabilities settled (676 ) (288 ) Accretion expense 768 498 Revisions in estimated liabilities 5,936 5,490 Asset retirement obligation at end of period $ 23,578 $ 17,505 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Components of Provision (Benefit) for Income Taxes | The components of the provision (benefit) for income taxes for the years ended December 31, 2017 and 2016 are as follows: Year Ended December 31, (Thousands of dollars) 2017 2016 Current: Federal $ 4,522 $ 1,789 State 262 164 Total current 4,784 1,953 Deferred: Federal (13,226 ) 117 State 689 30 Total deferred (12,537 ) 147 Total income tax provision (benefit) $ (7,753 ) $ 2,100 |
Components of Net Deferred Tax Assets and Liabilities | At December 31, (Thousands of dollars) 2017 2016 Deferred Tax Assets: Accrued liabilities $ 349 $ 550 Allowance for doubtful accounts 22 152 Derivative Contracts 684 1,273 Alternative minimum tax credits 9,919 6,612 Net operating loss carry-forwards 528 586 Percentage depletion carry-forwards 727 3,025 Total deferred tax assets 12,229 12,198 Deferred Tax Liabilities: Basis differences relating to managed partnerships 3,193 6,211 Depletion and depreciation 33,998 43,487 Total deferred tax liabilities 37,191 49,698 Net deferred tax liabilities $ 24,962 $ 37,500 |
Provision for Income Taxes Varies from Federal Statutory Tax Rate | The total provision for income taxes for the years ended December 31, 2017 and 2016 varies from the federal statutory tax rate as a result of the following: Year Ended December 31, (Thousands of dollars) 2017 2016 Expected tax expense $ 11,643 $ 1,885 Revaluation of deferred tax attributes (20,204 ) — State income tax, net of federal benefit 717 194 Percentage depletion (89 ) (84 ) IRS settlement — 75 Other, net 180 30 Total income tax provision (benefit) $ (7,753 ) $ 2,100 |
Segment Information and Major29
Segment Information and Major Customers (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Information by Major Customers | The Company sells its oil and gas production to a number of direct purchasers under direct contracts or through other operators under joint operating agreements. Listed below are the percent of the Company’s total oil and gas sales made which represented more than 10% of the Company’s oil and gas sales in the year 2017. Oil Purchasers: Apache Corporation 28 % Plains All American Inc. 23 % Sunoco, Inc. 16 % Shell Trading Company 10 % Gas Purchasers: Targa Pipeline Mid-Continent 25 % Apache Corporation 12 % |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis | The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2017 and December 31, 2016: December 31, 2017 Quoted Prices in Significant Significant Balance at (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 388 $ 388 Total assets $ — $ — $ 388 $ 388 Liabilities Commodity derivative contracts $ — $ — $ (3,422 ) $ (3,422 ) Total liabilities $ — $ — $ (3,422 ) $ (3,422 ) December 31, 2016 Quoted Prices in Significant Significant Balance at (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 57 $ 57 Total assets $ — $ — $ 57 $ 57 Liabilities Commodity derivative contract $ — $ — $ (3,639 ) $ (3,639 ) Total liabilities $ — $ — $ (3,639 ) $ (3,639 ) |
Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3 | The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 2017. (Thousands of dollars) Net Liabilities — December 31, 2016 $ (3,582 ) Total realized and unrealized (gains) losses: Included in earnings (a) 392 Purchases, sales, issuances and settlements 156 Net Liabilities — December 31, 2017 $ (3,034 ) (a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. |
Effect of Derivative Instruments on Consolidated Balance Sheets | The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2017 and 2016: Fair Value (Thousands of dollars) Balance Sheet Location December 31, December 31, Asset Derivatives: Derivatives not designated as cash-flow hedging instruments: Natural gas commodity contracts Other Current Assets $ 344 $ — Natural gas commodity contracts Other Assets 44 57 Total $ 388 $ 57 Liability Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contracts Derivative liability short-term (1,504 ) (1,065 ) Natural gas commodity contracts Derivative liability short-term (4 ) (1,482 ) Natural gas commodity contracts Derivative liability long-term (4 ) (463 ) Crude oil commodity contracts Derivative liability long-term (1,910 ) (629 ) Total $ (3,422 ) $ (3,639 ) Total derivative instruments $ (3,034 ) $ (3,582 ) |
Effect of Derivative Instruments on Consolidated Statements of Operations | The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2017 and 2016: Location of gain/loss recognized in income Amount of gain/loss (Thousands of dollars) 2017 2016 Derivative designated as cash-flow hedge instruments: Interest rate swap contracts Interest expense $ — $ (7 ) Derivatives not designated as cash-flow hedge instruments: Natural gas commodity contracts Unrealized gain (loss) on derivative instruments, net 2,267 (1,888 ) Crude oil commodity contracts Unrealized (loss) gain on derivative instruments, net (1,720 ) (1,694 ) Natural gas commodity contracts Realized (loss) gain on derivative instruments, net (9 ) 20 Crude oil commodity contracts Realized loss on derivative instruments, net (146 ) (36 ) $ 392 $ (3,605 ) |
Earnings per Share (Tables)
Earnings per Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earnings (Loss) per Share | The following reconciles amounts reported in the financial statements: Year Ended December 31, 2017 2016 Net Income Weighted Per Share Net Income Weighted Per Share Basic $ 41,998 2,211,985 $ 18.99 $ 3,444 2,293,688 $ 1.50 Effect of dilutive securities: Options 750,803 751,563 Diluted (a) $ 41,998 2,962,788 $ 14.18 $ 3,444 3,045,251 $ 1.13 |
Supplementary Information (Tabl
Supplementary Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Capitalized Costs Relating to Oil and Gas Producing Activities | CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES Years Ended December 31, 2017 and 2016 (Unaudited) As of December 31, (Thousands of dollars) 2017 2016 Proved Developed oil and gas properties $ 476,570 $ 417,824 Proved Undeveloped oil and gas properties — — Total Capitalized Costs 476,570 417,824 Accumulated depreciation, depletion and valuation allowance 263,569 230,333 Net Capitalized Costs $ 213,001 $ 187,491 |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | EXPLORATION AND DEVELOPMENT ACTIVITIES Years Ended December 31, 2017 and 2016 (Unaudited) Year Ended December 31, (Thousands of dollars) 2017 2016 Development Costs $ 59,361 $ 20,843 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES Years Ended December 31, 2017 and 2016 (Unaudited) As of December 31, (Thousands of dollars) 2017 2016 Future cash inflows $ 384,198 $ 221,542 Future production costs (175,099 ) (115,091 ) Future development costs (34,798 ) (31,870 ) Future income tax expenses (20,884 ) (7,883 ) Future Net Cash Flows 153,417 66,698 10% annual discount for estimated timing of cash flows (46,503 ) (14,461 ) Standardized Measure of Discounted Future Net Cash Flows $ 106,914 $ 52,237 |
Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves | STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES Years Ended December 31, 2017 and 2016 (Unaudited) The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2017 and 2016: Year Ended December 31, (Thousands of dollars) 2017 2016 Sales of oil and gas produced, net of production costs $ (36,003 ) $ (10,762 ) Net changes in prices and production costs 12,432 (6,895 ) Extensions, discoveries and improved recovery 76,694 27,706 Revisions of previous quantity estimates 19,808 (5,214 ) Net change in development costs (5,199 ) (26,953 ) Reserves sold (21 ) — Reserves purchased 1,372 — Accretion of discount 5,224 5,880 Net change in income taxes (13,001 ) (2,600 ) Changes in production rates (timing) and other (6,628 ) 12,273 Net change 54,677 (6,565 ) Standardized measure of discounted future net cash flow: Beginning of year 52,237 58,802 End of year $ 106,914 $ 52,237 |
Reserve Quantity Information | RESERVE QUANTITY INFORMATION Years Ended December 31, 2017 and 2016 (Unaudited) As of December 31, 2017 2016 Oil NGLs Gas Oil NGLs Gas Proved Developed Reserves: Beginning of year 3,107 1,265 13,001 4,579 1,673 23,275 Extensions, discoveries and improved recovery 2,263 488 3,253 577 176 1,136 Revisions of previous estimates 496 89 3,846 (1,425 ) (527 ) (7,342 ) Converted from undeveloped reserves 383 103 476 46 14 65 Reserves sold (2 ) — (13 ) — (1 ) (7 ) Reserve purchased 90 41 220 — — — Production (1,004 ) (282 ) (3,640 ) (670 ) (70 ) (4,126 ) End of year 5,333 1,704 17,143 3,107 1,265 13,001 Proved Undeveloped Reserves: Beginning of year 643 159 2,003 52 12 55 Extensions, discoveries and improved recovery 298 118 335 635 157 1,994 Revisions of previous estimates (53 ) (18 ) (1,153 ) 2 4 19 Converted to developed reserves (383 ) (103 ) (476 ) (46 ) (14 ) (65 ) End of year 505 156 709 643 159 2,003 Total Proved Reserves at the End of the Year 5,838 1,860 17,852 3,750 1,424 15,004 |
Results of Operations from Oil and Gas Producing Activities | RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES Years Ended December 31, 2017 and 2016 (Unaudited) Year Ended December 31, (Thousands of dollars) 2017 2016 Revenue: Oil and gas sales $ 66,883 $ 38,306 Costs and Expenses: Lease operating expenses 30,880 27,544 Depreciation, depletion and accretion 34,006 27,534 Income tax (benefit) expense (7,753 ) (5,870 ) Total Costs and Expenses 57,133 49,208 Results of Operations from Producing Activities (excluding corporate overhead and interest costs) $ 9,750 $ (10,902 ) |
Description of Operations and33
Description of Operations and Significant Accounting Policies - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2017USD ($)WellPartnershipTrust | Dec. 31, 2016USD ($) | |
Property, Plant and Equipment [Line Items] | ||
Number of wells under non-operating interests | 400 | |
Number of limited partnerships | Partnership | 6 | |
Number of business income trusts | Trust | 2 | |
Valuation allowance | $ | $ 0 | $ 0 |
Maximum maturity period of cash and cash equivalents | 90 days | |
Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Number of wells operating by the company | 1,500 | |
Depreciation period of equipment | 5 years | |
Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Depreciation period of equipment | 10 years |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Additional Information (Detail) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |
May 31, 2017USD ($)a | Mar. 31, 2018USD ($)aWell | Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | |
Business Acquisition [Line Items] | ||||
Purchase of non-controlling interests | $ 308,000 | $ 224,000 | ||
Capital expenditures, including exploration expense | 59,361,000 | 20,843,000 | ||
Proceeds from sale of property and equipment | 46,231,000 | 35,226,000 | ||
West Texas and Oklahoma [Member] | Mineral Acreage [Member] | ||||
Business Acquisition [Line Items] | ||||
Proceeds from sale of property and equipment | 46,000,000 | 34,400,000 | ||
Martin County [Member] | Mineral Acreage [Member] | ||||
Business Acquisition [Line Items] | ||||
Proceeds from sale of property and equipment | $ 37,400,000 | |||
Number of net acres sold or farmed-out leasehold rights | a | 2,096 | |||
OKLAHOMA | Mineral Acreage [Member] | ||||
Business Acquisition [Line Items] | ||||
Proceeds from sale of property and equipment | $ 8,600,000 | |||
Number of net acres sold or farmed-out leasehold rights | a | 1,554 | |||
Upton County, Texas [Member] | Mineral Acreage [Member] | ||||
Business Acquisition [Line Items] | ||||
Number of net acres acquired | a | 118 | |||
Capital expenditures, including exploration expense | $ 596,600 | |||
Partnership And Trust [Member] | ||||
Business Acquisition [Line Items] | ||||
Purchase of non-controlling interests | $ 308,000 | $ 224,000 | ||
Subsequent Event [Member] | ||||
Business Acquisition [Line Items] | ||||
Proceeds from sale of additional non-core acreage and properties | $ 1,800,000 | |||
Subsequent Event [Member] | Reagan County, Texas [Member] | Mineral Acreage [Member] | ||||
Business Acquisition [Line Items] | ||||
Number of net acres acquired | a | 464 | |||
Number of gross mineral acres acquired | a | 1,640 | |||
Capital expenditures, including exploration expense | $ 6,080,000 | |||
Number of oil wells with working interest ownership | Well | 53 | |||
Number of commercial salt water disposal well operated | Well | 1 | |||
Subsequent Event [Member] | Reagan County, Texas [Member] | Mineral Acreage [Member] | Minimum [Member] | ||||
Business Acquisition [Line Items] | ||||
Percentage of working interest ownership | 16.60% | |||
Subsequent Event [Member] | Reagan County, Texas [Member] | Mineral Acreage [Member] | Maximum [Member] | ||||
Business Acquisition [Line Items] | ||||
Percentage of working interest ownership | 33.40% |
Additional Balance Sheet Info35
Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts Receivable: | ||
Joint interest billings | $ 3,173 | $ 2,345 |
Trade receivables | 941 | 1,070 |
Oil and gas sales | 12,941 | 4,078 |
Other | 4 | 204 |
Accounts Receivable, Gross | 17,059 | 7,697 |
Less: Allowance for doubtful accounts | (98) | (297) |
Total | 16,961 | 7,400 |
Accounts Payable: | ||
Trade | 14,317 | 3,967 |
Royalty and other owners | 7,073 | 5,909 |
Partner advances | 1,268 | 592 |
Prepaid drilling deposits | 67 | 83 |
Other | 1,890 | 1,414 |
Total | 24,615 | 11,965 |
Accrued Liabilities: | ||
Compensation and related expenses | 2,449 | 2,295 |
Property costs | 9,141 | 3,317 |
Income tax | 4,180 | 1,988 |
Other | 524 | 584 |
Total | $ 16,294 | $ 8,184 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) | Jan. 26, 2018 | Jan. 12, 2018 | Feb. 15, 2017 | Jun. 26, 2015 | Dec. 31, 2014 | Aug. 31, 2014 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 22, 2017 | Jul. 29, 2014 | Jul. 31, 2013 |
Credit Agreement [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Maturity date of amended and restated credit agreement | Jul. 30, 2017 | ||||||||||
Outstanding borrowings under revolving credit facility | $ 47,700,000 | ||||||||||
Weighted-average interest rate of borrowings | 5.21% | ||||||||||
Credit facility remaining borrowing capacity | $ 37,300,000 | ||||||||||
Interest swap agreements period | 2 years | ||||||||||
Settlement of interest rate swaps | $ 7,000 | ||||||||||
Additional Equipment Loan [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility remaining borrowing capacity | $ 1,200,000 | ||||||||||
Company's bank debt | $ 1,870,000 | ||||||||||
Equipment Loan, face amount | $ 6,000,000 | ||||||||||
Percentage for base rate loans at the prime rate | 3.40% | ||||||||||
Equipment Loan, monthly payment | $ 87,800 | ||||||||||
Equipment Loan, maturity date | Jul. 31, 2019 | ||||||||||
Additional equipment Loan, drawings | $ 500,000 | $ 4,800,000 | |||||||||
Equipment Loan, interest rate description | Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan, with a rate of 3.50% and requiring monthly payments | ||||||||||
Fair Value Measurements, Valuation Techniques | Discounted cash flow model | ||||||||||
Additional Equipment Loan [Member] | Significant Unobservable Inputs (Level 3) [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt Instrument, Fair Value Disclosure | $ 3,110,000,000 | $ 6,147,000,000 | |||||||||
Revolving Line of Credit and Letter of Credit Facility [Member] | Credit Agreement [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility borrowing capacity | $ 250,000,000 | ||||||||||
Fixed Term Loan [Member] | Additional Equipment Loan [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Equipment Loan, monthly payment | $ 8,700 | ||||||||||
Equipment Loan, maturity date | Jun. 26, 2020 | ||||||||||
Equipment Loan, Interest rate on fixed loans | 3.50% | ||||||||||
2017 Credit Agreement [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility borrowing capacity | $ 300,000,000 | ||||||||||
Maturity date of amended and restated credit agreement | Feb. 15, 2021 | ||||||||||
Credit agreement date | Feb. 15, 2017 | ||||||||||
Credit facility borrowing base | $ 85,000,000 | ||||||||||
London Interbank Offered Rate (LIBOR) [Member] | Additional Equipment Loan [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
LIBOR rate loans | 2.50% | ||||||||||
Base Rate And Libor [Member] | Credit Agreement [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument basis weighted average interest rate spread on variable rate | 4.97% | 3.93% | |||||||||
Subsequent Event [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Percentage for base rate loans at the prime rate | 3.50% | ||||||||||
Equipment Loan, monthly payment | $ 7,986 | ||||||||||
Equipment Loan, maturity date | Jun. 26, 2020 | ||||||||||
Equipment Loan, principal payment amount | $ 20,858 | ||||||||||
Equipment Loan [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Company's bank debt | $ 1,267,000 | ||||||||||
Equipment Loan, face amount | $ 10,000,000 | ||||||||||
Percentage for base rate loans at the prime rate | 3.95% | ||||||||||
Equipment Loan, monthly payment | $ 184,000 | ||||||||||
Equipment Loan, maturity date | Jul. 31, 2018 | ||||||||||
Interest Rate Swap [Member] | Credit Agreement [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Swap agreement date | 2012-07 | ||||||||||
Commenced date | 2014-01 | ||||||||||
Termination date | 2016-01 | ||||||||||
Company's bank debt | $ 75,000,000 | ||||||||||
Interest Rate Swap [Member] | London Interbank Offered Rate (LIBOR) [Member] | Credit Agreement [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument, interest rate | 0.563% |
Commitments - Additional Inform
Commitments - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | ||
Lease period description | Term of more than one year | |
Rent expense for office space | $ 659,000 | $ 892,000 |
Commitments - Summary of Future
Commitments - Summary of Future Minimum Lease Payments for Non-Cancelable Operating Leases (Detail) $ in Thousands | Dec. 31, 2017USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,018 | $ 486 |
2,019 | 172 |
Total minimum payments | $ 658 |
Commitments - Reconciliation of
Commitments - Reconciliation of Liability for Plugging and Abandonment Costs (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | ||
Asset retirement obligation at beginning of period | $ 17,505 | $ 11,737 |
Liabilities incurred | 45 | 68 |
Liabilities settled | (676) | (288) |
Accretion expense | 768 | 498 |
Revisions in estimated liabilities | 5,936 | 5,490 |
Asset retirement obligation at end of period | $ 23,578 | $ 17,505 |
Stock Options and Other Compe40
Stock Options and Other Compensation - Additional Information (Detail) - Nonstatutory Stock Options [Member] | Dec. 31, 2017$ / sharesshares | Dec. 31, 2016$ / sharesshares | May 31, 1989Officers |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options outstanding, shares | shares | 767,500 | 767,500 | |
Options exercisable, shares | shares | 767,500 | 767,500 | |
Number of key executive officers to whom non-statutory stock options granted | Officers | 4 | ||
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Average exercise price | $ / shares | $ 1 | $ 1 | |
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Average exercise price | $ / shares | $ 1.25 | $ 1.25 |
Income Taxes - Components of Pr
Income Taxes - Components of Provision (Benefit) for Income Taxes (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Current: | ||
Federal | $ 4,522 | $ 1,789 |
State | 262 | 164 |
Total current | 4,784 | 1,953 |
Deferred: | ||
Federal | (13,226) | 117 |
State | 689 | 30 |
Total deferred | (12,537) | 147 |
Total income tax provision (benefit) | $ (7,753) | $ 2,100 |
Income Taxes - Components of Ne
Income Taxes - Components of Net Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Tax Assets: | ||
Accrued liabilities | $ 349 | $ 550 |
Allowance for doubtful accounts | 22 | 152 |
Derivative Contracts | 684 | 1,273 |
Alternative minimum tax credits | 9,919 | 6,612 |
Net operating loss carry-forwards | 528 | 586 |
Percentage depletion carry-forwards | 727 | 3,025 |
Total deferred tax assets | 12,229 | 12,198 |
Deferred Tax Liabilities: | ||
Basis differences relating to managed partnerships | 3,193 | 6,211 |
Depletion and depreciation | 33,998 | 43,487 |
Total deferred tax liabilities | 37,191 | 49,698 |
Net deferred tax liabilities | $ 24,962 | $ 37,500 |
Income Taxes - Provision for In
Income Taxes - Provision for Income Taxes Varies from Federal Statutory Tax Rate (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Expected tax expense | $ 11,643 | $ 1,885 |
Revaluation of deferred tax attributes | (20,204) | |
State income tax, net of federal benefit | 717 | 194 |
Percentage depletion | (89) | (84) |
IRS settlement | 75 | |
Other, net | 180 | 30 |
Total income tax provision (benefit) | $ (7,753) | $ 2,100 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) | 12 Months Ended | |||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Taxes And Tax Related [Line Items] | ||||||
Tax Cuts and Jobs Act of 2017, change in tax rate, income tax benefit | $ 20,204,000 | |||||
Alternative minimum tax credits | 9,919,000 | $ 6,612,000 | ||||
Expected credits against regular tax and refunds of previously paid taxes | $ 9,918,000 | |||||
Number of years in which tax refund is expected to be received | 4 years | |||||
Allowed tax credit operating losses carry forward | $ 528,000 | 586,000 | ||||
Tax paid in settlement of 2014 federal income tax return | $ 75,000 | |||||
Scenario, Forecast [Member] | ||||||
Income Taxes And Tax Related [Line Items] | ||||||
Percentage of AMT credit refundable | 100.00% | 50.00% | 50.00% | 50.00% | ||
Texas Franchise Tax [Member] | ||||||
Income Taxes And Tax Related [Line Items] | ||||||
Tax credit operating carry forward losses allowed after the period | $ 0 | |||||
Tax credit operating carry forward losses allowed after the period, Description | No credit may be carried forward past 2026. | |||||
Texas Franchise Tax [Member] | 2018 through 2026 [Member] | ||||||
Income Taxes And Tax Related [Line Items] | ||||||
Allowed tax credit operating losses carry forward | $ 89,000 |
Segment Information and Major45
Segment Information and Major Customers - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2017industries | |
Revenue, Major Customer [Line Items] | |
Number of industry in which company operates | 1 |
Sales [Member] | Customer Concentration Risk [Member] | Minimum [Member] | |
Revenue, Major Customer [Line Items] | |
Customer purchases with respect of company's sales | 10.00% |
Segment Information and Major46
Segment Information and Major Customers - Segment Information by Major Customers (Detail) - Sales [Member] - Customer Concentration Risk [Member] | 12 Months Ended |
Dec. 31, 2017 | |
Oil Purchasers [Member] | Apache Corporation [Member] | |
Revenue, Major Customer [Line Items] | |
Revenue by major customers | 28.00% |
Oil Purchasers [Member] | Plains All American Inc., Oil Purchasers [Member] | |
Revenue, Major Customer [Line Items] | |
Revenue by major customers | 23.00% |
Oil Purchasers [Member] | Sunoco, Inc. [Member] | |
Revenue, Major Customer [Line Items] | |
Revenue by major customers | 16.00% |
Oil Purchasers [Member] | Shell Trading Company [Member] | |
Revenue, Major Customer [Line Items] | |
Revenue by major customers | 10.00% |
Gas Purchasers [Member] | Apache Corporation [Member] | |
Revenue, Major Customer [Line Items] | |
Revenue by major customers | 12.00% |
Gas Purchasers [Member] | Targa Pipeline Mid-Continent [Member] | |
Revenue, Major Customer [Line Items] | |
Revenue by major customers | 25.00% |
Financial Instruments - Schedul
Financial Instruments - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Derivative assets | $ 388 | $ 57 |
Liabilities | ||
Derivative liabilities | (3,422) | (3,639) |
Fair Value, Measurements, Recurring [Member] | ||
Assets | ||
Derivative assets | 388 | 57 |
Liabilities | ||
Derivative liabilities | (3,422) | (3,639) |
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | ||
Assets | ||
Derivative assets | 388 | 57 |
Liabilities | ||
Derivative liabilities | (3,422) | (3,639) |
Significant Unobservable Inputs (Level 3) [Member] | Fair Value, Measurements, Recurring [Member] | ||
Assets | ||
Derivative assets | 388 | 57 |
Liabilities | ||
Derivative liabilities | (3,422) | (3,639) |
Significant Unobservable Inputs (Level 3) [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | ||
Assets | ||
Derivative assets | 388 | 57 |
Liabilities | ||
Derivative liabilities | $ (3,422) | $ (3,639) |
Financial Instruments - Sched48
Financial Instruments - Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3 (Detail) - Significant Unobservable Inputs (Level 3) [Member] $ in Thousands | 12 Months Ended | |
Dec. 31, 2017USD ($) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Net Liabilities at beginning of period | $ (3,582) | |
Total realized and unrealized (gains) losses: | ||
Included in earnings | 392 | [1] |
Purchases, sales, issuances and settlements | 156 | |
Net Liabilities at end of period | $ (3,034) | |
[1] | Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. |
Financial Instruments - Effect
Financial Instruments - Effect of Derivative Instruments on Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 388 | $ 57 |
Derivative liabilities | (3,422) | (3,639) |
Total derivative instruments | (3,034) | (3,582) |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Other Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 344 | |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Other Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 44 | 57 |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Derivative Liability Short-Term [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | (4) | (1,482) |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Derivative liability Long Term [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | (4) | (463) |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Derivative Liability Short-Term [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | (1,504) | (1,065) |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Derivative liability Long Term [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ (1,910) | $ (629) |
Financial Instruments - Effec50
Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/loss recognized in income | $ 392 | $ (3,605) |
Derivatives Designated as Cash-Flow Hedging Instruments [Member] | Interest Rate Swap [Member] | Interest Expense [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/loss recognized in income | (7) | |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Unrealized (Loss) Gain on Derivative Instruments, Net [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/loss recognized in income | 2,267 | (1,888) |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member] | Realized (Loss) Gain on Derivative Instruments, Net [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/loss recognized in income | (9) | 20 |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Unrealized (Loss) Gain on Derivative Instruments, Net [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/loss recognized in income | (1,720) | (1,694) |
Derivatives Not Designated as Cash-Flow Hedging Instruments [Member] | Crude Oil Commodity Contracts [Member] | Realized (Loss) Gain on Derivative Instruments, Net [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/loss recognized in income | $ (146) | $ (36) |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | ||
Purchase of non-controlling interests | $ 308 | $ 224 |
Purchase of treasury stock shares | 114,133 | 21,181 |
Partnership And Trust [Member] | ||
Related Party Transaction [Line Items] | ||
Purchase of non-controlling interests | $ 308 | $ 224 |
Related Party [Member] | ||
Related Party Transaction [Line Items] | ||
Purchase of treasury stock shares | 10,000 | 10,000 |
Salary Deferral Plan - Addition
Salary Deferral Plan - Additional Information (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Retirement Benefits [Abstract] | ||
Salary deferral plan, discretionary and matching contribution | $ 374,000 | $ 465,000 |
Earnings per Share - Computatio
Earnings per Share - Computation of Basic and Diluted Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Earnings Per Share [Abstract] | ||
Net (Loss) Income, Basic | $ 41,998 | $ 3,444 |
Net (Loss) Income, Diluted | $ 41,998 | $ 3,444 |
Weighted Average Number of Shares Outstanding, Basic | 2,211,985 | 2,293,688 |
Weighted Average Number of Shares Outstanding, Options | 750,803 | 751,563 |
Weighted Average Number of Shares Outstanding, Diluted | 2,962,788 | 3,045,251 |
Per Share Amount, Basic | $ 18.99 | $ 1.50 |
Per Share Amount, Diluted | $ 14.18 | $ 1.13 |
Supplementary Information - Cap
Supplementary Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Proved Developed oil and gas properties | $ 476,570 | $ 417,824 |
Proved Undeveloped oil and gas properties | 0 | 0 |
Total Capitalized Costs | 476,570 | 417,824 |
Accumulated depreciation, depletion and valuation allowance | 263,569 | 230,333 |
Net Capitalized Costs | $ 213,001 | $ 187,491 |
Supplementary Information - Cos
Supplementary Information - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Development Costs | $ 59,361 | $ 20,843 |
Supplementary Information - Sta
Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Future cash inflows | $ 384,198 | $ 221,542 | |
Future production costs | (175,099) | (115,091) | |
Future development costs | (34,798) | (31,870) | |
Future income tax expenses | (20,884) | (7,883) | |
Future Net Cash Flows | 153,417 | 66,698 | |
10% annual discount for estimated timing of cash flows | (46,503) | (14,461) | |
Standardized Measure of Discounted Future Net Cash Flows | $ 106,914 | $ 52,237 | $ 58,802 |
Supplementary Information - S57
Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Sales of oil and gas produced, net of production costs | $ (36,003) | $ (10,762) |
Net changes in prices and production costs | 12,432 | (6,895) |
Extensions, discoveries and improved recovery | 76,694 | 27,706 |
Revisions of previous quantity estimates | 19,808 | (5,214) |
Net change in development costs | (5,199) | (26,953) |
Reserves sold | (21) | |
Reserves purchased | 1,372 | |
Accretion of discount | 5,224 | 5,880 |
Net change in income taxes | (13,001) | (2,600) |
Changes in production rates (timing) and other | (6,628) | 12,273 |
Net change | 54,677 | (6,565) |
Standardized measure of discounted future net cash flow: | ||
Beginning of year | 52,237 | 58,802 |
End of year | $ 106,914 | $ 52,237 |
Supplementary Information - Res
Supplementary Information - Reserve Quantity Information (Detail) | 12 Months Ended | |
Dec. 31, 2017MMcfMBbls | Dec. 31, 2016MMcfMBbls | |
Oil [Member] | ||
Proved Developed Reserves: | ||
Beginning of year | 3,107 | 4,579 |
Extensions, discoveries and improved recovery | 2,263 | 577 |
Revisions of previous estimates | 496 | (1,425) |
Converted from undeveloped reserves | 383 | 46 |
Reserves sold | (2) | |
Reserve purchased | 90 | |
Production | (1,004) | (670) |
End of year | 5,333 | 3,107 |
Proved Undeveloped Reserves: | ||
Beginning of year | 643 | 52 |
Extensions, discoveries and improved recovery | 298 | 635 |
Revisions of previous estimates | (53) | 2 |
Converted to developed reserves | (383) | (46) |
End of year | 505 | 643 |
Total Proved Reserves at the End of the Year | 5,838 | 3,750 |
NGLs [Member] | ||
Proved Developed Reserves: | ||
Beginning of year | 1,265 | 1,673 |
Extensions, discoveries and improved recovery | 488 | 176 |
Revisions of previous estimates | 89 | (527) |
Converted from undeveloped reserves | 103 | 14 |
Reserves sold | (1) | |
Reserve purchased | 41 | |
Production | (282) | (70) |
End of year | 1,704 | 1,265 |
Proved Undeveloped Reserves: | ||
Beginning of year | 159 | 12 |
Extensions, discoveries and improved recovery | 118 | 157 |
Revisions of previous estimates | (18) | 4 |
Converted to developed reserves | (103) | (14) |
End of year | 156 | 159 |
Total Proved Reserves at the End of the Year | 1,860 | 1,424 |
Gas [Member] | ||
Proved Developed Reserves: | ||
Beginning of year | MMcf | 13,001 | 23,275 |
Extensions, discoveries and improved recovery | MMcf | 3,253 | 1,136 |
Revisions of previous estimates | MMcf | 3,846 | (7,342) |
Converted from undeveloped reserves | MMcf | 476 | 65 |
Reserves sold | MMcf | (13) | (7) |
Reserve purchased | MMcf | 220 | |
Production | MMcf | (3,640) | (4,126) |
End of year | MMcf | 17,143 | 13,001 |
Proved Undeveloped Reserves: | ||
Beginning of year | MMcf | 2,003 | 55 |
Extensions, discoveries and improved recovery | MMcf | 335 | 1,994 |
Revisions of previous estimates | MMcf | (1,153) | 19 |
Converted to developed reserves | MMcf | (476) | (65) |
End of year | MMcf | 709 | 2,003 |
Total Proved Reserves at the End of the Year | MMcf | 17,852 | 15,004 |
Supplementary Information - R59
Supplementary Information - Results of Operations from Oil and Gas Producing Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue: | ||
Oil and gas sales | $ 66,883 | $ 38,306 |
Costs and Expenses: | ||
Lease operating expenses | 30,880 | 27,544 |
Depreciation, depletion and accretion | 34,006 | 27,534 |
Income tax (benefit) expense | (7,753) | (5,870) |
Total Costs and Expenses | 57,133 | 49,208 |
Results of Operations from Producing Activities (excluding corporate overhead and interest costs) | $ 9,750 | $ (10,902) |
Supplementary Information - Add
Supplementary Information - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Interest rate of Company's reserves | 10.00% |
Rate of discounted future net cash flows | 10.00% |
Percentage of discounted future prices | 10.00% |