SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1996
INDEX

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

Liabilities and Stockholders' Equity

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(1) $.01 Par Value
(2) Unaudited


See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996 (UNAUDITED) AND DECEMBER 31, 1995

(1) GENERAL INFORMATION

 

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company (the "Company") and are unaudited, except for the balance sheet at December 31, 1995 which has been prepared from the audited financial statements at that date. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of management, necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in the latest Form 10-K and Annual Report.

Certain reclassifications have been made to the prior year balances to conform to current year presentation.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

 

For financial reporting purposes, 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 cost 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.

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 have been capitalized and through June 30, 1996 were being amortized over the life of the Debentures. Due to the conversion of all outstanding Debentures into Common Stock in August 1996, as discussed below, related unamortized costs ($1,097,551) were transferred to the Company's appropriate capital accounts in the third quarter of 1996.

All of the amounts under deferred charges and other at September 30, 1996 relate to the Company’s Employee Stock Ownership Plan ("ESOP"), effective as of January 1, 1996. All employees over the age of 21 with one year of service are participants. The Plan has a five year cliff vesting and service is recognized after the Plan effective date. The ESOP is designed to enable employees of the Company to accumulate stock ownership. While there will be no employee contributions, participants will receive an allocation of stock which has been contributed by the Company. The Plan may also acquire Swift Energy Company Common Stock purchased at fair market value. The ESOP can borrow money from the Company to buy Company stock as was done in September 1996 to purchase 25,000 shares from the Company’s Chairman. Benefits will be paid in a lump sum or installments, and the participant generally has the choice of receiving cash or stock.

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 a portion of this risk, the Company engages periodically in certain limited hedging activities, but only to the extent of buying put options as price floors for portions of its and the limited partnerships' oil and gas production. 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 period presented.

Deferred Revenues

 

In May 1992, the Company purchased interests in certain wells from the Manville Corporation for $13.8 million using funds provided by the Company's sale of a volumetric production payment in these properties to a subsidiary of Enron Corp. 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 specified periods through October 2000. Since entering into this agreement, the Company has met all scheduled deliveries. Volumes remaining to be delivered under the volumetric production payment (approximately 3.3 Bcf at September 30, 1996) are not included in the Company's proved reserves. Net proceeds from the sale of the production payment were recorded as deferred revenues. Deliveries under the production payment are recorded as oil and gas sales revenues and a corresponding reduction of deferred revenues. Hydrocarbons produced in excess of the amount required to be delivered are sold by the Company for its own account.

Limited Partnerships and Joint Ventures

 

Between 1991 and 1995, 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. 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 Company’s Consolidated Financial Statements. 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 is owed to the Company, and are not material for any of the periods presented in relation to the partnerships' respective assets.

Under the Swift Depository 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 oil and gas properties account.

Commencing September 15, 1993, the Company began offering, on a private placement basis, general and limited partnership interests in limited partnerships 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 September 30, 1996, approximately $34,800,000 had been raised in seven partnerships, one formed in each of 1993 and 1994, three in 1995, and two in 1996. In July and September 1996, the Company closed the sixth and seventh partnerships with total subscriptions of approximately $4,900,000 and $10,000,000, respectively. Costs of syndication, registration, 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.

Income Taxes

 

The Company accounts for income taxes using the 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.

Income taxes for the interim periods have been provided using the estimated annualized effective tax rate.

Income Per Share

 

Primary income 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 per share. The Company's Debentures were not Common Stock equivalents for the purpose of computing primary income per share.

The calculation of fully diluted income per share assumed conversion of the Company's Debentures as of the beginning of the period and the elimination of the related after-tax interest expense and assumed, as of the beginning of the period, exercise (using the treasury stock method) of stock options and warrants. The weighted average number of shares used in the computation of fully diluted per share amounts were 13,647,445 and 14,754,719 for the respective nine-month and three-month periods ended September 30, 1996. Due to the August 1996 conversion of these Debentures into 2.34 million shares of Common Stock, as described below, the effect of such conversion is included in primary income per share for the third quarter of 1996 and for future periods.

(3) BANK BORROWINGS

 

The Company has available through a two bank-group, a revolving line of credit. Effective April 30, 1996, this credit agreement was restated. The facility was increased to $100,000,000 and is now unsecured. The available borrowing base currently is $30,000,000, and will be redetermined periodically. Depending on the level of outstanding debt, the interest rate currently will be either the bank's base rate or the bank's base rate plus 0.25% (8.25% at September 30, 1996). This facility also allows, at the Company's option, draws which bear interest for specific periods at the London Interbank Offered Rate ("LIBOR"). The LIBOR option will now vary from plus 1% to plus 1.5%. There was no outstanding balance under this line of credit at December 31, 1995. At September 30, 1996, $17,000,000 was outstanding under this line, all bearing interest under the LIBOR rate option at rates ranging from 6.562% to 6.8125%. The outstanding amount under this facility at September 30, 1996 was borrowed primarily to fund the Company's working capital needs and capital expenditures. The restated revolving line of credit extends through September 30, 1999, and accordingly is classified on the balance sheet as a long-term liability.

The terms of the revolving line of credit include, among other restrictions, a limitation on the level of cash dividends (not to exceed $2,000,000 in any fiscal year), requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios) and limitations on incurring other debt. Since inception, no cash dividends have been declared on the Company's Common Stock. The Company presently intends to continue a policy of using retained earnings for expansion of its business. As of September 30, 1996 and December 31, 1995, the Company was in compliance with the provisions of these agreements.

The Company's other credit facility, which is the Company's only secured facility, is an amended and restated revolving line of credit with the lead bank of the two bank-group, secured by certain Company receivables. This facility, effective April 30, 1996, was amended to $7,000,000 (from $5,000,000), with interest at the bank's base rate less 0.25% (8% at September 30, 1996). At September 30, 1996, $170,000 was outstanding under this facility. There was no outstanding amount on this facility at December 31, 1995. This restated credit facility extends through September 30, 1999, and is also recorded as a long-term liability.

In addition to interest on these credit facilities, the Company pays a commitment fee to compensate the banks for making funds available. The fee on the revolving line of credit is calculated on the average daily remainder, if any, of the commitment amount less the aggregate principal amounts outstanding plus the amount of all outstanding letters of credit during the period. The aggregate amounts of commitment fees paid by the Company were $140,000 for the first nine months of 1996 and $154,000 for the twelve-month period in 1995.

(4) LONG-TERM DEBT

 

The Company's long-term debt previously consisted of $28,750,000 of 6.5% Convertible Subordinated Debentures due 2003. The Debentures were issued on June 30, 1993 under terms making them convertible into Common Stock of the Company by the holders at any time prior to maturity at an adjusted conversion price of $12.27 per share. Interest on the Debentures was payable semiannually on June 30 and December 31, commencing with the payment made at December 31, 1993. The Debentures become redeemable for cash at the option of the Company after June 30, 1996 at 104.55% of principal.

On July 1, 1996, the Company called all of the Debentures for redemption on August 5, 1996 at 104.55% of their face amount, plus accrued interest since June 30, 1996. The Debentures continued to be convertible into shares of Common Stock at $12.27 per share through August 5, 1996. Prior to the redemption date, the holders of all of the outstanding Debentures elected to convert their Debentures into shares of Common Stock, resulting in the issuance of 2.34 million shares of Common Stock in August 1996.

Upon conversion of the Debentures into Common Stock, the approximate $27,650,000 net carrying amount of the debt (the face amount less unamortized deferred charges) was transferred to the Company's appropriate capital accounts during the third quarter of 1996.

Interest expense on the Debentures, including amortization of debt issuance costs, totaled $993,890 for the six-month period ending June 30, 1996, the last interest payment date prior to conversion, and $1,981,639 for the twelve-month period ending December 31, 1995.

(5) STOCKHOLDERS' EQUITY

 

During the third quarter of 1995, the Company closed the sale to the public of 5,750,000 shares of Common Stock at a price of $8.50 per share. Net proceeds from this offering were $45,698,912 and were used to repay outstanding indebtedness, with the remaining proceeds being used to finance the Company's exploration and development activities, and to acquire producing oil and gas properties, including limited partnership interests.

In August 1996, the holders of the Company's Debentures converted such Debentures into 2.34 million shares of the Company's Common Stock, which resulted in a third quarter 1996 increase in the Company's capital accounts of approximately $27,650,000.

(6) FOREIGN ACTIVITIES

Russia

 

On September 3, 1993, the Company signed a Participation Agreement with Senega, a Russian Federation joint stock company (in which the Company has an indirect interest of less than 1%), to assist in the development and production of reserves from two fields in Western Siberia, providing the Company with a minimum 5% net profits interest from the sale of hydrocarbon products from the fields for providing managerial, technical, and financial support to Senega. Additionally, the Company purchased a 1% net profits interest from Senega for $300,000. In May 1995, the Company executed a Management Agreement with Senega, under which, in return for undertaking to obtain financing for development of these fields, Swift is entitled to receive a 49% interest in production income derived by Senega from this project after repayment of costs.

On July 12, 1996, the Company entered into a partnership agreement which provides for the Company to contribute its rights under the Participation and Management Agreement to the partnership and for the partners to share equally revenues and costs of developing the Samburg Field and funding and management of the license areas, all in conjunction with Senega. The partnership is to be funded by the partners upon fulfillment of certain conditions and completion of certain further arrangements with Senega. It is currently anticipated that these activities would be funded principally through project financing. At September 30, 1996, the Company's investment in Russia was approximately $9,220,000, and is included in the unproved properties portion of oil and gas properties.

Venezuela

 

The Company formed a wholly-owned subsidiary, Swift Energy de Venezuela, C.A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan Marginal Oil Field Reactivation Program. Although, the Company did not win the bids, it is continuing to pursue cooperative ventures involving other fields and opportunities in Venezuela. At September 30, 1996, the Company's investment in Venezuela was approximately $1,390,000 and is included in the unproved properties portion of oil and gas properties net of impairments of $45,668.

New Zealand

 

Since October 1995, the Company has been issued two Petroleum Exploration Permits by the New Zealand Minister of Energy. The first permit covers approximately 65,000 acres in the Onshore Taranaki Basin region in the Southwestern area of New Zealand’s North Island, and the second covers approximately 71,500 adjacent acres. Under the terms of the permits, the Company is obligated to analyze and interpret certain seismic data, acquire certain new seismic data, drill one exploratory well, followed by a further development well or perform additional seismic work, all of which is to be performed on a staged basis in order to maintain the permits, over periods extending through July 2000 in the case of the first permit, and July 2001 for the second permit. At September 30, 1996, the Company's investment in New Zealand was approximately $565,000 and is included in the unproved properties portion of oil and gas properties.

(7) SUBSEQUENT EVENT

 

On October 24, 1996, the Company filed with the Securities and Exchange Commission a registration statement for a public offering of $100,000,000 of Convertible Subordinated Notes due 2006. Proceeds of the offering will be used to repay all of the Company’s outstanding indebtedness, to finance development and exploration drilling activities, and to acquire oil and gas properties or used for other general corporate purposes.

SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the Company's Condensed Consolidated Financial Statements and Notes thereto.

GENERAL

 

The Company was formed in 1979, and from 1985 to 1991 grew primarily through the acquisition of producing properties funded through limited partnership financing. Commencing in 1991, the Company began to reemphasize the addition of reserves through increased exploration and development drilling activity while significantly reducing its reliance on limited partnership financing. This emphasis on exploration and development drilling has led to additions of increasing quantities of reserves in each of 1994, 1995, and the first nine months of 1996.

The statements contained in this Quarterly Report on Form 10-Q ("Quarterly Report") that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, and therefore involve a number of risks and uncertainties. The actual results of the future events described in such forward-looking statements in this Quarterly Report including those regarding the Company's financial results, levels of oil and gas production or revenue, capital expenditures, and capital resource activities could differ materially from those estimated. Among the factors that could cause actual results to differ materially are: general economic conditions, competition and government regulations, and fluctuations in oil and natural gas prices, as well as the risks and uncertainties set forth from time to time in the Company's other public reports, filings, and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year.

LIQUIDITY AND CAPITAL RESOURCES

 

In 1991, the Company’s strategy shifted toward increased reliance on exploration and development drilling activities, and the Company has significantly expanded reserves added through these efforts. Previously, the Company relied on limited partnership capital as its principal financing vehicle to fund its acquisitions of producing properties. As a result of this shift in strategy, the Company has reduced its reliance on cash flows generated from, and capital raised through, limited partnerships. Supplemental cash and working capital are provided through internally generated cash flows and debt and equity financing.

During the first half of 1995, the Company used a combination of bank financing, internally generated cash flows and partnership financing to fund its operations. In the third quarter of 1995, the Company realized $45,698,912 in net proceeds from an offering of Common Stock that provided sufficient capital to repay its bank financing and finance its capital expenditures for the second half of 1995. During the first nine months of 1996, the Company relied upon internally generated cash flows and bank borrowings to fund its capital expenditures. Described below are the major elements of the Company’s liquidity and capital resources:

Net Cash Provided by Operating Activities

 

For the nine month period ended September 30, 1996, net cash provided by operating activities increased significantly (208%) to $26,351,331, as compared to $8,547,184 during the first nine months of 1995. The 1996 increase of $17,804,147 was primarily due to an increase in cash flows from oil and gas sales, which increased $18,614,320 (134%), exclusive of the noncash amortization of deferred revenues associated with the Company's volumetric production payment. This increase in oil and gas sales was primarily the result of the Company's recent increase in drilling activity as described below.

1995 Stock Offering

 

During the third quarter of 1995, the Company sold 5,750,000 shares of Common Stock in a public offering at $8.50 per share, with net proceeds of $45,698,912. Net proceeds from the offering were used to repay outstanding indebtedness, and the remainder of the proceeds have been used to finance the Company's exploration and development activities, and to acquire producing oil and gas properties, including limited partnership interests.

Other Financing Activities

 

Convertible Subordinated Debentures. On June 30, 1993, the Company issued 6.5% Convertible Subordinated Debentures due 2003 in the amount of $28,750,000 in a public offering. Proceeds of the offering were used primarily to acquire producing oil and gas properties and to finance the Company's expanding exploration and development programs. As described in Note 4 to the Company's Condensed Consolidated Financial Statements included herein, in August 1996 the Debentures were converted by their holders into 2.34 million shares of the Company's Common Stock following the Company's July 1996 announcement that the Debentures would be redeemed in August 1996, unless earlier converted. As a result of this conversion, the Company’s stockholders’ equity increased approximately $27,650,000.

Partnership Programs. Between 1991 and 1995, the Company offered interests in oil and gas production partnerships under its Swift Depository Interests ("SDI") offering, and since late 1993 has offered private partnerships formed to drill for oil and gas. The SDI program concluded at the end of 1995. Four SDI partnerships were formed during 1995, with total subscriptions of approximately $12,400,000. During 1995, the Company closed three drilling partnerships with a total of $15,900,000 of subscriptions. In the first nine months of 1996 two drilling partnerships were formed, both in the third quarter, with total subscriptions of approximately $14,900,000. The Company anticipates that it will continue to offer the drilling partnerships for the foreseeable future.

At September 30, 1996, limited partnership formation and marketing costs (which under the current drilling partnership offerings are borne by the Company as part of the Company's general partner contribution) amounted to $767,682, a decrease of $90,877, when compared with the December 31, 1995 balance. Upon the Company's decision to conclude the SDI offering in December 1995, the remaining limited partnership formation and marketing costs related to the SDI offering (approximately $1,750,000) were transferred to the oil and gas properties account.

Credit Facilities

 

Recently, the Company's credit facilities have been used to fund a portion of the Company's exploration and development activities. Formerly, the Company established credit facilities which were used principally to finance the Company's purchase of producing oil and gas properties on an interim basis pending transfer of the properties to newly formed partnerships and joint ventures, and to provide working capital. These credit facilities consist of a $100,000,000 unsecured revolving line of credit with a $30,000,000 borrowing base, and a $7,000,000 secured revolving line of credit. The principal terms and restrictions of these credit facilities are described in Note 3 to the Company's Condensed Consolidated Financial Statements included herein.

At September 30, 1996, the Company had $17,170,000 outstanding under these borrowing arrangements which was used, along with internally generated cash flows of $26,351,000, principally to fund the Company's capital expenditures in the first nine months of 1996, and to a lesser extent, to provide working capital. The Company will continue to use these facilities until completion of the pending debt offering referenced in Note 7 to the Company’s Condensed Consolidated Financial Statements included herein. At December 31, 1995, the Company had no outstanding balances under these borrowing arrangements, as these borrowings were repaid with proceeds from the Company's 1995 stock offering.

Working Capital

 

The Company's working capital has decreased over the last nine months, from $3,247,185 at December 31, 1995, to a working capital deficit of $5,998,674 at September 30, 1996. This decrease is primarily the result of the Company’s capital expenditures as described below.

Since year end 1995, the Company's receivable account from limited partnerships decreased significantly due to (a) receipt of approximately $7,800,000 generated from property sales proceeds realized by these partnerships, and (b) an increase in oil and gas prices received by these partnerships. Both increased the cash flows of these partnerships, thus allowing them to reduce their balances owed to the Company.

Due to the nature of the Company's business highlighted above, the individual components of working capital fluctuate considerably from period to period. The Company incurs significant working capital requirements in connection with its role as operator of approximately 800 wells, its accelerated drilling program, and the management of affiliated partnerships. In this capacity, the Company is responsible for certain day-to-day cash management, including the collection and disbursement of oil and gas revenues and related expenses.

Capital Expenditures

 

Capital expenditures for property, plant, and equipment during the first nine months of 1996 were $55,996,465. These capital expenditures included: (a) $42,400,000 of drilling costs, both exploratory and developmental, (b) $9,200,000 of prospect costs (principally prospect leasehold, seismic and geological costs of unproved prospects for the Company's account), (c) $3,000,000 invested in foreign business opportunities in Russia (approximately $2,400,000), in Venezuela (approximately $300,000), and in New Zealand (approximately $300,000), as described in Note 6 to the Company's Condensed Consolidated Financial Statements included herein; and (d) $1,400,000 spent for computer equipment and furniture and fixtures. In the remaining three months of 1996, the Company expects capital expenditures to be approximately $25,000,000, including investments in all areas in which investments were made during the first nine months of the year as described above, with a particular focus on exploratory and development drilling. The Company currently plans to participate in the drilling of 162 gross wells this year, compared to 76 wells in 1995. Through September 30, 1996, the Company had participated in drilling 102 wells (6 exploratory and 96 development wells with 4 exploratory successes and 92 development successes). The steady growth in the Company's unproved property account which is not being amortized is indicative of the shift to a focus on drilling activity, as the Company acquires prospect acreage. During the first nine months of 1996, this account also reflects $3,000,000 of capital expenditures made in relation to the Company's foreign business opportunities, as described above.

The anticipated net proceeds in the fourth quarter from the sale of $100,000,000 of the Convertible Subordinated Notes due 2006, as described in Note 7 to the Company’s Condensed Consolidated Financial Statements included herein, after repayment of the Company’s outstanding indebtedness, will be added to working capital to fund the Company’s development and exploration drilling projects and possibly to acquire oil and gas properties, or used for other general corporate purposes. The Company believes the proceeds of such offering and anticipated internally generated cash flows (expected to increase as the Company’s production base increases as a result of its accelerated drilling program), will be sufficient to finance the costs associated with its currently budgeted capital expenditures of over $134.0 million for the remaining three months of 1996 and for 1997. Further liquidity needs may also be met by its existing credit facilities.

RESULTS OF OPERATIONS – Comparison of Nine Months Ended September 30, 1996 and 1995

 

Net income of $11,402,650 and earnings per share of $0.87 for the first nine months of 1996 were 352% and 172% higher, respectively, than net income of $2,520,431, and earnings per share of $0.32 in the same period for 1995. This increase in net income primarily reflected the effect of a 122% increase in oil and gas sales revenues as a result of a 98% increase in natural gas production, a 17% increase in crude oil production, and product price improvements. The lower percentage increase in earnings per share reflects a 64% increase in weighted average shares outstanding for the period, as a result of the sale of 5.75 million shares of Common Stock in the third quarter of 1995, and the conversion of the Debentures into 2.34 million shares of Common Stock in the third quarter of 1996.

Revenues

 

The Company’s revenues increased 97% during the first nine months of 1996 from the comparative period in 1995, due primarily to the increase in oil and gas sales. Oil and gas sales increased 122% to $33,733,101 in the first three quarters of 1996, compared to $15,208,354 for the comparative period in 1995. The 98% increase in natural gas production and the 17% increase in oil production were primarily the result of production from recent drilling activity, most notably from the Company's two primary development areas, the AWP Olmos Field and the Austin Chalk trend. The Company's net sales volume (including the volumetric production payment) in the first nine months of 1996 increased by 73% or 5,742,712 Mcfe (thousand cubic feet equivalent) over volumes in the comparable 1995 period. Oil and gas sales were also aided by 21% and 40% increases in average prices received for oil and gas, respectively, between the two periods, as highlighted in the table below.

Revenues from oil and gas sales comprised 86% and 77%, respectively, of total revenues for the first nine months of 1996 and 1995. The majority (74%) of these revenues were derived from the sale of the Company's gas production. The Company expects oil and gas sales to continue to increase as a direct consequence of the addition of oil and gas reserves through the Company's active drilling program.

The following table provides additional information regarding the Company's oil and gas sales.

Supervision fees increased 15%, having grown from $2,838,170 in the first nine months of 1995 to $3,277,111 in the first nine months of 1996. This increase is primarily due to the annual escalation in April for well overhead rates, and the increase in drilling activity by the Company, which in turn increases the drilling well overhead portion of such fees.

Costs and Expenses

 

General and administrative expenses for the first three quarters of 1996 increased approximately $630,000 or 16% when compared to the same period in 1995. However, the Company's general and administrative expenses per Mcfe produced decreased by 33% from $0.51 per Mcfe produced for the first nine months of 1995 to $0.34 per Mcfe produced for the comparable period in 1996. The majority of the companies in the oil and gas industry treat supervision fees as a reduction of their general and administrative expenses. If the Company were to follow this practice, these expenses net of supervision fees would have decreased from $0.14 per Mcfe produced for the first nine months of 1995 to $0.10 per Mcfe produced for the same period in 1996.

Depreciation, depletion, and amortization ("DD&A") increased 84% (approximately $5,200,000) for the first nine months of 1996, primarily due to the Company's reserve additions and associated costs, and the related sale of increased quantities of oil and gas therefrom. The Company's DD&A rate per Mcfe of production has increased from $0.78 per Mcfe produced in the 1995 period to $0.83 per Mcfe produced in the 1996 period, reflecting variations in the per unit cost of reserve additions.

The Company's production costs per Mcfe decreased from $0.65 per Mcfe produced in the 1995 period to $0.42 per Mcfe produced in the 1996 period. However, due to the increase in production volumes, oil and gas production costs increased 13% (approximately $648,000) in the first nine months of 1996 when compared to the first nine months of 1995. As discussed above, the Company's increase in production is primarily through its drilling activities in the AWP Olmos Field and Austin Chalk trend, where the Company already has an established operating base. The increase in production costs is partially offset by an exemption in these same fields from the 7.5% Texas severance tax applicable to gas production from certain natural gas wells certified to be in tight formations or to be deep wells by the Texas Railroad Commission. Additionally, commencing September 1, 1996, certain wells certified as "high cost gas" wells will be entitled to a reduction of severance tax based upon a formula amount. Therefore, the increase in drilling activity and production has not been accompanied by a proportionate increase in operating costs. This tax exemption has had a positive impact on the Company’s production costs during 1995 and 1996, although under the new rules, the proportionate amount of the exemption may be reduced in future periods.

Interest expense in the first nine months of 1996 on the Debentures, including amortization of debt issuance costs, totaled $993,890 ($1,485,730 in the 1995 period), while interest expense on the credit facilities, including commitment fees, totaled $789,909 ($1,617,924 in the 1995 period) for a total interest expense of $1,783,799 (of which $1,489,892 was capitalized). In the first nine months of 1995 these costs totaled $3,103,654 (of which $1,820,169 was capitalized). The Company capitalizes that portion of interest related to its exploration, partnership, and foreign business development activities. The decrease in interest expense in 1996 is attributable to (1) the decrease in the average balance under the Company's credit lines necessary to finance the Company's capital expenditures, as discussed above, and (2) the Company incurring only six months of interest in 1996, instead of nine months of interest in 1995, on the Debentures which were converted into Common Stock in the third quarter of 1996.

RESULTS OF OPERATIONS – Comparison of Three Months Ended September 30, 1996 and 1995

 

Net income of $4,641,953 and earnings per share of $0.33 in the third quarter of 1996 increased 267% and 175%, respectively, when compared to net income of $1,264,556 and earnings per share of $0.12 in the same period for 1995. The increase in net income was primarily due to the 142% increase in oil and gas sales revenues as a result of a 105% increase in natural gas production, a 9% increase in crude oil production, and product price improvements. The lower percent increase in earnings per share reflects a 35% increase in the weighted average shares outstanding for the period, for the same reasons discussed above.

Revenues

 

The Company’s revenues increased 119% during the third quarter of 1996 from the comparative period in 1995, due primarily to the increase in oil and gas sales. Oil and gas sales increased 142% to $13,226,521 in the third quarter of 1996, compared to $5,465,881 for the comparative period in 1995. The 105% increase in natural gas production and the 9% increase in oil production were primarily the result of production from recent drilling activity, most notably from the Company's two primary development areas, the AWP Olmos Field and the Austin Chalk trend. The Company's net sales volume (including the volumetric production payment) in the third quarter of 1996 increased by 77% or 2,204,308 Mcfe over volumes in the comparable 1995 period. Oil and gas sales were also aided by 37% and 45% increases in average prices received for oil and gas, respectively, between the two periods as highlighted in the table above.

Supervision fees increased 18% in the third quarter of 1996 when compared to the same period in 1995. This increase is primarily due to the annual escalation in April for well overhead rates, and the increase in drilling activity by the Company, which in turn, increases the drilling well overhead portion of such fees.

Costs and Expenses

 

General and administrative expenses for the third quarter of 1996 increased $531,261 or 44% when compared to the same period in 1995, primarily the result of the strategic shift in the Company’s activity toward more direct corporate participation in projects which do not result in reimbursement from other parties. However, on a Mcfe basis, the Company's general and administrative expenses decreased from $0.43 per Mcfe produced for the third quarter of 1995 to $0.35 per Mcfe produced for the same period in 1996.

Depreciation, depletion, and amortization increased 107% (approximately $2,300,000), primarily due to the reserve additions and their associated costs, and the related sale of increased quantities of oil and gas. The DD&A rate per Mcfe of production has increased from $0.75 per Mcfe produced in the 1995 period to $0.87 per Mcfe produced in the 1996 period, reflecting variations in the per unit cost of reserve additions.

The Company's production costs per Mcfe decreased from $0.62 per Mcfe produced in the 1995 period to $0.41 per Mcfe produced in the 1996 period. However, due to the increase in production volumes, oil and gas production costs increased 18% (approximately $325,000) in the third quarter of 1996 when compared to the third quarter of 1995. As described above, this reflects the Company's economies of scale in the AWP Olmos Field and the Austin Chalk trend, and the gas production severance tax abatement these fields receive.

There was no interest expense for the third quarter of 1996 on the Debentures as they were converted into Common Stock in the third quarter ($495,910 in 1995), while interest expense on the credit facilities, including commitment fees, totaled $312,510 ($308,640 in 1995) for a total of $312,510 (all of which was capitalized). The third quarter 1995 total was $804,550 (of which $611,389 was capitalized).

SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION

Item 1.	Legal Proceedings - N/A
Item 2.	Changes in Securities - N/A
Item 3.	Defaults Upon Senior Securities - N/A
Item 4.	Submission of Matters to a Vote of Security Holders - N/A
Item 5.	Other Information - N/A
Item 6.	Exhibits & Reports on Form 8K - None

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SWIFT ENERGY COMPANY
	(Registrant)
Date: October 30, 1996	By: (Original Signed By) John R. Alden Sr. Vice President - Finance Chief Financial Officer, Secretary
Date: October 30, 1996	By: (Original Signed By) Alton D. Heckaman, Jr. Vice President, Controller and Principal Accounting Officer

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