Estimates of Proved Oil and Gas Reserves
The estimates of the Partnership’s proved reserves at December 31, 2013, 2012, and 2011 have been prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by independent petroleum engineers.
Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.
Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing net income. A decline in estimated proved reserves and future cash flows also reduces the capitalized cost ceiling and may result in increased impairment expense.
Risks and Uncertainties
Historically, the oil and gas market has experienced significant price fluctuations. Prices are impacted by local weather, supply in the area, availability and price of competitive fuels, seasonal variations in local demand, limited transportation capacity to other regions, and the worldwide supply and demand for crude oil.
The Partnership has not engaged in commodity futures trading or hedging activities and has not entered into derivative financial instrument transactions for trading or other speculative purposes. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.
Restoration, Removal, and Environmental Liabilities
The Partnership is subject to extensive Federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or reliably determinable.
The Partnership has recognized an estimated liability for future plugging and abandonment costs. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled or acquired. Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.
The Partnership estimates a liability for plugging and abandonment costs based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
The following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2013 and 2012.
|
|
|
2013 |
|
2012 |
| ||
|
Beginning asset retirement obligation |
|
$ |
2,366,899 |
|
$ |
1,835,115 |
|
|
Additions related to new properties |
|
2,683 |
|
7,579 |
| ||
|
Revisions related to existing properties |
|
— |
|
438,610 |
| ||
|
Retirement related to property sales |
|
(5,859 |
) |
(1,605 |
) | ||
|
Retirement related to property abandonment and restoration |
|
(55,893 |
) |
(32,388 |
) | ||
|
Accretion expense |
|
155,345 |
|
119,588 |
| ||
|
Ending asset retirement obligation |
|
$ |
2,463,175 |
|
$ |
2,366,899 |
|
Cash and Cash Equivalents
The Partnership considers all highly liquid investments with maturity dates of no more than three months from the purchase date to be cash equivalents. Cash and cash equivalents consist of demand deposits and money market investments invested with a major national bank, which at times may exceed federally insured limits. The Partnership has not experienced any losses in such accounts, and does not expect any loss from this exposure. The carrying value of the Partnership’s cash equivalents approximates fair value.
Comprehensive Income
Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.
Fair Value of Financial Instruments
The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at December 31, 2013 and 2012, as it is subject to short-term floating interest rates that approximate the rates available to the Partnership for those periods, and is classified as Level 2 within the fair value hierarchy.
Income Taxes
The Partnership’s net income or loss flows directly through to its partners, who are responsible for the payment of Federal taxes on their respective share of any income or loss. Therefore, there is no provision for federal income taxes in the accompanying financial statements.
As of December 31, 2013, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $20.1 million, primarily due to the difference between property impairment costs deducted for financial reporting purposes and intangible drilling costs deducted for income tax purposes.
Accounting for Uncertainty in Income Taxes
The Financial Accounting Standards Board (“FASB”) provides guidance on accounting for uncertainty in income taxes. This guidance is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.
Under this guidance, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.
Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.
Based on the Partnership’s assessment, there are no material uncertain tax positions as of December 31, 2013 and 2012. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, 2013 and 2012. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.
Oil and Gas Properties
The Partnership follows the full cost method of accounting for its oil and gas activities. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to barrels of oil equivalent (“BOE”) at a rate of 6 Mcf to 1 Bbl. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.
In applying the full cost method, the Partnership is required to perform a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the sum of the estimated future net revenues from proved reserves using prices that are the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment expense of proved properties.
Unproved property consists of undrilled infill and offset acreage acquired in connection with the purchase of the Azalea Properties. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date. The assessment includes consideration of the following factors, among others: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property; and geological and geophysical evaluation. To the extent that the assessment indicates a property is impaired, the amount of impairment is added to the capitalized costs of oil and gas properties which are subject to the quarterly ceiling test. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment of unproved properties.
The Partnership excludes from amortization the cost of unproved properties. The Partnership expects that all unproved property costs incurred will be transferred to proved property cost within 10 years of their acquisition. The following schedule shows, by the year in which they were incurred, the amount of all unproved property cost not currently being amortized as of December 31, 2013.
|
|
|
Total |
|
2010 |
| ||
|
Acquisition costs — unproved property |
|
$ |
389,672 |
|
$ |
389,672 |
|
|
|
|
|
|
|
| ||
|
Total costs withheld from amortization |
|
$ |
389,672 |
|
$ |
389,672 |
|
Recognition of Revenue
The Partnership has entered into sales contracts for disposition of its share of crude oil and natural gas production from productive wells. Revenue is recognized based upon the Partnership’s share of metered volumes delivered to its purchasers each month. The Partnership had no material gas imbalances at December 31, 2013, 2012, and 2011.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the amounts reported in the financial statements and accompanying notes. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates and assumptions under different conditions. The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved crude oil and natural gas reserves, the use of these crude oil and natural gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations, and estimates of future abandonment obligations used in recording asset retirement obligations.