| Summary of Significant Accounting Policies | NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities and Exchange Commission (the “SEC”) regarding interim financial reporting and include all adjustments that are necessary for a fair presentation of our condensed consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The condensed consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. Principles of Consolidation Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated. Beginning May 1, 2020, we have no continuing common ownership or corporate affiliation with ATLS and its affiliates. We will continue to identify any transaction between us and other ATLS managed operations as transactions between affiliates for all historical periods. Use of Estimates The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals and depletion of gas and oil properties. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results may be recorded using estimated volumes and contract market prices. Actual results may differ from those estimates. Liquidity For the six months ended June 30, 2021 and 2020, we had net losses of $0.7 million and $6.4 million, respectively, and cash provided by operating activities of $0.2 million and cash used in operating activities of $0.8 million, respectively. With the Company’s negative working capital of $1.3 million as of June 30, 2021, the Company may not have sufficient resources to fund operations into 2022. Beginning in March 2020, significant price decline and price volatility for oil and gas products emerged in the market. We have been and could continue to be directly impacted by these price changes if demand and prices remain depressed for an extended period of time. Given the volatility and uncertainty, we may be at risk of being able to identify and secure a party to gather and purchase our products. A significant number of our product sales are short-term in nature with contract terms of one year or less, though generally subject to customary evergreen clauses. To date, we have been able to sell our production and we continue to identify multiple purchasers. However, should these parties become unwilling to purchase our production, we will need to work to identify other purchasers in the area to gather and purchase our oil and gas products. Failure to identify other purchasers and storage facilities, may result in the potential shut-in of the field. The financial statement impact, change in price and expected time for these changes is not estimable but could result in significant decreases in oil and gas operations. Our primary sources of liquidity are cash generated by gas and oil production and their subsequent sale. Our primary cash requirements, in addition to normal operating expenses, are for management fees and capital expenditures, which we expect to fund through operating cash flow. Accordingly, our sources of liquidity are currently not sufficient to satisfy our current obligations. The significant risks and uncertainties related to our inability to satisfy our current liabilities raise substantial doubt about our ability to continue as a going concern. If these liabilities are called, we will not have sufficient liquidity to repay all of our outstanding liabilities, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. As discussed above, on July 12, 2021 t he Board authorized and directed the General Partner, on behalf of itself and the Company , to take all necessary or advisable steps to dissolve, wind up and terminate the Company , including the execution and performance of the PSA. As the Board approval of the dissolution, wind up and termination and of the PSA occurred in July 2021, our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material. Property, Plant and Equipment Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations. We follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six Mcf of natural gas. Mcf is defined as one thousand cubic feet. Our depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. We also consider the estimated salvage value in our calculation of depletion. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in proportionately consolidated joint venture wells, wells drilled solely by us for our interests, properties purchased and working interests with other outside operators. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to our condensed consolidated statements of operations. Upon the sale of an individual well, we credit the proceeds to accumulated depreciation and depletion within our condensed consolidated balance sheet. Upon our sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in our condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. Support equipment and other are carried at cost and consist primarily of pipelines, processing and compression facilities, and gathering systems and related support equipment. We compute depreciation of support equipment and other using the straight-line balance method over the estimated useful life of each asset type, which is 15-20 years. Segment Reporting We derive revenue from our gas and oil production. The production facilities associated with our oil and gas production have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers. Oil, Natural Gas, and NGL Revenues Our revenues are derived from the sale of oil, natural gas, and NGLs, which is recognized in the period that the performance obligations are satisfied. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and the delivery of each unit represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser and title has transferred. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by us from a customer, are excluded from revenue. Payment is generally received one month after the sale has occurred. Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For oil contracts, we generally record sales based on the net amount received. Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. For natural gas contracts, we generally record wet gas sales (which consist of natural gas and NGLs based on end products after processing) at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to us at the tailgate of the plant. Conversely, we generally record residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to us at the tailgate of the plant. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination. Transaction Price Allocated to Remaining Performance Obligations A significant number of our product sales are short-term in nature with contract terms of one year or less, though generally subject to customary evergreen clauses pursuant to which these contracts typically automatically renew under the same terms and conditions. For those contracts, we have utilized the practical expedient that exempts 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 product sales that have a contract term greater than one year, we have utilized the practical expedient that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration. Contract Balances Under our sales contracts, customers are invoiced once performance obligations have been satisfied, at which point our right to payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $0.7 million and $0.5 million, respectively, at June 30, 2021 and December 31, 2020. Net Loss Per Common Unit Basic net loss attributable to common limited partners per unit is computed by dividing net loss attributable to common limited partners (which is determined after the deduction of the general partner’s interest) by the weighted average number of common limited partner units outstanding during the period. The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands):
Three Months Ended
Six Months Ended
June 30,
June 30,
2021
2020
2021
2020
Net loss
$
(344
)
$
(1,542
)
$
(688
)
$
(6,373
)
Less: General partner’s interest
(7
)
(31
)
(14
)
(127
)
Net loss attributable to common limited partners
$
(337
)
$
(1,511
)
$
(674
)
$
(6,246
) Diluted net loss attributable to common limited partners per unit is calculated by dividing net loss attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method. The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net loss attributable to common limited partners per unit with those used to compute diluted net loss attributable to common limited partners per unit (in thousands):
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
Weighted average number of common units – basic
23,300
23,300
23,300
23,300
Add effect of dilutive awards (1)
—
—
—
—
Weighted average number of common units – diluted
23,300
23,300
23,300
23,300
(1)
For each of the three and six months ended June 30, 2021 and 2020, 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. |
