Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Mar. 15, 2019 | Jun. 30, 2018 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | Carbon Energy Corp | ||
Entity Central Index Key | 0000086264 | ||
Trading Symbol | CRBO | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Small Business | true | ||
Entity Shell Company | false | ||
Entity Emerging Growth Company | false | ||
Entity Ex Transition Period | false | ||
Entity Public Float | $ 28.2 | ||
Entity Common Stock, Shares Outstanding | 7,655,759 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 5,736 | $ 1,650 |
Accounts receivable: | ||
Revenue | 19,671 | 2,206 |
Joint interest billings and other | 1,770 | 1,151 |
Insurance receivable (Note 3) | 522 | |
Due from related parties | 2,075 | |
Commodity derivative asset | 3,517 | 215 |
Prepaid expense, deposits, and other current assets | 1,894 | 783 |
Inventory | 900 | |
Total current assets | 34,010 | 8,080 |
Oil and gas properties, full cost method of accounting: | ||
Proved, net | 248,455 | 34,178 |
Unproved | 5,416 | 1,947 |
Other property, plant and equipment, net | 17,563 | 737 |
Total property, plant and equipment, net | 271,434 | 36,862 |
Investments in affiliates (Note 6) | 598 | 14,267 |
Commodity derivative asset - non-current | 3,505 | 10 |
Other non-current assets | 1,344 | 790 |
Total non-current assets | 276,881 | 51,929 |
Total assets | 310,891 | 60,009 |
Current liabilities: | ||
Accounts payable and accrued liabilities (Note 11) | 34,816 | 11,218 |
Firm transportation contract obligations (Note 14) | 6,129 | 127 |
Total current liabilities | 40,945 | 11,345 |
Non-current liabilities: | ||
Firm transportation contract obligations (Note 14) | 12,729 | 134 |
Production and property taxes payable | 2,914 | 520 |
Warrant liability | 2,017 | |
Asset retirement obligations (Note 3) | 19,211 | 7,357 |
Credit facilities and notes payable (Note 7) | 109,138 | 22,140 |
Notes payable – related party (Note 7) | 49,919 | |
Total non-current liabilities | 193,911 | 32,168 |
Commitments and contingencies (Note 14) | ||
Stockholders’ equity: | ||
Preferred stock, $0.01 par value; liquidation preference of $224,000; authorized 1,000,000 shares, 50,000 and zero shares issued and outstanding at December 31, 2018 and 2017, respectively | 1 | |
Common stock, $0.01 par value; authorized 35,000,000 shares, 7,655,759 and 6,005,633 shares issued and outstanding at December 31, 2018 and 2017, respectively | 77 | 60 |
Additional paid-in capital | 84,612 | 58,813 |
Accumulated deficit | (36,939) | (44,218) |
Total Carbon stockholders’ equity | 47,751 | 14,655 |
Non-controlling interests | 28,284 | 1,841 |
Total stockholders’ equity | 76,035 | 16,496 |
Total liabilities and stockholders’ equity | $ 310,891 | $ 60,009 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Balance Sheets [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 1,000,000 | 1,000,000 |
Preferred stock, shares issued | 50,000 | 0 |
Preferred stock, shares outstanding | 50,000 | 0 |
Preferred stock, liquidation preference | $ 224,000 | $ 224,000 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 35,000,000 | 35,000,000 |
Common stock, shares issued | 7,655,759 | 6,005,633 |
Common stock, shares outstanding | 7,655,759 | 6,005,633 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue: | ||
Natural gas sales | $ 16,018 | $ 15,298 |
Natural gas liquids | 1,143 | |
Oil sales | 30,891 | 4,213 |
Commodity derivative gain | 4,894 | 2,928 |
Other income | 105 | 34 |
Total revenue | 53,051 | 22,473 |
Expenses: | ||
Lease operating expenses | 15,960 | 6,141 |
Transportation and gathering costs | 4,453 | 2,172 |
Production and property taxes | 1,813 | 1,276 |
General and administrative | 13,779 | 9,528 |
General and administrative - deferred fees writedown | 1,999 | |
General and administrative - related party reimbursement | (4,547) | (2,703) |
Depreciation, depletion, and amortization | 8,108 | 2,544 |
Accretion of asset retirement obligation | 868 | 307 |
Total expenses | 42,433 | 19,265 |
Operating income | 10,618 | 3,208 |
Other income and (expense): | ||
Interest expense | (5,920) | (1,202) |
Warrant derivative gain | 225 | 3,133 |
Investment in affiliates | 7,859 | 1,158 |
Other | (3) | 28 |
Total other income | 2,161 | 3,117 |
Income before income taxes | 12,779 | 6,325 |
Provision for income taxes | (74) | |
Net income before non-controlling interest and preferred shares | 12,779 | 6,399 |
Net income attributable to non-controlling interests | 4,375 | 81 |
Net income attributable to preferred shares - beneficial conversion feature | 1,125 | |
Net income attributable to preferred shares - preferred return | 224 | |
Net income attributable to common shares | $ 7,055 | $ 6,318 |
Net income per common share: | ||
Basic | $ 0.94 | $ 1.12 |
Diluted | $ 0.87 | $ 0.49 |
Weighted average common shares outstanding (in thousands): | ||
Basic | 7,525 | 5,662 |
Diluted | 7,839 | 6,452 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock | Preferred Stock | Additional paid in capital | Non- controlling interest | Accumulated Deficit |
Balances at Dec. 31, 2016 | $ 8,973 | $ 55 | $ 57,588 | $ 1,865 | $ (50,536) | |
Balances, shares at Dec. 31, 2016 | 5,482 | |||||
Stock based compensation | 1,106 | 1,106 | ||||
Stock based compensation, shares | ||||||
Vested restricted stock | $ 1 | (1) | ||||
Vested restricted stock, shares | 67 | |||||
Vested performance units | $ 1 | (1) | ||||
Vested performance units, shares | 80 | |||||
Restricted stock and performance units exchanged for tax withholding | (399) | $ (1) | (398) | |||
Restricted stock and performance units exchanged for tax withholding, shares | (55) | |||||
Non-controlling interest contributions, net | (105) | (105) | ||||
Shares issued for exercise of warrant (Note 6) | 2,791 | $ 4 | 2,787 | |||
Shares issued for exercise of warrant (Note 6), shares | 432 | |||||
Warrant derivative extinguishment | 2,049 | 2,049 | ||||
Class B Fair Value (Note 6) | (4,317) | (4,317) | ||||
Net income | 6,399 | 81 | 6,318 | |||
Balances at Dec. 31, 2017 | 16,496 | $ 60 | 58,813 | 1,841 | (44,218) | |
Balances, shares at Dec. 31, 2017 | 6,006 | |||||
Stock based compensation | 1,133 | 1,133 | ||||
Stock based compensation, shares | ||||||
Vested restricted stock | $ 1 | (1) | ||||
Vested restricted stock, shares | 60 | |||||
Vested performance units | $ 1 | (1) | ||||
Vested performance units, shares | 108 | |||||
Restricted stock and performance units exchanged for tax withholding | (197) | (197) | ||||
Restricted stock and performance units exchanged for tax withholding, shares | (46) | |||||
Preferred share issuance | 5,000 | $ 1 | 4,999 | |||
Preferred share issuance, shares | 50 | |||||
Beneficial conversion feature | 1,125 | (1,125) | ||||
CCC warrant exercise - share issuance | 24,792 | $ 15 | 8,312 | 16,465 | ||
CCC warrant exercise - share issuance, shares | 1,528 | |||||
Majority control of CCC (Note 4) | 10,429 | 10,429 | ||||
Units issued with 2018 Subordinated Notes, related party (Note 7) | 489 | 489 | ||||
Non-controlling interest contributions, net | 5,114 | 5,114 | ||||
Net income | 12,779 | 4,375 | 8,404 | |||
Balances at Dec. 31, 2018 | $ 76,035 | $ 77 | $ 1 | $ 84,612 | $ 28,284 | $ (36,939) |
Balances, shares at Dec. 31, 2018 | 7,656 | 50 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities: | ||
Net income (loss) | $ 12,779 | $ 6,399 |
Items not involving cash: | ||
Depreciation, depletion and amortization | 8,108 | 2,544 |
Accretion of asset retirement obligations | 868 | 307 |
Unrealized commodity derivative gain | 8,742 | (2,158) |
Warrant derivative gain | (225) | (3,133) |
Stock-based compensation expense | 1,133 | 1,106 |
Investment in affiliates gain | (7,734) | (1,128) |
Amortization of debt issuance costs | 966 | 176 |
Other | (109) | |
Net change in: | ||
Accounts receivable | 545 | (812) |
Prepaid expenses, deposits and other current assets | 1,067 | (477) |
Accounts payable, accrued liabilities and firm transportation contracts | 2,472 | 1,205 |
Other non-current assets | (392) | |
Net cash provided by operating activities | 10,845 | 3,920 |
Cash flows from investing activities: | ||
Development and acquisition of properties and equipment | (2,995) | (1,591) |
Acquisition of oil and gas properties, asset acquisitions (Note 3) | (46,980) | |
Acquisition of oil and gas properties, business combinations, net of cash received (Note 3) | (20,461) | |
Other non-current assets | (145) | |
Investment in affiliates | (6,797) | |
Net cash used in investing activities | (70,436) | (8,533) |
Cash flows from financing activities: | ||
Vested restricted stock and performance units exchanged for tax withholding | (197) | (399) |
Proceeds from credit facilities and notes payable | 118,628 | 7,210 |
Proceeds from preferred shares | 5,000 | |
Payments on credit facilities and notes payable | (64,150) | (1,300) |
Payments of debt issuance costs | (718) | |
Contributions from non-controlling interests | 5,164 | |
Distributions to non-controlling interests | (50) | (106) |
Net cash provided by financing activities | 63,677 | 5,405 |
Net increase in cash and cash equivalents | 4,086 | 792 |
Cash and cash equivalents, beginning of period | 1,650 | 858 |
Cash and cash equivalents, end of period | $ 5,736 | $ 1,650 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2018 | |
Organization [Abstract] | |
Organization | Note 1 - Organization Carbon Energy Corporation’s and its subsidiaries’ (formerly known as Carbon Natural Gas Company and referred to herein as “we”, “us”, or “Carbon”) business is comprised of the assets and properties of us and our subsidiaries. Appalachian and Illinois Basin Operations In the Appalachian and Illinois Basins, operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates this relationship as of December 31, 2018. In December 2018, we completed the acquisition of all of the Class A Units of Carbon Appalachian Company, LLC, a Delaware limited liability company (“Carbon Appalachia”), owned by Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-A”), and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-B”), collectively (“Old Ironsides”) for a purchase price of $58.1 million subject to purchase price adjustments (“OIE Membership Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company, LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield Pipeline Company and Appalachia Gas Services Company, LLC). Ventura Basin Operations In California, Carbon California Operating Company, LLC (“CCOC”), conducts operations on behalf of Carbon California’s operations. On February 1, 2018, Yorktown exercised the California Warrant, resulting in our aggregate sharing percentage in Carbon California increasing from 17.81% to 56.40%. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates (“Prudential”) owns 46.08% of the voting and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The following organizational chart illustrates this relationship as of December 31, 2018. Collectively, references to “us” include Carbon California, CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”), Nytis LLC, and Carbon Appalachia. |
Reverse Stock Split
Reverse Stock Split | 12 Months Ended |
Dec. 31, 2018 | |
Reverse Stock Split [Abstract] | |
Reverse Stock Split | Note 2 - Reverse Stock Split Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of our issued and outstanding common stock became one share of common stock and no fractional shares were issued. The accompanying financial statements and related disclosures give retroactive effect to the reverse stock split for all periods presented. In connection with the reverse stock split, the number of authorized shares of our common stock was decreased from 200,000,000 to 10,000,000. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 3 - Summary of Significant Accounting Policies Accounting policies used by us reflect industry practices and conform to accounting principles generally accepted in the United States of America (“GAAP”). The more significant of such accounting policies are briefly discussed below. Principles of Consolidation The consolidated financial statements include the accounts of us and our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA. Nytis USA owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships. Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest. Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying consolidated financial statements. Cash and Cash Equivalents Cash and cash equivalents, if any, in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the consolidated financial statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments. Accounts Receivable We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that we have identified. At December 31, 2018 and 2017, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates. Revenue Our Accounts receivable - Revenue is comprised of oil and natural gas revenues from producing activities. Marketing Gas Revenue We sell production purchased from third parties as well as production from our own oil and gas producing properties. Gas revenues are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction. Storage Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our storage systems and are not directly dependent on commodity prices. Transportation, gathering, and compression We generally purchase natural gas from producers at the wellhead or other receipt points, gather the natural gas through our gathering system, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds or index arrangements generally correlate with the price of natural gas. Joint Interest Billings and Other Our accounts receivable - joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings. The Company recognizes revenues associated with over-deliveries or under-deliveries of natural gas to purchasers as an asset or a liability, whichever is appropriate. As of December 31, 2018, and 2017, there was an imbalance due to us in the amount of approximately $551,000 and $193,000, respectively. Insurance Receivable Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider and is in receipt of a portion of funds associated with the claims as of December 31, 2018. The Company has determined the receivable is collectible and is included in insurance receivable on the consolidated balance sheets. As of December 31, 2018, the Company has an insurance receivable of $522,000 and collected $3.1 million from previously submitted claims. In January 2019, the Company received a settlement of $800,000 for all remaining claims with the insurance company (see Note 18). Inventory Inventory, which consist primarily of natural gas, is recorded at the lower of weighted average cost or market value. Gas that is available for immediate use, referred to as working gas, is recorded within current assets. Inventory also consists of material and supplies used in connection with the Company’s maintenance, storage and handling. Inventory is stated at the lower of cost or net realizable value. Prepaid Expense, Deposits and Other Current Assets Our prepaid expense, deposit and other current assets are comprised of prepaid insurance, the current portion of unamortized debt issuance costs and deposits. Oil and Natural Gas Sales We sell our oil, natural gas and natural gas liquids production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil, natural gas, and natural gas liquids sales for the years ended December 31, 2018 and 2017. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business. For the years ended Purchaser 2018 2017 Purchaser A 17 % 23 % Purchaser E 16 % - % Purchaser B 12 % 17 % Purchaser C 9 % 12 % Purchaser D 8 % 11 % As of December 31, 2018, none of the above purchasers comprised more than 10% of total accounts receivable. One purchaser’s receivable acquired with the closing of the OIE Membership Acquisition accounts for approximately 10% of accounts receivable as of December 31, 2018. We recognize an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2018, and 2017, we had a purchaser imbalance receivable of $551,000 and $193,000, respectively, within account receivables-joint interest billings and other. As of December 31, 2018 and 2017, we had a purchaser imbalance payable of approximately $0 and $25,000 within accounts payable and accrued expenses, respectively. Accounting for Oil and Gas Operations We use the full cost method of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by us for our own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods. For the years ended December 31, 2018 and 2017, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity. We capitalize interest in accordance with Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore, interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities. Other Property, Plant and Equipment Other property, plant and equipment are recorded at cost upon acquisition. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5 years, and pipeline facilities and equipment are depreciated over twenty years. Leasehold improvements are depreciated, using the straight-line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts. Base Gas Gas that is used to maintain wellhead pressures within the storage fields, referred to as base gas, is recorded other property, plant and equipment on the consolidated balance sheet. Base gas is held in a storage field that is not intended for sale but is required for efficient and reliable operation of the facility. Non-current Assets We review our non-current assets, consisting of property, plant and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not non-current assets have been impaired. Other Non-current Assets Our other non-current assets are comprised of bonds and the non-current portion of deferred debt issue and financing costs. Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Investment in affiliates will increase or decrease by our share of the affiliates’ profits or losses and such profits or losses are recognized in our consolidated statements of operations. If we hold greater than 50% of voting shares, we will generally consolidate the entities under the voting interest model. Prior to their consolidation on February 1, 2018 and December 31, 2018 for our investments in Carbon California and Carbon Appalachia, respectively, we used the hypothetical liquidation at book value (“HLBV”) method to recognize our share of profits or losses. We review equity method investments for impairment whenever events or changes in circumstances indicate that “an other than temporary” decline in value has occurred. Related Party Transactions Management Reimbursements In our role as manager of Carbon California and Carbon Appalachia (prior to completion of the OIE Membership Acquisition on December 31, 2018), we receive reimbursements for management services. These reimbursements are included in general and administrative – related party reimbursement on our consolidated statements of operations. Operating Reimbursements In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable – due from related parties on our consolidated balance sheets and are therefore not included in our operating expenses on our consolidated statements of operations (see Note 17). Due from Related parties As of December 31, 2017, and prior to consolidation of Carbon California and Carbon Appalachia as of February 1, 2018 and December 31, 2018, respectively, our receivables - due from related parties are comprised of receivables from Carbon California and Carbon Appalachia in our role as manager and operator of these entities (see Note 17). General and Administrative – Deferred Fees Writedown Approximately $2.0 million in financing costs were expensed in the preparation of an equity raise that we do not believe is likely to occur in the short term. Warrant Liability We issued warrants related to investments in Carbon California and Carbon Appalachia. We accounted for these warrants in accordance with guidance contained in Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging Asset Retirement Obligations Our asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred, and the cost of such liability is recorded as an increase in the carrying amount of the related non-current asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs (see Note 12). The following table is a reconciliation of the ARO for the years ended December 31, 2018 and 2017. Year Ended December 31, (in thousands) 2018 2017 Balance at beginning of year $ 7,357 $ 5,120 Accretion expense 868 307 Change in estimate of cash outflow 361 2,402 Additions from Carbon California (Note 4) 2,921 - Additions from Seneca Acquisition (Note 4) 5,132 - Additions from Liberty Acquisition (Note 4) 45 - Additions from OIE Membership Acquisition 5,626 - Less: sale of wells - (92 ) 22,310 7,737 Less: ARO recognized as accounts payable and accrued liabilities (3,099 ) (380 ) Balance at end of year $ 19,211 $ 7,357 For the year ended December 31, 2017, we did not have any additions of ARO compared to $14.1 million of additions to ARO in 2018, primarily due to the acquisition of producing oil and gas properties in both the Ventura and Appalachian Basins. Upon the closing of the OIE Membership Acquisition on December 31, 2018 and the closing of the Carbon California Acquisition on February 1, 2018, the asset retirement obligations associated with Carbon Appalachia and Carbon California assets were required to be remeasured at fair value, resulting in the change noted above. During the year ended December 31, 2017, we increased the estimated cost of retirement obligations for certain wells in the Appalachian Basin. Our estimated costs range from $20,000 to $45,000 per well in the Appalachian Basin. This increase to estimated costs resulted in a $2.4 million increase to our ARO in 2017. Financial Instruments Our financial instruments include cash and cash equivalents; accounts receivables; prepaid expense, deposits and other current assets; accounts payable and accrued liabilities; commodity derivative assets and liabilities, warrant liability, notes payable and our credit facilities. The carrying value of cash and cash equivalents, accounts receivable, and accounts payables and accrued liabilities are representative of their fair value, due to the short maturity of these instruments. Our commodity derivative assets and liabilities and warrant liability are recorded at fair value, as discussed below and in Note 12. The carrying amount of our credit facilities approximate fair value since borrowings bear interest at variable rates, which are representative of our credit adjusted borrowing rate. Commodity Derivative Instruments We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the consolidated balance sheets and the changes in fair value are recognized as gains or losses in revenues in the consolidated statements of operations. Income Taxes We account for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. With the passage of the Tax Cut and Jobs Act (“TCJA”), we were required to remeasure deferred income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate became effective January 1, 2018. We account for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized. Stock - Based Compensation For restricted stock, compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). For performance units, once it becomes probable that the performance measure(s) will be achieved, expense is recognized over the remainder of the performance period. Revenue Recognition Oil, natural gas and natural gas liquids revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability is reasonably assured. Natural gas revenues are recognized on the basis of our net revenue interest (see Note 10). Earnings Per Common Share Basic earnings per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period). The following table sets forth the calculation of basic and diluted income per share: For the Year Ended (in thousands except per share amounts) 2018 2017 Net income attributable to common shareholders $ 7,055 $ 6,318 Less: warrant derivative gain (225 ) (3,133 ) Diluted net income 6,830 3,185 Basic weighted-average common shares outstanding during the period 7,525 5,662 Add dilutive effects of warrants and non-vested shares of restricted stock 314 790 Diluted weighted-average common shares outstanding during the period 7,839 6,452 Basic net income per common share $ 0.94 $ 1.12 Diluted net income per common share $ 0.87 $ 0.49 For the year ended December 31, 2018, we had net income and the diluted income per common share calculation includes the anti-dilutive effects of approximately 314,000 non-vested shares of restricted stock. In addition, approximately 280,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. For the year ended December 31, 2017, we had net income and the diluted income per common share calculation includes the anti-dilutive effects of approximately 519,000 warrants and approximately 271,000 non-vested shares of restricted stock. In addition, approximately 259,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. Oil and Gas Reserves Oil and gas reserves represent theoretical quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates and the projected economic value of our properties will differ from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery of these reserves. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments, fair value of warrants, fair value of equity method investments, fair value of assets acquired and liabilities assumed qualifying as business contributions and asset retirement obligations. Actual results could differ from those estimates and assumptions used. Recently Adopted Accounting Pronouncement In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers Recently Issued Accounting Pronouncements In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes a comprehensive new lease standard designed 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. ASU 2016-02 is effective for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The Company adopted this guidance on January 1, 2019, using the modified retrospective approach. As part of the assessment process, the Company utilized external consultants to evaluate agreements under this guidance as well as assess the completeness of the lease population. The Company continues to evaluate the effect of adopting ASU 2016-02 on the financial statements, accounting policies, and internal controls. The adoption is expected to result in an increase in the assets and liabilities recorded on its consolidated balance sheet and additional disclosures. The Company does not expect a material impact on its consolidated statement of operations. In January 2018, the FASB issued Update 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 In July 2018, the FASB issued Update No. 2018-11, Leases (Topic 842): Targeted Improvements There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Acquisitions and Divestitures [Abstract] | |
Acquisitions and Divestitures | Note 4 - Acquisitions and Divestitures Acquisitions Majority Control of Carbon California Carbon California was formed in 2016 by us and entities managed by Yorktown and Prudential to acquire oil and gas producing assets in the Ventura Basin of California. In connection with the entry into the limited liability company agreement of Carbon California, we received Class B Units and issued to Yorktown the California Warrant exercisable for shares of our common stock. The exercise price for the California Warrant was payable exclusively with Class A Units of Carbon California held by Yorktown and the number of shares of our common stock for which the California Warrant was exercisable was determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant. The issuance of the Class B Units and the California Warrant were in contemplation of each other (Note 6), and under non-monetary related party guidance, we accounted for the California Warrant, at issuance, based on the fair value of the California Warrant as of the date of grant (February 15, 2017) and recorded a non-current warrant liability with an associated offset to Additional Paid in Capital (“APIC”). Future changes to the fair value of the California Warrant were recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became our investment in Carbon California with an offsetting entry to Additional Paid In Capital (“APIC”). Additionally, we accounted for our 17.81% profits interest in Carbon California as an equity method investment until January 31, 2018. On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests, and Prudential owns 46.08% voting and profits interest in Carbon California. The exercise of the California Warrant and the acquisition of the additional ownership interest is accounted for as a step acquisition in which we obtained control in accordance with ASC 805, Business Combinations Amount Fair value of Carbon common shares transferred as consideration $ 8,327 Fair value of NCI 16,466 Fair value of previously held interest 7,243 Fair value of contribution associated with acquisition of Yorktown’s interest in CCC 8,637 Fair value of business acquired $ 40,673 Assets acquired and liabilities assumed are as follows: Amount Cash $ 275 Accounts receivable: Joint interest billings and other 690 Receivable - related party 1,610 Prepaid expense, deposits, and other current assets 1,723 Oil and gas properties: Proved 65,114 Unproved 1,495 Other property, plant, and equipment, net 877 Other non-current assets 475 Accounts payable and accrued liabilities (6,054 ) Commodity derivative liability - current (916 ) Commodity derivative liability - non-current (1,729 ) Asset retirement obligations - current (384 ) Asset retirement obligations - non-current (2,537 ) Subordinated Notes, related party, net (8,874 ) Senior Revolving Notes, related party (11,000 ) Notes payable (92 ) Total net assets acquired $ 40,673 During the 4 th On the date of the acquisition, we derecognized our equity investment in Carbon California and recognized a gain of approximately $5.4 million based on the fair value of our previously held interest compared to its carrying value. For assets and liabilities accounted for as business combinations, including the Carbon California Acquisition, to determine the fair value of the assets acquired, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The determination of the fair value of the accounts payable and accrued liabilities assumed, required significant judgement, including estimates relating to production assets. Seneca Acquisition On May 1, 2018, Carbon California acquired approximately 309 oil wells and approximately 6,800 gross acres (6,600 net) of oil and gas leases, and fee interests in and to certain lands, situated in the Ventura Basin, together with associated pipelines, facilities, equipment and other property rights from Seneca Resources Corporation (“ Seneca Acquisition Utilizing the assistance of third-party valuation specialists, we considered various factors in our estimate of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, and (vi) working conditions and expected lives of vehicles and equipment. We determined that substantially all of the fair value of the assets acquired related to proved oil and gas properties and, as such, the Seneca Acquisition does not meet the definition of a business. Therefore, we have accounted for the transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired. The fair value of the production assets were determined using the income approach using Level 3 inputs according to the ASC 820, Fair Value Amount Identifiable assets acquired: Proved oil and gas properties $ 38,021 Unproved oil and gas properties 100 Other property, plant and equipment 588 Other assets 167 Total identified assets $ 38,876 Consolidation of Carbon California and Seneca Acquisition Unaudited Pro Forma Results of Operations Below are unaudited consolidated results of operations for the twelve months ended December 31, 2018 and 2017, as though the Carbon California Acquisition and the Seneca Acquisition had been completed as of January 1, 2017. The Carbon California Acquisition closed February 1, 2018, and the Seneca Acquisition closed May 1, 2018, and accordingly, our unaudited consolidated statements of operations for the year ended December 31, 2018, includes the Carbon California Acquisition results of operations for the period February 1, 2018 through December 31, 2018, inclusive of the Seneca Acquisition results of operations for the period May 1, 2018 through December 31, 2018. Unaudited Pro Forma (in thousands, except per share amounts) 2018 2017 Revenue $ 33,256 $ 35,122 Net (loss) income before non-controlling interests 5,232 13,969 Net (loss) income attributable to non-controlling interests (2,334 ) 92 Net (loss) income attributable to controlling interests $ 7,566 $ 13,877 Net income per share (basic) $ 1.00 $ 2.49 Net income per share (diluted) $ 0.96 $ 2.14 Liberty Acquisition On July 11, 2018, we completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and the associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “ Liberty Acquisition Majority Control of Carbon Appalachia On December 16, 2016, Carbon Appalachia was formed by us, entities managed by Yorktown and entities managed by Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia began substantial operations on April 3, 2017 and is engaged primarily in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas in the Appalachia Basin. On April 3, 2017, Carbon, Yorktown and Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0 million has been contributed as of December 31, 2018. Carbon Appalachia (i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of the Company, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”) with an initial borrowing base of $10.0 million. In connection with Carbon entering into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received 1,000 Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price dictated by the warrant agreement (the “Appalachia Warrant”). The Appalachia Warrant is payable exclusively with Class A Units of Carbon Appalachia held by Yorktown. On November 1, 2017, Yorktown exercised the Appalachia Warrant, resulting in us acquiring 2,940 Class A Units from Yorktown. On August 15, 2017, the Carbon Appalachia LLC Agreement was amended and, as a result, we agreed to contribute an initial commitment of future capital contributions as well as Yorktown’s, and Yorktown will not participate in future capital contributions. Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver. On September 29, 2017, Carbon Appalachia issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $11.0 million. Prior to the closing of the OIE Membership Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia. On December 31, 2018, we acquired all of Old Ironsides Class A Units of Carbon Appalachia for approximately $58.1 million, subject to certain closing adjustments. We paid $33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also provide for mandatory prepayments upon the occurrence of certain subsequent liquidity events and a one-time principal reduction payment in the aggregate amount of $2.0 million on or before February 1, 2019. The $2.0 million payment was made to Old Ironsides on February 1, 2019. The Old Ironsides Acquisition is accounted for as a business combination in accordance with ASC 805, Business Combinations The Company, utilizing the assistance of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate market conditions. We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired on a preliminary basis as follows: Amount Cash consideration $ 33,000 Old Ironsides Notes 25,065 Fair value of previously held equity interest 14,158 Fair value of business acquired $ 72,223 Assets acquired and liabilities assumed are as follows: Amount Cash $ 12,283 Accounts receivable: Revenue 12,834 Trade receivable 1,941 Commodity derivative asset 198 Inventory 900 Prepaid expenses, deposits, and other current assets 456 Oil and gas properties: Proved 107,499 Unproved 1,869 Other property, plant and equipment, net 15,626 Other non-current assets 514 Accounts payable and accrued liabilities (19,114 ) Due to related parties (458 ) Firm transportation contract obligations (18,724 ) Asset retirement obligations (5,626 ) Notes payable (37,975 ) Total net assets acquired $ 72,223 The preliminary fair value of the assets acquired and liabilities assumed were determined using various valuation techniques, including an income approach. On the date of the acquisition, we derecognized our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 million based on the fair value of our previously held interest compared to its carrying value. For assets and liabilities accounted for as business combinations, including the Carbon Appalachia acquisition, to determine the fair value of the assets acquired, the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The Company used the income approach and made market assumptions as to projections of utilization, future operating costs and a market participant weighted average costs of capital to determine the fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets. Consolidation of Carbon Appalachia and OIE Membership Acquisition Unaudited Pro Forma Results of Operations Below are unaudited consolidated results of operations for the twelve months ended December 31, 2018 and for the period of April 3, 2017 (inception) through December 31, 2017, as though the OIE Membership Acquisition had been completed as of April 3, 2017. For Year Ended December 31, For the period of April 3, 2017 (inception) through December 31, (in thousands, except per share amounts) 2018 2017 Revenue $ 136,592 $ 54,058 Net (loss) income before non-controlling interests 11,320 7,208 Net (loss) income attributable to non-controlling interests 4,375 81 Net (loss) income attributable to controlling interests $ 5,596 7,127 Net income per share (basic) $ 0.74 1.26 Net income per share (diluted) $ 0.69 0.62 |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Property and Equipment [Abstract] | |
Property and Equipment | Note 5 – Property, Plant and Equipment Net property, plant and equipment at December 31, 2018 and 2017 consists of the following: (in thousands) As of December 31, 2018 2017 Oil and gas properties: Proved oil and gas properties $ 347,059 $ 114,893 Unproved properties not subject to depletion 5,416 1,947 Accumulated depreciation, depletion, amortization and impairment (98,604 ) (80,715 ) Net oil and gas properties 253,871 36,125 Pipeline facilities and equipment 12,714 - Base gas 2,122 - Furniture and fixtures, computer hardware and software, and other equipment 6,649 1,758 Accumulated depreciation and amortization (3,922 ) (1,021 ) Net other property, plant and equipment 17,563 737 Total property, plant and equipment, net $ 271,434 $ 36,862 We had approximately $5.4 million and $1.9 million, at December 31, 2018 and 2017, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2018 and 2017, our unproved properties consist principally of leasehold acquisition costs in the following areas: As of December 31, (in thousands) 2018 2017 Ventura Basin: California $ 1,595 $ - Illinois Basin: Indiana 432 432 Illinois 136 136 Appalachian Basin: Kentucky 920 915 Ohio 66 66 Tennessee 1,869 - West Virginia 398 398 Total unproved properties not subject to depletion $ 5,416 $ 1,947 During the year ended December 31, 2018, there were no leasehold costs reclassified into proved property. During the year ended December 31, 2017, expiring leasehold costs reclassified into proved property were approximately $52,000. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. These costs do not relate to any individually significant projects. The excluded properties are assessed for impairment at least annually. We capitalized overhead applicable to acquisition and exploration activities of approximately $337,000 and $66,000 for the years ended December 31, 2018 and 2017, respectively. Depletion expense related to oil and gas properties for the years ended December 31, 2018 and 2017 was approximately $7.3 million and $2.2 million or $0.89 and $0.40 per Mcfe, respectively. Depreciation expense related to furniture and fixtures, computer hardware and software and other equipment for the years ended December 31, 2018 and 2017 was approximately $803,000 and $387,000, respectively. |
Investments in Affiliates
Investments in Affiliates | 12 Months Ended |
Dec. 31, 2018 | |
Investments in Affiliates [Abstract] | |
Investments in Affiliates | Note 6 - Investments in Affiliates The following table outlines the changes in our investments in affiliates: (in thousands) Carbon California Carbon Appalachia Other Total Balance, December 31, 2016 $ - $ - $ 668 $ 668 Investment in affiliates gain - 1,090 38 1,128 Cash distributions - - (68 ) (68 ) Cash contributions - 6,865 - 6,865 Class B Units issuance 1,854 924 - 2,778 Appalachia Warrant exercise - 2,896 2,896 Balance, December 31, 2017 $ 1,854 $ 11,775 $ 638 $ 14,267 Investment in affiliates gain - 1,026 85 1,111 Cash distributions - - (125 ) (125 ) California Warrant exercise (1,854 ) - (1,854 ) OIE Membership Acquisition (12,801 ) (12,801 ) Balance, December 31, 2018 $ - $ - $ 598 $ 598 Carbon California For the period February 15, 2017 (inception) through January 31, 2018, based on our 17.81% interest in Carbon California, our ability to appoint a member to the board of directors and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“HLBV”) to determine our share of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would have received if Carbon California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed to members holding Class B Units and any remaining proceeds are then distributed to members holding Class A Units. For the period February 15, 2017 (inception) through January 31, 2018, Carbon California incurred a net loss of which our share (as a holder of Class B Units for that period) was zero. Effective February 1, 2018, upon the exercise of the California Warrant, we consolidate Carbon California in our consolidated financial statements (see Note 4). The following table sets forth, selected historical financial data for Carbon California. (in thousands) As of December 31, 2018 As of December 31, 2017 Current assets $ 11,829 $ 3,968 Total oil and gas properties, net 84,825 43,458 Non-current assets 89,173 44,759 Current liabilities 6,773 6,899 Non-current liabilities 56,664 23,279 Total members’ equity 37,565 18,549 (in thousands) Year Ended December 31, Period February 15, Revenues $ 32,317 $ 7,235 Operating expenses 20,057 9,893 Income (loss) from operations 12,260 (2,658 ) Net income (loss) 8,526 (6,552 ) Carbon Appalachia Outlined below is a summary of i) our contributions, ii) our resulting percent of Class A unit ownership and iii) our overall resulting Sharing Percentage of Carbon Appalachia after giving effect of all classes of ownership. Holders of units within each class of units participate in profit or losses and distributions according to their proportionate share of each class of units (“Sharing Percentage”). Timing Capital Resulting Class A Resulting April 2017 $0.24 million 2.00 % 2.98 % August 2017 $3.71 million 15.20 % 16.04 % September 2017 $2.92 million 18.55 % 19.37 % November 2017 Warrant exercise 26.50 % 27.24 % December 2018 OIE Membership Acquisition 100 % 100 % Based on our 27.24% combined Class A, Class B and Class C interest (and our ability as of December 31, 2018 to earn up to an additional 14.7%) in Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we are accounting for our investment in Carbon Appalachia under the equity method of accounting as it believes it can exert significant influence. We use the HLBV to determine its share of profits or losses in Carbon Appalachia and adjusts the carrying value of its investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which it acquired by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units. For the year ended December 31, 2018, Carbon Appalachia incurred a net gain, of which our share is approximately $1.0 million. For the period of April 3, 2017 (inception) through December 31, 2017, Carbon Appalachia incurred a net gain, of which our share is approximately $1.1 million. On December 31, 2018, we acquired all of Old Ironsides Class A Units of Carbon Appalachia for approximately $58.1 million, subject to certain closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides. Effective December 31, 2018, upon the closing of the OlE Membership Acquisition, we consolidate Carbon Appalachia in our consolidated financial statements. See Note 4. The following table sets forth, selected historical financial data for Carbon Appalachia. (in thousands) As of December 31, 2018 As of December 31, 2017 Current assets $ 28,613 $ 20,794 Total oil and gas properties, net 80,674 84,402 Non-current assets 96,814 97,762 Current liabilities 22,126 18,207 Non-current liabilities 58,480 59,420 Total members’ equity 44,821 40,929 (in thousands) Year Ended December 31, Period April 3, Revenues $ 83,541 $ 31,584 Operating expenses 77,084 26,764 Income from operations 6,457 4,820 Net income 4,053 3,005 |
Credit Facilities and Notes Pay
Credit Facilities and Notes Payable | 12 Months Ended |
Dec. 31, 2018 | |
Credit Facilities and Notes Payable [Abstract] | |
Credit Facilities and Notes Payable | Note 7 – Credit Facilities and Notes Payable The table below summarizes the outstanding credit facilities and notes payable as of December 31, 2018 (in thousands): 2018 Credit Facility – revolver $ 69,150 2018 Credit Facility – term note 15,000 Old Ironsides Notes 25,065 Non-current debt 57 Total gross notes payable 109,272 Less: Notes discount (134 ) Total net notes payable $ 109,138 The table below summarizes the outstanding notes payable – related party as of December 31, 2018 (in thousands): Senior Revolving Notes, related party, due February 15, 2022 $ 38,500 Subordinated Notes, related party, due February 15, 2024 13,000 Total gross notes payable 51,500 Less: Deferred notes costs 156 Less: Notes discount (1,737 ) Total net notes payable $ 49,919 2018 Credit Facility In connection with and concurrently with the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated the Credit Facility and the CAE Credit Facility which provides for a $500.0 million senior secured asset-based revolving credit facility (the “2018 Credit Facility”) (“Nytis USA” “Borrowers” The 2018 Credit Facility is guaranteed by each existing and future direct or indirect subsidiaries of the Borrowers and certain other subsidiaries of the Company (subject to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and real property (subject to certain exclusions). Interest accrues on borrowings under the 2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under the 2018 Credit Facility may be prepaid without premium or penalty. The 2018 Credit Facility also provides for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020. The 2018 Credit Facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes to the accounting treatment or reporting practices; (xii) amend their constituent documents; and (xiii) enter into certain hedging transactions. The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the 2018 Credit Facility requires the Borrower’s compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio of 3.50 to 1.00 and a current ratio minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019. We expect to be in compliance with these covenants throughout the next twelve month period. Fees paid in connection with the 2018 Credit Facility included origination fees of $450,000 and arrangement fees of $80,000. As of December 31, 2018, there was approximately $70.0 million in outstanding borrowings and letters of credit and $5.0 million of additional borrowing capacity under the 2018 Credit Facility. The terms of the 2018 Credit Facility require us to enter into derivative contracts at fixed pricing for a certain percentage of our production. We are party to an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility. We incurred fees of approximately $962,000 directly associated with the issuance of our previous credit facility and amortized these fees over the life of the credit facility. The unamortized amount of fees associated with the previous credit facility was written off on December 31, 2018 in connection with the amendment. The current portion of unamortized fees is included in prepaid expense, deposits and other current assets and the non-current portion is included in other non-current assets. As of December 31, 2017, we had unamortized deferred issuance costs of $484,000 associated with the previous credit facility. During the years ended December 31, 2018 and 2017, we amortized approximately $786,000 and $176,000, respectively, as interest expense associated with the previous credit facility. Old Ironsides Notes On December 31, 2018, as part of the OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the “ Old Ironsides Notes Carbon California – Credit Facilities Effective as of February 1, 2018, our ownership in Carbon California increased to 56.41% due to the exercise of the California Warrant. As a result of this transaction, we consolidate Carbon California for financial reporting purposes. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests, and Prudential owns 46.08% voting and profit interest in Carbon California. Carbon California – Senior Revolving Notes, Related Party On February 15, 2017, Carbon California entered into the Note Purchase Agreement with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America for the issuance and sale of the Senior Revolving Notes due February 15, 2022. We are not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of December 31, 2018, the borrowing base was $41.0 million, of which $38.5 million was outstanding. Carbon California may elect to incur interest at either (i) 5.0% plus the London interbank offered rate (“LIBOR”) or (ii) 4.00% plus the Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of December 31, 2018, the effective borrowing rate for the Senior Revolving Notes was 7.39%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year. The Senior Revolving Notes are secured by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted. Carbon California incurred fees directly associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes. The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other non-current assets for a combined value of approximately $900,000. For the year ended December 31, 2018, Carbon California amortized fees of $217,000. The Note Purchase Agreement requires Carbon California to maintain certain financial and non-financial covenants which include the following ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, current ratio, and other qualitative covenants as defined in the Note Purchase Agreement. As of December 31, 2018, Carbon California was in compliance with its financial covenants. 2017 Carbon California – Subordinated Notes On February 15, 2017, Carbon California entered into the Securities Purchase Agreement with Prudential Capital Energy Partners, L.P. for the issuance and sale of the Subordinated Notes due February 15, 2024, bearing interest of 12% per annum. We are not a guarantor of the Subordinated Notes. The closing of the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of Subordinated Notes in the original principal amount of $10.0 million, of which $10.0 million remains outstanding as of December 31, 2018. Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. As of December 31, 2018, Carbon California has an outstanding discount of $1.7 million, which is presented net of the Subordinated Notes within Credit facility-related party on the consolidated balance sheets. The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively. Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted. The Securities Purchase Agreement requires Carbon California to maintain certain financial and non-financial covenants, which include the following ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative covenants as defined in the Securities Purchase Agreement. As of December 31, 2018, Carbon California was in compliance with its financial covenants. Carbon California – 2018 Subordinated Notes On May 1, 2018, Carbon California entered into an agreement with Prudential for the issuance and sale of the Carbon California 2018 Subordinated Notes in the amount of $3.0 million, of which $3.0 million remains outstanding as of December 31, 2018. Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Carbon California 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the Carbon California 2018 Subordinated Notes. As of December 31, 2018, Carbon California had an outstanding discount of $390,000 associated with these notes, which is presented net of the Carbon California 2018 Subordinated Notes within Credit facility – related party on the consolidated balance sheets. During the year ended December 31, 2018, Carbon California amortized $57,000. The Carbon California 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively. Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted. The Carbon California 2018 Subordinated Notes agreement requires Carbon California to maintain certain financial and non-financial covenants, which include the following ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative covenants as defined in the Carbon California 2018 Subordinated Notes. As of December 31, 2018, Carbon California was in compliance with its financial covenants. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Taxes [Abstract] | |
Income Taxes | Note 8 - Income Taxes The provision for income taxes for the years ended December 31, 2018 and 2017 consists of the following: (in thousands) For the Year Ended December 31, 2018 2017 Current income tax benefit $ - $ (74 ) Deferred income tax (benefit) expense (260 ) 7,080 Change in valuation allowance 260 (7,080 ) Total income tax benefit $ - $ (74 ) The effective income tax rate for the years ended December 31, 2018 and 2017 differed from the statutory U.S. federal income tax rate as follows: For the Year Ended December 31, 2018 2017 Federal income tax rate 21.0 % 35.0 % State income taxes, net of federal benefit 5.1 3.8 Permanent differences (1.2 ) (20.5 ) Non-controlling interest in consolidated partnerships (9.8 ) (0.8 ) True-up of prior year depletion in excess of basis 1.3 1.1 Stock-based compensation deficiency 1.1 3.1 Rate changes of prior year deferred (1.0 ) (1.8 ) True-up of prior year deferred 4.0 (4.5 ) Effect of tax cuts and TCJA - 91.0 Increase in valuation allowance and other 2.0 (107.7 ) Total effective income tax rate 22.5 % (1.1 )% The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2018 and 2017 are presented below: (in thousands) As of December 31, 2018 2017 Deferred tax assets Net operating loss carryforwards $ 8,066 $ 6,407 Depletion carryforwards 2,185 1,934 Accrual and other 863 450 Stock-based compensation 449 476 Asset retirement obligations 4,640 1,944 Property, plant and equipment 2,340 2,972 Total deferred tax assets 18,543 14,183 Deferred tax liability Interest in partnerships (517 ) (790 ) Derivative and other (1,056 ) (57 ) Less valuation allowance (16,970 ) (13,336 ) Net deferred tax asset $ - $ - The Company has net operating losses (“NOL”) of approximately $29.2 million available to reduce future years’ federal taxable income. The federal net operating losses generated before 2018 expire beginning in 2031 through 2037. While the 2018 net operating loss will never expire, it is available to offset only 80% of future years’ federal taxable income. The Company has various state NOL carryforwards available to reduce future years’ state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL will expire beginning in 2023 through 2037 depending upon each jurisdiction’s specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. The results of any audits will be accounted for in the period in which they are determined. The Company believes that the tax positions taken in the Company’s tax returns satisfy the more likely than not threshold for benefit recognition. Accordingly, no liabilities have been recorded by the Company. Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to the Company’s NOL and another deferred tax asset. The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December 31, 2017, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year. On December 22, 2017 the U.S. Government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act. The TCJA makes broad and complex changes to the U.S. tax code applicable to certain items in 2017 as well as those applicable to 2018 and subsequent years. ASC 740 requires the recognition of the tax effects of the of the TCJA for annual periods that include December 22, 2017. At December 31, 2017, the Company had made reasonable estimates of the effects on its existing deferred tax balances. The Company remeasured certain federal deferred tax assets and liabilities based upon the rates at which they are expected to reverse in the future, which is generally twenty one percent. The provisional amount recognized related to the remeasurement of its federal deferred tax balance was $6.0 million, which was subject to a valuation allowance at December 31, 2017. The Company will continue to analyze the TCJA and future IRS regulations, refine its calculations and gain a more thorough understanding of how individual states are implementing this new law. This further analysis could potentially affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders' Equity [Abstract] | |
Stockholders' Equity | Note 9 - Stockholders’ Equity Authorized and Issued Capital Stock Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented. On June 1, 2018, we amended our charter to increase the number of authorized shares of our common stock from 10,000,000 to 35,000,000. As of December 31, 2018, we had 35.0 million shares of common stock authorized with a par value of $0.01 per share, of which approximately 7.7 million were issued and outstanding, and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. On April 6, 2018, the Company entered into a preferred stock purchase agreement with Yorktown for a private placement of 50,000 shares of preferred stock for $5.0 million. During the year ended December 31, 2018, the increase in our issued and outstanding common stock is primarily due to (a) Yorktown’s exercise of the California Warrant (see Note 4), resulting in the issuance of approximately 1.5 million shares of our common stock in exchange for Class A Units in Carbon California representing approximately 46.96% of the then outstanding Class A Units, in addition to (b) restricted stock and restricted performance units, net of shares exchanged for payroll tax obligations paid by us, that vested during the year. Carbon Stock Incentive Plans We have two stock plans, the Carbon 2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were approved by our shareholders and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans. The Carbon Plans provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards, or a combination of the foregoing, to employees, officers, directors or consultants, provided that only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock awards. Restricted Stock Restricted stock awards for employees vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors, the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated other than for cause. We recognize compensation expense for these restricted stock grants based on the grant date fair value. The following table shows a summary of our unvested restricted stock under the Carbon Plans as of December 31, 2018 and 2017 as well as activity during the years then ended. Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, unvested, January 1, 2017 267,750 $ 7.78 Granted 81,050 7.20 Vested (65,753 ) 8.38 Forfeited (13,050 ) 6.19 Restricted stock awards, unvested, December 31, 2017 269,997 $ 7.54 Granted 106,000 9.820 Vested (59,550 ) 6.82 Forfeited (2,240 ) 7.41 Restricted stock awards, unvested, December 31, 2018 314,207 $ 8.40 Compensation costs recognized for these restricted stock grants were approximately $725,000 and $664,000 for the years ended December 31, 2018 and 2017, respectively. As of December 31, 2018, there was approximately $1.4 million of unrecognized compensation costs related to these restricted stock grants which we expect to be recognized over the next 6.3 years. Restricted Performance Units Performance units represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time as well as, in some cases, continued service requirements. The following table shows a summary of our unvested performance units as of December 31, 2018 and 2017 as well as activity during the years then ended. Number of Shares Restricted performance units, unvested, January 1, 2017 296,311 Granted 60,050 Vested (80,000 ) Forfeited (17,550 ) Restricted performance units, unvested, December 31, 2017 258,811 Granted 136,159 Vested (108,484 ) Forfeited (6,610 ) Restricted performance units, unvested, December 31, 2018 279,876 We account for the performance units granted during 2014 through 2018 at their fair value determined at the date of grant, which were $11.80, $8.00, $5.40, $7.20, and $9.80 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2018, we estimated that none of the performance units granted in 2018 and 2017 would vest, and, accordingly, no compensation cost has been recorded for these performance units. We estimated that it was probable that the performance units granted in 2014 and 2015 would vest and therefore compensation costs of approximately $135,000 and $442,000 related to these performance units were recognized for the years ended December 31, 2018 and 2017, respectively. During 2018, we estimated that it was probable that the performance units granted in 2016 would vest and therefore compensation costs of approximately $273,000 were recognized, As of December 31, 2018, if change in control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated unrecognized compensation cost related to unvested performance units would be approximately $3.0 million. Preferred Stock Series B Convertible Preferred Stock – Related Party In connection with the closing of the Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. The Preferred Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares for cash. The Preferred Stock accrues cash dividends at a rate of six percent (6%) of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus a preferred return over common stock holders and the holders of any junior ranking stock. As of December 31, 2018, the preferred return was approximately $224,000. We apply the guidance in ASC 480 “ Distinguishing Liabilities from Equity We have evaluated the Preferred Stock in accordance with ASC 815, “ Derivatives and Hedging Debt |
Revenue Recognition
Revenue Recognition | 12 Months Ended |
Dec. 31, 2018 | |
Revenue Recognition [Abstract] | |
Revenue Recognition | Note 10 - Revenue Recognition Revenue from Contracts with Customers We recognize revenue when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration we expect to receive in exchange for those products. Revenues from contracts with customers are recorded on the consolidated statements of operations based on the type of product being sold. Performance Obligations and Significant Judgments We sell oil and natural gas products in the United States through a single reportable segment. We primarily sell products within two regions of the United States: Appalachia and Illinois Basins and the Ventura Basin. We enter into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. Most of our 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 prevailing supply and demand conditions. The oil and natural gas is typically sold in an unprocessed state to third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when control of the oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. Transfer of control drives the presentation of transportation and gathering costs within the accompanying consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized as a reduction to the related revenue. A portion of our product sales are short-term in nature. For those contracts, we use the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period. We do not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained. Disaggregation of Revenues In the following table, revenue for the year ended December 31, 2018, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment. (in thousands) Type Appalachian and Illinois Basin Ventura Basin Total Natural gas sales $ 14,768 $ 1,250 $ 16,018 Natural gas liquids sales - 1,143 1,143 Oil sales 4,963 25,928 30,891 Total natural gas, natural gas liquids, and oil revenue $ 19,731 $ 28,321 $ 48,052 In the following table, revenue for the year ended December 31, 2017, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment. (in thousands) Type Appalachian and Illinois Basin Ventura Basin Total Natural gas sales $ 15,298 $ - $ 15,298 Oil sales 4,213 - 4,213 Total natural gas and oil revenue $ 19,511 $ - $ 19,511 Contract Balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606. Prior Period Performance Obligations We record revenue in the month production is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production. As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals are recorded in the month payment is received from the customer. These differences have not historically been material. For the year ended December 31, 2018, revenue recognized in the reporting period related to prior period performance obligations is immaterial. The estimated revenue is recorded within Accounts receivable – Revenue on the consolidated balance sheets. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 11 - Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at December 31, 2018 and 2017 consist of the following: (in thousands) As of December 31, 2018 2017 Accounts payable $ 7,670 $ 3,274 Oil and gas revenue suspense 2,675 1,776 Gathering and transportation payables 1,774 497 Production taxes payable 1,860 214 Drilling advances received from joint venture partner - 245 Accrued lease operating costs 3,155 684 Accrued ad valorem taxes-current 3,474 1,054 Accrued general and administrative expenses 3,111 2,473 Accrued asset retirement obligation-current 3,099 380 Accrued interest 955 247 Accrued gas purchases 5,441 - Other liabilities 1,603 374 Total accounts payable and accrued liabilities $ 34,816 $ 11,218 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | Note 12 - Fair Value Measurements Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of us. Unobservable inputs are inputs that reflect our assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities; Level 2: Quoted prices in active markets for similar assets or liabilities that are observable for the asset or liability; or Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. We have consistently applied the valuation techniques discussed below for all periods presented. The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy: (in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total December 31, 2018 Asset: Commodity derivatives $ - $ 7,022 $ - $ 7,022 December 31, 2017 Asset: Commodity derivatives $ - $ 225 $ - $ 225 Liability: Warrant derivative liability $ - $ - $ 2,017 $ 2,017 Commodity Derivative As of December 31, 2018, our commodity derivative financial instruments are comprised of fifteen natural gas swaps, twenty-eight oil swap, and eight natural gas costless collar agreements. As of December 31, 2017, our commodity derivative financial instruments were comprised of eight natural gas swaps, eight oil swaps, and one natural gas costless collar agreements. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all of our outstanding commodity derivative financial instruments as of December 31, 2018 is BP Energy Company. Warrant Derivative A third-party valuation specialist is utilized to determine the fair value of our California Warrant and Appalachia Warrant. These warrants are designated as Level 3. We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources. We estimated the fair value of the California Warrant on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8% and a risk-free rate of 2.3%. As we will receive Class A units in Carbon California in the event the holder exercises the California Warrant, we also considered the fair value of the Class A units in its valuation. We remeasured the California Warrant as of December 31, 2017, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on our shares at various timelines, the percentage return on the privately-held Carbon California Class A units at various timelines, an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.4 years. The California Warrant was exercised on February 1, 2018; therefore, the warrant liability was extinguished. We estimated the fair value of the Appalachia Warrant on April 3, 2017, the grant date of the warrant, to be approximately $1.3 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 39.3% and a risk-free rate of 2.1%. As we will receive Class A units in Carbon Appalachia in the event the holder exercises the Appalachia Warrant, we also considered the fair value of the Class A units in its valuation. We remeasured the Appalachia Warrant as of November 1, 2017, immediately prior to its exercise, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on our shares at various timelines, the percentage return on the privately-held Carbon Appalachia Class A units at various timelines, an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.5 years. As of December 31, 2017, the warrant liability had been extinguished. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: (in thousands) California Warrant Appalachia Warrant Total Balance, December 31, 2016 $ - $ - $ - Warrant liability 5,769 1,325 7,094 Unrealized (gain) loss included in warrant gain (3,752 ) 619 (3,133 ) Settlement of warrant liability - (1,944 ) (1,944 ) Balance, December 31, 2017 $ 2,017 $ - $ 2,017 Unrealized (gain) included in warrant gain (225 ) - (225 ) Settlement of warrant liability (1,792 ) - (1,792 ) Balance, December 31, 2018 $ - $ - $ - Assets and Liabilities Measured and Recorded at Fair Value on a Non-Recurring Basis The fair value of each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy. The fair value of the non-controlling interest in the partnerships we are required to consolidate was determined based on the net discounted cash flows of the proved developed producing properties attributable to the non-controlling interests in these partnerships. See Note 4 for the fair value of the non-controlling interest in Carbon California. We assume, at times, certain firm transportation contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation contract obligations was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These contractual obligations are being amortized on a monthly basis as we pay these firm transportation obligations in the future. The fair value measurements associated with the assets acquired and liabilities assumed in the business combinations for the majority control of Carbon California and OIE Membership Acquisition of Carbon Appalachia are outlined within Note 4. Debt Discount The fair value of the debt discount from the 1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million and $490,000, respectively. The debt discount was a Level 3 fair value assessment and was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Units. Asset Retirement Obligation The fair value of our asset retirement obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning oil and gas wells ranging from $20,000 to $45,000, which is based on our historical experience and industry expectations for similar work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, which takes into account our credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see Note 3). During the year ended December 31, 2018, we recorded additions to asset retirement obligations of approximately $14.1 million, which was the result of the Carbon California, Seneca, Liberty, and OIE Membership Acquisitions. We use the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money. Class B Units We received Class B units from Carbon California and Carbon Appalachia as part of the entry into the Carbon California LLC Agreement and Carbon Appalachia LLC Agreement, respectively. We estimated the fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation specialists. The fair values were based upon enterprise values derived from inputs including estimated future production rates, future commodity prices including price differentials as of the dates of closing, future operating and development costs and comparable market participants. |
Commodity Derivatives
Commodity Derivatives | 12 Months Ended |
Dec. 31, 2018 | |
Commodity Derivatives [Abstract] | |
Commodity Derivatives | Note 13 - Commodity Derivatives We historically have used commodity-based derivative contracts to manage exposures to commodity price on certain of our oil and natural gas production. We do not hold or issue derivative financial instruments for speculative or trading purposes. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the consolidated financial statements. Pursuant to the terms of our credit facilities with LegacyTexas Bank and Prudential, we have entered into swap and collar derivative agreements to hedge certain of our oil and natural gas production through 2021. As of December 31, 2018, these derivative agreements consisted of the following: Natural Gas Swaps Natural Gas Collars (1) Oil Swaps (1) Weighted Weighted Weighted Weighted Average Average Price WTI Average Brent Average Year MMBtu Price (a) MMBtu Range (a) Bbl Price (b) Bbl Price (c) 2019 15,055,000 $ 2.85 836,000 $ 2.60 – $3.19 218,597 $ 53.50 148,086 $ 66.82 2020 12,433,000 $ 2.73 1,018,000 $ 2.50 – $2.70 121,147 $ 55.37 151,982 $ 66.03 2021 2,598,000 $ 2.69 - $ - - $ - 86,341 $ 67.12 (1) Includes 100% of Carbon California’s outstanding derivative hedges at December 31, 2018, and not our proportionate share. (a) NYMEX Henry Hub Natural Gas futures contract for the respective period. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period. (c) Brent future contracts for the respective period. For our swap instruments, we receive a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that we will receive for the volumes under contract, while the floor establishes a minimum price. The following table summarizes the fair value of the derivatives recorded in the consolidated balance sheets (Note 11). These derivative instruments are not designated as cash flow hedging instruments for accounting purposes: (in thousands) As of December 31, 2018 2017 Commodity derivative contracts: Commodity derivative asset $ 3,517 $ 215 Commodity derivative asset – non-current $ 3,505 $ 10 The table below summarizes the commodity settlements and unrealized gains and losses related to our derivative instruments for the years ended December 31, 2018 and 2017. These commodity settlements and unrealized gains and losses are recorded and included in commodity derivative gain or loss in the accompanying consolidated statements of operations. (in thousands) For the year ended 2018 2017 Commodity derivative contracts: Settlement (loss) gains $ (3,848 ) $ 770 Unrealized gains 8,742 2,158 Total settlement and unrealized gains, net $ 4,894 $ 2,928 Commodity derivative settlement gains and losses are included in cash flows from operating activities in our consolidated statements of cash flows. The counterparty in all our derivative instruments is BP Energy Company. We have entered into International Swaps and Derivatives Association (“ISDA”) Master Agreements with BP Energy Company that establishes standard terms for the derivative contracts and inter-creditor agreements with LegacyTexas Bank/Prudential and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facilities. We net our derivative instrument fair value amounts executed with BP Energy Company pursuant to ISDA master agreements, which provides for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheet as of December 31, 2018. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative $ 4,605 $ (1,088 ) $ 3,517 Other non-current assets 4,690 (1,185 ) 3,505 Total derivative assets $ 9,295 $ (2,273 ) $ 7,022 Commodity derivative liabilities: Commodity derivative $ (1,088 ) $ 1,088 $ - Commodity derivative: non-current (1,185 ) 1,185 - Total derivative liabilities $ (2,273 ) $ 2,273 $ - The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheet as of December 31, 2017. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative $ 624 $ (409 ) $ 215 Other non-current assets 250 (240 ) 10 Total derivative assets $ 874 $ (649 ) $ 225 Commodity derivative liabilities: Commodity derivative $ (409 ) $ 409 $ - Commodity derivative: non-current (240 ) 240 - Total derivative liabilities $ (649 ) $ 649 $ - Due to the volatility of oil and natural gas prices, the estimated fair values of our derivatives are subject to large fluctuations from period to period. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies [Abstract] | |
Commitments and Contingencies | Note 14 - Commitments and Contingencies We have entered into employment agreements with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides for renewal provisions in one-year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events. We have entered into non-current firm transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at December 31, 2018 are summarized in the table below. Period Dekatherms per day Demand Charges January 2019 – March 2020 3,230 $ 0.20 – 0.62 April 2020 – May 2020 2,150 $ 0.20 June 2020 – May 2036 1,000 $ 0.20 Jan 2019 – Oct 2020 6,300 $ 0.21 Jan 2019 – Aug 2022 49,341 $ 0.21 – 0.56 Sep 2022 – May 2027 29,990 $ 0.21 F-36 As of December 31, 2018, the remaining commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition is $18.9 million and reflected in the Company’s consolidated balance sheet. The fair values of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being reduced monthly as the Company pays these firm transportation obligations in the future. Natural gas processing agreement We have entered into an initial five-year gas processing agreement. We have an option to extend the term of the agreement by another five years. The related demand charges for volume commitments over the remaining term of the agreement at December 31, 2018 are approximately $1.8 million per year. We will pay a processing fee of $2.50 per MCF for the term of the agreement, with a minimum annual volume commitment of 720,000 MCF. Capital Commitment As of December 31, 2018, we had no capital commitments associated with Carbon California. |
Retirement Savings Plan
Retirement Savings Plan | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Savings Plan [Abstract] | |
Retirement Savings Plan | Note 15 - Retirement Savings Plan We have a 401(k) plan available to eligible employees. The plan provides for 6% matching which vests immediately. For the years ended December 31, 2018 and 2017, we contributed approximately $441,000 and $175,000, respectively, for 401(k) contributions and related administrative expenses. |
Supplemental Cash Flow Disclosu
Supplemental Cash Flow Disclosure | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Disclosure [Abstract] | |
Supplemental Cash Flow Disclosure | Note 16 - Supplemental Cash Flow Disclosure Supplemental cash flow disclosures are presented below. Non-cash transaction items are primarily related to the consolidation of Carbon California and Carbon Appalachia during the year ended December 31, 2018. (in thousands) For the Years Ended 2018 2017 Cash paid during the period for: Interest payments $ 4,217 $ 967 Non-cash transactions: Units issued for 2018 Subordinated Notes $ 489 - Accounts receivable (17,076 ) - Prepaid expense (2,178 ) - Commodity derivative asset – current (198 ) - Inventory (900 ) - Proved oil and gas properties (139,613 ) - Unproved oil and gas properties (3,364 ) - Other fixed assets (16,502 ) - Equity method investments 14,655 5,674 Other non-current assets (989 ) - Accounts payable and accrued liabilities 26,292 67 Commodity derivative liability – non-current 2,645 - Firm transportation contract obligations 18,724 - Warrant liability (1,792 ) - Notes payable 83,006 - Asset retirement obligations 7,879 2,402 |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2018 | |
Related Parties [Abstract] | |
Related Parties | Note 17 - Related Parties During the years ended December 31, 2018 and 2017, we were engaged in the following transactions with related parties: Carbon California In 2017, we received 5,077 Class B Units of Carbon California, representing 17.81% of the voting and profits interest. On February 1, 2018, we received 11,000 Class A Units of Carbon California upon Yorktown’s exercise of the California Warrant. On May 1, 2018, we received 5,000 Class A Units of Carbon California in connection with our equity contribution of $5.0 million. On February 15, 2017, we entered into a management service agreement with Carbon California whereby we provide general management and administrative services. We initially received $600,000 annually, payable in four equal quarterly installments. We also received a one-time reimbursement of $500,000 in connection with the CRC and Mirada Acquisitions. Effective May 1, 2018, concurrent with the closing of the Seneca Acquisition, we receive $1.2 million annually. Carbon California reimburses us for all management related expenses such as travel, required third-party geological and/or accounting consulting, and other necessary expenses incurred by us in the normal course of managing Carbon California. In our role as manager of Carbon California we received reimbursements for the provision of management services from Carbon California of $50,000 for the one month ended January 31, 2018. These reimbursements are included in general and administrative - related party reimbursement on our consolidated statements of operations. Effective February 1, 2018, the management reimbursement received from Carbon California is eliminated at consolidation. This elimination was approximately $950,000 for the period February 1, 2018 through December 31, 2018. In addition to the management reimbursements, approximately $14,000 in general and administrative expenses were reimbursed for the one month ended January 31, 2018. General and administrative expenses reimbursed by Carbon California and eliminated in consolidation were approximately $42,000 for the period February 1, 2018, through December 31, 2018. Carbon California Operating Company (“CCOC”) is our subsidiary and the operator of Carbon California through an operating agreement. The operating agreement includes reimbursements and allocations made under the agreement. As of December 31, 2018, and 2017, approximately zero and $300,000, respectively, is due from Carbon California and included in accounts receivable - due from related party on the consolidated balance sheets. Carbon Appalachia During 2017, we received 1,000 Class B Units of Carbon Appalachia, representing a future profits interest after certain return thresholds to Class A Units are met. We also received 121 Class C Units of Carbon Appalachia, representing an approximate 1.0% profits interest, in exchange for unevaluated property in Tennessee. On November 1, 2017, we received 2,940 Class A units of Carbon Appalachia upon Yorktown’s exercise of the Appalachia Warrant. On December 31, 2018, we closed the OIE Membership Acquisition, whereby we acquired 100% of all outstanding interests in Carbon Appalachia owned by Old Ironside. On April 3, 2017, we entered into a management service agreement with Carbon Appalachia whereby we provide general management and administrative services. We initially received a quarterly reimbursement of $75,000; however, after the Enervest Acquisition in August 2017, the amount of the reimbursement varies quarterly based upon the percentage of our production in relation to the total of our production and Carbon Appalachia. During 2017, we also received a one-time reimbursement of $300,000 in connection with the CNX Acquisition. In our role as manager of Carbon Appalachia, prior to the completion of the OIE Membership Acquisition in December 2018, we received reimbursements for the provision of management services from Carbon Appalachia of approximately $3.0 million for the year ended December 31, 2018. These reimbursements are included in general and administrative - related party reimbursement on our consolidated statements of operations. In addition to the management reimbursements, approximately $1.5 million in general and administrative expenses were reimbursed for the year ended December 31, 2018 from Carbon Appalachia. Nytis LLC is the operator of Carbon Appalachia through an operating agreement. The operating agreement includes reimbursements and allocations made under the agreement. As of December 31, 2018, and 2017, approximately zero and $1.8 million, respectively, is due from Carbon Appalachia and included in accounts receivable – due from related party on the consolidated balance sheets. Ohio Basic Minerals During 2017, we received $96,000 in management reimbursements from Ohio Basic Minerals. There were no such reimbursements in 2018. Total Management Reimbursements Total management reimbursements recorded by us for the year ended December 31, 2018 and 2017 and described in detail above, were approximately $4.5 million and $1.6 million, respectively, of which approximately zero and $579,000 was included in accounts receivable – due from related party on the consolidated balance sheets as of December 31, 2018 and 2017. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 18 - Subsequent Events In January 2019, we reached a settlement agreement and received an $800,000 payment from our insurance provider related to the damage caused by the Carbon California wildfires. We evaluated activities from December 31, 2018, to the date of the independent registered public accountants report, the date these financial statements were available for issuance, we believe there are no additional subsequent events requiring recognition or disclosure. |
Supplemental Financial Data - O
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) | Note 19 - Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) Estimated Proved Oil, Natural Gas, and Natural Gas Liquid Reserves The reserve estimates as of December 31, 2018 and 2017 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance. Proved oil, natural gas, and natural gas liquid reserves as of December 31, 2018 and 2017 were calculated based on the prices for oil, natural gas, and natural gas liquids during the twelve-month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. SEC rules dictate the types of technologies that a company may use to establish reserve estimates, including the extraction of non-traditional resources, such as bitumen extracted from oil sands as well as oil and gas extracted from shales. Our estimates of our net proved, net proved developed, and net proved undeveloped oil, gas and natural gas liquids reserves and changes in our net proved oil, natural gas, and natural gas liquid reserves for 2018 and 2017 are presented in the table below. Proved oil, natural gas, and natural gas liquid reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include the average prices for oil and gas during the twelve-month period prior to the reporting date of December 31, 2018 and 2017 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. The independent engineering firm, Cawley, Gillespie & Associates, Inc. (“ CGA Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. A summary of the changes in quantities of proved oil, natural gas, and natural gas liquid reserves for the years ended December 31, 2018 and 2017 are as follows (in thousands): 2018 2017 Oil Natural Gas NGL Total Oil Natural Gas NGL Total MBbls MMcf MBbls MMcfe MBbls MMcf MBbls MMcfe Proved reserves, beginning of year 919 81,702 - 87,216 882 74,265 - 79,557 Revisions of previous estimates (2,803 ) 1,832 (1,147 ) (21,868 ) 107 12,199 - 12,841 Extensions and discoveries - - - - 16 136 - 232 Production (451 ) (4,798 ) (33 ) (7,702 ) (86 ) (4,898 ) - (5,414 ) Purchases of reserves in-place 21,233 376,664 3,103 522,680 - - - - Sales of reserves in-place - - - - - - - - Proved reserves, end of year 18,898 455,400 1,923 580,326 919 81,702 - 87,216 Proved developed reserves at: End of year 14,336 450,424 1,472 545,272 903 81,702 - 87,216 Proved undeveloped reserves at: End of year 4,562 4,976 451 35,054 16 - - 96 The estimated proved reserves for December 31, 2018 and 2017 includes approximately 3.3 Bcfe and 3.0 Bcfe, respectively, attributed to non-controlling interests of consolidated partnerships. Aggregate Capitalized Costs The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows: (in thousands) 2018 2017 Oil and gas properties: Proved oil and gas properties $ 347,059 $ 114,893 Unproved properties not subject to depletion 5,416 1,947 Accumulated depreciation, depletion, amortization and impairment (98,604 ) (80,715 ) Total $ 253,871 $ 36,125 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2018 and 2017: (in thousands) 2018 2017 Property acquisition costs: Unevaluated properties $ 3,464 $ 1 Proved properties and gathering facilities 63,517 289 Development costs 2,074 952 Gathering facilities 460 43 Asset retirement obligation 14,085 2,309 Total $ 83,600 $ 3,594 Our investment in unproved properties as of December 31, 2018, by the year in which such costs were incurred is set forth in the table below: 2018 2017 2016 (in thousands) Acquisition costs $ 3,464 $ 1 $ 1,946 Results of Operations from Oil and Gas Producing Activities Results of operations from oil and gas producing activities for the years ended December 31, 2018 and 2017 are presented below: (in thousands) 2018 2017 Revenues: Oil and gas sales, including commodity derivative gains and losses $ 52,946 $ 22,439 Expenses: Production expenses 22,226 9,589 Depletion expense 7,305 2,157 Accretion of asset retirement obligations 868 307 Total expenses 30,399 12,053 Results of operations from oil and gas producing activities $ 22,547 $ 10,386 Depletion rate per Mcfe $ 0.89 $ 0.40 Standardized Measure of Discounted Future Net Cash Flows Future oil and gas sales are calculated applying the prices used in estimating our proved oil and gas reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. Management does not rely upon the information that follows in making investment decisions. (in thousands) December 31, 2018 2017 Future cash inflows $ 2,878,392 $ 283,664 Future production costs (1,538,870 ) (119,501 ) Future development costs (76,852 ) (210 ) Future income taxes (258,277 ) (35,482 ) Future net cash flows 1,004,393 128,471 10% annual discount (612,325 ) (71,389 ) Standardized measure of discounted future net cash flows $ 392,068 $ 57,082 Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows: December 31, 2018 2017 (in thousands) Standardized measure of discounted future net cash flows, beginning of period $ 57,082 $ 44,711 Sales of oil and gas, net of production costs and taxes (25,681 ) (10,038 ) Price revisions 133,789 17,588 Extensions, discoveries and improved recovery, less related costs - 298 Changes in estimated future development costs (32,711 ) (324 ) Development costs incurred during the period 926 804 Quantity revisions (23,484 ) 11,196 Accretion of discount 5,708 4,471 Net changes in future income taxes (89,117 ) (7,425 ) Purchases of reserves-in-place 391,877 - Sales of reserves-in-place - - Changes in production rate timing and other (26,321 ) (4,199 ) Standardized measure of discounted future net cash flows, end of period $ 392,068 $ 57,082 The twelve-month weighted averaged adjusted prices in effect at December 31, 2018 and 2017 were as follows: 2018 2017 Oil (per Bbl) $ 65.56 $ 51.34 Natural Gas (per Mcf) $ 3.10 $ 2.98 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Summary of Significant Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of us and our consolidated subsidiaries. Upon the closing of the OIE Membership Acquisition on December 31, 2018, we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA. Nytis USA owns approximately 98.1% of Nytis LLC. Nytis LLC holds interests in various oil and gas partnerships. Partnerships and subsidiaries in which we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on our consolidated statements of operations and also reflect the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on our consolidated balance sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling interest. Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying consolidated financial statements. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents, if any, in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the consolidated financial statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments. |
Accounts Receivable | Accounts Receivable We grant credit to all qualified customers, which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and, if necessary, maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues that we have identified. At December 31, 2018 and 2017, we had not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts was provided for on those dates. Revenue Our Accounts receivable - Revenue is comprised of oil and natural gas revenues from producing activities. Marketing Gas Revenue We sell production purchased from third parties as well as production from our own oil and gas producing properties. Gas revenues are recognized on a gross basis as we purchase and take control of the gas prior to sale and are the principal in the transaction. Storage Under fee-based arrangements, we receive a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our storage systems and are not directly dependent on commodity prices. Transportation, gathering, and compression We generally purchase natural gas from producers at the wellhead or other receipt points, gather the natural gas through our gathering system, and then sell the natural gas based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. Our revenues under percent-of-proceeds or index arrangements generally correlate with the price of natural gas. Joint Interest Billings and Other Our accounts receivable - joint interest billings and other is comprised of receivables due from other exploration and production companies and individuals who own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability to withhold future revenues disbursements to recover any non-payment of joint-interest billings. The Company recognizes revenues associated with over-deliveries or under-deliveries of natural gas to purchasers as an asset or a liability, whichever is appropriate. As of December 31, 2018, and 2017, there was an imbalance due to us in the amount of approximately $551,000 and $193,000, respectively. |
Insurance Receivable | Insurance Receivable Insurance receivable is comprised of insurance claims for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The Company filed claims with its insurance provider and is in receipt of a portion of funds associated with the claims as of December 31, 2018. The Company has determined the receivable is collectible and is included in insurance receivable on the consolidated balance sheets. As of December 31, 2018, the Company has an insurance receivable of $522,000 and collected $3.1 million from previously submitted claims. In January 2019, the Company received a settlement of $800,000 for all remaining claims with the insurance company (see Note 18). |
Inventory | Inventory Inventory, which consist primarily of natural gas, is recorded at the lower of weighted average cost or market value. Gas that is available for immediate use, referred to as working gas, is recorded within current assets. Inventory also consists of material and supplies used in connection with the Company’s maintenance, storage and handling. Inventory is stated at the lower of cost or net realizable value. |
Prepaid Expense, Deposits, Inventory, and Other Current Assets | Prepaid Expense, Deposits and Other Current Assets Our prepaid expense, deposit and other current assets are comprised of prepaid insurance, the current portion of unamortized debt issuance costs and deposits. |
Oil and Natural Gas Sales | Oil and Natural Gas Sales We sell our oil, natural gas and natural gas liquids production to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil, natural gas, and natural gas liquids sales for the years ended December 31, 2018 and 2017. There are several purchasers in the areas where we sell our production. We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business. For the years ended Purchaser 2018 2017 Purchaser A 17 % 23 % Purchaser E 16 % - % Purchaser B 12 % 17 % Purchaser C 9 % 12 % Purchaser D 8 % 11 % As of December 31, 2018, none of the above purchasers comprised more than 10% of total accounts receivable. One purchaser’s receivable acquired with the closing of the OIE Membership Acquisition accounts for approximately 10% of accounts receivable as of December 31, 2018. We recognize an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2018, and 2017, we had a purchaser imbalance receivable of $551,000 and $193,000, respectively, within account receivables-joint interest billings and other. As of December 31, 2018 and 2017, we had a purchaser imbalance payable of approximately $0 and $25,000 within accounts payable and accrued expenses, respectively. |
Accounting for Oil and Gas Operations | Accounting for Oil and Gas Operations We use the full cost method of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by us for our own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. We perform a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods. For the years ended December 31, 2018 and 2017, we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. Future declines in oil and natural gas prices, increases in future operating expenses and future development costs could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity. We capitalize interest in accordance with Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore, interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration and development activities. |
Other Property, Plant and Equipment | Other Property, Plant and Equipment Other property, plant and equipment are recorded at cost upon acquisition. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5 years, and pipeline facilities and equipment are depreciated over twenty years. Leasehold improvements are depreciated, using the straight-line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts. Base Gas Gas that is used to maintain wellhead pressures within the storage fields, referred to as base gas, is recorded other property, plant and equipment on the consolidated balance sheet. Base gas is held in a storage field that is not intended for sale but is required for efficient and reliable operation of the facility. |
Non-current Assets | Non-current Assets We review our non-current assets, consisting of property, plant and equipment, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or not non-current assets have been impaired. |
Other Non-current Assets | Other Non-current Assets Our other non-current assets are comprised of bonds and the non-current portion of deferred debt issue and financing costs. |
Investments in Affiliates | Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. |
Related Party Transactions | Related Party Transactions Management Reimbursements In our role as manager of Carbon California and Carbon Appalachia (prior to completion of the OIE Membership Acquisition on December 31, 2018), we receive reimbursements for management services. These reimbursements are included in general and administrative – related party reimbursement on our consolidated statements of operations. Operating Reimbursements In our role as operator of Carbon California and Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable – due from related parties on our consolidated balance sheets and are therefore not included in our operating expenses on our consolidated statements of operations (see Note 17). Due from Related parties As of December 31, 2017, and prior to consolidation of Carbon California and Carbon Appalachia as of February 1, 2018 and December 31, 2018, respectively, our receivables - due from related parties are comprised of receivables from Carbon California and Carbon Appalachia in our role as manager and operator of these entities (see Note 17). |
General and Administrative - Deferred Fees Writedown | General and Administrative – Deferred Fees Writedown Approximately $2.0 million in financing costs were expensed in the preparation of an equity raise that we do not believe is likely to occur in the short term. |
Warrant Liability | Warrant Liability We issued warrants related to investments in Carbon California and Carbon Appalachia. We accounted for these warrants in accordance with guidance contained in Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging |
Asset Retirement Obligations | Asset Retirement Obligations Our asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred, and the cost of such liability is recorded as an increase in the carrying amount of the related non-current asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs (see Note 12). The following table is a reconciliation of the ARO for the years ended December 31, 2018 and 2017. Year Ended December 31, (in thousands) 2018 2017 Balance at beginning of year $ 7,357 $ 5,120 Accretion expense 868 307 Change in estimate of cash outflow 361 2,402 Additions from Carbon California (Note 4) 2,921 - Additions from Seneca Acquisition (Note 4) 5,132 - Additions from Liberty Acquisition (Note 4) 45 - Additions from OIE Membership Acquisition 5,626 - Less: sale of wells - (92 ) 22,310 7,737 Less: ARO recognized as accounts payable and accrued liabilities (3,099 ) (380 ) Balance at end of year $ 19,211 $ 7,357 For the year ended December 31, 2017, we did not have any additions of ARO compared to $14.1 million of additions to ARO in 2018, primarily due to the acquisition of producing oil and gas properties in both the Ventura and Appalachian Basins. Upon the closing of the OIE Membership Acquisition on December 31, 2018 and the closing of the Carbon California Acquisition on February 1, 2018, the asset retirement obligations associated with Carbon Appalachia and Carbon California assets were required to be remeasured at fair value, resulting in the change noted above. During the year ended December 31, 2017, we increased the estimated cost of retirement obligations for certain wells in the Appalachian Basin. Our estimated costs range from $20,000 to $45,000 per well in the Appalachian Basin. This increase to estimated costs resulted in a $2.4 million increase to our ARO in 2017. |
Financial Instruments | Financial Instruments Our financial instruments include cash and cash equivalents; accounts receivables; prepaid expense, deposits and other current assets; accounts payable and accrued liabilities; commodity derivative assets and liabilities, warrant liability, notes payable and our credit facilities. The carrying value of cash and cash equivalents, accounts receivable, and accounts payables and accrued liabilities are representative of their fair value, due to the short maturity of these instruments. Our commodity derivative assets and liabilities and warrant liability are recorded at fair value, as discussed below and in Note 12. The carrying amount of our credit facilities approximate fair value since borrowings bear interest at variable rates, which are representative of our credit adjusted borrowing rate. |
Commodity Derivative Instruments | Commodity Derivative Instruments We enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have elected not to designate our derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the consolidated balance sheets and the changes in fair value are recognized as gains or losses in revenues in the consolidated statements of operations. |
Income Taxes | Income Taxes We account for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. With the passage of the Tax Cut and Jobs Act (“TCJA”), we were required to remeasure deferred income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate became effective January 1, 2018. |
Stock - Based Compensation | Stock - Based Compensation For restricted stock, compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). For performance units, once it becomes probable that the performance measure(s) will be achieved, expense is recognized over the remainder of the performance period. |
Revenue Recognition | Revenue Recognition Oil, natural gas and natural gas liquids revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability is reasonably assured. Natural gas revenues are recognized on the basis of our net revenue interest (see Note 10). |
Earnings Per Common Share | Earnings Per Common Share Basic earnings per common share is computed by dividing the net income (loss) attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period). The following table sets forth the calculation of basic and diluted income per share: For the Year Ended (in thousands except per share amounts) 2018 2017 Net income attributable to common shareholders $ 7,055 $ 6,318 Less: warrant derivative gain (225 ) (3,133 ) Diluted net income 6,830 3,185 Basic weighted-average common shares outstanding during the period 7,525 5,662 Add dilutive effects of warrants and non-vested shares of restricted stock 314 790 Diluted weighted-average common shares outstanding during the period 7,839 6,452 Basic net income per common share $ 0.94 $ 1.12 Diluted net income per common share $ 0.87 $ 0.49 For the year ended December 31, 2018, we had net income and the diluted income per common share calculation includes the anti-dilutive effects of approximately 314,000 non-vested shares of restricted stock. In addition, approximately 280,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. For the year ended December 31, 2017, we had net income and the diluted income per common share calculation includes the anti-dilutive effects of approximately 519,000 warrants and approximately 271,000 non-vested shares of restricted stock. In addition, approximately 259,000 restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations. |
Oil and Gas Reserves | Oil and Gas Reserves Oil and gas reserves represent theoretical quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates and the projected economic value of our properties will differ from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery of these reserves. |
Use of Estimates in the Preparation of Financial Statements | Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments, fair value of warrants, fair value of equity method investments, fair value of assets acquired and liabilities assumed qualifying as business contributions and asset retirement obligations. Actual results could differ from those estimates and assumptions used. |
Recently Adopted Accounting Pronouncement | Recently Issued Accounting Pronouncements In February 2016, the FASB issued ASU 2016-02, Leases As part of the assessment process, the Company utilized external consultants to evaluate agreements under this guidance as well as assess the completeness of the lease population. The Company continues to evaluate the effect of adopting ASU 2016-02 on the financial statements, accounting policies, and internal controls. The adoption is expected to result in an increase in the assets and liabilities recorded on its consolidated balance sheet and additional disclosures. The Company does not expect a material impact on its consolidated statement of operations. In January 2018, the FASB issued Update 2018-01, Leases Land Easement Practical Expedient for Transition to Topic 842 In July 2018, the FASB issued Update No. 2018-11, Leases Targeted Improvements There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows. |
Recently Issued Accounting Pronouncements | Recently Issued Accounting Pronouncements In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes a comprehensive new lease standard designed 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. ASU 2016-02 is effective for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The Company adopted this guidance on January 1, 2019, using the modified retrospective approach. As part of the assessment process, the Company utilized external consultants to evaluate agreements under this guidance as well as assess the completeness of the lease population. The Company continues to evaluate the effect of adopting ASU 2016-02 on the financial statements, accounting policies, and internal controls. The adoption is expected to result in an increase in the assets and liabilities recorded on its consolidated balance sheet and additional disclosures. The Company does not expect a material impact on its consolidated statement of operations. In January 2018, the FASB issued Update 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 In July 2018, the FASB issued Update No. 2018-11, Leases (Topic 842): Targeted Improvements There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Summary of Significant Accounting Policies [Abstract] | |
Schedule of purchasers that account for 10% or more of total oil and natural gas sales | For the years ended Purchaser 2018 2017 Purchaser A 17 % 23 % Purchaser E 16 % - % Purchaser B 12 % 17 % Purchaser C 9 % 12 % Purchaser D 8 % 11 % |
Schedule of reconciliation of the ARO | Year Ended December 31, (in thousands) 2018 2017 Balance at beginning of year $ 7,357 $ 5,120 Accretion expense 868 307 Change in estimate of cash outflow 361 2,402 Additions from Carbon California (Note 4) 2,921 - Additions from Seneca Acquisition (Note 4) 5,132 - Additions from Liberty Acquisition (Note 4) 45 - Additions from OIE Membership Acquisition 5,626 - Less: sale of wells - (92 ) 22,310 7,737 Less: ARO recognized as accounts payable and accrued liabilities (3,099 ) (380 ) Balance at end of year $ 19,211 $ 7,357 |
Schedule of basic and diluted income (loss) per share | For the Year Ended (in thousands except per share amounts) 2018 2017 Net income attributable to common shareholders $ 7,055 $ 6,318 Less: warrant derivative gain (225 ) (3,133 ) Diluted net income 6,830 3,185 Basic weighted-average common shares outstanding during the period 7,525 5,662 Add dilutive effects of warrants and non-vested shares of restricted stock 314 790 Diluted weighted-average common shares outstanding during the period 7,839 6,452 Basic net income per common share $ 0.94 $ 1.12 Diluted net income per common share $ 0.87 $ 0.49 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |
Schedule of fair value of business acquired | Amount Fair value of Carbon common shares transferred as consideration $ 8,327 Fair value of NCI 16,466 Fair value of previously held interest 7,243 Fair value of contribution associated with acquisition of Yorktown’s interest in CCC 8,637 Fair value of business acquired $ 40,673 |
Schedule of assets acquired and liabilities assumed | Amount Cash $ 275 Accounts receivable: Joint interest billings and other 690 Receivable - related party 1,610 Prepaid expense, deposits, and other current assets 1,723 Oil and gas properties: Proved 65,114 Unproved 1,495 Other property, plant, and equipment, net 877 Other non-current assets 475 Accounts payable and accrued liabilities (6,054 ) Commodity derivative liability - current (916 ) Commodity derivative liability - non-current (1,729 ) Asset retirement obligations - current (384 ) Asset retirement obligations - non-current (2,537 ) Subordinated Notes, related party, net (8,874 ) Senior Revolving Notes, related party (11,000 ) Notes payable (92 ) Total net assets acquired $ 40,673 |
Schedule of unaudited pro-forma consolidated results | Unaudited Pro Forma (in thousands, except per share amounts) 2018 2017 Revenue $ 33,256 $ 35,122 Net (loss) income before non-controlling interests 5,232 13,969 Net (loss) income attributable to non-controlling interests (2,334 ) 92 Net (loss) income attributable to controlling interests $ 7,566 $ 13,877 Net income per share (basic) $ 1.00 $ 2.49 Net income per share (diluted) $ 0.96 $ 2.14 |
Seneca Acquisition [Member] | |
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |
Schedule of assets acquired and liabilities assumed | Amount Identifiable assets acquired: Proved oil and gas properties $ 38,021 Unproved oil and gas properties 100 Other property, plant and equipment 588 Other assets 167 Total identified assets $ 38,876 |
Old Ironsides [Member] | |
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | |
Schedule of fair value of business acquired | Amount Cash consideration $ 33,000 Old Ironsides Notes 25,065 Fair value of previously held equity interest 14,158 Fair value of business acquired $ 72,223 |
Schedule of assets acquired and liabilities assumed | Amount Cash $ 12,283 Accounts receivable: Revenue 12,834 Trade receivable 1,941 Commodity derivative asset 198 Inventory 900 Prepaid expenses, deposits, and other current assets 456 Oil and gas properties: Proved 107,499 Unproved 1,869 Other property, plant and equipment, net 15,626 Other non-current assets 514 Accounts payable and accrued liabilities (19,114 ) Due to related parties (458 ) Firm transportation contract obligations (18,724 ) Asset retirement obligations (5,626 ) Notes payable (37,975 ) Total net assets acquired $ 72,223 |
Schedule of unaudited pro-forma consolidated results | For Year Ended For the period of April 3, 2017 (inception) through December 31, (in thousands, except per share amounts) 2018 2017 Revenue $ 136,592 $ 54,058 Net (loss) income before non-controlling interests 11,320 7,208 Net (loss) income attributable to non-controlling interests 4,375 81 Net (loss) income attributable to controlling interests $ 5,596 7,127 Net income per share (basic) $ 0.74 1.26 Net income per share (diluted) $ 0.69 0.62 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property and Equipment [Abstract] | |
Schedule of net property and equipment | (in thousands) As of December 31, 2018 2017 Oil and gas properties: Proved oil and gas properties $ 347,059 $ 114,893 Unproved properties not subject to depletion 5,416 1,947 Accumulated depreciation, depletion, amortization and impairment (98,604 ) (80,715 ) Net oil and gas properties 253,871 36,125 Pipeline facilities and equipment 12,714 - Base gas 2,122 - Furniture and fixtures, computer hardware and software, and other equipment 6,649 1,758 Accumulated depreciation and amortization (3,922 ) (1,021 ) Net other property, plant and equipment 17,563 737 Total property, plant and equipment, net $ 271,434 $ 36,862 |
Schedule of unproved oil and gas properties | As of December 31, (in thousands) 2018 2017 Ventura Basin: California $ 1,595 $ - Illinois Basin: Indiana 432 432 Illinois 136 136 Appalachian Basin: Kentucky 920 915 Ohio 66 66 Tennessee 1,869 - West Virginia 398 398 Total unproved properties not subject to depletion $ 5,416 $ 1,947 |
Investments in Affiliates (Tabl
Investments in Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Schedule of Equity Method Investments [Line Items] | |
Schedule of changes in investments in affiliates | (in thousands) Carbon California Carbon Appalachia Other Total Balance, December 31, 2016 $ - $ - $ 668 $ 668 Investment in affiliates gain - 1,090 38 1,128 Cash distributions - - (68 ) (68 ) Cash contributions - 6,865 - 6,865 Class B Units issuance 1,854 924 - 2,778 Appalachia Warrant exercise - 2,896 2,896 Balance, December 31, 2017 $ 1,854 $ 11,775 $ 638 $ 14,267 Investment in affiliates gain - 1,026 85 1,111 Cash distributions - - (125 ) (125 ) California Warrant exercise (1,854 ) - (1,854 ) OIE Membership Acquisition (12,801 ) (12,801 ) Balance, December 31, 2018 $ - - $ 598 $ 598 |
Carbon California [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Schedule of selected historical financial data | (in thousands) As of December 31, 2018 As of December 31, 2017 Current assets $ 11,829 $ 3,968 Total oil and gas properties, net 84,825 43,458 Non-current assets 89,173 44,759 Current liabilities 6,773 6,899 Non-current liabilities 56,664 23,279 Total members’ equity 37,565 18,549 (in thousands) Year Ended December 31, Period February 15, Revenues $ 32,317 $ 7,235 Operating expenses 20,057 9,893 Income (loss) from operations 12,260 (2,658 ) Net income (loss) 8,526 (6,552 ) |
Carbon Appalachia [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Schedule of company's contributions | Timing Capital Resulting Class A Resulting April 2017 $0.24 million 2.00 % 2.98 % August 2017 $3.71 million 15.20 % 16.04 % September 2017 $2.92 million 18.55 % 19.37 % November 2017 Warrant exercise 26.50 % 27.24 % December 2018 OIE Membership Acquisition 100 % 100 % |
Schedule of selected historical financial data | (in thousands) As of December 31, 2018 As of December 31, 2017 Current assets $ 28,613 $ 20,794 Total oil and gas properties, net 80,674 84,402 Non-current assets 96,814 97,762 Current liabilities 22,126 18,207 Non-current liabilities 58,480 59,420 Total members’ equity 44,821 40,929 (in thousands) Year Ended December 31, Period April 3, Revenues $ 83,541 $ 31,584 Operating expenses 77,084 26,764 Income from operations 6,457 4,820 Net income 4,053 3,005 |
Credit Facilities and Notes P_2
Credit Facilities and Notes Payable (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Credit Facilities and Notes Payable [Abstract] | |
Schedule of outstanding credit facilities and notes payable | The table below summarizes the outstanding credit facilities and notes payable as of December 31, 2018 (in thousands): 2018 Credit Facility – revolver $ 69,150 2018 Credit Facility – term note 15,000 Old Ironsides Notes 25,065 Non-current debt 57 Total gross notes payable 109,272 Less: Notes discount (134 ) Total net notes payable $ 109,138 |
Schedule of notes payable outstanding | The table below summarizes the outstanding notes payable – related party as of December 31, 2018 (in thousands): Senior Revolving Notes, related party, due February 15, 2022 $ 38,500 Subordinated Notes, related party, due February 15, 2024 13,000 Total gross notes payable 51,500 Less: Deferred notes costs 156 Less: Notes discount (1,737 ) Total net notes payable $ 49,919 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Taxes [Abstract] | |
Schedule of provision for income taxes | (in thousands) For the Year Ended December 31, 2018 2017 Current income tax benefit $ - $ (74 ) Deferred income tax (benefit) expense (260 ) 7,080 Change in valuation allowance 260 (7,080 ) Total income tax benefit $ - $ (74 ) |
Schedule of effective income tax rate differed from the statutory U.S. federal income tax rate | For the Year Ended December 31, 2018 2017 Federal income tax rate 21.0 % 35.0 % State income taxes, net of federal benefit 5.1 3.8 Permanent differences (1.2 ) (20.5 ) Non-controlling interest in consolidated partnerships (9.8 ) (0.8 ) True-up of prior year depletion in excess of basis 1.3 1.1 Stock-based compensation deficiency 1.1 3.1 Rate changes of prior year deferred (1.0 ) (1.8 ) True-up of prior year deferred 4.0 (4.5 ) Effect of tax cuts and TCJA - 91.0 Increase in valuation allowance and other 2.0 (107.7 ) Total effective income tax rate 22.5 % (1.1 )% |
Schedule of deferred tax assets and liabilities | (in thousands) As of December 31, 2018 2017 Deferred tax assets Net operating loss carryforwards $ 8,066 $ 6,407 Depletion carryforwards 2,185 1,934 Accrual and other 863 450 Stock-based compensation 449 476 Asset retirement obligations 4,640 1,944 Property, plant and equipment 2,340 2,972 Total deferred tax assets 18,543 14,183 Deferred tax liability Interest in partnerships (517 ) (790 ) Derivative and other (1,056 ) (57 ) Less valuation allowance (16,970 ) (13,336 ) Net deferred tax asset $ - $ - |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Restricted Stock Awards [Member] | |
Class of Stock [Line Items] | |
Schedule of company's unvested restricted stock | Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, unvested, January 1, 2017 267,750 $ 7.78 Granted 81,050 7.20 Vested (65,753 ) 8.38 Forfeited (13,050 ) 6.19 Restricted stock awards, unvested, December 31, 2017 269,997 $ 7.54 Granted 106,000 9.820 Vested (59,550 ) 6.82 Forfeited (2,240 ) 7.41 Restricted stock awards, unvested, December 31, 2018 314,207 $ 8.40 |
Restricted Performance Units [Member] | |
Class of Stock [Line Items] | |
Schedule of company's unvested restricted stock | Number of Shares Restricted performance units, unvested, January 1, 2017 296,311 Granted 60,050 Vested (80,000 ) Forfeited (17,550 ) Restricted performance units, unvested, December 31, 2017 258,811 Granted 136,159 Vested (108,484 ) Forfeited (6,610 ) Restricted performance units, unvested, December 31, 2018 279,876 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue Recognition [Abstract] | |
Schedule of disaggregation of revenue | In the following table, revenue for the year ended December 31, 2018, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment. (in thousands) Type Appalachian and Illinois Basin Ventura Basin Total Natural gas sales $ 14,768 $ 1,250 $ 16,018 Natural gas liquids sales - 1,143 1,143 Oil sales 4,963 25,928 30,891 Total natural gas, natural gas liquids, and oil revenue $ 19,731 $ 28,321 $ 48,052 In the following table, revenue for the year ended December 31, 2017, is disaggregated by primary region within the United States and major product line. As noted above, we operate as one reportable segment. (in thousands) Type Appalachian and Illinois Basin Ventura Basin Total Natural gas sales $ 15,298 $ - $ 15,298 Oil sales 4,213 - 4,213 Total natural gas and oil revenue $ 19,511 $ - $ 19,511 |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Schedule of accounts payable and accrued liabilities | (in thousands) As of December 31, 2018 2017 Accounts payable $ 7,670 $ 3,274 Oil and gas revenue suspense 2,675 1,776 Gathering and transportation payables 1,774 497 Production taxes payable 1,860 214 Drilling advances received from joint venture partner - 245 Accrued lease operating costs 3,155 684 Accrued ad valorem taxes-current 3,474 1,054 Accrued general and administrative expenses 3,111 2,473 Accrued asset retirement obligation-current 3,099 380 Accrued interest 955 247 Accrued gas purchases 5,441 - Other liabilities 1,603 374 Total accounts payable and accrued liabilities $ 34,816 $ 11,218 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Measurements [Abstract] | |
Schedule of financial assets and liabilities at fair value | (in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total December 31, 2018 Asset: Commodity derivatives $ - $ 7,022 $ - $ 7,022 December 31, 2017 Asset: Commodity derivatives $ - $ 225 $ - $ 225 Liability: Warrant derivative liability $ - $ - $ 2,017 $ 2,017 |
Schedule of changes in fair value of financial instruments | (in thousands) California Warrant Appalachia Warrant Total Balance, December 31, 2016 $ - $ - $ - Warrant liability 5,769 1,325 7,094 Unrealized (gain) loss included in warrant gain (3,752 ) 619 (3,133 ) Settlement of warrant liability - (1,944 ) (1,944 ) Balance, December 31, 2017 $ 2,017 $ - $ 2,017 Unrealized (gain) included in warrant gain (225 ) - (225 ) Settlement of warrant liability (1,792 ) - (1,792 ) Balance, December 31, 2018 $ - $ - $ - |
Commodity Derivatives (Tables)
Commodity Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivatives, Fair Value [Line Items] | |
Schedule of swap derivative agreements | Natural Gas Swaps Natural Gas Collars (1) Oil Swaps (1) Weighted Weighted Weighted Weighted Average Average Price WTI Average Brent Average Year MMBtu Price (a) MMBtu Range (a) Bbl Price (b) Bbl Price (c) 2019 15,055,000 $ 2.85 836,000 $ 2.60 – $3.19 218,597 $ 53.50 148,086 $ 66.82 2020 12,433,000 $ 2.73 1,018,000 $ 2.50 – $2.70 121,147 $ 55.37 151,982 $ 66.03 2021 2,598,000 $ 2.69 - $ - - $ - 86,341 $ 67.12 (1) Includes 100% of Carbon California’s outstanding derivative hedges at December 31, 2018, and not our proportionate share. (a) NYMEX Henry Hub Natural Gas futures contract for the respective period. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period. (c) Brent future contracts for the respective period. |
Schedule of fair value of the derivatives recorded | (in thousands) As of December 31, 2018 2017 Commodity derivative contracts: Commodity derivative asset $ 3,517 $ 215 Commodity derivative asset – non-current $ 3,505 $ 10 |
Schedule of realized and unrealized gains and losses | (in thousands) For the year ended 2018 2017 Commodity derivative contracts: Settlement (loss) gains $ (3,848 ) $ 770 Unrealized gains 8,742 2,158 Total settlement and unrealized gains, net $ 4,894 $ 2,928 |
Schedule of fair value amounts of all derivative instruments assets and liabilities | The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheet as of December 31, 2018. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative $ 4,605 $ (1,088 ) $ 3,517 Other non-current assets 4,690 (1,185 ) 3,505 Total derivative assets $ 9,295 $ (2,273 ) $ 7,022 Commodity derivative liabilities: Commodity derivative $ (1,088 ) $ 1,088 $ - Commodity derivative: non-current (1,185 ) 1,185 - Total derivative liabilities $ (2,273 ) $ 2,273 $ - The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheet as of December 31, 2017. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Commodity derivative $ 624 $ (409 ) $ 215 Other non-current assets 250 (240 ) 10 Total derivative assets $ 874 $ (649 ) $ 225 Commodity derivative liabilities: Commodity derivative $ (409 ) $ 409 $ - Commodity derivative: non-current (240 ) 240 - Total derivative liabilities $ (649 ) $ 649 $ - |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies [Abstract] | |
Schedule of firm transportation volumes and related demand charges | Period Dekatherms per day Demand Charges January 2019 – March 2020 3,230 $ 0.20 – 0.62 April 2020 – May 2020 2,150 $ 0.20 June 2020 – May 2036 1,000 $ 0.20 Jan 2019 – Oct 2020 6,300 $ 0.21 Jan 2019 – Aug 2022 49,341 $ 0.21 – 0.56 Sep 2022 – May 2027 29,990 $ 0.21 |
Supplemental Cash Flow Disclo_2
Supplemental Cash Flow Disclosure (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Disclosure [Abstract] | |
Schedule of supplemental cash flow disclosures | (in thousands) For the Years Ended 2018 2017 Cash paid during the period for: Interest payments $ 4,217 $ 967 Non-cash transactions: Units issued for 2018 Subordinated Notes $ 489 - Accounts receivable (17,076 ) - Prepaid expense (2,178 ) - Commodity derivative asset – current (198 ) - Inventory (900 ) - Proved oil and gas properties (139,613 ) - Unproved oil and gas properties (3,364 ) - Other fixed assets (16,502 ) - Equity method investments 14,655 5,674 Other non-current assets (989 ) - Accounts payable and accrued liabilities 26,292 67 Commodity derivative liability – non-current 2,645 - Firm transportation contract obligations 18,724 - Warrant liability (1,792 ) - Notes payable 83,006 - Asset retirement obligations 7,879 2,402 |
Supplemental Financial Data -_2
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Schedule of proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | 2018 2017 Oil Natural Gas NGL Total Oil Natural Gas NGL Total MBbls MMcf MBbls MMcfe MBbls MMcf MBbls MMcfe Proved reserves, beginning of year 919 81,702 - 87,216 882 74,265 - 79,557 Revisions of previous estimates (2,803 ) 1,832 (1,147 ) (21,868 ) 107 12,199 - 12,841 Extensions and discoveries - - - - 16 136 - 232 Production (451 ) (4,798 ) (33 ) (7,702 ) (86 ) (4,898 ) - (5,414 ) Purchases of reserves in-place 21,233 376,664 3,103 522,680 - - - - Sales of reserves in-place - - - - - - - - Proved reserves, end of year 18,898 455,400 1,923 580,326 919 81,702 - 87,216 Proved developed reserves at: End of year 14,336 450,424 1,472 545,272 903 81,702 - 87,216 Proved undeveloped reserves at: End of year 4,562 4,976 451 35,054 16 - - 96 |
Schedule of aggregate capitalized costs relating to oil and gas producing activities | (in thousands) 2018 2017 Oil and gas properties: Proved oil and gas properties $ 347,059 $ 114,893 Unproved properties not subject to depletion 5,416 1,947 Accumulated depreciation, depletion, amortization and impairment (98,604 ) (80,715 ) Total $ 253,871 $ 36,125 |
Schedule of costs incurred in oil and gas property acquisition, exploration, and development activities | (in thousands) 2018 2017 Property acquisition costs: Unevaluated properties $ 3,464 $ 1 Proved properties and gathering facilities 63,517 289 Development costs 2,074 952 Gathering facilities 460 43 Asset retirement obligation 14,085 2,309 Total $ 83,600 $ 3,594 |
Schedule of company's investment in unproved properties | 2018 2017 2016 (in thousands) Acquisition costs $ 3,464 $ 1 $ 1,946 |
Schedule of results of operations from oil and gas producing activities | (in thousands) 2018 2017 Revenues: Oil and gas sales, including commodity derivative gains and losses $ 52,946 $ 22,439 Expenses: Production expenses 22,226 9,589 Depletion expense 7,305 2,157 Accretion of asset retirement obligations 868 307 Total expenses 30,399 12,053 Results of operations from oil and gas producing activities $ 22,547 $ 10,386 Depletion rate per Mcfe $ 0.89 $ 0.40 |
Schedule of estimate of the current market value of the Company's proved reserves | (in thousands) December 31, 2018 2017 Future cash inflows $ 2,878,392 $ 283,664 Future production costs (1,538,870 ) (119,501 ) Future development costs (76,852 ) (210 ) Future income taxes (258,277 ) (35,482 ) Future net cash flows 1,004,393 128,471 10% annual discount (612,325 ) (71,389 ) Standardized measure of discounted future net cash flows $ 392,068 $ 57,082 |
Schedule of discounted future cash flows relating to proved oil and gas reserves | December 31, 2018 2017 (in thousands) Standardized measure of discounted future net cash flows, beginning of period $ 57,082 $ 44,711 Sales of oil and gas, net of production costs and taxes (25,681 ) (10,038 ) Price revisions 133,789 17,588 Extensions, discoveries and improved recovery, less related costs - 298 Changes in estimated future development costs (32,711 ) (324 ) Development costs incurred during the period 926 804 Quantity revisions (23,484 ) 11,196 Accretion of discount 5,708 4,471 Net changes in future income taxes (89,117 ) (7,425 ) Purchases of reserves-in-place 391,877 - Sales of reserves-in-place - - Changes in production rate timing and other (26,321 ) (4,199 ) Standardized measure of discounted future net cash flows, end of period $ 392,068 $ 57,082 |
Schedule of weighted averaged adjusted prices | 2018 2017 Oil (per Bbl) $ 65.56 $ 51.34 Natural Gas (per Mcf) $ 3.10 $ 2.98 |
Organization (Details)
Organization (Details) - USD ($) $ in Millions | May 01, 2018 | Dec. 31, 2018 | Feb. 01, 2018 |
Organization (Textual) | |||
Voting percentage | 100.00% | ||
Carbon California [Member] | |||
Organization (Textual) | |||
Divestitures, description | The voting and profits interests and Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America or its affiliates ("Prudential") owns 46.08% of the voting and profits interest in Carbon California. | ||
Voting percentage | 53.92% | ||
Delaware Limited Liability Company [Member] | |||
Organization (Textual) | |||
Business acquisation purchase price | $ 58.1 | ||
Maximum [Member] | Carbon California [Member] | |||
Organization (Textual) | |||
Voting percentage | 56.41% | ||
Minimum [Member] | Carbon California [Member] | |||
Organization (Textual) | |||
Voting percentage | 17.81% |
Reverse Stock Split (Details)
Reverse Stock Split (Details) - shares | Mar. 15, 2017 | Dec. 31, 2018 | Jun. 01, 2018 | Dec. 31, 2017 |
Reverse Stock Split (Textual) | ||||
Reverse stock split, description | Reverse stock split approved by the shareholders and Board of Directors, each 20 shares of our issued and outstanding common stock became one share of common stock and no fractional shares were issued. | |||
Common stock, shares authorized | 35,000,000 | 35,000,000 | ||
Maximum [Member] | ||||
Reverse Stock Split (Textual) | ||||
Common stock, shares authorized | 200,000,000 | 35,000,000 | ||
Minimum [Member] | ||||
Reverse Stock Split (Textual) | ||||
Common stock, shares authorized | 10,000,000 | 10,000,000 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Purchaser A [Member] | ||
Concentration Risk [Line Items] | ||
Percentages by purchaser | 17.00% | |
Purchaser E [Member] | ||
Concentration Risk [Line Items] | ||
Percentages by purchaser | 16.00% | |
Purchaser B [Member] | ||
Concentration Risk [Line Items] | ||
Percentages by purchaser | 12.00% | 17.00% |
Purchaser C [Member] | ||
Concentration Risk [Line Items] | ||
Percentages by purchaser | 9.00% | 12.00% |
Purchaser D [Member] | ||
Concentration Risk [Line Items] | ||
Percentages by purchaser | 8.00% | 11.00% |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | ||
Balance at beginning of year | $ 7,357 | $ 5,120 |
Accretion expense | 868 | 307 |
Change in estimate of cash outflow | 361 | 2,402 |
Additions from Carbon California (Note 4) | 2,921 | |
Additions from Seneca Acquisition (Note 4) | 5,132 | |
Additions from Liberty Acquisition (Note 4) | 45 | |
Additions from OIE Membership Acquisition | 5,626 | |
Less: sale of wells | (92) | |
Reconciliation of ARO, Gross | 22,310 | 7,737 |
Less: ARO recognized as accounts payable and accrued liabilities | (3,099) | (380) |
Balance at end of year | $ 19,211 | $ 7,357 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | ||
Net income attributable to common shareholders | $ 7,055 | $ 6,318 |
Less: warrant derivative gain | (225) | (3,133) |
Diluted net income | $ 6,830 | $ 3,185 |
Basic weighted-average common shares outstanding during the period | 7,525 | 5,662 |
Add dilutive effects of warrants and non-vested shares of restricted stock | 314 | 790 |
Diluted weighted-average common shares outstanding during the period | 7,839 | 6,452 |
Basic net income per common share | $ 0.94 | $ 1.12 |
Diluted net income per common share | $ 0.87 | $ 0.49 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies (Details Textual) | Nov. 01, 2017USD ($) | Jan. 31, 2019USD ($) | Dec. 31, 2018USD ($)Partnershipshares | Dec. 31, 2017USD ($)shares |
Summary of Significant Accounting Policies (Textual) | ||||
Purchaser imbalance receivable | $ 551,000 | $ 193,000 | ||
Purchaser imbalance liability | 0 | 25,000 | ||
Additions of ARO | 14,100,000 | |||
Estimated cost of retirement obligations | 2,400,000 | |||
Fair value of warrants accounted for gains | $ 225,000 | $ 3,100,000 | ||
Number of consolidated partnerships | Partnership | 46 | |||
Cost method investments, additional information | The cost method of accounting is generally used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. | |||
Equity method investment, additional information | If we hold between 20% and 50% of the voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability company and exert significant influence or control (e.g., through our influence with a seat on the board of directors or management of operations), the equity method of accounting is generally used to account for the investment. Investment in affiliates will increase or decrease by our share of the affiliates' profits or losses and such profits or losses are recognized in our consolidated statements of operations. If we hold greater than 50% of voting shares, we will generally consolidate the entities under the voting interest model. Prior to their consolidation on February 1, 2018 and December 31, 2018 for our investments in Carbon California and Carbon Appalachia, respectively, we used the hypothetical liquidation at book value ("HLBV") method to recognize our share of profits or losses. | |||
Insurance receivable | $ 522,000 | |||
Insurance collected from previously submitted claims | $ 3,100,000 | |||
Income taxes, description | The Tax Cut and Jobs Act ("TCJA"), we were required to remeasure deferred income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate became effective January 1, 2018. | |||
Retirement obligations accrued discount factor percentage | 10.00% | |||
Inventory adjustments | $ 600,000 | |||
Description of oil and natural gas sales | None of the above purchasers comprised more than 10% of total accounts receivable. One purchaser's receivable acquired with the closing of the OIE Membership Acquisition accounts for approximately 10% of accounts receivable as of December 31, 2018. | |||
Description of other property, plant and equipment | Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5 years, and pipeline facilities and equipment are depreciated over twenty years. | |||
Financing costs | $ 2,000,000 | |||
Purchaser A [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentages by purchaser | 17.00% | |||
Oil and Natural Gas Sales [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentages by purchaser | 10.00% | 10.00% | ||
Subsequent Event [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Payment of insurance | $ 800,000 | |||
Warrant [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Anti-dilutive earnings per shares | shares | 519,000 | |||
Restricted Stock [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Anti-dilutive earnings per shares | shares | 259,000 | 271,000 | ||
Restricted Performance Units [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Common stock equivalent restricted to future contingencies | shares | 280,000 | |||
Anti-dilutive earnings per shares | shares | 314,000 | |||
Nytis LLC [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentage of ownership interest in the subsidiary | 98.10% | |||
Nytis USA [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentage of ownership interest in the subsidiary | 100.00% | |||
Carbon Appalachia [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Percentage of ownership interest in the subsidiary | 100.00% | |||
Carbon Appalachia [Member] | Warrant [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Fair value of warrants accounted for gains | $ 1,300,000 | $ 619,000,000 | ||
Minimum [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Estimated cost of retirement obligations | 20,000 | |||
Maximum [Member] | ||||
Summary of Significant Accounting Policies (Textual) | ||||
Estimated cost of retirement obligations | $ 45,000 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures (Details) - USD ($) $ in Thousands | Feb. 15, 2017 | Dec. 31, 2018 |
Old Ironsides [Member] | ||
Acquisitions and Divestitures [Line Items] | ||
Fair value of previously held interest | $ 14,158 | |
Cash consideration | 33,000 | |
Old Ironsides Notes | 25,065 | |
Fair value of business acquired | $ 72,223 | |
California Warrant [Member] | ||
Acquisitions and Divestitures [Line Items] | ||
Fair value of Carbon common shares transferred as consideration | $ 8,327 | |
Fair value of NCI | 16,466 | |
Fair value of previously held interest | 7,243 | |
Fair value of contribution associated with acquisition of Yorktown’s interest in CCC | 8,637 | |
Fair value of business acquired | $ 40,673 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures (Details 1) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Feb. 15, 2017 |
Oil and gas properties: | |||
Commodity derivative liability - current | |||
Commodity derivative liability - non-current | |||
Asset retirement obligations - current | 955 | $ 247 | |
Old Ironsides [Member] | |||
Acquisitions and Divestitures [Line Items] | |||
Cash | 12,283 | ||
Accounts receivable: | |||
Revenue | 12,834 | ||
Trade receivable | 1,941 | ||
Commodity derivative asset | 198 | ||
Inventory | 900 | ||
Prepaid expense, deposits, and other current assets | 456 | ||
Oil and gas properties: | |||
Proved | 107,499 | ||
Unproved | 1,869 | ||
Other property, plant, and equipment, net | 15,626 | ||
Other non-current assets | 514 | ||
Accounts payable and accrued liabilities | (19,114) | ||
Due to related parties | (458) | ||
Firm transportation contract obligations | (18,724) | ||
Asset retirement obligations - current | (5,626) | ||
Notes payable | (37,975) | ||
Total net assets acquired | $ 72,223 | ||
Carbon California [Member] | |||
Acquisitions and Divestitures [Line Items] | |||
Cash | $ 275 | ||
Accounts receivable: | |||
Joint interest billings and other | 690 | ||
Receivable - related party | 1,610 | ||
Prepaid expense, deposits, and other current assets | 1,723 | ||
Oil and gas properties: | |||
Proved | 65,114 | ||
Unproved | 1,495 | ||
Other property, plant, and equipment, net | 877 | ||
Other non-current assets | 475 | ||
Accounts payable and accrued liabilities | (6,054) | ||
Commodity derivative liability - current | (916) | ||
Commodity derivative liability - non-current | (1,729) | ||
Asset retirement obligations - current | (384) | ||
Asset retirement obligations - non-current | (2,537) | ||
Subordinated Notes, related party, net | (8,874) | ||
Senior Revolving Notes, related party | (11,000) | ||
Notes payable | (92) | ||
Total net assets acquired | $ 40,673 |
Acquisitions and Divestitures_4
Acquisitions and Divestitures (Details 2) $ in Thousands | Dec. 31, 2018USD ($) |
Identifiable assets acquired: | |
Proved oil and gas properties | $ 38,021 |
Unproved oil and gas properties | 100 |
Other property, plant and equipment | 588 |
Other assets | 167 |
Total identified assets | $ 38,876 |
Acquisitions and Divestitures_5
Acquisitions and Divestitures (Details 3) - USD ($) $ / shares in Units, $ in Thousands | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | |
Acquisitions and Divestitures [Line Items] | |||
Revenue | $ 33,256 | $ 35,122 | |
Net (loss) income before non-controlling interests | 5,232 | 13,969 | |
Net (loss) income attributable to non-controlling interests | (2,334) | 92 | |
Net (loss) income attributable to controlling interests | $ 7,566 | $ 13,877 | |
Net income per share (basic) | $ 1 | $ 2.49 | |
Net income per share (diluted) | $ 0.96 | $ 2.14 | |
Old Ironsides [Member] | |||
Acquisitions and Divestitures [Line Items] | |||
Revenue | $ 54,058 | $ 136,592 | |
Net (loss) income before non-controlling interests | 7,208 | 11,320 | |
Net (loss) income attributable to non-controlling interests | 81 | 4,375 | |
Net (loss) income attributable to controlling interests | $ 7,127 | $ 5,596 | |
Net income per share (basic) | $ 1.26 | $ 0.74 | |
Net income per share (diluted) | $ 0.62 | $ 0.69 |
Acquisitions and Divestitures_6
Acquisitions and Divestitures (Details Textual) | Feb. 01, 2019USD ($) | Jul. 11, 2018 | Feb. 01, 2018 | Nov. 01, 2017shares | Apr. 03, 2017USD ($)shares | Oct. 31, 2017USD ($)Acres | Sep. 29, 2017USD ($) | Dec. 31, 2018USD ($) | May 01, 2018 | Jan. 31, 2018 | Aug. 15, 2017USD ($) | Feb. 15, 2017USD ($) |
Acquisitions and Divestitures (Textual) | ||||||||||||
Purchase price of acquired assets | $ 38,876,000 | |||||||||||
Transaction and due diligence costs | 18,900,000 | |||||||||||
Aggregate cash consideration | 8,600,000 | |||||||||||
Borrowing Revolver Increased | $ 8,000,000 | |||||||||||
Principal amount | $ 2,000,000 | |||||||||||
Percentage of identifiable assets acquired and liabilities | 100.00% | |||||||||||
Class A Units [Member] | Yorktown [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Warrant to purchase common stock | shares | 2,940 | |||||||||||
Class B Units [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Profits interest | 14.70% | |||||||||||
Aggregate share ownership | 14.70% | |||||||||||
Carbon California [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Recognized gain based on fair value | $ 5,400,000 | |||||||||||
Qualifies as a business combination, description | We recognized 100% of the identifiable assets acquired, liabilities assumed and the non-controlling interest at their respective fair value as of the date of the acquisition. We exchanged 1,527,778 common shares at a fair value of approximately $8.3 million ($5.45 per share), for 11,000 Class A Units of Carbon California, representing a 38.59% profits ownership interest in Carbon California. | |||||||||||
Percentage of profits interest | 56.40% | 53.92% | 17.81% | |||||||||
Acquisitions issuance shares, description | On February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon California. | |||||||||||
Bearing interest of per annum | 12.00% | |||||||||||
Percentage of identifiable assets acquired and liabilities | 53.92% | |||||||||||
Carbon Appalachia [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Profits interest | 100.00% | |||||||||||
Recognized gain based on fair value | $ 1,300,000 | |||||||||||
Purchase price | 58,100,000 | |||||||||||
Description of seneca acquisition | (i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to us, and (iii) issued Class C Units to us. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company, LLC ("Carbon Appalachia Enterprises"), a subsidiary of the Company, entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the "Revolver") with an initial borrowing base of $10.0 million. | |||||||||||
Equity commitment | $ 2,000,000 | $ 37,000,000 | ||||||||||
Aggregate cash consideration | 14,000,000 | |||||||||||
Borrowing Revolver Increased | $ 22,000,000 | |||||||||||
Aggregate share ownership | 100.00% | |||||||||||
Carbon Appalachia [Member] | Yorktown [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Warrant to purchase common stock | shares | 408,000 | |||||||||||
Carbon Appalachia [Member] | Class A Units [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Acquisitions issuance shares, description | (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate share ownership of Carbon Appalachia. | |||||||||||
Equity commitment | $ 240,000 | |||||||||||
Aggregate cash consideration | $ 11,000,000 | |||||||||||
Acquired of Class A Units | $ 58,100,000 | |||||||||||
Acquired cash paid | 33,000,000 | |||||||||||
Carbon Appalachia [Member] | Class B Units [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Warrant to purchase common stock | shares | 1,000 | |||||||||||
Prudential [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Profits interest | 46.08% | |||||||||||
Aggregate share ownership | 46.08% | |||||||||||
Purchase Agreement [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Purchase price of acquired assets | $ 1,500,000 | |||||||||||
Seneca Acquisition [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Transaction and due diligence costs | $ 318,000 | |||||||||||
Non-operated oil wells covering, gross acres | Acres | 6,800 | |||||||||||
Non-operated oil wells covering, net | Acres | 6,600 | |||||||||||
Purchase price | $ 43,000,000 | |||||||||||
Description of seneca acquisition | We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price. We raised our $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. Prudential also contributed $5.0 million to fund its share of the equity portion of the purchase price. Carbon California funded the remaining purchase price from cash, increased borrowings under the Senior Revolving Notes and $3.0 million in proceeds from the issuance of Senior Subordinated Notes. | |||||||||||
Assumed liabilities | $ 330,000 | |||||||||||
Old Ironsides [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Acquired of Class A Units | 14,158,000 | |||||||||||
Principal amount | $ 25,100,000 | |||||||||||
Bearing interest of per annum | 10.00% | |||||||||||
Old Ironsides [Member] | Subsequent Event [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Principal amount | $ 2,000,000 | |||||||||||
ARO [Member] | Seneca Acquisition [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Assumed liabilities | $ 5,100,000 | |||||||||||
Liberty Energy, LLC [Member] | ||||||||||||
Acquisitions and Divestitures (Textual) | ||||||||||||
Description of liberty acquisition | We completed an acquisition of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and the associated mineral interests in the Appalachian Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the "Liberty Acquisition"). The Liberty Acquisition increased our ownership in the acquired wells from 60% to 100%. The Liberty Acquisition was funded through borrowings under our Credit Facility. The Liberty Acquisition is accounted for as a non-significant asset acquisition. |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and gas properties: | ||
Accumulated depreciation, depletion, amortization and impairment | $ (98,604) | $ (80,715) |
Net oil and gas properties | 253,871 | 36,125 |
Pipeline Facilities Equipment | 12,714 | |
Base Gas Amount | 2,122 | |
Furniture and fixtures, computer hardware and software, and other equipment | 6,649 | 1,758 |
Accumulated depreciation and amortization | (3,922) | (1,021) |
Net other property and equipment | 17,563 | 737 |
Total property and equipment, net | 271,434 | 36,862 |
Proved oil and gas properties [Member] | ||
Oil and gas properties: | ||
Oil and gas properties, gross | 337,660 | 114,893 |
Unproved properties not subject to depletion [Member] | ||
Oil and gas properties: | ||
Oil and gas properties, gross | $ 5,416 | $ 1,947 |
Property and Equipment (Detai_2
Property and Equipment (Details 1) - Unproved properties not subject to depletion [Member] - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | $ 5,416 | $ 1,947 |
California [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | 1,595 | |
Indiana [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | 432 | 432 |
Illinois [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | 136 | 136 |
Kentucky [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | 915 | 915 |
Ohio [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | 66 | 66 |
West Virginia [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | 398 | 398 |
Tennessee [Member] | ||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||
Oil and gas properties, gross | $ 1,869 |
Property and Equipment (Detai_3
Property and Equipment (Details Textual) | 12 Months Ended | |
Dec. 31, 2018USD ($)USD_Bbl | Dec. 31, 2017USD ($)USD_Bbl | |
Property and Equipment (Textual) | ||
Proved property | $ 52,000 | |
Capitalized overhead | $ 337,000 | 66,000 |
Depletion expense related to oil and gas properties | $ 7,300,000 | $ 2,200,000 |
Depletion expense related to oil and gas properties (in dollars per Mcfe) | USD_Bbl | 0.89 | 0.40 |
Depreciation and amortization expense | $ 8,108,000 | $ 2,544,000 |
Unproved properties not subject to depletion [Member] | ||
Property and Equipment (Textual) | ||
Depletion expense related to oil and gas properties | 5,400,000 | 1,900,000 |
Furniture and fixtures [Member] | ||
Property and Equipment (Textual) | ||
Depreciation and amortization expense | $ 803,000 | $ 387,000 |
Investments in Affiliates (Deta
Investments in Affiliates (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning balance, Investments | $ 14,267 | $ 668 |
Investment in affiliates gain | 7,734 | 1,128 |
Cash distributions | (125) | (68) |
Cash contributions | 6,865 | |
Class B Units issuance | 2,778 | |
Appalachia Warrant exercise | 2,896 | |
California Warrant exercise | (1,854) | |
OIE Membership Acquisition | (12,801) | |
Ending balance, Investments | 598 | 14,267 |
Carbon California [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning balance, Investments | 1,854 | |
Investment in affiliates gain | ||
Cash distributions | ||
Cash contributions | ||
Class B Units issuance | 1,854 | |
Appalachia Warrant exercise | ||
California Warrant exercise | (1,854) | |
Ending balance, Investments | 1,854 | |
Carbon Appalachia [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning balance, Investments | 11,775 | |
Investment in affiliates gain | 1,026 | 1,090 |
Cash distributions | ||
Cash contributions | 6,865 | |
Class B Units issuance | 924 | |
Appalachia Warrant exercise | 2,896 | |
California Warrant exercise | ||
OIE Membership Acquisition | (12,801) | |
Ending balance, Investments | 11,775 | |
Other [Member] | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning balance, Investments | 638 | 668 |
Investment in affiliates gain | 85 | 38 |
Cash distributions | (125) | (68) |
Cash contributions | ||
Class B Units issuance | ||
Ending balance, Investments | $ 598 | $ 638 |
Investments in Affiliates (De_2
Investments in Affiliates (Details 1) $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($) | |
April 2017 [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Capital Contribution | $ 240 |
Resulting Class A Units (%) | 2.00% |
Resulting Sharing % | 2.98% |
August 2017 [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Capital Contribution | $ 3,710 |
Resulting Class A Units (%) | 15.20% |
Resulting Sharing % | 16.04% |
September 2017 [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Capital Contribution | $ 2,920 |
Resulting Class A Units (%) | 18.55% |
Resulting Sharing % | 19.37% |
November 2017 [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Capital Contribution | Warrant exercise |
Resulting Class A Units (%) | 26.50% |
Resulting Sharing % | 27.24% |
December 2018 [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Capital Contribution | OIE Membership Acquisition |
Resulting Class A Units (%) | 100.00% |
Resulting Sharing % | 100.00% |
Investments in Affiliates (De_3
Investments in Affiliates (Details 2) - USD ($) $ in Thousands | 9 Months Ended | 11 Months Ended | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | |
Schedule of Equity Method Investments [Line Items] | ||||
Current assets | $ 8,080 | $ 8,080 | $ 34,010 | $ 8,080 |
Total oil and gas properties, net | 36,862 | 36,862 | 271,434 | 36,862 |
Non-current assets | 51,929 | 51,929 | 276,881 | 51,929 |
Current liabilities | 11,345 | 11,345 | 40,945 | 11,345 |
Non-current liabilities | 32,168 | 32,168 | 193,911 | 32,168 |
Total members' equity | 14,655 | 14,655 | 47,751 | 14,655 |
Revenues | 53,051 | 22,473 | ||
Operating expenses | 10,618 | 3,208 | ||
Net income | 7,055 | 6,318 | ||
Carbon California [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Current assets | 3,968 | 3,968 | 11,829 | 3,968 |
Total oil and gas properties, net | 43,458 | 43,458 | 84,825 | 43,458 |
Non-current assets | 44,759 | 44,759 | 89,173 | 44,759 |
Current liabilities | 6,899 | 6,899 | 6,773 | 6,899 |
Non-current liabilities | 23,279 | 23,279 | 56,664 | 23,279 |
Total members' equity | 18,549 | 18,549 | 37,565 | 18,549 |
Revenues | 7,235 | 32,317 | ||
Operating expenses | 9,893 | 20,057 | ||
Income from operations | (2,658) | 12,260 | ||
Net income | (6,552) | 8,526 | ||
Carbon Appalachia [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Current assets | 20,794 | 20,794 | 28,613 | 20,794 |
Total oil and gas properties, net | 84,402 | 84,402 | 80,674 | 84,402 |
Non-current assets | 97,762 | 97,762 | 96,814 | 97,762 |
Current liabilities | 18,207 | 18,207 | 22,126 | 18,207 |
Non-current liabilities | 59,420 | 59,420 | 58,480 | 59,420 |
Total members' equity | 40,929 | $ 40,929 | 44,821 | $ 40,929 |
Revenues | 31,584 | 83,541 | ||
Operating expenses | 26,764 | 77,084 | ||
Income from operations | 4,820 | 6,457 | ||
Net income | $ 3,005 | $ 4,053 |
Investments in Affiliates (De_4
Investments in Affiliates (Details Textual) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Jan. 31, 2018 | |
Carbon California [Member] | ||
Investments in Affiliates (Textual) | ||
Percentage of interests | 17.81% | |
Carbon Appalachia [Member] | ||
Investments in Affiliates (Textual) | ||
Ownership interest, percentage | 100.00% | |
Class A Units [Member] | Carbon Appalachia [Member] | ||
Investments in Affiliates (Textual) | ||
Percentage of interests | 10.00% | |
Investment in cash and unevaluated property | $ 6.9 | |
Revolving credit facility, description | We acquired all of Old Ironsides Class A Units of Carbon Appalachia for approximately $58.1 million, subject to certain closing adjustments. We paid $ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides. | |
Earned net gain | $ 1 | |
Class B Units [Member] | ||
Investments in Affiliates (Textual) | ||
Ownership interest, percentage | 14.70% | |
Class B Units [Member] | Carbon Appalachia [Member] | ||
Investments in Affiliates (Textual) | ||
Earned net gain | $ 1 | |
Class C Units [Member] | ||
Investments in Affiliates (Textual) | ||
Ownership interest, percentage | 14.70% | |
Class C Units [Member] | Carbon Appalachia [Member] | ||
Investments in Affiliates (Textual) | ||
Percentage of interests | 10.00% | |
Investment in cash and unevaluated property | $ 6.9 | |
Earned net gain | $ 1 |
Credit Facilities and Notes P_3
Credit Facilities and Notes Payable (Details) - Credit Facilities [Member] $ in Thousands | Dec. 31, 2018USD ($) |
Line Of Credit Facility [Line Items] | |
2018 Credit Facility - revolver | $ 69,150 |
2018 Credit Facility - term note | 15,000 |
Old Ironsides Notes | 25,065 |
Non-current debt | 57 |
Total gross notes payable | 109,272 |
Less: Notes discount | (134) |
Total net notes payable | $ 109,138 |
Credit Facilities and Notes P_4
Credit Facilities and Notes Payable (Details 1) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Line Of Credit Facility [Line Items] | ||
Subordinated Notes, related party, due February 15, 2024 | $ 49,919 | |
Related Party [Member] | ||
Line Of Credit Facility [Line Items] | ||
Senior Revolving Notes, related party, due February 15, 2022 | 38,500 | |
Subordinated Notes, related party, due February 15, 2024 | 13,000 | |
Total gross notes payable | 51,500 | |
Less: Deferred notes costs | 156 | |
Less: Notes discount | (1,737) | |
Total net notes payable | $ 49,919 |
Credit Facilities and Notes P_5
Credit Facilities and Notes Payable (Details Textual) | May 01, 2018 | May 01, 2018USD ($) | Feb. 15, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Feb. 01, 2018 |
Credit Facilities and Notes Payable (Textual) | ||||||
Unamortized deferred issuance costs | $ 484,000 | |||||
Senior secured asset-based revolving credit facility | 118,628,000 | $ 7,210,000 | ||||
Initial borrowing | 10,000,000 | |||||
Amortized interest expense | $ 786,000 | $ 176,000 | ||||
Business acquisitions, description | The OIE Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1 million to Old Ironsides (the "Old Ironsides Notes"). The Old Ironsides Notes bear interest at 10% per annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments upon the occurrence of certain subsequent liquidity events and a one-time principal reduction payment in the aggregate amount of $2.0 million on or before February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased to be a related party. | |||||
Voting percentage | 100.00% | |||||
Incurred fees | $ 962,000 | |||||
Credit facility fee, description | The 2018 Credit Facility included origination fees of $450,000 and arrangement fees of $80,000. As of December 31, 2018, there was approximately $70.0 million in outstanding borrowings and letters of credit and $5.0 million of additional borrowing capacity under the 2018 Credit Facility. | |||||
Carbon California [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Effective borrowing rate (as a percent) | 56.41% | |||||
Business acquisitions, description | (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0 million. | |||||
Unsecured notes due date | Feb. 15, 2024 | |||||
Outstanding discount amount of notes | $ 1,737,000 | |||||
Voting percentage | 53.92% | 53.92% | ||||
Revolving Notes in the principal amount | $ 10,000,000 | |||||
Description of voting rights | The exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests, and Prudential owns 46.08%. | |||||
Carbon California- Senior Revolving Notes, Related Party [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Borrowing base amount | 41,000,000 | |||||
Line of credit facility maximum borrowing capacity | 38,500,000 | |||||
Variable interest rate basis, description | (i) 5.0% plus the London interbank offered rate ("LIBOR") or (ii) 4.00% plus Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of September 30, 2018, the effective borrowing rate for the Senior Revolving Notes was 8.14%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year. | |||||
Other non-current assets value | 900,000 | |||||
Amortized interest expense | $ 217,000 | |||||
Business acquisitions, description | Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America for the issuance and sale of the Senior Revolving Notes due February 15, 2022. We are not a guarantor of the Senior Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California's proved oil and gas reserves which is to be determined at least semi-annually. As of December 31, 2018, the borrowing base was $41.0 million, of which $38.5 million was outstanding. | |||||
Description of the revolver requirements | The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated proved developed production at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to equity members are generally restricted. | |||||
Revolving Notes in the principal amount | $ 10,000,000 | |||||
Carbon California Notes [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Effective borrowing rate (as a percent) | 12.00% | |||||
Description of the revolver requirements | The Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively. | |||||
Amount of unsecured notes issuance | $ 3,000,000 | $ 10,000,000 | ||||
Unsecured notes due date | Feb. 15, 2024 | Feb. 15, 2024 | ||||
Description of notes prepayment terms | Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. | |||||
Outstanding discount amount of notes | $ 1,700,000 | |||||
Notes issuance additional, description | Prudential received an additional 1,425 Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3 million, which was recorded as a discount to the Subordinated Notes. | |||||
Carbon California-2018 Subordinated Notes [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Effective borrowing rate (as a percent) | 12.00% | 12.00% | ||||
Description of the revolver requirements | The Carbon California 2018 Subordinated Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively. | |||||
Amount of unsecured notes issuance | $ 3,000,000 | |||||
Description of notes prepayment terms | Prepayment of the Subordinated Notes is available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is not subject to a prepayment fee after February 17, 2020. Distributions to equity members are generally restricted. | |||||
Outstanding discount amount of notes | $ 390,000 | |||||
Notes issuance additional, description | Prudential for the issuance and sale of the Carbon California 2018 Subordinated Notes in the amount of $3.0 million, of which $3.0 million remains outstanding as of December 31, 2018. Prudential received 585 Class A Units, representing an approximate 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the outstanding Carbon California 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the Carbon California 2018 Subordinated Notes. As of December 31, 2018, Carbon California had an outstanding discount of $390,000 associated with these notes, which is presented net of the Carbon California 2018 Subordinated Notes within Credit facility related party on the consolidated balance sheets. During the year ended December 31, 2018, Carbon California amortized $57,000. | |||||
Minimum [Member] | Carbon California [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Voting percentage | 17.81% | |||||
Maximum [Member] | Carbon California [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Voting percentage | 56.41% | |||||
Line of Credit [Member] | Minimum [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Funded debt ratio required to be maintained | 1 | |||||
Current ratio required to be maintained | 1 | |||||
Line of Credit [Member] | Maximum [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Funded debt ratio required to be maintained | 3.5 | |||||
Current ratio required to be maintained | 1 | |||||
2018 Credit Facility [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Variable interest rate basis, description | (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the utilization percentage, at the Borrower' option. The Borrowers are obligated to pay certain fees and expenses in connection the 2018 Credit Facility, including a commitment fee for any unused amounts of .050% and an origination fee of 0.50%. | |||||
Covenant description | Payable in 18 equal monthly installments beginning February 1, 2019 with the last payment due on June 30, 2020. | |||||
Initial borrowing | $ 75,000,000 | |||||
Additional borrowing capacity available | $ 5,000,000 | |||||
Effective borrowing rate (as a percent) | 6.25% | |||||
Letters of credit | $ 70,000,000 | |||||
Outstanding borrowings | $ 15,000,000 | |||||
Business acquisitions, description | The Company and its subsidiaries amended and restated the Credit Facility and the CAE Credit Facility which provides for a $500.0 million senior secured asset-based revolving credit facility (the "2018 Credit Facility") which matures December 31, 2022 and a $15.0 million term loan which matures in 2020. The 2018 Credit Facility includes a sublimit of $1.5 million for letters of credit. | |||||
Cash and cash equivalents of borrowers not to exceed | $ 3,000,000 | |||||
Credit facility included origination fees | 450,000 | |||||
Arrangement fees | $ 80,000 | |||||
Effective borrowing rate | 0.00% | |||||
2018 Credit Facility [Member] | Minimum [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Funded debt ratio required to be maintained | 1 | |||||
Current ratio required to be maintained | 1 | |||||
2018 Credit Facility [Member] | Maximum [Member] | ||||||
Credit Facilities and Notes Payable (Textual) | ||||||
Funded debt ratio required to be maintained | 3.5 | |||||
Current ratio required to be maintained | 1 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Taxes [Abstract] | ||
Current income tax benefit | $ (74) | |
Deferred income tax (benefit) expense | (260) | 7,080 |
Change in valuation allowance | 260 | (7,080) |
Total income tax benefit | $ (74) |
Income Taxes (Details 1)
Income Taxes (Details 1) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate | ||
Federal income tax rate | 21.00% | 35.00% |
State income taxes, net of federal benefit | 5.10% | 3.80% |
Permanent differences | (1.20%) | (20.50%) |
Non-controlling interest in consolidated partnerships | (9.80%) | (0.80%) |
True-up of prior year depletion in excess of basis | 1.30% | 1.10% |
Stock-based compensation deficiency | 1.10% | 3.10% |
Rate changes of prior year deferred | (1.00%) | (1.80%) |
True-up of prior year deferred | 4.00% | (4.50%) |
Effect of tax cuts and TCJA | 91.00% | |
Increase in valuation allowance and other | 2.00% | (107.70%) |
Total effective income tax rate | 22.50% | (1.10%) |
Income Taxes (Details 2)
Income Taxes (Details 2) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax assets | ||
Net operating loss carryforwards | $ 8,066 | $ 6,407 |
Depletion carryforwards | 2,185 | 1,934 |
Accrual and other | 863 | 450 |
Stock-based compensation | 449 | 476 |
Asset retirement obligations | 4,640 | 1,944 |
Property, plant and equipment | 2,340 | 2,972 |
Total deferred tax assets | 18,543 | 14,183 |
Deferred tax liability | ||
Interest in partnerships | (517) | (790) |
Derivative and other | (1,056) | (57) |
Less valuation allowance | (16,970) | (13,336) |
Net deferred tax asset |
Income Taxes (Details Textual)
Income Taxes (Details Textual) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Income Taxes (Textual) | |
Net operating losses | $ 29.2 |
NOL carryforwards expire, description | The federal net operating losses generated before 2018 expire beginning in 2031 through 2037. While the current 2018 net operating loss will never expire, they are available to offset only 80% of future years' federal taxable income. The Company has various state NOL carryforwards available to reduce future years' state taxable income, which are dependent on apportionment percentages and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL will expire beginning in 2023 through 2037 depending upon each jurisdiction's specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. |
Federal deferred tax balance re-measurement, description | The Company remeasured certain federal deferred tax assets and liabilities based upon the rates at which they are expected to reverse in the future, which is generally twenty one percent. The provisional amount recognized related to the remeasurement of its federal deferred tax balance was $6.0 million, which was subject to a valuation allowance at December 31, 2017. |
Stockholders' Equity (Details)
Stockholders' Equity (Details) - Restricted Stock Awards [Member] - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Class of Stock [Line Items] | ||
Number of Shares, unvested, Beginning Balance | 269,997 | 267,750 |
Granted, Number of Shares | 106,000 | 81,050 |
Vested, Number of Shares | (59,550) | (65,753) |
Forfeited, Number of Shares | (2,240) | (13,050) |
Number of Shares, unvested, Ending Balance | 314,207 | 269,997 |
Unvested, Beginning Balance, Weighted Avg Grant Date Fair Value | $ 7.54 | $ 7.78 |
Granted, Weighted Avg Grant Date Fair Value | 9.820 | 7.20 |
Vested, Weighted Avg Grant Date Fair Value | 6.82 | 8.38 |
Forfeited, Weighted Avg Grant Date Fair Value | 7.41 | 6.19 |
Unvested, Ending Balance, Weighted Avg Grant Date Fair Value | $ 8.40 | $ 7.54 |
Stockholders' Equity (Details 1
Stockholders' Equity (Details 1) - Restricted Performance Units [Member] - shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Class of Stock [Line Items] | ||
Number of Shares, unvested, Beginning Balance | 258,811 | 296,311 |
Granted, Number of Shares | 136,159 | 60,050 |
Vested, Number of Shares | (108,484) | (80,000) |
Forfeited, Number of Shares | (6,610) | (17,550) |
Number of Shares, unvested, Ending Balance | 279,876 | 258,811 |
Stockholders' Equity (Details T
Stockholders' Equity (Details Textual) - USD ($) | Apr. 06, 2018 | Mar. 15, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 01, 2018 |
Stockholders' Equity (Textual) | ||||||||
Reverse stock split, description | Reverse stock split approved by the shareholders and Board of Directors, each 20 shares of our issued and outstanding common stock became one share of common stock and no fractional shares were issued. | |||||||
Compensation cost recognized | $ 273,000 | |||||||
Exercise price | $ 100 | |||||||
Grant date fair value | $ 9.80 | $ 7.20 | $ 5.40 | $ 8 | $ 11.80 | |||
Number of shares issued | 50,000 | |||||||
Proceeds from issuance of preferred stock | $ 5,000,000 | |||||||
Conversion of common stock, description | The number of shares of common stock issuable upon conversion is dependent upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing. Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. | |||||||
Beneficial conversion feature | $ 1,125,000 | |||||||
Accrued dividends | $ 224,000 | |||||||
Beneficial conversion feature, description | We recorded the BCF as a reduction of retained earnings and an increase to APIC of $1.1 million, which is based on the difference between the floor price of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued. | |||||||
Common stock, shares authorized | 35,000,000 | 35,000,000 | ||||||
Common stock, par value | $ 0.01 | $ 0.01 | ||||||
Common stock, shares issued | 7,655,759 | 6,005,633 | ||||||
Common stock, shares outstanding | 7,655,759 | 6,005,633 | ||||||
Preferred stock, shares authorized | 1,000,000 | 1,000,000 | ||||||
Preferred stock, par value | $ 0.01 | $ 0.01 | ||||||
Maximum [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Common stock, shares authorized | 200,000,000 | 35,000,000 | ||||||
Minimum [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Common stock, shares authorized | 10,000,000 | 10,000,000 | ||||||
Series B Convertible Preferred Stock [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Accrue cash dividends rate | 6.00% | |||||||
Accrued dividends | $ 100 | |||||||
Series B Shares [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Accrue cash dividends rate | 6.00% | |||||||
Stockholders and Board of Directors [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Reverse stock split, description | A reverse stock split approved by the stockholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. | |||||||
Restricted Stock Units (RSUs) [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Unrecognized compensation cost | 1,400,000 | |||||||
Compensation costs for restricted stock grants | $ 725,000 | $ 664,000 | ||||||
Expected period of recognition of unrecognized compensation costs | 6 years 3 months 19 days | |||||||
Restricted Performance Units [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Unrecognized compensation cost | $ 0 | |||||||
Compensation cost recognized | $ 135,000 | $ 442,000 | ||||||
Granted, Number of Shares | 136,159 | 60,050 | ||||||
Carbon Stock Incentive Plans [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Number of shares issued | 1,100,000 | |||||||
Carbon Stock Incentive Plans [Member] | Officers, Directors, Employees or Consultants [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Stock incentive plan, common stock shares authorized | 1,100,000 | |||||||
Issued Capital Stock [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Common stock, shares authorized | 35,000,000 | |||||||
Common stock, par value | $ 0.01 | |||||||
Common stock, shares issued | 7,700,000 | |||||||
Common stock, shares outstanding | 7,700,000 | |||||||
Preferred stock, shares authorized | 1,000,000 | |||||||
Preferred stock, par value | $ 0.01 | |||||||
Description of increase in our issued and outstanding common stock | The increase in our issued and outstanding common stock is primarily due to (a) Yorktown's exercise of the California Warrant (see note 4), resulting in the issuance of approximately 1.5 million shares of our common stock in exchange for Class A Units in Carbon California representing approximately 46.96% of the then outstanding Class A Units, in addition to (b) restricted stock and restricted performance units, net of shares exchanged for payroll tax obligations paid by us, that vested during the year. | |||||||
Issued Capital Stock [Member] | Private Placement [Member] | ||||||||
Stockholders' Equity (Textual) | ||||||||
Preferred stock purchase agreement shares | 50,000 | |||||||
Preferred stock purchase agreement value | $ 5,000,000 |
Revenue Recognition (Details)
Revenue Recognition (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue Recognition, Multiple-deliverable Arrangements [Line Items] | ||
Natural gas sales | $ 16,018 | $ 15,298 |
Natural gas liquids sales | 1,143 | |
Oil sales | 30,891 | 4,213 |
Total natural gas, natural gas liquids, and oil revenue | 48,052 | 19,511 |
Appalachia and Illinois Basin [Member] | ||
Revenue Recognition, Multiple-deliverable Arrangements [Line Items] | ||
Natural gas sales | 14,768 | 15,298 |
Natural gas liquids sales | ||
Oil sales | 4,963 | 4,213 |
Total natural gas, natural gas liquids, and oil revenue | 19,731 | 19,511 |
Ventura Basin [Member] | ||
Revenue Recognition, Multiple-deliverable Arrangements [Line Items] | ||
Natural gas sales | 1,250 | |
Natural gas liquids sales | 1,143 | |
Oil sales | 25,928 | |
Total natural gas, natural gas liquids, and oil revenue | $ 28,321 |
Revenue Recognition (Details Te
Revenue Recognition (Details Textual) | 12 Months Ended |
Dec. 31, 2018Segments | |
Revenue Recognition (Textual) | |
Number of reportable segment | 1 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts Payable and Accrued Liabilities [Abstract] | ||
Accounts payable | $ 7,670 | $ 3,274 |
Oil and gas revenue suspense | 2,675 | 1,776 |
Gathering and transportation payables | 1,774 | 497 |
Production taxes payable | 1,860 | 214 |
Drilling advances received from joint venture partner | 245 | |
Accrued drilling costs | 3,155 | 684 |
Accrued lease operating costs | 3,474 | 1,054 |
Accrued ad valorem taxes-current | 3,111 | 2,473 |
Accrued general and administrative expenses | 3,099 | 380 |
Accrued asset retirement obligation-current | 955 | 247 |
Accrued interest | 5,441 | |
Accrued gas purchases | 1,603 | |
Other liabilities | 374 | |
Total accounts payable and accrued liabilities | $ 34,816 | $ 11,218 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Level 3 [Member] | ||
Liabilities | ||
Warrant derivative liability | $ 7,094 | |
Fair Value Measurements [Member] | ||
Asset: | ||
Commodity derivatives | $ 7,022 | 225 |
Liabilities | ||
Warrant derivative liability | 2,017 | |
Fair Value Measurements [Member] | Level 1 [Member] | ||
Asset: | ||
Commodity derivatives | ||
Liabilities | ||
Warrant derivative liability | ||
Fair Value Measurements [Member] | Level 2 [Member] | ||
Asset: | ||
Commodity derivatives | 7,022 | 225 |
Liabilities | ||
Warrant derivative liability | ||
Fair Value Measurements [Member] | Level 3 [Member] | ||
Asset: | ||
Commodity derivatives | ||
Liabilities | ||
Warrant derivative liability | $ 2,017 |
Fair Value Measurements (Deta_2
Fair Value Measurements (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items] | ||
Unrealized (gain) loss included in warrant gain | $ (8,742) | $ 2,158 |
Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items] | ||
Beginning Balance | 2,017 | |
Warrant liability | 7,094 | |
Unrealized (gain) loss included in warrant gain | (225) | (3,133) |
Settlement of warrant liability | (1,792) | (1,944) |
Ending Balance | 2,017 | |
Level 3 [Member] | California Warrant [Member] | ||
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items] | ||
Beginning Balance | 2,017 | |
Warrant liability | 5,769 | |
Unrealized (gain) loss included in warrant gain | (225) | (3,752) |
Settlement of warrant liability | (1,792) | |
Ending Balance | 2,017 | |
Level 3 [Member] | Appalachia Warrant [Member] | ||
Fair Value, Assets and Liabilities Measured On Recurring and Nonrecurring Basis [Line Items] | ||
Beginning Balance | ||
Warrant liability | 1,325 | |
Unrealized (gain) loss included in warrant gain | 619 | |
Settlement of warrant liability | (1,944) | |
Ending Balance |
Fair Value Measurements (Deta_3
Fair Value Measurements (Details Textual) - USD ($) | Nov. 01, 2017 | Apr. 03, 2017 | Feb. 15, 2017 | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value Measurements (Textual) | |||||
Asset retirement obligation | $ 13,700,000 | ||||
Asset retirement obligation, description | The estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate between 1.92% to 2.10%; and a credit adjusted risk-free rate between 7.24% to 8.13%, which takes into account our credit risk and the time value of money. | ||||
Class A Units [Member] | California Warrant [Member] | Maximum [Member] | |||||
Fair Value Measurements (Textual) | |||||
Fair value of warrant | $ 45,000 | ||||
Class A Units [Member] | California Warrant [Member] | Minimum [Member] | |||||
Fair Value Measurements (Textual) | |||||
Fair value of warrant | 20,000 | ||||
Level 3 [Member] | |||||
Fair Value Measurements (Textual) | |||||
Asset retirement obligation | $ 13,700,000 | ||||
Level 3 [Member] | California Warrant [Member] | |||||
Fair Value Measurements (Textual) | |||||
Fair value of warrant | $ 5,800,000 | ||||
Volatility rate | 41.80% | ||||
Risk-free rate | 2.30% | ||||
Exercise price | $ 7.20 | ||||
Term | 7 years | ||||
Level 3 [Member] | Appalachia Warrant [Member] | |||||
Fair Value Measurements (Textual) | |||||
Fair value of warrant | $ 1,300,000 | ||||
Volatility rate | 39.30% | ||||
Risk-free rate | 2.10% | ||||
Exercise price | $ 7.20 | ||||
Level 3 [Member] | Class A Units [Member] | California Warrant [Member] | |||||
Fair Value Measurements (Textual) | |||||
Fair value of warrant | $ 2,000,000 | ||||
Volatility rate | 45.00% | ||||
Risk-free rate | 2.10% | ||||
Exercise price | $ 7.20 | ||||
Term | 6 years 4 months 24 days | ||||
Level 3 [Member] | Class A Units [Member] | Appalachia Warrant [Member] | |||||
Fair Value Measurements (Textual) | |||||
Volatility rate | 45.00% | ||||
Risk-free rate | 2.10% | ||||
Exercise price | $ 7.20 | ||||
Term | 6 years 6 months |
Commodity Derivatives (Details)
Commodity Derivatives (Details) | Dec. 31, 2018USD_BblUSD-MMBtu$ / shares | |
2019 [Member] | Carbon Energy Corporation [Member] | Natural Gas Swaps [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | 15,055,000 | |
Weighted Average Price | $ 2.85 | [1] |
2019 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | 836,000 | |
2019 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | Minimum [Member] | ||
Derivative agreements details: | ||
Weighted Average Price | $ 2.60 | [1] |
2019 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | Maximum [Member] | ||
Derivative agreements details: | ||
Weighted Average Price | $ 3.19 | [1] |
2019 [Member] | Carbon Energy Corporation [Member] | Oil Swaps [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 218,597 | |
Weighted Average Price | $ 56.24 | [2] |
2019 [Member] | Carbon California [Member] | Natural Gas Collars [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | 330,000 | |
2019 [Member] | Carbon California [Member] | Natural Gas Collars [Member] | Minimum [Member] | ||
Derivative agreements details: | ||
Weighted Average Price | $ 2.60 | [1] |
2019 [Member] | Carbon California [Member] | Natural Gas Collars [Member] | Maximum [Member] | ||
Derivative agreements details: | ||
Weighted Average Price | $ 3.03 | [1] |
2019 [Member] | Carbon California [Member] | Oil Swaps [Member] | WTI Bbl [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 139,797 | |
Weighted Average Price | $ 51.96 | [3] |
2019 [Member] | Carbon California [Member] | Oil Swaps [Member] | Brent Bbl [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 148,086 | |
Weighted Average Price | $ 66.82 | [4] |
2020 [Member] | Carbon Energy Corporation [Member] | Natural Gas Swaps [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | 12,433,000 | |
Weighted Average Price | $ 2.73 | [1] |
2020 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | 1,018,000 | |
2020 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | Minimum [Member] | ||
Derivative agreements details: | ||
Weighted Average Price | $ 2.50 | [1] |
2020 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | Maximum [Member] | ||
Derivative agreements details: | ||
Weighted Average Price | $ 2.70 | [1] |
2020 [Member] | Carbon Energy Corporation [Member] | Oil Swaps [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 121,147 | |
Weighted Average Price | $ 63.38 | [2] |
2020 [Member] | Carbon California [Member] | Oil Swaps [Member] | WTI Bbl [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 73,147 | |
Weighted Average Price | $ 50.12 | [3] |
2020 [Member] | Carbon California [Member] | Oil Swaps [Member] | Brent Bbl [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 151,982 | |
Weighted Average Price | $ 66.03 | [4] |
2021 [Member] | Carbon Energy Corporation [Member] | Natural Gas Swaps [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | 2,598,000 | |
Weighted Average Price | $ 2.69 | [1] |
2021 [Member] | Carbon Energy Corporation [Member] | Natural Gas Collars [Member] | ||
Derivative agreements details: | ||
Quantity | USD-MMBtu | ||
Weighted Average Price | [2] | |
2021 [Member] | Carbon Energy Corporation [Member] | Oil Swaps [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | ||
Weighted Average Price | [2] | |
2021 [Member] | Carbon California [Member] | Oil Swaps [Member] | WTI Bbl [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | ||
Weighted Average Price | [3] | |
2021 [Member] | Carbon California [Member] | Oil Swaps [Member] | Brent Bbl [Member] | ||
Derivative agreements details: | ||
Quantity | USD_Bbl | 86,341 | |
Weighted Average Price | $ 67.12 | [4] |
[1] | NYMEX Henry Hub Natural Gas futures contract for the respective period. | |
[2] | Includes 100% of Carbon California's outstanding derivative hedges at December 31, 2018, and not our proportionate share. | |
[3] | NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective period. | |
[4] | Brent future and NYMEX contracts for the respective period. |
Commodity Derivatives (Details
Commodity Derivatives (Details 1) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Commodity derivative contracts: | ||
Commodity derivative asset | $ 3,517 | $ 215 |
Other long-term assets | 3,505 | 10 |
Commodity derivative liabilities | ||
Commodity derivative liabilities, non-current |
Commodity Derivatives (Detail_2
Commodity Derivatives (Details 2) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Commodity derivative contracts: | ||
Settlement gains (loss) | $ (3,848) | $ 770 |
Unrealized gains (loss) | (8,742) | 2,158 |
Total settlement and unrealized gains (losses), net | $ 4,894 | $ 2,928 |
Commodity Derivatives (Detail_3
Commodity Derivatives (Details 3) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Commodity derivative assets: | ||
Commodity derivative asset | $ 3,517 | $ 215 |
Other long-term assets | 3,505 | 10 |
Commodity derivative liabilities: | ||
Commodity derivative | ||
Commodity derivative: non-current | ||
Gross Recognized Assets/Liabilities [Member] | ||
Commodity derivative assets: | ||
Commodity derivative asset | 4,605 | 624 |
Other long-term assets | 4,691 | 250 |
Total derivative assets | 9,296 | 874 |
Commodity derivative liabilities: | ||
Commodity derivative | (1,088) | (409) |
Commodity derivative: non-current | (1,186) | (240) |
Total derivative liabilities | (2,274) | (649) |
Gross Amounts Offset [Member] | ||
Commodity derivative assets: | ||
Commodity derivative asset | (1,088) | (409) |
Other long-term assets | (1,186) | (240) |
Total derivative assets | (2,274) | (649) |
Commodity derivative liabilities: | ||
Commodity derivative | 1,088 | 409 |
Commodity derivative: non-current | 1,186 | 240 |
Total derivative liabilities | 2,274 | 649 |
Net Recognized Fair Value Assets/Liabilities [Member] | ||
Commodity derivative assets: | ||
Commodity derivative asset | 3,517 | 215 |
Other long-term assets | 3,505 | 10 |
Total derivative assets | 7,022 | 225 |
Commodity derivative liabilities: | ||
Commodity derivative | ||
Commodity derivative: non-current | ||
Total derivative liabilities |
Commitments and Contingencies_2
Commitments and Contingencies (Details) | 12 Months Ended |
Dec. 31, 2018USD_BblPartnership | |
January 2019 - March 2020 [Member] | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 3,230 |
January 2019 - March 2020 [Member] | Minimum [Member] | |
Other Commitments [Line Items] | |
Demand Charges (in dollars per dekatherm) | 0.20 |
January 2019 - March 2020 [Member] | Maximum [Member] | |
Other Commitments [Line Items] | |
Demand Charges (in dollars per dekatherm) | 0.62 |
April 2020 - May 2020 [Member] | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 2,150 |
Demand Charges (in dollars per dekatherm) | 0.20 |
June 2020 - May 2036 [Member] | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 1,000 |
Demand Charges (in dollars per dekatherm) | 0.20 |
Jan 2019 - Oct 2020 [Member] | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 6,300 |
Demand Charges (in dollars per dekatherm) | 0.21 |
Jan 2019 - Aug 2022 [Member] | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 49,341 |
Demand Charges (in dollars per dekatherm) | 0.21 |
Sep 2022 - May 2027 [Member] | |
Other Commitments [Line Items] | |
Capacity levels (Dekatherms per day) | Partnership | 29,990 |
Demand Charges (in dollars per dekatherm) | 0.56 |
Commitments and Contingencies_3
Commitments and Contingencies (Details Textual) $ in Millions | Dec. 31, 2018USD ($) |
Commitment and Contingencies (Textual) | |
Acquisition amount | $ 18.9 |
Retirement Savings Plan (Detail
Retirement Savings Plan (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Retirement Savings Plan (Textual) | ||
Matching percentage under retirement savings plan | 6.00% | |
401(K) contributions and related administrative expenses | $ 441 | $ 175 |
Supplemental Cash Flow Disclo_3
Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Cash paid during the period for: | ||
Interest payments | $ 4,217 | $ 967 |
Non-cash transactions: | ||
Accounts receivable | 489 | |
Prepaid expense | (17,076) | |
Commodity derivative asset - current | (2,178) | |
Inventory | 900 | |
Proved oil and gas properties | (900) | |
Unproved oil and gas properties | (139,613) | |
Other fixed assets | (3,364) | |
Equity method investments | 14,655 | 5,674 |
Other non-current assets | (989) | |
Accounts payable and accrued liabilities | 26,292 | 67 |
Commodity derivative liability - non-current | 2,645 | |
Firm transportation contract obligations | 18,724 | |
Warrant liability | (1,792) | |
Notes payable | 83,006 | |
Asset retirement obligations | $ 7,879 | $ 2,402 |
Related Parties (Details)
Related Parties (Details) - USD ($) | May 01, 2018 | Feb. 01, 2018 | Apr. 03, 2017 | Feb. 15, 2017 | Dec. 31, 2018 | Dec. 31, 2017 |
Related Parties (Textual) | ||||||
Accounts receivable - due from related party | $ 0 | $ 300,000 | ||||
Due from related party | 300,000 | |||||
Carbon California [Member] | ||||||
Related Parties (Textual) | ||||||
Releted parties units received | 5,077 | |||||
Related party accounts payable | $ 600,000 | |||||
One-time reimbursement | 500,000 | |||||
Closing of acquisition annual | $ 1,200,000 | |||||
Total management reimbursements | $ 1,100,000 | $ 1,000,000 | ||||
Carbon California [Member] | Class A Units [Member] | ||||||
Related Parties (Textual) | ||||||
Releted parties units received | 5,000 | 11,000 | ||||
Equity contribution | $ 5,000,000 | |||||
Carbon California [Member] | Class B Units [Member] | ||||||
Related Parties (Textual) | ||||||
Related party, percentage | 17.81% | |||||
Carbon Appalachia [Member] | ||||||
Related Parties (Textual) | ||||||
Related party, percentage | 100.00% | |||||
Accounts receivable - due from related party | $ 0 | $ 579,000 | ||||
One-time reimbursement | $ 75,000 | 4,500,000 | 1,600,000 | |||
Due from related party | $ 1,800,000 | 0 | ||||
Ohio Basic Minerals [Member] | ||||||
Related Parties (Textual) | ||||||
One-time reimbursement | $ 96,000 |
Subsequent Events (Details)
Subsequent Events (Details) | 1 Months Ended |
Jan. 31, 2019USD ($) | |
Subsequent Event [Member] | |
Subsequent Events (Textual) | |
Payment of insurance | $ 800,000 |
Supplemental Financial Data -_3
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details) | 12 Months Ended | |||||
Dec. 31, 2018MMcfMMBbls | Dec. 31, 2018MMcfMBblsMMBbls | Dec. 31, 2018MMcfMMBbls | Dec. 31, 2017MMcfMMBbls | Dec. 31, 2017MMcfMBblsMMBbls | Dec. 31, 2017MMcfMMBbls | |
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 87,216 | 79,557 | ||||
Revisions of previous estimates | (21,868) | 12,841 | ||||
Extensions and discoveries | 232 | |||||
Production | (7,702) | (5,414) | ||||
Purchases of reserves in-place | 522,680 | |||||
Sales of reserves in-place | ||||||
Proved reserves, end of year | 580,326 | 87,216 | ||||
Proved developed reserves at: | ||||||
End of Year | 545,272 | 545,272 | 545,272 | 87,216 | 87,216 | 87,216 |
Proved undeveloped reserves at: | ||||||
End of Year | 35,054 | 35,054 | 35,054 | 96 | 96 | 96 |
Carbon California [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 14,124 | |||||
Proved reserves, end of year | 14,124 | |||||
Carbon Appalchia [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 100,507 | |||||
Proved reserves, end of year | 100,507 | |||||
Company [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 79,557 | 79,557 | ||||
Proved reserves, end of year | 87,216 | 79,557 | ||||
Oil [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 4,169 | 919 | 882 | 882 | ||
Revisions of previous estimates | MMBbls | (2,803) | 107 | ||||
Extensions and discoveries | MMBbls | 16 | |||||
Production | MMBbls | (451) | (86) | ||||
Purchases of reserves in-place | MMBbls | 21,233 | |||||
Sales of reserves in-place | MMBbls | ||||||
Proved reserves, end of year | 18,898 | 4,169 | 919 | |||
Proved developed reserves at: | ||||||
End of Year | MMBbls | 14,336 | 14,336 | 14,336 | 903 | 903 | 903 |
Proved undeveloped reserves at: | ||||||
End of Year | MMBbls | 4,562 | 4,562 | 4,562 | 16 | 16 | 16 |
Oil [Member] | Carbon California [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | MBbls | 1,625 | |||||
Proved reserves, end of year | MBbls | 1,625 | |||||
Oil [Member] | Carbon Appalchia [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | MBbls | 72 | |||||
Proved reserves, end of year | MBbls | 72 | |||||
Oil [Member] | Company [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | MBbls | 882 | 882 | ||||
Proved reserves, end of year | MBbls | 919 | 882 | ||||
Natural Gas [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 81,702 | 74,265 | ||||
Revisions of previous estimates | 1,832 | 12,199 | ||||
Extensions and discoveries | 136 | |||||
Production | (4,798) | (4,898) | ||||
Purchases of reserves in-place | 376,664 | |||||
Sales of reserves in-place | ||||||
Proved reserves, end of year | 455,400 | 81,702 | ||||
Proved developed reserves at: | ||||||
End of Year | 450,424 | 450,424 | 450,424 | 81,702 | 81,702 | 81,702 |
Proved undeveloped reserves at: | ||||||
End of Year | 4,976 | 4,976 | 4,976 | |||
Natural Gas [Member] | Carbon California [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 3,012 | |||||
Proved reserves, end of year | 3,012 | |||||
Natural Gas [Member] | Carbon Appalchia [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 90,757 | |||||
Proved reserves, end of year | 90,757 | |||||
Natural Gas [Member] | Company [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 74,265 | 74,265 | ||||
Proved reserves, end of year | 81,702 | 74,265 | ||||
NGL [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | 227 | |||||
Revisions of previous estimates | MMBbls | (1,147) | |||||
Extensions and discoveries | MMBbls | ||||||
Production | MMBbls | (33) | |||||
Purchases of reserves in-place | MMBbls | 3,103 | |||||
Sales of reserves in-place | MMBbls | ||||||
Proved reserves, end of year | 1,923 | 227 | ||||
Proved developed reserves at: | ||||||
End of Year | MMBbls | 1,472 | 1,472 | 1,472 | |||
Proved undeveloped reserves at: | ||||||
End of Year | MMBbls | 451 | 451 | 451 | |||
NGL [Member] | Carbon California [Member] | ||||||
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells | ||||||
Proved reserves, beginning of year | MBbls | 227 | |||||
Proved reserves, end of year | MBbls | 227 |
Supplemental Financial Data -_4
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 1) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and gas properties | ||
Proved oil and gas properties | $ 347,059 | $ 114,893 |
Unproved properties not subject to depletion | 5,416 | 1,947 |
Accumulated depreciation, depletion, amortization and impairment | (98,604) | (80,715) |
Net oil and gas properties | $ 253,871 | $ 36,125 |
Supplemental Financial Data -_5
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 2) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Property acquisition costs: | ||
Unevaluated properties | $ 3,464 | $ 1 |
Proved properties and gathering facilities | 63,517 | 289 |
Development costs | 2,074 | 952 |
Gathering facilities | 460 | 43 |
Asset retirement obligation | 14,085 | 2,309 |
Total costs incurred | $ 83,600 | $ 3,594 |
Supplemental Financial Data -_6
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 3) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |||
Total acquisition costs | $ 3,464 | $ 1 | $ 1,946 |
Supplemental Financial Data -_7
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 4) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018USD ($)MMcf | Dec. 31, 2017USD ($)MMcf | |
Revenue: | ||
Oil and gas sales, including commodity derivative gains and losses | $ 52,946 | $ 22,439 |
Expenses: | ||
Production expenses | 22,226 | 9,589 |
Depletion expense | 7,305 | 2,157 |
Accretion of asset retirement obligations | 868 | 307 |
Total expenses | 30,399 | 12,053 |
Results of operations from oil and gas producing activities | $ 22,547 | $ 10,386 |
Depletion rate per Mcfe | MMcf | 0.89 | 0.4 |
Supplemental Financial Data -_8
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 5) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Summary of estimate of the current market value of the Company's proved reserves | |||
Future cash inflows | $ 2,878,392 | $ 283,664 | |
Future production costs | (1,538,870) | (119,501) | |
Future development costs | (76,852) | (210) | |
Future income taxes | (258,277) | (35,482) | |
Future net cash flows | 1,004,393 | 128,471 | |
10% annual discount | (612,325) | (71,389) | |
Standardized measure of discounted future net cash flows | $ 392,068 | $ 57,082 | $ 44,711 |
Supplemental Financial Data -_9
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 6) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract] | ||
Standardized measure of discounted future net cash flows, beginning of year | $ 57,082 | $ 44,711 |
Sales of oil and gas, net of production costs and taxes | (25,681) | (10,038) |
Price revisions | 133,789 | 17,588 |
Extensions, discoveries and improved recovery, less related costs | 298 | |
Changes in estimated future development costs | (32,711) | (324) |
Development costs incurred during the period | 926 | 804 |
Quantity revisions | (23,484) | 11,196 |
Accretion of discount | 5,708 | 4,471 |
Net changes in future income taxes | (89,117) | (7,425) |
Purchases of reserves-in-place | 391,877 | |
Sales of reserves-in-place | ||
Changes in production rate timing and other | (26,321) | (4,199) |
Standardized measure of discounted future net cash flows, end of year | $ 392,068 | $ 57,082 |
Supplemental Financial Data _10
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 7) | 12 Months Ended | |
Dec. 31, 2018USD_Bbl | Dec. 31, 2017Per_Mcf | |
Oil (per Bbl) [Member] | ||
Average Sales Price And Production Cost Per Unit [Abstract] | ||
Weighted averaged adjusted prices | 51.34 | 65.56 |
Natural Gas (per Mcf) [Member] | ||
Average Sales Price And Production Cost Per Unit [Abstract] | ||
Weighted averaged adjusted prices | 3.10 | 2.98 |
Supplemental Financial Data _11
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details Textual) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual) | ||
Estimated proved reserves, description | 3.0 Bcfe | 3.0 Bcfe |
Discount rate, description | All cash flow amounts, including income taxes, are discounted at 10%. | |
Carbon California [Member] | ||
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual) | ||
Propotionate share, percentage | 17.81% | |
Carbon Appalachia [Member] | ||
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual) | ||
Propotionate share, percentage | 27.24% | |
Purchases of reserves-in-place, description | We held a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; November 1, 2017 through December 31, 2017, respectively. |