Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2016USD ($)shares | |
Document And Entity Information [Abstract] | |
Document Type | 10-K |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2016 |
Document Fiscal Year Focus | 2,016 |
Document Fiscal Period Focus | FY |
Entity Registrant Name | ATLAS RESOURCES SERIES 28-2010 L.P. |
Entity Central Index Key | 1,487,561 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Smaller Reporting Company |
Entity Common Stock, Shares Outstanding | shares | 0 |
Entity Public Float | $ | $ 0 |
Entity Current Reporting Status | Yes |
Entity Well-known Seasoned Issuer | No |
Entity Voluntary Filers | No |
BALANCE SHEETS
BALANCE SHEETS - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash | $ 171,800 | $ 181,200 |
Accounts receivable trade-affiliate | 1,223,800 | 1,068,400 |
Current portion of derivative assets | 0 | 799,500 |
Total current assets | 1,395,600 | 2,049,100 |
Gas and oil properties, net | 24,494,800 | 26,622,200 |
Long-term asset retirement receivable-affiliate | 110,000 | 40,400 |
Total assets | 26,000,400 | 28,711,700 |
Current liabilities: | ||
Accrued liabilities | 206,300 | 181,600 |
Current portion of put premiums payable-affiliate | 0 | 162,700 |
Total current liabilities | 206,300 | 344,300 |
Asset retirement obligations | 3,956,700 | 3,793,000 |
Commitments and contingencies (Note 9) | ||
Partners’ capital: | ||
Managing general partner’s interest | 3,691,000 | 3,905,600 |
Limited partners’ interest (7,500 units) | 18,146,400 | 20,665,000 |
Accumulated other comprehensive income | 3,800 | |
Total partners’ capital | 21,837,400 | 24,574,400 |
Total liabilities and partners’ capital | $ 26,000,400 | $ 28,711,700 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) | Dec. 31, 2016shares |
Statement Of Financial Position [Abstract] | |
Limited partners' units | 7,500 |
STATEMENTS OF OPERATIONS
STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
REVENUES | ||
Natural gas | $ 5,351,700 | $ 6,964,000 |
Gain on mark-to-market derivatives | 2,800 | 654,500 |
Total revenues | 5,354,500 | 7,618,500 |
COSTS AND EXPENSES | ||
Production | 3,541,700 | 4,317,800 |
Depletion | 1,898,700 | 2,361,600 |
Impairment | 212,400 | 6,320,500 |
Accretion of asset retirement obligations | 169,700 | 216,300 |
General and administrative | 132,000 | 137,800 |
Total costs and expenses | 5,954,500 | 13,354,000 |
Operating loss | (600,000) | (5,735,500) |
Loss on abandonment of well | (288,200) | |
Net loss | (600,000) | (6,023,700) |
Allocation of net income (loss): | ||
Managing general partner | 88,000 | (1,945,000) |
Limited partners | $ (688,000) | $ (4,078,700) |
Net loss per limited partnership unit | $ (92) | $ (544) |
STATEMENTS OF COMPREHENSIVE LOS
STATEMENTS OF COMPREHENSIVE LOSS - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Statement Of Income And Comprehensive Income [Abstract] | ||
Net loss | $ (600,000) | $ (6,023,700) |
Other comprehensive loss: | ||
Difference in estimated hedge gains receivable | (294,500) | |
Reclassification adjustment to net loss of mark-to-market (gains) losses on cash flow hedges | (3,800) | 35,400 |
Total other comprehensive loss | (3,800) | (259,100) |
Comprehensive loss | $ (603,800) | $ (6,282,800) |
STATEMENTS OF CHANGES IN PARTNE
STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) | Total | Managing General Partner | Limited Partners | Accumulated Other Comprehensive Income (Loss) |
Beginning balance at Dec. 31, 2014 | $ 35,614,200 | $ 7,423,600 | $ 27,927,700 | $ 262,900 |
Participation in revenues and costs and expenses: | ||||
Net production revenues | 2,646,200 | 975,500 | 1,670,700 | |
Gain on mark-to-market derivatives | 654,500 | 654,500 | ||
Loss on abandonment of well | (288,200) | (288,200) | ||
Depletion | (2,361,600) | (455,600) | (1,906,000) | |
Impairment | (6,320,500) | (2,043,600) | (4,276,900) | |
Accretion of asset retirement obligations | (216,300) | (81,300) | (135,000) | |
General and administrative | (137,800) | (51,800) | (86,000) | |
Net loss | (6,023,700) | (1,945,000) | (4,078,700) | |
Other comprehensive loss | (259,100) | (259,100) | ||
Working interest adjustment | (5,600) | 5,600 | ||
Subordination | (731,200) | 731,200 | ||
Distributions to partners | (4,757,000) | (836,200) | (3,920,800) | |
Ending balance at Dec. 31, 2015 | 24,574,400 | 3,905,600 | 20,665,000 | 3,800 |
Participation in revenues and costs and expenses: | ||||
Net production revenues | 1,810,000 | 703,400 | 1,106,600 | |
Gain on mark-to-market derivatives | 2,800 | 2,800 | ||
Depletion | (1,898,700) | (402,900) | (1,495,800) | |
Impairment | (212,400) | (99,100) | (113,300) | |
Accretion of asset retirement obligations | (169,700) | (63,800) | (105,900) | |
General and administrative | (132,000) | (49,600) | (82,400) | |
Net loss | (600,000) | 88,000 | (688,000) | |
Other comprehensive loss | (3,800) | $ (3,800) | ||
Working interest adjustment | 0 | |||
Subordination | (126,600) | 126,600 | ||
Distributions to partners | (2,133,200) | (176,000) | (1,957,200) | |
Ending balance at Dec. 31, 2016 | $ 21,837,400 | $ 3,691,000 | $ 18,146,400 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | ||
Net loss | $ (600,000) | $ (6,023,700) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depletion | 1,898,700 | 2,361,600 |
Impairment | 212,400 | 6,320,500 |
Non-cash loss on derivative value | 633,000 | 210,700 |
Accretion of asset retirement obligations | 169,700 | 216,300 |
Loss on abandonment of well | 288,200 | |
Changes in operating assets and liabilities: | ||
(Increase) decrease in accounts receivable trade-affiliate | (155,400) | 1,779,000 |
Increase in asset retirement receivable-affiliate | (69,600) | |
Increase (decrease) in accrued liabilities | 24,700 | (2,900) |
Asset retirement obligations settled | (6,000) | (557,600) |
Net cash provided by operating activities | 2,107,500 | 4,592,100 |
Cash flows from investing activities: | ||
Proceeds from sale of tangible equipment | 16,300 | 150,000 |
Proceeds from sale of gas and oil properties | 196,100 | |
Net cash provided by investing activities | 16,300 | 346,100 |
Cash flows from financing activities: | ||
Distributions to partners | (2,133,200) | (4,757,000) |
Net cash used in financing activities | (2,133,200) | (4,757,000) |
Net change in cash | (9,400) | 181,200 |
Cash at beginning of year | 181,200 | |
Cash at end of year | $ 171,800 | $ 181,200 |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
BASIS OF PRESENTATION | NOTE 1—BASIS OF PRESENTATION Atlas Resources Series 28-2010 L.P. (the “Partnership”) is a Delaware limited partnership, formed on April 1, 2010 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Titan Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Series 28-2010 L.P. Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan. The Partnership has drilled and currently operates wells located in Pennsylvania, Indiana and Colorado. We have no employees and rely on our MGP for management, which in turn, relies on Atlas Energy Group for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas. Produced natural gas is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling. The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues. The prices at which the Partnership’s natural gas will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas that the Partnership can produce economically. ARP Restructuring and Chapter 11 Bankruptcy Proceedings On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that reduced debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby were being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” ARP and the MGP operated the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired and were satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP and the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business. The Partnership was not a party to the Restructuring Support Agreement. The ARP Restructuring did not materially impact the MGP’s ability to perform as the managing general partner and operator of the Partnership’s operations. In June 2016, the MGP transferred $380,900 of funds to the Partnership based on projected monthly distributions to its limited partners over the next several months to ensure accessible distribution funding coverage in accordance with the Partnership’s operations and partnership agreements in the event the MGP experienced a prolonged restructuring period as the MGP performs all administrative and management functions for the Partnership. As of December 31, 2016, the Partnership has used these funds for distributions. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner would not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership. Atlas Energy Group was not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring did not have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses. On August 26, 2016, an order confirming ARP’s Plan was entered by the Bankruptcy Court. On September 1, 2016, ARP’s Plan became effective and ARP emerged as Titan. Liquidity, Capital Resources and Ability to Continue as a Going Concern The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations had been adequate to fund its obligations and distributions to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position The uncertainties of Titan’s and the MGP’s liquidity and capital resources (as further described below) raise substantial doubt about Titan’s and the MGP’s ability to continue as a going concern, which also raises substantial doubt about the Partnership’s ability to continue as a going concern. If Titan is unsuccessful in taking actions to resolve its liquidity issues (as further described below), the MGP’s ability to continue the Partnership’s operations may be further impacted and may make it uneconomical for the Partnership to produce its wells until they are depleted as originally intended. If the Partnership is not able to continue as a going concern, the Partnership will liquidate. If the Partnership’s operations are liquidated, a valuation of the Partnership’s assets and liabilities would be determined by an independent expert in accordance with the partnership agreement. It is possible that based on such determination, the Partnership would not be able to make any liquidation distributions to its limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners. The 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. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of the Partnership’s assets and liabilities and the reported amounts of income and expenses could be required and could be material. MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under Titan’s credit facilities. The MGP’s primary cash requirements are operating expenses, payments to Titan for debt service including interest, and capital expenditures. The MGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under Titan’s credit facilities and equity and debt offerings. The MGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities. Titan was not in compliance with certain of the financial covenants under its credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. Titan and the MGP do not currently have sufficient liquidity to repay all of Titan’s outstanding indebtedness, and as a result, there is substantial doubt regarding Titan’s and the MGP’s ability to continue as a going concern. Titan expects to finalize an amendment to its first lien credit facility on April 19, 2017 in an attempt to ameliorate some of its liquidity concerns, subject to receiving the remaining lenders’ consent. The amendment is expected to provide for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility. Unless Titan is able to obtain an amendment or waiver, the lenders under Titan’s second lien credit facility may declare a default with respect to Titan’s failure to comply with financial covenants and deliver audited financial statements without a going concern qualification. However, pursuant to the intercreditor agreement, the lenders under Titan’s second lien credit facility are restricted in their ability to pursue remedies for 180 days from any such notice of default. As of the date hereof, the lenders under Titan’s second lient credit facility have not yet given notice of any default. Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for Titan’s stakeholders. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of the Partnership’s 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 the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. 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 were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates. Receivables Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2016 and 2015, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets. Asset retirement receivable – affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnership’s wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnership’s wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells. The following is a reconciliation of the Partnerships’ asset retirement receivable – affiliate for the years indicated: December 31, 2016 2015 Asset retirement receivable – affiliate, beginning of year $ 40,400 $ 40,400 Asset retirement estimates withheld 69,600 78,900 Plugging and abandonment costs incurred - (78,900 ) Asset retirement receivable –affiliate, end of year $ 110,000 $ 40,400 Gas Properties Gas properties are stated at cost. Maintenance and repairs that 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 that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. The Partnership follows the successful efforts method of accounting for gas producing activities. The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, 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 cost of developed producing properties. The Partnership also considers the estimated salvage value in the calculation of depletion. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets. Impairment of Long-Lived Assets The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value (see Note 4). The review of the Partnership’s gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The determination of natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. Derivative Instruments The Partnership’s MGP entered into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings. Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its gas wells and related facilities (See Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Income Taxes The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements. The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2016 and 2015. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2016. Environmental Matters The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2016 and 2015. Concentration of Credit Risk The Partnership sells natural gas under contracts to various purchasers in the normal course of business. For the year ended December 31, 2016, the Partnership had two customers that individually accounted for approximately 73% and 22% of the Partnership’s natural gas revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, the Partnership had two customers that individually accounted for approximately 53% and 43%, of the Partnership’s natural gas combined revenues, excluding the impact of all financial derivative activity. Revenue Recognition The Partnership generally sells natural gas at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at December 31, 2016 and 2015 of $858,800 and $750,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. Loss on Abandonment of Well During the year ended December 31, 2015, the Partnership plugged and abandoned the remaining Michigan well. The remaining net asset value recorded in the Partnership’s gas properties prior to plugging and abandonment was $300. This net asset value was written off as part of the net loss on abandonment of well in the Partnership’s statement of operations for the year ended December 31, 2015 and also removed from gas properties on the Partnership’s balance sheet. Plugging and abandonment costs incurred through December 31, 2015 total $557,800, of which $269,600 had been previously recorded as an asset retirement obligation, resulting in a net loss on abandonment of well of $288,200. Comprehensive Income (Loss) Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2016, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). Recently Issued Accounting Standards In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of December 15, 2016 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our financial statements. This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation. |
Participation in Revenues and C
Participation in Revenues and Costs | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
PARTICIPATION IN REVENUES AND COSTS | NOTE 3—PARTICIPATION IN REVENUES AND COSTS Working Interest The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. At December 31, 2016 and 2015, $0 and $5,600, respectively, of net earnings resulting from the working interest adjustment were reclassified from the MGP’s capital account to the limited partners’ capital account. The MGP and the limited partners generally participated in revenues and costs in the following manner: Managing Limited Organization and offering cost 100% 0% Lease costs 100% 0% Intangible drilling costs 8% 92% Tangible equipment costs 52% 48% Revenues (1) 37% 63% Operating costs, administrative costs, direct and all other costs (2) 37% 63% (1) Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues. (2) These costs will be charged to the partners in the same ratio as the related production revenues are credited. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property Plant And Equipment [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | NOTE 4 — The following is a summary of natural gas properties at the dates indicated: December 31, 2016 2015 Proved properties: Leasehold interests $ 5,301,300 $ 5,301,300 Wells and related equipment 159,420,100 159,436,400 Total natural gas and oil properties 164,721,400 164,737,700 Accumulated depletion and impairment (140,226,600 ) (138,115,500 ) Gas and oil properties, net $ 24,494,800 $ 26,622,200 The Partnership recorded depletion expense on natural gas properties of $1,898,700 and $2,361,600 for the years ended December 31, 2016 and 2015, respectively. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. During the years ended December 31, 2016 and 2015, the Partnership recognized $212,400 and $6,420,500, respectively, of impairment related to gas properties. These impairments relate to the carrying amount of these gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2016 and 2015. At December 31, 2016, the MGP redetermined estimated salvage values to be lower than previous estimates. This redetermination resulted in the impairment of gas and oil properties. At December 31, 2015, the estimate of fair value of these gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | NOTE 5—ASSET RETIREMENT OBLIGATIONS The Partnership recognizes an estimated liability for the plugging and abandonment of its gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership’s gas properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets. The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of December 31, 2016 and 2015, the MGP withheld $110,000 and $40,400, respectively, of net production revenue for future plugging and abandonment costs. A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows: Years Ended December 31, 2016 2015 Beginning of year $ 3,793,000 $ 3,846,300 Accretion expense 169,700 216,300 Settlements (6,000 ) (269,600 ) End of year $ 3,956,700 $ 3,793,000 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | NOTE 6—DERIVATIVE INSTRUMENTS The MGP, on behalf of the Partnership, used a number of different derivative instruments, principally swaps and options, in connection with the Partnership’s commodity price risk management activities. Management used financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. The Partnership entered into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $0 and $799,500 at December 31, 2016 and 2015, respectively. The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Years Ended 2016 2015 Gain (loss) reclassified from accumulated other comprehensive income into natural gas revenues $ 3,800 $ (35,400 ) Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ 2,800 $ 654,500 Put Premiums Payable During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2016 and 2015, the put premiums were recorded as short-term payables to affiliate of $0 and $162,700, respectively. The MGP has a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas properties and first priority security interests in substantially all of its assets and by a guarantee of the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. As of December 31, 2016, only the Partnership’s natural gas swaps are included in the secured hedge facility. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE OF FINANCIAL INSTRUMENTS | NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value: Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques . Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument. Information for assets and liabilities measured at fair value was as follows: Level 1 Level 2 Level 3 Total As of December 31, 2016 Derivative assets, gross Commodity swaps $ - $ - $ - $ - Commodity puts - - - - Total derivative assets, gross $ - $ - $ - $ - As of December 31, 2015 Derivative assets, gross Commodity swaps $ - $ 447,200 $ - $ 447,200 Commodity puts - 352,300 - 352,300 Total derivative assets, gross $ - $ 799,500 $ - $ 799,500 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5). The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the years ended December 31, 2016 and 2015, the Partnership recognized $212,400 and $6,420,500, respectively, of impairment of long-lived assets which were defined as Level 3 fair value measurements (See Note 4: Property, Plant and Equipment). |
Certain Relationships and Relat
Certain Relationships and Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS | NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells, $600 per well per month for horizontal Antrim Shale wells and for Colorado wells a fee of $400 is charged per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 16% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. The following table provides information with respect to these costs and the periods incurred. Years Ended 2016 2015 Administrative fees $ 66,000 $ 72,800 Supervision fees 705,300 838,800 Transportation fees 539,300 721,900 Direct costs 2,363,100 2,822,100 Total $ 3,673,700 $ 4,455,600 The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. Subordination by Managing General Partner Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (March 2011) and expiring 60 months from that date. The MGP subordinated $126,600 and $731,200 of its net production revenues to the limited partners for the years ended December 31, 2016 and 2015, respectively. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | NOTE 9—COMMITMENTS AND CONTINGENCIES General Commitments Subject to certain conditions, investor partners may present their interests beginning in 2015 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation. Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2016 and 2015, the MGP withheld $110,000 and $40,400, respectively, of net production revenue for future plugging and abandonment costs. Legal Proceedings The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations. Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | NOTE 10—SUBSEQUENT EVENTS Management has considered for disclosure any material subsequent events through the date the financial statements were issued. |
Supplemental Gas Information (U
Supplemental Gas Information (Unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
SUPPLEMENTAL GAS INFORMATION (UNAUDITED) | NOTE 11—SUPPLEMENTAL GAS INFORMATION (UNAUDITED) Gas Reserve Information. The preparation of the Partnership’s natural gas reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas industry experience. The reserve estimates were reviewed and approved by the MGP’s senior engineering staff and management, with final approval by the MGP’s President. The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of gas reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas prices and in production and development costs and other factors, for their effects have not been proved. Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited): Gas (Mcf) Balance, December 31, 2014 49,648,700 Revisions (1) (936,600 ) Production (3,618,100 ) Balance, December 31, 2015 (2 ) 45,094,000 Revisions (3 ) (8,313,100 ) Production (2,969,300 ) Balance, December 31, 2016 33,811,600 (1) The downward revision in natural gas forecasts is primarily due to a decrease in SEC base pricing from the prior year, resulting in shorter economic life. (2) We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 and 2016 due to the significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the years ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas equivalent reserves due to anticipated future changes in gas commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. (3) The downward revision in natural gas forecasts is primarily due to forecast adjustments in order to reflect actual production. Capitalized Costs Related to Gas Producing Activities. The components of capitalized costs related to gas producing activities of the Partnership during the periods indicated were as follows: Years Ended December 31, 2016 2015 Natural gas properties: Leasehold interest $ 5,301,300 $ 5,301,300 Wells and related equipment 159,420,100 159,436,400 Accumulated depletion, accretion and impairment (140,226,600 ) (138,115,500 ) Net capitalized costs $ 24,494,800 $ 26,622,200 Results of Operations from Gas Producing Activities. The results of operations related to the Partnership’s gas producing activities during the periods indicated were as follows: Years Ended December 31, 2016 2015 Revenues $ 5,351,700 $ 6,964,000 Production costs (3,541,700 ) (4,317,800 ) Depletion (1,898,700 ) (2,361,600 ) Impairment (212,400 ) (6,320,500 ) $ (301,100 ) $ (6,035,900 ) Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2016 and 2015 adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations: Years Ended December 31, 2016 2015 (1) Future cash inflows $ 50,652,900 $ 79,780,100 Future production costs (25,552,100 ) (30,111,800 ) Future net cash flows 25,100,800 49,668,300 Less 10% annual discount for estimated timing of cash flows (11,957,400 ) (25,726,900 ) Standardized measure of discounted future net cash flows $ 13,143,400 $ 23,941,400 (1) We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas equivalent reserves due to anticipated future changes in gas commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. |
Summary of Significant Accoun19
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Summary Of Significant Accounting Policies [Line Items] | |
Liquidity, Capital Resources and Ability to Continue as a Going Concern | Liquidity, Capital Resources and Ability to Continue as a Going Concern The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations had been adequate to fund its obligations and distributions to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position The uncertainties of Titan’s and the MGP’s liquidity and capital resources (as further described below) raise substantial doubt about Titan’s and the MGP’s ability to continue as a going concern, which also raises substantial doubt about the Partnership’s ability to continue as a going concern. If Titan is unsuccessful in taking actions to resolve its liquidity issues (as further described below), the MGP’s ability to continue the Partnership’s operations may be further impacted and may make it uneconomical for the Partnership to produce its wells until they are depleted as originally intended. If the Partnership is not able to continue as a going concern, the Partnership will liquidate. If the Partnership’s operations are liquidated, a valuation of the Partnership’s assets and liabilities would be determined by an independent expert in accordance with the partnership agreement. It is possible that based on such determination, the Partnership would not be able to make any liquidation distributions to its limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners. The 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. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of the Partnership’s assets and liabilities and the reported amounts of income and expenses could be required and could be material. |
Use of Estimates | Use of Estimates The preparation of the Partnership’s 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 the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. 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 were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates. |
Receivables | Receivables Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2016 and 2015, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets. Asset retirement receivable – affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnership’s wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnership’s wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells. The following is a reconciliation of the Partnerships’ asset retirement receivable – affiliate for the years indicated: December 31, 2016 2015 Asset retirement receivable – affiliate, beginning of year $ 40,400 $ 40,400 Asset retirement estimates withheld 69,600 78,900 Plugging and abandonment costs incurred - (78,900 ) Asset retirement receivable –affiliate, end of year $ 110,000 $ 40,400 |
Gas Properties | Gas Properties Gas properties are stated at cost. Maintenance and repairs that 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 that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. The Partnership follows the successful efforts method of accounting for gas producing activities. The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, 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 cost of developed producing properties. The Partnership also considers the estimated salvage value in the calculation of depletion. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value (see Note 4). The review of the Partnership’s gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The determination of natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. |
Derivative Instruments | Derivative Instruments The Partnership’s MGP entered into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings. |
Asset Retirement Obligations | Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its gas wells and related facilities (See Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. |
Income Taxes | Income Taxes The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements. The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2016 and 2015. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2016. |
Environmental Matters | Environmental Matters The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2016 and 2015. |
Concentration of Credit Risk | Concentration of Credit Risk The Partnership sells natural gas under contracts to various purchasers in the normal course of business. For the year ended December 31, 2016, the Partnership had two customers that individually accounted for approximately 73% and 22% of the Partnership’s natural gas revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, the Partnership had two customers that individually accounted for approximately 53% and 43%, of the Partnership’s natural gas combined revenues, excluding the impact of all financial derivative activity. |
Revenue Recognition | Revenue Recognition The Partnership generally sells natural gas at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at December 31, 2016 and 2015 of $858,800 and $750,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. |
Loss on Abandonment of Well | Loss on Abandonment of Well During the year ended December 31, 2015, the Partnership plugged and abandoned the remaining Michigan well. The remaining net asset value recorded in the Partnership’s gas properties prior to plugging and abandonment was $300. This net asset value was written off as part of the net loss on abandonment of well in the Partnership’s statement of operations for the year ended December 31, 2015 and also removed from gas properties on the Partnership’s balance sheet. Plugging and abandonment costs incurred through December 31, 2015 total $557,800, of which $269,600 had been previously recorded as an asset retirement obligation, resulting in a net loss on abandonment of well of $288,200. |
Comprehensive Income (Loss) | Comprehensive Income (Loss) Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2016, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). |
Recently Issued Accounting Standards | In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of December 15, 2016 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our financial statements. This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation. |
MGP | |
Summary Of Significant Accounting Policies [Line Items] | |
Liquidity, Capital Resources and Ability to Continue as a Going Concern | MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under Titan’s credit facilities. The MGP’s primary cash requirements are operating expenses, payments to Titan for debt service including interest, and capital expenditures. The MGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under Titan’s credit facilities and equity and debt offerings. The MGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities. Titan was not in compliance with certain of the financial covenants under its credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. Titan and the MGP do not currently have sufficient liquidity to repay all of Titan’s outstanding indebtedness, and as a result, there is substantial doubt regarding Titan’s and the MGP’s ability to continue as a going concern. Titan expects to finalize an amendment to its first lien credit facility on April 19, 2017 in an attempt to ameliorate some of its liquidity concerns, subject to receiving the remaining lenders’ consent. The amendment is expected to provide for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility. Unless Titan is able to obtain an amendment or waiver, the lenders under Titan’s second lien credit facility may declare a default with respect to Titan’s failure to comply with financial covenants and deliver audited financial statements without a going concern qualification. However, pursuant to the intercreditor agreement, the lenders under Titan’s second lien credit facility are restricted in their ability to pursue remedies for 180 days from any such notice of default. As of the date hereof, the lenders under Titan’s second lient credit facility have not yet given notice of any default. Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for Titan’s stakeholders. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility. |
Summary of Significant Accoun20
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Reconciliation of the Partnerships Asset Retirement Receivable | The following is a reconciliation of the Partnerships’ asset retirement receivable – affiliate for the years indicated: December 31, 2016 2015 Asset retirement receivable – affiliate, beginning of year $ 40,400 $ 40,400 Asset retirement estimates withheld 69,600 78,900 Plugging and abandonment costs incurred - (78,900 ) Asset retirement receivable –affiliate, end of year $ 110,000 $ 40,400 |
Participation in Revenues and21
Participation in Revenues and Costs (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Schedule of Participation in Revenues and Costs, Allocation | The MGP and the limited partners generally participated in revenues and costs in the following manner: Managing Limited Organization and offering cost 100% 0% Lease costs 100% 0% Intangible drilling costs 8% 92% Tangible equipment costs 52% 48% Revenues (1) 37% 63% Operating costs, administrative costs, direct and all other costs (2) 37% 63% (1) Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues. (2) These costs will be charged to the partners in the same ratio as the related production revenues are credited. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property Plant And Equipment [Abstract] | |
Summary of Natural Gas Properties | The following is a summary of natural gas properties at the dates indicated: December 31, 2016 2015 Proved properties: Leasehold interests $ 5,301,300 $ 5,301,300 Wells and related equipment 159,420,100 159,436,400 Total natural gas and oil properties 164,721,400 164,737,700 Accumulated depletion and impairment (140,226,600 ) (138,115,500 ) Gas and oil properties, net $ 24,494,800 $ 26,622,200 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows: Years Ended December 31, 2016 2015 Beginning of year $ 3,793,000 $ 3,846,300 Accretion expense 169,700 216,300 Settlements (6,000 ) (269,600 ) End of year $ 3,956,700 $ 3,793,000 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges | The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Years Ended 2016 2015 Gain (loss) reclassified from accumulated other comprehensive income into natural gas revenues $ 3,800 $ (35,400 ) Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ 2,800 $ 654,500 |
Fair Value of Financial Instr25
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Information for assets and liabilities measured at fair value was as follows: Level 1 Level 2 Level 3 Total As of December 31, 2016 Derivative assets, gross Commodity swaps $ - $ - $ - $ - Commodity puts - - - - Total derivative assets, gross $ - $ - $ - $ - As of December 31, 2015 Derivative assets, gross Commodity swaps $ - $ 447,200 $ - $ 447,200 Commodity puts - 352,300 - 352,300 Total derivative assets, gross $ - $ 799,500 $ - $ 799,500 |
Certain Relationships and Rel26
Certain Relationships and Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Certain Relationships and Related Party Transactions | The following table provides information with respect to these costs and the periods incurred. Years Ended 2016 2015 Administrative fees $ 66,000 $ 72,800 Supervision fees 705,300 838,800 Transportation fees 539,300 721,900 Direct costs 2,363,100 2,822,100 Total $ 3,673,700 $ 4,455,600 |
Supplemental Gas Information 27
Supplemental Gas Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
Changes in Proved Reserve Quantities | Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited): Gas (Mcf) Balance, December 31, 2014 49,648,700 Revisions (1) (936,600 ) Production (3,618,100 ) Balance, December 31, 2015 (2 ) 45,094,000 Revisions (3 ) (8,313,100 ) Production (2,969,300 ) Balance, December 31, 2016 33,811,600 (1) The downward revision in natural gas forecasts is primarily due to a decrease in SEC base pricing from the prior year, resulting in shorter economic life. (2) We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 and 2016 due to the significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the years ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas equivalent reserves due to anticipated future changes in gas commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. (3) The downward revision in natural gas forecasts is primarily due to forecast adjustments in order to reflect actual production. |
Capitalized Costs Relating to Gas Producing Activities | Capitalized Costs Related to Gas Producing Activities. The components of capitalized costs related to gas producing activities of the Partnership during the periods indicated were as follows: Years Ended December 31, 2016 2015 Natural gas properties: Leasehold interest $ 5,301,300 $ 5,301,300 Wells and related equipment 159,420,100 159,436,400 Accumulated depletion, accretion and impairment (140,226,600 ) (138,115,500 ) Net capitalized costs $ 24,494,800 $ 26,622,200 |
Results of Operations from Gas Producing Activities | Results of Operations from Gas Producing Activities. The results of operations r elated to the Partnership’s gas producing activities during the periods indicated were as follows: Years Ended December 31, 2016 2015 Revenues $ 5,351,700 $ 6,964,000 Production costs (3,541,700 ) (4,317,800 ) Depletion (1,898,700 ) (2,361,600 ) Impairment (212,400 ) (6,320,500 ) $ (301,100 ) $ (6,035,900 ) |
Standardized Measure of Discounted Future Cash Flows | Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2016 and 2015 adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations: Years Ended December 31, 2016 2015 (1) Future cash inflows $ 50,652,900 $ 79,780,100 Future production costs (25,552,100 ) (30,111,800 ) Future net cash flows 25,100,800 49,668,300 Less 10% annual discount for estimated timing of cash flows (11,957,400 ) (25,726,900 ) Standardized measure of discounted future net cash flows $ 13,143,400 $ 23,941,400 (1) We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas equivalent reserves due to anticipated future changes in gas commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. |
Basis of Presentation (Details)
Basis of Presentation (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Jun. 30, 2016 | |
Basis Of Presentation [Line Items] | ||
Atlas Resources Series 28-2010 L.P. | Apr. 1, 2010 | |
MGP | ||
Basis Of Presentation [Line Items] | ||
Funds transferred to partners | $ 380,900 | |
Atlas Energy Group, LLC | Titan Energy, LLC | Preferred Member Interest | ||
Basis Of Presentation [Line Items] | ||
Percentage of preferred interest | 2.00% |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | |
Dec. 31, 2016USD ($)Customer | Dec. 31, 2015USD ($)Customer | |
Summary Of Significant Accounting Policies [Line Items] | ||
Allowance for Uncollectible Accounts Receivable | $ 0 | $ 0 |
Federal or state deferred income tax | 0 | |
Income tax, penalties and interest expense | $ 0 | $ 0 |
Number of major customers | Customer | 2 | 2 |
Unbilled Revenues | $ 858,800 | $ 750,000 |
Net asset value | 300 | |
Plugging and abandonment costs | 557,800 | |
Asset Retirement Obligation | 269,600 | |
Loss on abandonment of well | $ 288,200 | |
Customer Concentration Risk | Customer 1 | Sales Revenues | ||
Summary Of Significant Accounting Policies [Line Items] | ||
Concentration Risk, Percentage | 73.00% | 53.00% |
Customer Concentration Risk | Customer 2 | Sales Revenues | ||
Summary Of Significant Accounting Policies [Line Items] | ||
Concentration Risk, Percentage | 22.00% | 43.00% |
Summary of Significant Accoun30
Summary of Significant Accounting Policies (Reconciliation of the Partnerships Asset Retirement Receivable) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Receivable Disclosure [Abstract] | ||
Asset retirement receivable – affiliate, beginning of year | $ 40,400 | $ 40,400 |
Asset retirement estimates withheld | 69,600 | 78,900 |
Plugging and abandonment costs incurred | (78,900) | |
Asset retirement receivable –affiliate, end of year | $ 110,000 | $ 40,400 |
Participation in Revenues and31
Participation in Revenues and Costs (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Managing General Partner | ||
Capital Unit [Line Items] | ||
Additional partnership revenues to receive, Percentage | 10.00% | |
Working interest adjustment | $ (5,600) | |
Limited Partners | ||
Capital Unit [Line Items] | ||
Working interest adjustment | $ 0 | $ 5,600 |
Participation in Revenues and32
Participation in Revenues and Costs (Schedule of Participation in Revenues and Costs, Allocation) (Details) | 12 Months Ended | |
Dec. 31, 2016 | ||
Managing General Partner | ||
Capital Unit [Line Items] | ||
Additional partnership revenues to receive, Percentage | 10.00% | |
Organization and Offering Cost | Managing General Partner | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 100.00% | |
Organization and Offering Cost | Limited Partners | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 0.00% | |
Lease Costs | Managing General Partner | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 100.00% | |
Lease Costs | Limited Partners | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 0.00% | |
Intangible Drilling Costs | Managing General Partner | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 8.00% | |
Intangible Drilling Costs | Limited Partners | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 92.00% | |
Tangible Equipment Costs | Managing General Partner | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 52.00% | |
Tangible Equipment Costs | Limited Partners | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 48.00% | |
Revenues | Managing General Partner | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 37.00% | [1] |
Revenues | Limited Partners | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 63.00% | [1] |
Operating Costs, Administrative Costs, Direct and All Other Costs | Managing General Partner | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 37.00% | [2] |
Operating Costs, Administrative Costs, Direct and All Other Costs | Limited Partners | ||
Capital Unit [Line Items] | ||
Participation In Revenues And Costs, Percentage | 63.00% | [2] |
[1] | Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues. | |
[2] | These costs will be charged to the partners in the same ratio as the related production revenues are credited. |
Property, Plant and Equipment33
Property, Plant and Equipment (Summary of Natural Gas Properties) (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Property Plant And Equipment [Line Items] | ||
Total natural gas and oil properties | $ 164,721,400 | $ 164,737,700 |
Accumulated depletion and impairment | (140,226,600) | (138,115,500) |
Gas and oil properties, net | 24,494,800 | 26,622,200 |
Leasehold interests | ||
Property Plant And Equipment [Line Items] | ||
Total natural gas and oil properties | 5,301,300 | 5,301,300 |
Wells and related equipment | ||
Property Plant And Equipment [Line Items] | ||
Total natural gas and oil properties | $ 159,420,100 | $ 159,436,400 |
Property, Plant and Equipment34
Property, Plant and Equipment (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Property Plant And Equipment [Abstract] | ||
Depletion of natural gas properties | $ 1,898,700 | $ 2,361,600 |
Asset impairment | $ 212,400 | $ 6,420,500 |
Asset Retirement Obligations (N
Asset Retirement Obligations (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Net production revenue for future plugging and abandonment costs | $ 110,000 | $ 40,400 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward] | ||
Beginning of year | $ 3,793,000 | $ 3,846,300 |
Accretion expense | 169,700 | 216,300 |
Settlements | (6,000) | (269,600) |
End of year | $ 3,956,700 | $ 3,793,000 |
Derivative Instruments (Narrati
Derivative Instruments (Narrative) (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Net derivative assets | $ 0 | $ 799,500 |
Current portion of put premiums payable-affiliate | $ 0 | $ 162,700 |
Derivative Instruments (Summary
Derivative Instruments (Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||
Gain (loss) reclassified from accumulated other comprehensive income into natural gas revenues | $ 3,800 | $ (35,400) |
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives | $ 2,800 | $ 654,500 |
Fair Value of Financial Instr39
Fair Value of Financial Instruments (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) | Dec. 31, 2015USD ($) |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Fair Value Asset | $ 799,500 |
Commodity Swaps | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Fair Value Asset | 447,200 |
Commodity Puts | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Fair Value Asset | 352,300 |
Fair Value, Inputs, Level 2 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Fair Value Asset | 799,500 |
Fair Value, Inputs, Level 2 | Commodity Swaps | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Fair Value Asset | 447,200 |
Fair Value, Inputs, Level 2 | Commodity Puts | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Fair Value Asset | $ 352,300 |
Fair Value of Financial Instr40
Fair Value of Financial Instruments (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Impairment | $ 212,400 | $ 6,320,500 |
Fair Value, Inputs, Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Impairment | $ 212,400 | $ 6,420,500 |
Certain Relationships and Rel41
Certain Relationships and Related Party Transactions (Narrative) (Details) | 12 Months Ended | |
Dec. 31, 2016USD ($)$ / mo | Dec. 31, 2015USD ($) | |
Related Party Transaction [Line Items] | ||
Managing General Partner Maximum Subordination Percentage Of Share Of Net Production Revenues | 50.00% | |
MGP | ||
Related Party Transaction [Line Items] | ||
Subordination | $ | $ 126,600 | $ 731,200 |
MGP | First 12 Month Subordination Period | ||
Related Party Transaction [Line Items] | ||
Subordination Target Return Rate For Limited Partner Subscriptions | 12.00% | |
MGP | Next Three 12 Month Subordination Periods | ||
Related Party Transaction [Line Items] | ||
Subordination Target Return Rate For Limited Partner Subscriptions | 10.00% | |
MGP | Fifth 12 Month Subordination Period | ||
Related Party Transaction [Line Items] | ||
Subordination Target Return Rate For Limited Partner Subscriptions | 8.00% | |
MGP and Affiliates | General and administrative expenses | ||
Related Party Transaction [Line Items] | ||
Monthly Administrative Costs Per Well | 75 | |
MGP and Affiliates | Production | ||
Related Party Transaction [Line Items] | ||
Transportation Fee Rate As Percentage Of Natural Gas Sales Price | 16.00% | |
MGP and Affiliates | Production | Marcellus wells | ||
Related Party Transaction [Line Items] | ||
Monthly Supervision Fees Per Well | 975 | |
MGP and Affiliates | Production | New Albany Wells | ||
Related Party Transaction [Line Items] | ||
Monthly Supervision Fees Per Well | 1,500 | |
MGP and Affiliates | Production | Antrim Shale Wells | ||
Related Party Transaction [Line Items] | ||
Monthly Supervision Fees Per Well | 600 | |
MGP and Affiliates | Production | Colorado Wells | ||
Related Party Transaction [Line Items] | ||
Monthly Supervision Fees Per Well | 400 |
Certain Relationships and Rel42
Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | ||
Related Party Transaction, Expenses from Transactions with Related Party | $ 3,673,700 | $ 4,455,600 |
Administrative fees | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Expenses from Transactions with Related Party | 66,000 | 72,800 |
Supervision fees | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Expenses from Transactions with Related Party | 705,300 | 838,800 |
Transportation fees | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Expenses from Transactions with Related Party | 539,300 | 721,900 |
Direct costs | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Expenses from Transactions with Related Party | $ 2,363,100 | $ 2,822,100 |
Commitments and Contingencies (
Commitments and Contingencies (Narrative) (Details) | 12 Months Ended | |
Dec. 31, 2016USD ($)$ / mo | Dec. 31, 2015USD ($) | |
Commitments And Contingencies Disclosure [Abstract] | ||
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage | 5.00% | |
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly | $ / mo | 200 | |
Net production revenue for future plugging and abandonment costs | $ | $ 110,000 | $ 40,400 |
Supplemental Gas Information 44
Supplemental Gas Information (Unaudited) (Changes in Proved Reserve Quantities) (Details) - Gas (Mcf) - Mcf | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | |||
Reserve Quantities [Line Items] | ||||
Balance | 45,094,000 | [1] | 49,648,700 | |
Revisions | (8,313,100) | [2] | (936,600) | [3] |
Production | (2,969,300) | (3,618,100) | ||
Balance | 33,811,600 | 45,094,000 | [1] | |
[1] | We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 and 2016 due to the significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the years ended December 31, 2016 and 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas equivalent reserves due to anticipated future changes in gas commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. | |||
[2] | The downward revision in natural gas forecasts is primarily due to forecast adjustments in order to reflect actual production | |||
[3] | The downward revision in natural gas forecasts is primarily due to a decrease in SEC base pricing from the prior year, resulting in shorter economic life. |
Supplemental Gas Information 45
Supplemental Gas Information (Unaudited) (Capitalized Costs Relating to Gas Producing Activities) (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Natural Gas Producing Activities [Abstract] | ||
Natural gas properties: Leasehold interest | $ 5,301,300 | $ 5,301,300 |
Natural gas properties: Wells and related equipment | 159,420,100 | 159,436,400 |
Accumulated depletion, accretion and impairment | (140,226,600) | (138,115,500) |
Net capitalized costs | $ 24,494,800 | $ 26,622,200 |
Supplemental Gas Information 46
Supplemental Gas Information (Unaudited) (Results of Operations from Gas Producing Activities) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Natural Gas Producing Activities [Abstract] | ||
Revenues | $ 5,351,700 | $ 6,964,000 |
Production costs | (3,541,700) | (4,317,800) |
Depletion | (1,898,700) | (2,361,600) |
Impairment | (212,400) | (6,320,500) |
Total Results of Operations from Gas Producing Activities | $ (301,100) | $ (6,035,900) |
Supplemental Gas Information 47
Supplemental Gas Information (Unaudited) (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Natural Gas Producing Activities [Abstract] | |
Present value of discount factor | 10.00% |
Supplemental Gas Information 48
Supplemental Gas Information (Unaudited) (Standardized Measure of Discounted Future Cash Flows) (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | [1] |
Natural Gas Producing Activities [Abstract] | |||
Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Future Cash Inflows | $ 50,652,900 | $ 79,780,100 | |
Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Future Production Costs | (25,552,100) | (30,111,800) | |
Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Future Net Cash Flows, Total | 25,100,800 | 49,668,300 | |
Discounted Future Net Cash Flows Relating to Proved Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows | (11,957,400) | (25,726,900) | |
Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Standardized Measure, Total | $ 13,143,400 | $ 23,941,400 | |
[1] | We experienced significant downward revisions of our natural gas reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas equivalent reserves due to anticipated future changes in gas commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. |