Document And Entity Information
Document And Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Aug. 06, 2018 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
Entity Registrant Name | Contango Oil & Gas Company | |
Entity Central Index Key | 1,071,993 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 25,723,135 | |
Entity Current Reporting Status | Yes |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
CURRENT ASSETS: | ||
Accounts receivable, net | $ 10,927 | $ 13,059 |
Prepaid expenses | 1,540 | 1,892 |
Current derivative asset | 161 | 822 |
Total current assets | 12,628 | 15,773 |
Natural gas and oil properties, successful efforts method of accounting: | ||
Proved properties | 1,194,753 | 1,239,662 |
Unproved properties | 27,249 | 35,243 |
Other property and equipment | 1,272 | 1,272 |
Accumulated depreciation, depletion and amortization | (883,321) | (930,220) |
Total property, plant and equipment, net | 339,953 | 345,957 |
OTHER NON-CURRENT ASSETS: | ||
Investments in affiliates | 18,696 | 18,464 |
Long-term derivative asset | 152 | |
Deferred tax asset | 424 | 424 |
Other | 595 | 835 |
Total other non-current assets | 19,867 | 19,723 |
TOTAL ASSETS | 372,448 | 381,453 |
CURRENT LIABILITIES: | ||
Accounts payable and accrued liabilities | 42,111 | 46,755 |
Current derivative liability | 2,951 | 1,765 |
Current asset retirement obligations | 1,209 | 2,017 |
Total current liabilities | 46,271 | 50,537 |
NON-CURRENT LIABILITIES: | ||
Long-term debt | 80,827 | 85,380 |
Long-term derivative liability | 915 | 300 |
Asset retirement obligations | 19,722 | 20,388 |
Other long term liabilities | 3,541 | 248 |
Total non-current liabilities | 105,005 | 106,316 |
Total liabilities | 151,276 | 156,853 |
COMMITMENTS AND CONTINGENCIES (NOTE 11) | ||
SHAREHOLDERS' EQUITY: | ||
Common stock, $0.04 par value, 50 million shares authorized, 31,156,772 shares issued and 25,739,282 shares outstanding at June 30, 2018, 30,873,470 shares issued and 25,505,715 shares outstanding at December 31, 2017 | 1,235 | 1,223 |
Additional paid-in capital | 305,523 | 302,527 |
Treasury shares at cost (5,417,490 shares at June 30, 2018 and 5,367,755 shares at December 31, 2017) | (128,778) | (128,583) |
Retained earnings | 43,192 | 49,433 |
Total shareholders' equity | 221,172 | 224,600 |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ 372,448 | $ 381,453 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
CONSOLIDATED BALANCE SHEETS | ||
Common stock, par value (in dollars per share) | $ 0.04 | $ 0.04 |
Common stock, shares authorized | 50,000,000 | 50,000,000 |
Common stock, shares issued | 31,156,772 | 30,873,470 |
Common stock, shares outstanding | 25,739,282 | 25,505,715 |
Treasury stock, shares | 5,417,490 | 5,367,755 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
REVENUES: | ||||
Revenues | $ 18,448 | $ 20,276 | $ 38,885 | $ 39,700 |
EXPENSES: | ||||
Operating expenses | 6,478 | 6,329 | 13,405 | 13,162 |
Exploration expenses | 394 | 284 | 863 | 375 |
Depreciation, depletion and amortization | 9,498 | 12,714 | 19,983 | 24,485 |
Impairment and abandonment of oil and gas properties | 777 | 1,401 | 4,104 | 1,431 |
General and administrative expenses | 5,354 | 5,833 | 12,080 | 12,429 |
Total expenses | 22,501 | 26,561 | 50,435 | 51,882 |
OTHER INCOME (EXPENSE): | ||||
Gain (loss) from investment in affiliates, net of income taxes | (475) | 166 | 232 | 1,950 |
Gain (loss) from sale of assets | 1,370 | (420) | 10,817 | 2,520 |
Interest expense | (1,262) | (925) | (2,671) | (1,684) |
Gain (loss) on derivatives, net | (2,610) | 1,487 | (3,642) | 4,583 |
Other income (expense) | 3 | 61 | 882 | (27) |
Total other income (expense) | (2,974) | 369 | 5,618 | 7,342 |
NET LOSS BEFORE INCOME TAXES | (7,027) | (5,916) | (5,932) | (4,840) |
Income tax provision | (151) | (118) | (309) | (309) |
NET LOSS | $ (7,178) | $ (6,034) | $ (6,241) | $ (5,149) |
NET LOSS PER SHARE: | ||||
Basic (in dollars per share) | $ (0.29) | $ (0.24) | $ (0.25) | $ (0.21) |
Diluted (in dollars per share) | $ (0.29) | $ (0.24) | $ (0.25) | $ (0.21) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | ||||
Basic (in shares) | 24,933 | 24,671 | 24,863 | 24,639 |
Diluted (in shares) | 24,933 | 24,671 | 24,863 | 24,639 |
Oil and condensate [Member] | ||||
REVENUES: | ||||
Revenues | $ 9,607 | $ 6,483 | $ 18,418 | $ 12,025 |
Natural gas [Member] | ||||
REVENUES: | ||||
Revenues | 5,848 | 11,135 | 14,457 | 22,275 |
Natural gas liquids [Member] | ||||
REVENUES: | ||||
Revenues | $ 2,993 | $ 2,658 | $ 6,010 | $ 5,400 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net loss | $ (6,241) | $ (5,149) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 19,983 | 24,485 |
Impairment of natural gas and oil properties | 3,890 | 1,400 |
Exploration recovery | (232) | |
Gain on sale of assets | (10,817) | (2,520) |
Gain from investment in affiliates | (232) | (1,950) |
Stock-based compensation | 3,008 | 3,078 |
Unrealized loss (gain) on derivative instruments | 2,311 | (4,327) |
Changes in operating assets and liabilities: | ||
Decrease in accounts receivable & other receivables | 2,132 | 5,044 |
Decrease (increase) in prepaids | 352 | (402) |
Decrease in inventory | 123 | |
Decrease in accounts payable & advances from joint owners | (2,027) | (41) |
Decrease in other accrued liabilities | (2,618) | (1,260) |
Increase (decrease) in income taxes payable, net | 229 | (201) |
Other | 3,293 | 61 |
Net cash provided by operating activities | 13,263 | 18,109 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Natural gas and oil exploration and development expenditures | (30,077) | (35,553) |
Additions to furniture & equipment | (39) | |
Sale of furniture & equipment | 12 | |
Sale of oil and gas properties | 21,562 | 670 |
Net cash used in investing activities | (8,515) | (34,910) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under credit facility | 130,677 | 113,506 |
Repayments under credit facility | (135,230) | (96,544) |
Purchase of treasury stock | (195) | (161) |
Net cash provided by (used in) financing activities | (4,748) | 16,801 |
NET CHANGE IN CASH AND CASH EQUIVALENTS | 0 | 0 |
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 0 | 0 |
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ 0 | $ 0 |
CONSOLIDATED STATEMENT OF SHARE
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands | Common Stock | Additional Paid- in Capital | Treasury Stock | Retained Earnings | Total |
Balance at Dec. 31, 2017 | $ 1,223 | $ 302,527 | $ (128,583) | $ 49,433 | $ 224,600 |
Balance, shares at Dec. 31, 2017 | 25,505,715 | 25,505,715 | |||
Treasury shares at cost | (195) | $ (195) | |||
Treasury shares at cost, shares | (49,735) | ||||
Restricted shares activity | $ 12 | (12) | |||
Restricted shares activity, shares | 283,302 | ||||
Stock-based compensation | 3,008 | 3,008 | |||
Net loss | (6,241) | (6,241) | |||
Balance at Jun. 30, 2018 | $ 1,235 | $ 305,523 | $ (128,778) | $ 43,192 | $ 221,172 |
Balance, shares at Jun. 30, 2018 | 25,739,282 | 25,739,282 |
Organization and Business
Organization and Business | 6 Months Ended |
Jun. 30, 2018 | |
Organization And Business [Abstract] | |
Organization and Business | 1. Organization and Business Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States. The following table lists the Company’s primary producing areas as of June 30, 2018: Location Formation Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Madison and Grimes counties, Texas Woodbine (Upper Lewisville) Pecos County, Texas Southern Delaware Basin (Wolfcamp) Other Texas Gulf Coast Conventional and smaller unconventional formations Zavala and Dimmit counties, Texas Buda / Eagle Ford Weston County, Wyoming Muddy Sandstone Sublette County, Wyoming Jonah Field (1) (1) Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this investment is not included in the Company’s reported production results for the three and six months ended June 30, 2018. The Company’s 2018 capital program has focused on the development of the Company’s 16,500 gross (6,800 net) acres in the Southern Delaware Basin. Additionally, the Company will continue to identify opportunities for cost efficiencies in all areas of its operations, maintain core leases and continue to identify new resource potential opportunities internally and, where appropriate and assuming the Company has adequate capital to do so, through acquisition. Acquisition efforts will typically be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where the Company can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves. The Company continuously monitors the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, makes adjustments to its strategy as the year progresses. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2018 | |
Summary Of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2017 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this report. Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2017 Form 10-K. The consolidated results of operations for the six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company (“Contaro”), is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results. Oil and Gas Properties - Successful Efforts The Company’s application of the successful efforts method of accounting for the Company’s natural gas and oil exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized $2.7 million in non-cash proved property impairment charges for the six months ended June 30, 2018, including a $2.3 million impairment related to its Vermilion 170 offshore property during the three months ended March 31, 2018 and a $0.4 million impairment related to non-core onshore properties due to revised estimated reserves during the three months ended June 30, 2018. No impairment of proved properties was recognized during the three and six months ended June 30, 2017. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized impairment expense of approximately $0.4 million and approximately $1.2 million for the three and six months ended June 30, 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases. The Company also recognized $1.4 million in impairment expense for the three and six months ended June 30, 2017 related to the partial impairment of two unused offshore platforms that were subsequently sold. Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, Performance Stock Units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three months ended June 30, 2018, the Company excluded 1,133,534 potentially dilutive securities, as they were antidilutive, and excluded 1,197,029 potentially dilutive securities for the six months ended June 30, 2018, as they were antidilutive. For the three months ended June 30, 2017, the Company excluded 1,366,091 potentially dilutive securities, as they were antidilutive, and excluded 1,367,242 potentially dilutive securities for the six months ended June 30, 2017, as they were antidilutive. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. The Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. Revenue Recognition Adoption of ASC 606 As of January 1, 2018 the Company adopted Accounting Standards Codification 606 – Revenue from Contracts with Customers (“ASC 606”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Revenue from Contracts with Customers Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606. Transaction Price Allocated to Remaining Performance Obligations Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required. Contract Balances The Company receives purchaser statements from the majority of the Company’s customers but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply. Prior Period Performance Obligations The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. Impact of Adoption of ASC 606 The Company has reviewed all of the Company’s natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to the Company’s operating results for the six months ended June 30, 2018. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment. Recent Accounting Pronouncements In January 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-01 – Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in this update permit an entity to elect an optional transition practical expedient to not evaluate under Topic 842 land easements (right of way payments) that exist or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. Right of way payments do not have a material impact on the Company’s results of operations and the Company plans to elect the practical expedient to evaluate right of way payments prospectively on adoption of Topic 842. In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016 02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company is currently collating all leases and potential leases for evaluation and will continue to assess the impact this may have on its financial position, results of operations and cash flows. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | 3. Acquisitions and Dispositions On May 25, 2018, the Company sold its non-operated assets located in Starr County, Texas for a cash purchase price of $0.6 million. The Company recorded a gain of $1.4 million after removal of the asset retirement obligations associated with the sold properties. On March 28, 2018, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.4 million. Effective February 1, 2017, the Company sold to a third party all of its assets in the Bob West North area and its operated assets in the Escobas area, both located in Southeast Texas, for a cash purchase price of $650,000. The Company recorded a net gain of $2.9 million after removal of the asset retirement obligations associated with the sold properties. |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | 4. Fair Value Measurements Pursuant to Accounting Standards Codification 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 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). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants 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 classifies fair value balances based on the observability of those inputs. The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of June 30, 2018. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Fair value information for financial assets and liabilities was as follows as of June 30, 2018 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 313 $ — $ 313 $ — Commodity price contracts - liabilities $ (3,866) $ — $ (3,866) $ — Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives. As of June 30, 2018, the Company's derivative contracts were with certain members of its credit facility lending group, which are major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's credit facility with the Royal Bank of Canada and other lenders (the “RBC Credit Facility”) approximates carrying value because the facility interest rate approximates current market rates and is reset at least every six months. See Note 9 - "Long-Term Debt" for further information. Impairments Contango tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Asset Retirement Obligations The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments [Abstract] | |
Derivative Instruments | 5. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of June 30, 2018, the Company’s natural gas and oil derivative positions consisted of “swaps” and “costless collars”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract. It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the RBC Credit Facility. See Note 9 - "Long-Term Debt" for further information regarding the RBC Credit Facility. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain (loss) on derivatives, net" on the consolidated statements of operations. As of June 30, 2018, the following derivative instruments were in place (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas July 2018 Swap 370,000 MMBtus $ 3.07 (1) Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $ 3.07 (1) Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $ 3.07 (1) Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 (2) Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 (2) Oil July 2018 - Dec 2018 Collar 2,000 Bbls $ 52.00 - 58.76 (3) Oil July 2018 Collar 6,000 Bbls $ 58.00 - 68.00 (2) Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $ 58.00 - 68.00 (2) Oil July 2018 Swap 6,000 Bbls $ 70.11 (3) Oil Aug 2018 - Oct 2018 Swap 3,000 Bbls $ 70.11 (3) Oil Nov 2018 - Dec 2018 Swap 6,000 Bbls $ 70.11 (3) Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) Oil Jan 2019 - July 2019 Swap 6,000 Bbls $ 66.10 (3) Total net fair value of derivative instruments $ (3,553) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of June 30, 2018 (in thousands): Gross Netting (1) Total Assets $ 313 $ — $ 313 Liabilities $ (3,866) $ — $ (3,866) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2017 (in thousands): Gross Netting (1) Total Assets $ 1,188 $ (1,188) $ — Liabilities $ (2,431) $ 1,188 $ (1,243) (1) Represents counterparty netting under agreements governing such derivatives. The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and six months ended June 30, 2018 and 2017 (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Crude oil contracts $ (1,123) $ 367 $ (1,711) $ 537 Natural gas contracts 305 68 380 (281) Realized gain (loss) $ (818) $ 435 $ (1,331) $ 256 Crude oil contracts $ (1,311) $ 293 $ (1,594) $ 817 Natural gas contracts (481) 759 (717) 3,510 Unrealized gain (loss) $ (1,792) $ 1,052 $ (2,311) $ 4,327 Gain (loss) on derivatives, net $ (2,610) $ 1,487 $ (3,642) $ 4,583 |
Stock-Based Compensation
Stock-Based Compensation | 6 Months Ended |
Jun. 30, 2018 | |
Stock-Based Compensation [Abstract] | |
Stock-Based Compensation | 6. Stock-Based Compensation The Company recognized approximately $3.0 million and $3.1 million in stock compensation expense during the six months ended June 30, 2018 and 2017, respectively, for equity awards granted to its officers, employees and directors. As of June 30, 2018, an additional $4.7 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 1.7 years. This includes expense related to restricted stock, Performance Stock Units (“PSUs”) and stock options. Restricted Stock During the six months ended June 30, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. Additionally, the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the six months ended June 30, 2018, was $3.76 with a total fair value of approximately $1.2 million with no adjustment for an estimated weighted average forfeiture rate. During the six months ended June 30, 2018, 24,980 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2018 was approximately $222 thousand. Approximately 1.2 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of June 30, 2018, assuming PSUs are settled at 100% of target. During the six months ended June 30, 2017, the Company granted 43,000 shares of restricted common stock, which vest over three years, to newly hired employees as part of their overall compensation package. Additionally, the Company granted 338,076 shares of restricted stock to existing employees, which vest over three years, as part of their overall compensation package, and 74,325 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the six months ended June 30, 2017, was $7.56 with a total fair value of approximately $3.4 million after adjustment for an estimated weighted average forfeiture rate of 5.7%. During the six months ended June 30, 2017, 63,490 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2017 was approximately $688 thousand. Performance Stock Units During the six months ended June 30, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, at a weighted average fair value of $7.69 per unit. During the six months ended June 30, 2017, the Company granted 30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit. An additional 160,908 PSUs were granted to executive officers, as part of their overall compensation package, at a value of $13.91 per unit during the six months ended June 30, 2017. All fair value prices were determined using the Monte Carlo simulation model. During the six months ended June 30, 2018 and 2017, 19,300 and 34,899 PSUs were forfeited by former employees, respectively. PSUs represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 300% of the number of PSUs awarded contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period. Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is contemplated that the PSUs will be settled with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award. Stock Options Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the six months ended June 30, 2018 and 2017, there was no excess tax benefit recognized. Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the six months ended June 30, 2018 or 2017. During the six months ended June 30, 2018, no stock options were exercised or forfeited. During the six months ended June 30, 2017, no stock options were exercised and stock options for 14,586 shares of common stock were forfeited by former employees. |
Other Financial Information
Other Financial Information | 6 Months Ended |
Jun. 30, 2018 | |
Other Financial Information [Abstract] | |
Other Financial Information | 7. Other Financial Information The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): June 30, 2018 December 31, 2017 Accounts receivable: Trade receivables $ 5,316 $ 6,565 Receivable for Alta Resources Distribution 1,993 1,993 Joint interest billings 3,887 4,030 Income taxes receivable 424 424 Other receivables 88 828 Allowance for doubtful accounts (781) (781) Total accounts receivable $ 10,927 $ 13,059 Prepaid expenses and other: Prepaid insurance $ 920 $ 1,177 Other 620 715 Total prepaid expenses and other $ 1,540 $ 1,892 Accounts payable and accrued liabilities: Royalties and revenue payable $ 18,888 $ 18,181 Advances from partners 4,145 2,243 Accrued exploration and development 8,171 8,400 Trade payables 4,726 9,559 Accrued general and administrative expenses 2,322 2,960 Accrued operating expenses 1,662 1,654 Other accounts payable and accrued liabilities 2,197 3,758 Total accounts payable and accrued liabilities $ 42,111 $ 46,755 Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the six months ended June 30, 2018 and 2017 (in thousands): Six Months Ended June 30, 2018 2017 Cash payments: Interest payments $ 2,596 $ 1,491 Income tax payments $ 81 $ 498 Non-cash investing activities in the consolidated statements of cash flows: Decrease in accrued capital expenditures $ (229) $ (7,935) |
Investment In Exaro Energy III
Investment In Exaro Energy III LLC | 6 Months Ended |
Jun. 30, 2018 | |
Investment In Exaro Energy III LLC [Abstract] | |
Investment In Exaro Energy III LLC | 8. Investment in Exaro Energy III LLC The Company maintains an ownership interest in Exaro of approximately 37%. The following table (in thousands) presents unaudited condensed balance sheet data for Exaro as of June 30, 2018 and December 31, 2017. The balance sheet data was derived from Exaro’s balance sheet as of June 30, 2018 and December 31, 2017 and was not adjusted to represent the Company’s percentage of ownership interest in Exaro. The Company’s share in the equity of Exaro at June 30, 2018 was approximately $18.6 million. June 30, 2018 December 31, 2017 Current assets (1) $ 12,910 $ 17,063 Non-current assets: Net property and equipment 77,837 82,450 Gas processing deposit 1,150 1,150 Other non-current assets 445 390 Total non-current assets 79,432 83,990 Total assets $ 92,342 $ 101,053 Current liabilities $ 4,415 $ 6,199 Non-current liabilities: Long-term debt 32,411 40,375 Other non-current liabilities 3,958 3,858 Total non-current liabilities 36,369 44,233 Members' equity 51,558 50,621 Total liabilities & members' equity $ 92,342 $ 101,053 (1) Approximately $9.6 million and $12.8 million of current assets as of June 30, 2018 and December 31, 2017, respectively, is cash. The following table (in thousands) presents the unaudited condensed results of operations for Exaro for the three and six months ended June 30, 2018 and 2017. The results of operations for the three and six months ended June 30, 2018 and 2017 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ownership interest but rather reflects the results of Exaro as a company. The Company’s share in Exaro’s results of operations recognized for the three months ended June 30, 2018 and 2017 was a loss of $0.5 million, net of no tax expense, and a gain of $0.2 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the six months ended June 30, 2018 and 2017 was a gain of $0.2 million, net of no tax expense, and a gain of $2.0 million, net of no tax expense, respectively. Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Production: Oil (thousand barrels) 21 28 43 54 Gas (million cubic feet) 1,946 2,272 3,881 4,580 Total (million cubic feet equivalent) 2,072 2,442 4,139 4,902 Oil and natural gas sales $ 5,955 $ 7,844 $ 12,838 $ 17,016 Gain (loss) on derivatives (582) 841 1,044 3,402 Less: Lease operating expenses 3,278 4,767 6,668 7,987 Depreciation, depletion, amortization & accretion 2,321 2,249 4,729 4,591 General & administrative expense 351 874 705 1,606 Income (loss) from continuing operations (577) 795 1,780 6,234 Net interest expense (636) (328) (1,079) (952) Net income (loss) $ (1,213) $ 467 $ 701 $ 5,282 Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes. |
Long-Term Debt
Long-Term Debt | 6 Months Ended |
Jun. 30, 2018 | |
Long-Term Debt [Abstract] | |
Long-Term Debt | 9. Long-Term Debt RBC Credit Facility In October 2013, the Company entered into a $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”), the maturity of which has been extended by subsequent amendment to October 1, 2019. The borrowing base under the facility is redetermined each November and May. As of June 30, 2018, the borrowing base under the RBC Credit Facility was $110 million, but was reduced to $105 million effective August 1, 2018, as agreed to during the May 2018 redetermination. As of June 30, 2018, the Company had approximately $80.8 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2017, the Company had approximately $85.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of June 30, 2018, borrowing availability under the RBC Credit Facility was $27.3 million. The RBC Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties. Total interest expense under the RBC Credit Facility, including commitment fees, for the three and six months ended June 30, 2018 was approximately $1.3 million and $2.7 million, respectively. Total interest expense under the RBC Credit Facility, including commitment fees, for the three and six months ended June 30, 2017 was approximately $0.9 million and $1.7 million, respectively. The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. As of June 30, 2018, the Company was in compliance with all but the Current Ratio covenant under the RBC Credit Facility, although the Company obtained a waiver for such non-compliance effective as of June 30, 2018. The Company intends to review the amount and timing of its remaining 2018 capital expenditure program after the drilling of its next three Southern Delaware Basin wells. The Company’s ability or commitment to continue its capital expenditure program will be determined based on its evaluation of well results, commodity prices (including the impact of the dramatic increase in the Midland-Cushing oil price differentials) and the availability of capital. The RBC Credit Facility contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, payment defaults, breach of certain covenants including the current ratio covenant, bankruptcy, insolvency or change of control events. The weighted average interest rate in effect at June 30, 2018 and December 31, 2017 was 5.8% and 5.2%, respectively. The RBC Credit Facility matures on October 1, 2019, at which time any outstanding balances will be due. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2018 | |
Income Taxes [Abstract] | |
Income Taxes | 10. Income Taxes The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Current tax provision: Federal $ — $ — $ — $ — State 151 118 309 309 Total $ 151 $ 118 $ 309 $ 309 Total tax provision: Federal $ — $ — $ — $ — State 151 118 309 309 Total income tax provision $ 151 $ 118 $ 309 $ 309 In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the six months ended June 30, 2018, the Company continues to take a full valuation allowance against its deferred tax asset except for the portion attributable to the estimated refundable Alternative Minimum Tax (“AMT”) credit. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Company completed the accounting for the effects of the Act during 2017. The Company’s financial statements for the six months ended June 30, 2018 reflect certain effects of the Act which includes the reduced corporate tax of 21%, elimination of the corporate AMT, limitations on the use of interest expense and net operating losses, accelerated expensing of tangible property, as well as other changes. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Commitments And Contingencies [Abstract] | |
Commitments and Contingencies | 11. Commitments and Contingencies Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals. In the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. The Company previously filed a motion for rehearing with the Court of Appeals, which was recently denied, as expected. The Company continues to vigorously defend this lawsuit and is currently preparing a petition requesting a review by the Texas Supreme Court. In addition, the Company is also in the process of seeking amicus briefs from industry associations whose members would be affected the by the Court of Appeals’ ruling. In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the District Court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The plaintiff appealed the trial court’s decision to the applicable state Court of Appeals. On December 14, 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff has indicated that it intends to file a petition requesting that the matter be reviewed by the Texas Supreme Court. The Company continues to vigorously defend this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit. While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely. Throughput Contract Commitment The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. The Company currently forecasts that monthly gas volume deliveries through this line in its Southeast Texas area will not meet minimum throughput requirements under the agreement. Without further development in that area, the volume deficiency will continue through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in April of each calendar year. As of June 30, 2018, the Company estimates that the net deficiency fee will be approximately $1.0 million annually for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. As of June 30, 2018, based upon the current commodity price market and the Company’s short term strategic drilling plans, the Company has recorded a $0.7 million loss contingency through December 31, 2018. The Company will assess this commitment in the fourth quarter when its development plans for this area are addressed in the approved budget for 2019. |
Summary of Significant Accoun18
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Summary Of Significant Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2017 Form 10-K. The consolidated results of operations for the six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. |
Principles Of Consolidation | The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company (“Contaro”), is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results. |
Oil and Gas Properties - Successful Efforts | Oil and Gas Properties - Successful Efforts The Company’s application of the successful efforts method of accounting for the Company’s natural gas and oil exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized $2.7 million in non-cash proved property impairment charges for the six months ended June 30, 2018, including a $2.3 million impairment related to its Vermilion 170 offshore property during the three months ended March 31, 2018 and a $0.4 million impairment related to non-core onshore properties due to revised estimated reserves during the three months ended June 30, 2018. No impairment of proved properties was recognized during the three and six months ended June 30, 2017. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized impairment expense of approximately $0.4 million and approximately $1.2 million for the three and six months ended June 30, 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases. The Company also recognized $1.4 million in impairment expense for the three and six months ended June 30, 2017 related to the partial impairment of two unused offshore platforms that were subsequently sold. |
Net Loss Per Common Share | Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, Performance Stock Units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three months ended June 30, 2018, the Company excluded 1,133,534 potentially dilutive securities, as they were antidilutive, and excluded 1,197,029 potentially dilutive securities for the six months ended June 30, 2018, as they were antidilutive. For the three months ended June 30, 2017, the Company excluded 1,366,091 potentially dilutive securities, as they were antidilutive, and excluded 1,367,242 potentially dilutive securities for the six months ended June 30, 2017, as they were antidilutive. |
Subsidiary Guarantees | Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. The Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. |
Revenue Recognition | Revenue Recognition Adoption of ASC 606 As of January 1, 2018 the Company adopted Accounting Standards Codification 606 – Revenue from Contracts with Customers (“ASC 606”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Revenue from Contracts with Customers Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606. Transaction Price Allocated to Remaining Performance Obligations Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required. Contract Balances The Company receives purchaser statements from the majority of the Company’s customers but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply. Prior Period Performance Obligations The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. Impact of Adoption of ASC 606 The Company has reviewed all of the Company’s natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to the Company’s operating results for the six months ended June 30, 2018. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In January 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-01 – Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in this update permit an entity to elect an optional transition practical expedient to not evaluate under Topic 842 land easements (right of way payments) that exist or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. Right of way payments do not have a material impact on the Company’s results of operations and the Company plans to elect the practical expedient to evaluate right of way payments prospectively on adoption of Topic 842. In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016 02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company is currently collating all leases and potential leases for evaluation and will continue to assess the impact this may have on its financial position, results of operations and cash flows. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Measurements [Abstract] | |
Schedule Of Fair Value Of Financial Assets And (Liabilities) | Fair value information for financial assets and liabilities was as follows as of June 30, 2018 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 313 $ — $ 313 $ — Commodity price contracts - liabilities $ (3,866) $ — $ (3,866) $ — |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments [Abstract] | |
Schedule Of Derivative Contracts | As of June 30, 2018, the following derivative instruments were in place (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas July 2018 Swap 370,000 MMBtus $ 3.07 (1) Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $ 3.07 (1) Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $ 3.07 (1) Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 (2) Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 (2) Oil July 2018 - Dec 2018 Collar 2,000 Bbls $ 52.00 - 58.76 (3) Oil July 2018 Collar 6,000 Bbls $ 58.00 - 68.00 (2) Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $ 58.00 - 68.00 (2) Oil July 2018 Swap 6,000 Bbls $ 70.11 (3) Oil Aug 2018 - Oct 2018 Swap 3,000 Bbls $ 70.11 (3) Oil Nov 2018 - Dec 2018 Swap 6,000 Bbls $ 70.11 (3) Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) Oil Jan 2019 - July 2019 Swap 6,000 Bbls $ 66.10 (3) Total net fair value of derivative instruments $ (3,553) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. |
Schedule Of Fair Value Of Commodity Derivatives | The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of June 30, 2018 (in thousands): Gross Netting (1) Total Assets $ 313 $ — $ 313 Liabilities $ (3,866) $ — $ (3,866) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2017 (in thousands): Gross Netting (1) Total Assets $ 1,188 $ (1,188) $ — Liabilities $ (2,431) $ 1,188 $ (1,243) (1) Represents counterparty netting under agreements governing such derivatives. |
Schedule Of Derivative Contracts On Operations | The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and six months ended June 30, 2018 and 2017 (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Crude oil contracts $ (1,123) $ 367 $ (1,711) $ 537 Natural gas contracts 305 68 380 (281) Realized gain (loss) $ (818) $ 435 $ (1,331) $ 256 Crude oil contracts $ (1,311) $ 293 $ (1,594) $ 817 Natural gas contracts (481) 759 (717) 3,510 Unrealized gain (loss) $ (1,792) $ 1,052 $ (2,311) $ 4,327 Gain (loss) on derivatives, net $ (2,610) $ 1,487 $ (3,642) $ 4,583 |
Other Financial Information (Ta
Other Financial Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Other Financial Information [Abstract] | |
Schedule Of Additional Financial Details | The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): June 30, 2018 December 31, 2017 Accounts receivable: Trade receivables $ 5,316 $ 6,565 Receivable for Alta Resources Distribution 1,993 1,993 Joint interest billings 3,887 4,030 Income taxes receivable 424 424 Other receivables 88 828 Allowance for doubtful accounts (781) (781) Total accounts receivable $ 10,927 $ 13,059 Prepaid expenses and other: Prepaid insurance $ 920 $ 1,177 Other 620 715 Total prepaid expenses and other $ 1,540 $ 1,892 Accounts payable and accrued liabilities: Royalties and revenue payable $ 18,888 $ 18,181 Advances from partners 4,145 2,243 Accrued exploration and development 8,171 8,400 Trade payables 4,726 9,559 Accrued general and administrative expenses 2,322 2,960 Accrued operating expenses 1,662 1,654 Other accounts payable and accrued liabilities 2,197 3,758 Total accounts payable and accrued liabilities $ 42,111 $ 46,755 |
Schedule Of Supplemental Disclosures | Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the six months ended June 30, 2018 and 2017 (in thousands): Six Months Ended June 30, 2018 2017 Cash payments: Interest payments $ 2,596 $ 1,491 Income tax payments $ 81 $ 498 Non-cash investing activities in the consolidated statements of cash flows: Decrease in accrued capital expenditures $ (229) $ (7,935) |
Investment In Exaro Energy II22
Investment In Exaro Energy III LLC (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Investment In Exaro Energy III LLC [Abstract] | |
Schedule Of Condensed Balance Sheet Data | June 30, 2018 December 31, 2017 Current assets (1) $ 12,910 $ 17,063 Non-current assets: Net property and equipment 77,837 82,450 Gas processing deposit 1,150 1,150 Other non-current assets 445 390 Total non-current assets 79,432 83,990 Total assets $ 92,342 $ 101,053 Current liabilities $ 4,415 $ 6,199 Non-current liabilities: Long-term debt 32,411 40,375 Other non-current liabilities 3,958 3,858 Total non-current liabilities 36,369 44,233 Members' equity 51,558 50,621 Total liabilities & members' equity $ 92,342 $ 101,053 (1) Approximately $9.6 million and $12.8 million of current assets as of June 30, 2018 and December 31, 2017, respectively, is cash. |
Schedule Of Condensed Income Statement Data | Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Production: Oil (thousand barrels) 21 28 43 54 Gas (million cubic feet) 1,946 2,272 3,881 4,580 Total (million cubic feet equivalent) 2,072 2,442 4,139 4,902 Oil and natural gas sales $ 5,955 $ 7,844 $ 12,838 $ 17,016 Gain (loss) on derivatives (582) 841 1,044 3,402 Less: Lease operating expenses 3,278 4,767 6,668 7,987 Depreciation, depletion, amortization & accretion 2,321 2,249 4,729 4,591 General & administrative expense 351 874 705 1,606 Income (loss) from continuing operations (577) 795 1,780 6,234 Net interest expense (636) (328) (1,079) (952) Net income (loss) $ (1,213) $ 467 $ 701 $ 5,282 |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Income Taxes [Abstract] | |
Components Of Income Tax Expense (Benefit) | The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Current tax provision: Federal $ — $ — $ — $ — State 151 118 309 309 Total $ 151 $ 118 $ 309 $ 309 Total tax provision: Federal $ — $ — $ — $ — State 151 118 309 309 Total income tax provision $ 151 $ 118 $ 309 $ 309 |
Organization and Business (Deta
Organization and Business (Details) | 6 Months Ended |
Jun. 30, 2018aft | |
Southern Delaware Basin Of Texas [Member] | |
Organization and Business | |
Gross acres | 16,500 |
Net acres | 6,800 |
Maximum [Member] | Gulf of Mexico [Member] | |
Organization and Business | |
Water depth of operations | ft | 300 |
Exaro Energy III LLC [Member] | |
Organization and Business | |
Equity method investment, ownership percentage | 37.00% |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Details) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018USD ($)shares | Mar. 31, 2018USD ($) | Jun. 30, 2017USD ($)itemshares | Jun. 30, 2018USD ($)itemshares | Jun. 30, 2017USD ($)itemshares | Dec. 31, 2017 | |
Significant Accounting Policies [Line Items] | ||||||
Impairment of proved properties | $ 0 | $ 2.7 | $ 0 | |||
Impairment charges, unproved properties | $ 0.4 | $ 1.4 | $ 1.2 | $ 1.4 | ||
Number of platforms | item | 2 | 2 | ||||
Antidilutive (in shares) | shares | 1,133,534 | 1,366,091 | 1,197,029 | 1,367,242 | ||
Number of subsidiaries inactive and not Subsidiary Guarantor | item | 1 | |||||
Restricted assets, percent of net assets | 25.00% | |||||
Term of contract | 1 year | |||||
Revenue, Practical Expedient, Initial Application and Transition, Nondisclosure of Transaction Price Allocation to Remaining Performance Obligation [true/false] | true | |||||
Vermilion 170 [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Impairment of proved properties | $ 2.3 | |||||
Non-core onshore | ||||||
Significant Accounting Policies [Line Items] | ||||||
Impairment of proved properties | $ 0.4 | |||||
Minimum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Period settlement statements are received | 30 days | |||||
Maximum [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Period settlement statements are received | 90 days |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Details) - Disposal Group Disposed Of By Sale Not Discontinued Operations [Member] - USD ($) | May 25, 2018 | Mar. 28, 2018 | Feb. 01, 2017 |
Starr County Texas Assets [Member] | |||
Acquisition | |||
Aggregate sales price of assets sold | $ 600,000 | ||
Gain on sale of oil and gas property | $ 1,400,000 | ||
Karnes County Texas Assets [Member] | |||
Acquisition | |||
Aggregate sales price of assets sold | $ 21,000,000 | ||
Gain on sale of oil and gas property | $ 9,400,000 | ||
Southeast Texas Assets [Member] | |||
Acquisition | |||
Aggregate sales price of assets sold | $ 650,000 | ||
Gain on sale of oil and gas property | $ 2,900,000 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity price contracts - assets | $ 313 | |
Commodity price contracts - liabilities | (3,866) | $ (1,243) |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity price contracts - assets | 313 | |
Commodity price contracts - liabilities | $ (3,866) | |
RBC Credit Facility [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Maximum period of interest rate on floating-rate debt | 6 months |
Derivative Instruments (Derivat
Derivative Instruments (Derivative Contracts) (Details) $ in Thousands | 6 Months Ended |
Jun. 30, 2018USD ($)item$ / Mcf$ / bbl | |
Derivative [Line Items] | |
Fair Value | $ | $ (3,553) |
Derivative Contract Period July 2018 [Member] | Swap [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ 27 |
Commodity Derivative Flow Rate | item | 370,000 |
Price/Unit-Swap | $ / Mcf | 3.07 |
Derivative Contract Period July 2018 [Member] | Swap [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (21) |
Commodity Derivative Flow Rate | item | 6,000 |
Price/Unit-Swap | 70.11 |
Derivative Contract Period July 2018 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (54) |
Commodity Derivative Flow Rate | item | 6,000 |
Price/Unit-Floor | 58 |
Price/Unit-Cap | 68 |
Derivative Contract Period August To October 2018 [Member] | Swap [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ 34 |
Commodity Derivative Flow Rate | item | 70,000 |
Price/Unit-Swap | $ / Mcf | 3.07 |
Derivative Contract Period August To October 2018 [Member] | Swap [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (7) |
Commodity Derivative Flow Rate | item | 3,000 |
Price/Unit-Swap | 70.11 |
Derivative Contract Period July To October 2018 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (1,466) |
Commodity Derivative Flow Rate | item | 20,000 |
Price/Unit-Floor | 52 |
Price/Unit-Cap | 56.85 |
Derivative Contract Period1, November To December 2018 [Member] | Swap [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ 45 |
Commodity Derivative Flow Rate | item | 320,000 |
Price/Unit-Swap | $ / Mcf | 3.07 |
Derivative Contract Period1, November To December 2018 [Member] | Swap [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ 14 |
Commodity Derivative Flow Rate | item | 6,000 |
Price/Unit-Swap | 70.11 |
Derivative Contract Period1, November To December 2018 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (484) |
Commodity Derivative Flow Rate | item | 15,000 |
Price/Unit-Floor | 52 |
Price/Unit-Cap | 56.85 |
Derivative Contract Period2, November To December 2018 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (68) |
Commodity Derivative Flow Rate | item | 5,000 |
Price/Unit-Floor | 58 |
Price/Unit-Cap | 68 |
Derivative Contract Period July to December 2018 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (149) |
Commodity Derivative Flow Rate | item | 2,000 |
Price/Unit-Floor | 52 |
Price/Unit-Cap | 58.76 |
Derivative Contract Period1, January to December 2019 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (373) |
Commodity Derivative Flow Rate | item | 4,000 |
Price/Unit-Floor | 52 |
Price/Unit-Cap | 59.45 |
Derivative Contract Period2, January to December 2019 [Member] | Collar Options [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (1,037) |
Commodity Derivative Flow Rate | item | 7,000 |
Price/Unit-Floor | 50 |
Price/Unit-Cap | 58 |
Derivative Contract Period January To July 2019 [Member] | Swap [Member] | Oil [Member] | |
Derivative [Line Items] | |
Fair Value | $ | $ (14) |
Commodity Derivative Flow Rate | item | 6,000 |
Price/Unit-Swap | 66.10 |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Assets | ||
Gross | $ 313 | $ 1,188 |
Netting | (1,188) | |
Total | 313 | |
Liabilities: | ||
Gross | (3,866) | (2,431) |
Netting | 1,188 | |
Total | $ (3,866) | $ (1,243) |
Derivative Instruments (Operati
Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | $ (818) | $ 435 | $ (1,331) | $ 256 |
Unrealized gain (loss) | (1,792) | 1,052 | (2,311) | 4,327 |
Gain (loss) on derivatives, net | (2,610) | 1,487 | (3,642) | 4,583 |
Oil [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | (1,123) | 367 | (1,711) | 537 |
Unrealized gain (loss) | (1,311) | 293 | (1,594) | 817 |
Natural Gas [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | 305 | 68 | 380 | (281) |
Unrealized gain (loss) | $ (481) | $ 759 | $ (717) | $ 3,510 |
Stock Based Compensation (NonOp
Stock Based Compensation (NonOption) (Details) - USD ($) $ / shares in Units, $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Restricted Stock [Member] | ||
Activity, shares | ||
Canceled/Forfeited (in shares) | 24,980 | 63,490 |
Activity, weighted average fair value | ||
Granted (in dollars per share) | $ 3.76 | $ 7.56 |
Stock-based compensation | ||
Stock-based compensation expense | $ 3,000 | $ 3,100 |
Compensation expense not yet recognized | $ 4,700 | |
Compensation expense, remaining weighted average vesting period | 1 year 8 months 12 days | |
Target (as a percent) | 100.00% | |
Value of issued stock | $ 1,200 | $ 3,400 |
Weighted average forfeiture rate | 0.00% | 5.70% |
Value of restricted shares forfeited | $ 222 | $ 688 |
Shares available for grant | 1,200,000 | |
Performance Stock Units [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 3 years | |
Activity, shares | ||
Canceled/Forfeited (in shares) | 19,300 | 34,899 |
New Employees [Member] | Restricted Stock [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 3 years | |
Activity, shares | ||
Granted non-option (in shares) | 43,000 | |
New Employees [Member] | Performance Stock Units [Member] | ||
Activity, shares | ||
Granted non-option (in shares) | 30,000 | |
Activity, weighted average fair value | ||
Granted (in dollars per share) | $ 8.32 | |
Employees [Member] | Restricted Stock [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 3 years | |
Activity, shares | ||
Granted non-option (in shares) | 338,076 | |
Board of Directors [Member] | Restricted Stock [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 1 year | 1 year |
Activity, shares | ||
Granted non-option (in shares) | 82,500 | 74,325 |
Executives [Member] | Restricted Stock [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 3 years | |
Activity, shares | ||
Granted non-option (in shares) | 225,782 | |
Executives [Member] | Performance Stock Units [Member] | ||
Activity, shares | ||
Granted non-option (in shares) | 190,782 | 160,908 |
Activity, weighted average fair value | ||
Granted (in dollars per share) | $ 7.69 | $ 13.91 |
Minimum [Member] | Performance Stock Units [Member] | ||
Stock-based compensation | ||
Target (as a percent) | 0.00% | |
Maximum [Member] | Performance Stock Units [Member] | ||
Stock-based compensation | ||
Target (as a percent) | 300.00% |
Stock Based Compensation (Optio
Stock Based Compensation (Options) (Details) - Employee Stock Options [Member] - USD ($) | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Option roll forward | ||
Stock options granted in period (in shares) | 0 | 0 |
Exercise of stock options, shares | 0 | 0 |
Expired / Forfeited (in shares) | 0 | 14,586 |
Stock-based compensation | ||
Excess tax benefit from exercise/cancellation of stock options | $ 0 | $ 0 |
Other Financial Information (Ba
Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Accounts Receivable: | ||
Trade receivables | $ 5,316 | $ 6,565 |
Receivable for Alta Resources Distribution | 1,993 | 1,993 |
Joint interest billings | 3,887 | 4,030 |
Income taxes receivable | 424 | 424 |
Other receivables | 88 | 828 |
Allowance for doubtful accounts | (781) | (781) |
Total Accounts Receivable | 10,927 | 13,059 |
Prepaid expenses and other: | ||
Prepaid insurance | 920 | 1,177 |
Other | 620 | 715 |
Total prepaid expenses and other | 1,540 | 1,892 |
Accounts payable and accrued liabilities: | ||
Royalties and revenue payable | 18,888 | 18,181 |
Advances from partners | 4,145 | 2,243 |
Accrued exploration and development | 8,171 | 8,400 |
Trade payables | 4,726 | 9,559 |
Accrued general and administrative expenses | 2,322 | 2,960 |
Accrued operating expenses | 1,662 | 1,654 |
Other accounts payable and accrued liabilities | 2,197 | 3,758 |
Total Accounts Payable and Accrued Liabilities | $ 42,111 | $ 46,755 |
Other Financial Information (Su
Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash payments: | ||
Interest payments | $ 2,596 | $ 1,491 |
Income tax payments | 81 | 498 |
Non-cash investing activities in the consolidated statements of cash flows: | ||
Decrease in accrued capital expenditures | $ (229) | $ (7,935) |
Investment in Exaro Energy II35
Investment in Exaro Energy III LLC (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Schedule of Equity Method Investments Financials | ||||
Gain (loss) from investment in affiliates, net of income taxes | $ (475) | $ 166 | $ 232 | $ 1,950 |
Exaro Energy III LLC [Member] | ||||
Schedule of Equity Method Investments Financials | ||||
Equity method investment, ownership percentage | 37.00% | 37.00% | ||
Share of equity in investment | $ 18,600 | $ 18,600 | ||
Gain (loss) from investment in affiliates, net of income taxes | (500) | 200 | 200 | 2,000 |
Tax (expense) benefit from equity investment | $ 0 | $ 0 | $ 0 | $ 0 |
Investment in Exaro Energy II36
Investment in Exaro Energy III LLC (Balance Sheet) (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Non-current assets: | ||
Net property and equipment | $ 339,953 | $ 345,957 |
Other non-current assets | 19,867 | 19,723 |
Non-current liabilities: | ||
Other non-current liabilities | 3,541 | 248 |
Exaro Energy III LLC [Member] | ||
Schedule of Equity Method Investments Financials | ||
Current assets | 12,910 | 17,063 |
Non-current assets: | ||
Net property and equipment | 77,837 | 82,450 |
Gas processing deposit | 1,150 | 1,150 |
Other non-current assets | 445 | 390 |
Total non-current assets | 79,432 | 83,990 |
Total assets | 92,342 | 101,053 |
Current liabilities | 4,415 | 6,199 |
Non-current liabilities: | ||
Long-term debt | 32,411 | 40,375 |
Other non-current liabilities | 3,958 | 3,858 |
Total non-current liabilities | 36,369 | 44,233 |
Member's equity | 51,558 | 50,621 |
Total liabilities & member's equity | 92,342 | 101,053 |
Cash and cash equivalents | $ 9,600 | $ 12,800 |
Investment in Exaro Energy II37
Investment in Exaro Energy III LLC (Income Statement) (Details) MMcfe in Thousands, MMcf in Thousands, MBbls in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||||||||||||||
Jun. 30, 2018MMcf | Jun. 30, 2018MBbls | Jun. 30, 2018MMcfe | Jun. 30, 2018USD ($) | Jun. 30, 2017MMcf | Jun. 30, 2017MBbls | Jun. 30, 2017MMcfe | Jun. 30, 2017USD ($) | Jun. 30, 2018MMcf | Jun. 30, 2018MBbls | Jun. 30, 2018MMcfe | Jun. 30, 2018USD ($) | Jun. 30, 2017MMcf | Jun. 30, 2017MBbls | Jun. 30, 2017MMcfe | Jun. 30, 2017USD ($) | |
Schedule of Equity Method Investments Financials | ||||||||||||||||
Revenues | $ 18,448 | $ 20,276 | $ 38,885 | $ 39,700 | ||||||||||||
Gain (loss) on derivatives | (2,610) | 1,487 | (3,642) | 4,583 | ||||||||||||
Impairment expense | 3,890 | 1,400 | ||||||||||||||
General & administrative expense | 5,354 | 5,833 | 12,080 | 12,429 | ||||||||||||
Net income (loss) | (6,241) | (5,149) | ||||||||||||||
Exaro Energy III LLC [Member] | ||||||||||||||||
Schedule of Equity Method Investments Financials | ||||||||||||||||
Production | 1,946 | 21 | 2,272 | 28 | 3,881 | 43 | 4,580 | 54 | ||||||||
Total Production (Mcfe) | MMcfe | 2,072 | 2,442 | 4,139 | 4,902 | ||||||||||||
Revenues | 5,955 | 7,844 | 12,838 | 17,016 | ||||||||||||
Gain (loss) on derivatives | (582) | 841 | 1,044 | 3,402 | ||||||||||||
Lease operating expenses | 3,278 | 4,767 | 6,668 | 7,987 | ||||||||||||
Depreciation, depletion, amortization & accretion | 2,321 | 2,249 | 4,729 | 4,591 | ||||||||||||
General & administrative expense | 351 | 874 | 705 | 1,606 | ||||||||||||
Income (loss) from continuing operations | (577) | 795 | 1,780 | 6,234 | ||||||||||||
Net interest expense | (636) | (328) | (1,079) | (952) | ||||||||||||
Net income (loss) | $ (1,213) | $ 467 | $ 701 | $ 5,282 |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||||
Oct. 31, 2013USD ($) | Jun. 30, 2018USD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2018USD ($)item | Jun. 30, 2017USD ($) | Aug. 01, 2018USD ($) | Dec. 31, 2017USD ($) | |
Debt Instrument [Line Items] | |||||||
Interest expense | $ 1,262 | $ 925 | $ 2,671 | $ 1,684 | |||
RBC Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Revolving credit facility, maximum borrowing capacity | $ 500,000 | ||||||
Revolving credit facility, borrowing base | 110,000 | 110,000 | $ 105,000 | ||||
Credit facility amount outstanding | 80,800 | 80,800 | $ 85,400 | ||||
Letters of credit amount outstanding | 1,900 | 1,900 | $ 1,900 | ||||
Line of credit, available | 27,300 | 27,300 | |||||
Interest expense | $ 1,300 | $ 900 | $ 2,700 | $ 1,700 | |||
Weighted average interest rate (as a percent) | 5.80% | 5.80% | 5.20% | ||||
RBC Credit Facility [Member] | Minimum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Current ratio | 1 | ||||||
RBC Credit Facility [Member] | Maximum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Leverage ratio | 3.50 | ||||||
RBC Credit Facility [Member] | Southern Delaware Basin Of Texas [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Number of wells | item | 3 |
Income Taxes (Expense Benefit)
Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Current: | ||||
State | $ 151 | $ 118 | $ 309 | $ 309 |
Total | 151 | 118 | 309 | 309 |
Total: | ||||
State | 151 | 118 | 309 | 309 |
Income tax provision | $ 151 | $ 118 | $ 309 | $ 309 |
U.S. federal statutory corporate rate (as a percent) | 21.00% |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Millions | 1 Months Ended | 6 Months Ended | |
Sep. 30, 2012USD ($) | Nov. 30, 2010USD ($)site | Jun. 30, 2018USD ($) | |
Throughput commitment | |||
Loss Contingency | |||
Estimated deficiency | $ 1 | ||
Loss contingency expense | $ 0.7 | ||
Lavaca County Case [Member] | |||
Legal Proceedings | |||
Damages sought by plaintiffs | $ 5.3 | ||
Number of wells involved in litigation | site | 2 | ||
Litigation Case Filed by Mineral Interest Owner Harris County [Member] | |||
Legal Proceedings | |||
Damages sought by plaintiffs | $ 10.7 | ||
Additional portion of mineral interest claimed by plaintiff | 6.25% |