GROWTH THROUGH TECHNOLOGY
AND TEAMWORK

                                           1996 ANNUAL REPORT

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

 

Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company (Swift) and its wholly owned subsidiaries (collectively referred to as the "Company"), which are engaged in the acquisition, development, operation, and exploration of oil and natural gas properties, with particular emphasis on U.S. onshore natural gas reserves. The Company also has oil and gas investments in Russia, Venezuela, and New Zealand. The Company’s investments in associated oil and gas partnerships and its joint ventures are accounted for using the proportionate consolidation method, whereby the Company’s proportionate share of each entity’s assets, liabilities, revenues, and expenses is included in the appropriate classifications in the consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the consolidated statements. Certain reclassifications have been made to prior year amounts to conform to the current year presentation.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Property and Equipment. The Company follows the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Such costs include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. General and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions that involve a significant amount of reserves. The proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. Fees from associated oil and gas exploration and development limited partnerships are credited to oil and gas property costs to the extent they do not represent reimbursement of general and administrative expenses currently charged to expense.

Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as the Company’s capitalized oil and gas property costs are amortized. The Company’s properties are all onshore and historically the salvage value of the tangible equipment offsets the Company’s site restoration and dismantlement and abandonment costs. The Company expects this relationship will continue.

The Company computes the provision for depreciation, depletion, and amortization of oil and gas properties on the unit-of-production method. Under this method, the Company computes the provision by multiplying the total unamortized costs of oil and gas properties--including future development, site restoration, and dismantlement and abandonment costs but excluding costs of unproved properties--by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. The cost of unproved properties not being amortized is assessed quarterly to determine whether the value has been impaired below the capitalized cost. Any impairment assessed is added to the cost of proved properties being amortized.

At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Limitation").

The calculation of the Ceiling Limitation and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered.

All other equipment is depreciated by the straight-line method at rates based on the estimated useful lives of the property. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

Deferred Charges and Other. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the issuance of the Company’s 6.5% Convertible Subordinated Debentures due 2003 (the "Debentures") in June 1993 were capitalized and through June 1996 were being amortized over the life of the Debentures. Due to the conversion of all outstanding Debentures into common stock in August 1996, the related unamortized costs ($1,097,551) were transferred to the Company’s appropriate capital accounts in the third quarter of 1996. The issuance costs associated with the Company’s 6.25% Convertible Subordinated Notes (the "Notes") sold in a public offering in November 1996 have been capitalized and are being amortized over the life of the Notes, which mature on November 15, 2006. The balance of these issuance costs at December 31, 1996 ($4,511,481) is net of accumulated amortization of $38,519.

Limited Partnerships and Joint Ventures. Between 1991 and 1995 (and for prior periods), the Company formed limited partnerships and joint ventures for the purpose of acquiring interests in producing oil and gas properties and, since 1993, partnerships engaged in drilling for oil and gas reserves. The Company serves as managing general partner or manager of these entities. Because the Company serves as the general partner of these entities, under state partnership law it is contingently liable for the liabilities of these partnerships, virtually all of which are owed to the Company and are not material for any of the periods presented in relation to the partnerships’ respective assets.

Under the Swift Depositary Interests limited partnership offering ("SDI Offering"), which commenced in March 1991 and concluded in December 1995, the Company received a reimbursement of certain costs and a fee, both payable out of revenues. The Company bore all front-end costs of the offering and partnership formations for which it received an interest in the partnerships. Upon the Company’s decision to conclude the SDI offering at the end of 1995, the remaining limited partnership formation and marketing costs related to the SDI offering (approximately $1,750,000) were accordingly transferred to the Company’s oil and gas properties account.

The Company acquires producing oil and gas properties and transfers those properties to the entities at cost, including interest, other carrying costs, closing costs, and screening and evaluation costs of properties not acquired, or in certain instances at fair market value based upon the opinion of an independent expert. These costs are reduced by net operating revenues from the effective date of the acquisition to the date of transfer to the entities. Such net operating revenue amounts totaled approximately $300,000, $600,000, and $4,100,000 in 1996, 1995, and 1994, respectively.

Commencing September 15, 1993, the Company began offering, on a private placement basis, general and limited partnership interests in limited partnerships to be formed to drill for oil and gas. As managing general partner, the Company pays for all front-end costs incurred in connection with these offerings, for which the Company receives an interest in the partnerships. Through December 31, 1996, approximately $41.9 million had been raised in eight partnerships, one formed in each of 1993 and 1994, and three in each of 1995 and 1996. In July, September, and November 1996, the Company closed the sixth, seventh, and eighth partnerships with total subscriptions of approximately $4.9 million, $10.0 million, and $7.1 million, respectively. Costs of syndication and qualification of these limited partnerships incurred by the Company have been deferred. Under the current private limited partnership offerings, selling and formation costs borne by the Company serve as the Company’s general partner contribution to such partnerships.

During 1996, the limited partners in 18 partnerships, which had been in operation over nine years and have produced a substantial majority of their reserves, voted to sell their remaining properties and liquidate the limited partnerships. In 1996, 10 of the earliest public income partnerships were liquidated, and in early 1997 eight private drilling partnerships will be liquidated. The Company intends to make similar proposals to other partnerships for an orderly sale of their properties and liquidation of the partnerships over the next several years. The Company may offer to acquire certain portions of the remaining property interests owned by these limited partnerships.

Hedging Activities. The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and adversely affect operating results. To mitigate some of this risk, the Company does engage periodically in certain limited hedging activities, but only to the extent of buying protection price floors for portions of its and the limited partnerships’ oil and gas production (see Form 10-K Excerpts--"Price Risk Management"). Costs and/or benefits derived from these price floors are accordingly recorded as a reduction or increase in oil and gas sales revenue and were not significant for any year presented. The costs to purchase put options are amortized over the option period. The costs related to the open contracts totaled approximately $127,000 and had a market value of $68,400 as of December 31, 1996.

Income (Loss) Per Share. Primary income (loss) per share has been computed using the weighted average number of common shares outstanding during the respective periods. Stock options and warrants outstanding do not have a dilutive effect on primary income (loss) per share. The Company’s Debentures were not and the Notes are not common stock equivalents for the purpose of computing primary income (loss) per share.

Primary income (loss) per share has been retroactively restated in all periods presented to give recognition to an equivalent change in capital structure as a result of a 10% stock dividend in September 1994, resulting in an additional 606,262 shares being issued.

The calculation of fully diluted income (loss) per share assumes conversion of the Company’s Notes as of the issuance date and Debentures as of the beginning of the period and the elimination of the related after-tax interest expense and assumes, as of the beginning of the period, exercise (using the treasury stock method) of stock options and warrants. For the periods presented in which the Debentures were outstanding, the conversion price of the Debentures was revised to reflect the 10% stock dividend declared in September 1994. The original conversion price was $13.50 per common share and the revised conversion price per common share was $12.27. Fully diluted income (loss) per share has also been retroactively restated for all periods presented to give effect to the resulting conversion price revision stemming from the 10% stock dividend. The weighted average number of shares used in the computation of fully diluted per share amounts was 14,512,242, 11,671,243, and 9,053,736 for the respective years ended December 31, 1996, 1995, and 1994.

Income Taxes. The Company accounts for Income Taxes using Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." SFAS No. 109 utilizes the liability method and deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax bases of assets and liabilities given the provisions of the enacted tax laws.

Deferred Revenues. In May 1992, as discussed in Note 9, "Oil and Gas Producing Activities," the Company purchased interests in certain wells using funds provided by the Company’s sale of a volumetric production payment in these properties. Under the terms of the production payment agreement, the Company continues to own the properties purchased but is required to deliver a minimum quantity of hydrocarbons produced from the properties (meeting certain quality and heating equivalent requirements) over a specified period. Since entering into this agreement, the Company has met all scheduled deliveries. Net proceeds from the sale of the production payment were recorded as deferred revenues. Deliveries under the production payment agreement are recorded as oil and gas sales revenues and a corresponding reduction of deferred revenues.

Cash and Cash Equivalents. The Company considers all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents.

Credit Risk Due to Certain Concentrations. The Company extends credit to various companies in the oil and gas industry which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions and may accordingly impact the Company’s overall credit risk. However, the Company believes that the risk is mitigated by the size, reputation, and nature of the companies to which the Company extends credit.

During the year ended December 31, 1996, three oil or gas purchasers each accounted for 10% or more of the Company’s revenues, with those purchasers together accounting for 51%. Only one oil or gas purchaser accounted for 10% or more of the Company’s revenues during the year ended December 31, 1995, with that purchaser accounting for approximately 12%. Because of the availability of other purchasers, the Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair value of long-term debt was determined based upon interest rates currently available to the Company for borrowings with similar terms. The fair value of long-term debt approximates the carrying amount as of December 31, 1996.

Go to...

This page was last updated on Saturday, February 08, 2003 , at 07:28:43 PM .

Copyright © 1994-2008 by Swift Energy Company.
Click here to go to our home page or search page.
Please note the terms of use for the Swift Energy web site.
If you have comments or questions, see our feedback or requests pages.
Contact Swift Energy Company Stockholder Relations through e-mail info@swiftenergy.com or telephone (281) 874-2700.