| 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. |
