-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, HXURgHk18dU/EnL0BtrWBdnp0tv4y0ZDZbc6i1kdticKBWgOimMJLMUSMJpIDh9U lgTB8lcoRdd5Fs66PCpIRg== 0000950129-95-000815.txt : 19950728 0000950129-95-000815.hdr.sgml : 19950728 ACCESSION NUMBER: 0000950129-95-000815 CONFORMED SUBMISSION TYPE: 424B1 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19950727 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: SWIFT ENERGY CO CENTRAL INDEX KEY: 0000351817 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 742073055 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B1 SEC ACT: 1933 Act SEC FILE NUMBER: 033-60469 FILM NUMBER: 95556282 BUSINESS ADDRESS: STREET 1: 16825 NORTHCHASE DR STE 400 CITY: HOUSTON STATE: TX ZIP: 77060 BUSINESS PHONE: 7138742700 MAIL ADDRESS: STREET 1: 16825 NORTHCHASE DRIVE STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77060 424B1 1 FORM 424B1 1 5,000,000 SHARES (LOGO) SWIFT ENERGY COMPANY COMMON STOCK ------------------------------ All of the shares of Common Stock offered hereby are being sold by Swift Energy Company ("Swift" or the "Company"). The Company's Common Stock is listed on the New York Stock Exchange and the Pacific Stock Exchange under the symbol "SFY." On July 25, 1995, the last reported sale price of the Company's Common Stock on the New York Stock Exchange was $8.625 per share. See "Price Range of Common Stock and Dividend Policy." THE COMMON STOCK OFFERED HEREBY INVOLVES A HIGH DEGREE OF RISK. SEE "RISK FACTORS" ON PAGE 7. ------------------------------ THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
- ------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------- PRICE TO UNDERWRITING PROCEEDS TO PUBLIC DISCOUNT(1) COMPANY(2) - ------------------------------------------------------------------------------------------------- Per Share......................... $8.50 $0.48 $8.02 Total(3).......................... $42,500,000 $2,400,000 $40,100,000 - ------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------
(1) See "Underwriting" for information concerning indemnification of the Underwriters and other information. (2) Before deducting expenses of the offering payable by the Company estimated at $500,000. (3) The Company has granted the Underwriters an option, exercisable within 30 days of the date hereof, to purchase up to 750,000 additional shares of Common Stock for the purpose of covering over-allotments, if any. If the Underwriters exercise such option in full, the total Price to Public, Underwriting Discount and Proceeds to Company will be $48,875,000, $2,760,000 and $46,115,000, respectively. See "Underwriting." ------------------------------ The shares of Common Stock are offered severally by the Underwriters when, as and if delivered to and accepted by them, subject to their right to withdraw, cancel or reject orders in whole or in part and subject to certain other conditions. It is expected that delivery of the certificates representing the shares will be made against payment on or about July 31, 1995 at the offices of Oppenheimer & Co., Inc., Oppenheimer Tower, World Financial Center, New York, New York 10281. ------------------------------ OPPENHEIMER & CO., INC. MORGAN KEEGAN & COMPANY, INC. SOUTHCOAST CAPITAL CORPORATION The date of this Prospectus is July 26, 1995. 2 AVAILABLE INFORMATION The Company has filed with the Securities and Exchange Commission (the "SEC") a Registration Statement on Form S-2 (of which this Prospectus is a part) under the Securities Act of 1933, as amended, with respect to the securities offered hereby. This Prospectus does not contain all the information set forth in the Registration Statement or the exhibits thereto, to which reference is made concerning the contents of such exhibits. Reference to each such exhibit qualifies all information related thereto. The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and accordingly files reports, proxy statements and other information ("Reports") with the SEC. The Registration Statement, the exhibits thereto, and the Reports, can be inspected and copied at the public reference facilities maintained by the SEC at 450 5th Street, N.W., Room 1024, Washington, D.C. 20549, and at the following regional offices of the SEC: 7 World Trade Center, 13th Floor, New York, New York 10048 and Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661, at prescribed rates. Reports concerning the Company can also be inspected at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005 and the Pacific Stock Exchange Incorporated, 115 Sansome Street, 8th Floor, San Francisco, California 94104. IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, THE PACIFIC STOCK EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. DEFINED TERMS The following defined terms have the indicated meanings when used in this Prospectus: "BCF " means billion cubic feet of natural gas. "BCFE" means billion cubic feet equivalent. See "-- Mcfe." "BBL" means barrel or barrels of oil. "MBBL" means thousand barrels of oil. "MMBBL" means million barrels of oil. "MMBTU" means a million British Thermal Units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale. "MCF " means thousand cubic feet of natural gas. "MCFE" means thousand cubic feet equivalent which is determined using the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas. "MMCF " means million cubic feet of natural gas. "MMCFE" means million cubic feet equivalent. See "-- Mcfe." "PV-10 VALUE" means the estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense or depreciation, depletion and amortization. See "Risk Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues." "RESERVE REPLACEMENT COST" means, with respect to proved reserves, a three-year average calculated by dividing total acquisition, exploration and development costs by net reserves added during the period. "VOLUMETRIC PRODUCTION PAYMENT" means the 1992 agreement pursuant to which the Company financed the purchase of certain oil and gas interests and committed to deliver certain monthly quantities of natural gas. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General." 2 3 PROSPECTUS SUMMARY This summary is qualified in its entirety by the detailed information and financial data appearing elsewhere in this Prospectus. In September 1994, the Company distributed a 10% stock dividend. Primary and fully diluted income (loss) per share has been restated for all periods set forth in this Prospectus to reflect the effect of the stock dividend. Investors should carefully consider the information set forth under "Risk Factors." Unless otherwise indicated, the information contained in this Prospectus assumes that the Underwriters' over- allotment option will not be exercised. The Company's principal executive offices are located at 16825 Northchase Drive, Suite 400, Houston, Texas 77060, and its telephone number is (713) 874-2700. Defined terms used herein to describe quantities of oil and gas and other matters are explained under "Defined Terms" above. THE COMPANY The Company is engaged in the exploration, development, acquisition and operation of oil and gas properties with a primary focus on U.S. onshore natural gas reserves. The Company has interests in approximately 4,100 oil and gas wells located in 15 states, with over 80% of its proved reserve base concentrated in Texas, Oklahoma and Louisiana. The Company was formed in 1979 and, since 1985, has grown primarily through the acquisition of producing properties funded through limited partnership financing. Commencing in 1991, the Company began to re-emphasize the addition of reserves through increased exploration and development drilling activity while significantly reducing its reliance on limited partnership financing. In 1994, the Company added approximately 24.8 Bcfe of proved reserves through exploration and development drilling, at a cost of $0.51 per Mcfe, representing approximately 250% of 1994 production. The Company's proved reserve base, production and cash flow from operations have increased at annualized compounded rates of 35%, 38% and 30%, respectively, over the last five years. At May 31, 1995, the Company had estimated proved reserves of 133.3 Bcf of natural gas and 5.4 MMBbls of oil (totalling approximately 165.8 Bcfe) with a PV-10 Value of approximately $100.2 million. The proved reserves at May 31, 1995 represent an increase of 60% over estimated amounts at December 31, 1994. Approximately 80% of the Company's proved reserve base at that date was natural gas. The Company's reserve replacement cost over the last three years has averaged $0.79 per Mcfe, which it believes is better than industry averages. At December 31, 1994, the Company operated 750 wells which represented 61% of its proved reserve base, and managed reserves on behalf of limited partnerships which, exclusive of the Company's interests, had proved reserves of approximately 200 Bcfe. Five oil and gas fields accounted for 54% of the Company's PV-10 Value at December 31, 1994, of which the two largest were the AWP Olmos Field and the Giddings Field. The AWP Olmos Field, located in McMullen County, Texas, and the Giddings Field located in Fayette County, Texas, accounted for 25% and 12%, respectively, of the Company's PV-10 Value as of such date. The Company believes that the Giddings Field's prolific but short-lived wells complement the long-lived reserves of the AWP Olmos Field. The application of advanced technologies and achievement of operating efficiencies have enabled the Company to reduce costs and enhance reserve recoveries in these fields. BUSINESS STRATEGY The Company intends to continue to increase its reserves, cash flow and underlying net asset value through a balanced strategy that includes an expanded exploration and development drilling program, strategic acquisitions and the application of advanced technologies. Key elements of the Company's strategy include the following: - Increased exploration and development drilling activities. The Company believes that its existing properties, including its substantial inventory of undeveloped acreage, provide significant future exploration and development potential. In 1994, the Company achieved success rates of 43% for exploratory wells and 87% for development wells, which it believes exceed industry averages. The Company anticipates expenditures of approximately $70.0 million on currently planned drilling activities during 1995 and 1996 (of which approximately $3.8 million was spent in the first quarter of 1995). Through December 31, 1996, the Company currently anticipates expenditures of approximately 3 4 $55.0 million on development drilling activities, including approximately $30.0 million in the AWP Olmos and Giddings fields in Texas. The Company pursues a "controlled risk" approach to exploration, focusing its exploration activities in regions where it possesses technological or geological expertise and which are adjacent to known producing horizons. The Company also is pursuing opportunities in Russia and Venezuela. Swift currently anticipates expenditures of approximately $15.0 million on exploratory drilling through 1996 in the Yegua, Frio, Lobo, Wilcox and Austin Chalk trends in the Gulf Coast Basin, the Smackover trend in the North Louisiana Salt Dome Basin, the Red Fork formation in the Anadarko Basin in Oklahoma and the Minnelusa trend in Wyoming. - Strategic acquisitions. Through December 31, 1994, the Company had acquired approximately $460.0 million of producing oil and natural gas properties on behalf of itself and its co-investors in 120 separate transactions. Approximately $108.0 million of this amount, representing approximately 139.7 Bcfe, was acquired for the Company's own account, including 12.9 Bcfe purchased in 1994. The Company is continuously reviewing acquisition opportunities, with a particular emphasis on identifying properties in close proximity to the Company's current reserves, where such reserves can be increased through development drilling and improved operating efficiencies can be achieved. Using these criteria, the Company employs a disciplined, market-driven approach to acquisitions that can result in varying levels of annual spending on acquisitions. Through 1996, the Company anticipates spending approximately $25.0 million for the acquisition of producing property interests, including the purchase of interests from limited partnerships. - Application of advanced technologies. To minimize the risks associated with exploration and development drilling and improve operating results, the Company has devoted considerable resources to develop advanced technological expertise. These technologies include 2-D and 3-D seismic analysis, AVO (amplitude versus offset) studies and detailed formation depletion studies. The Company has attained substantial expertise in horizontal well technology, having participated in 17 such wells in the past two years with a 100% success rate. Additionally, the use of innovative fracturing methods and coiled tubing technology in the AWP Olmos Field has enabled the Company to achieve improved production yields. THE OFFERING Common Stock Offered by the Company.......... 5,000,000 shares. Common Stock Outstanding after the Offering(1)................................ 11,718,742 shares. Use of Proceeds(2)........................... Net proceeds of this offering will be used to repay outstanding indebtedness under the Company's credit facilities, and will be added to working capital to be available for exploration and development activities, acquisitions and general corporate purposes. New York Stock Exchange and Pacific Stock Exchange Symbol............................ SFY.
- --------------- (1) Calculated as of May 31, 1995, and includes 8,330 shares issued between March 31, 1995 and May 31, 1995 pursuant to stock benefit plans, but excludes (a) 1,324,288 shares issuable upon exercise of employee and director stock options outstanding as of May 31, 1995, (b) 68,750 shares issuable upon the exercise of stock options outstanding as of May 31, 1995, granted to other individuals, and (c) 2,343,113 shares issuable upon conversion of the outstanding $28.75 million of 6 1/2% Convertible Subordinated Debentures due 2003. See "Management" and the Company's Consolidated Financial Statements and the Notes thereto. (2) See "Use of Proceeds." 4 5 SUMMARY FINANCIAL DATA The following tables, parts of which have been derived from the Company's audited financial statements, set forth selected historical financial information for the Company and should be read in conjunction with the Company's Consolidated Financial Statements and Notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. The financial data for the three-month periods ended March 31, 1995 and 1994 were derived from the unaudited financial statements of the Company that, in management's opinion, include all adjustments (consisting of only normal recurring adjustments, except as disclosed below) necessary to present fairly the results for such periods. The operating results for such periods are not necessarily indicative of the operating results to be expected for a full fiscal year and none of the data presented below are necessarily indicative of future results.
YEARS ENDED THREE MONTHS DECEMBER 31, ENDED MARCH 31, -------------------------------- --------------------- 1992 1993 1994 1994 1995 ------- ------- -------- -------- ------ (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) SELECTED OPERATING DATA: Revenues..................................... $19,209 $24,133 $ 25,375 $ 6,139 $6,259 Costs and expenses: General and administrative (net)........... 4,977 5,065 5,198 1,196 1,307 Depreciation, depletion and amortization... 4,906 7,301 7,905 1,689 2,168 Oil and gas production..................... 3,934 4,540 5,639 1,142 1,629 Interest expense........................... 76 598 1,795 359 478 Other expenses............................. 628 -- -- -- -- ------- ------- ------- -------- ------ Income before income taxes................... 4,688 6,629 4,838 1,753 677 Income before cumulative effect of change in accounting principle....................... 3,170 4,897 3,726 1,211 525 ------- ------- ------- -------- ------ Cumulative effect of change in accounting principle.................................. 915(1) -- (16,773)(2) (16,773)(2) -- ------- ------- ------- -------- ------ Net income (loss)............................ $ 4,085 $ 4,897 $(13,047) $(15,562) $ 525 ======= ======= ======= ======== ====== Per share data: Primary: Income before cumulative effect of change in accounting principle............... $ 0.52 $ 0.74 $ 0.56 $ 0.18 $ 0.08 Cumulative effect of change in accounting principle............................. 0.15 -- (2.52) (2.54) -- ------- ------- ------- -------- ------ Net income (loss)........................ $ 0.67 $ 0.74 $ (1.96) $ (2.36) $ 0.08 ======= ======= ======= ======== ====== Fully diluted: Income before cumulative effect of change in accounting principle............... $ 0.52 $ 0.70 $ 0.56 $ 0.17 $ 0.08 Cumulative effect of change in accounting principle............................. 0.15 -- (2.52) (2.54) -- ------- ------- ------- -------- ------ Net income (loss)........................ $ 0.67 $ 0.70 $ (1.96) $ (2.36) $ 0.08 ======= ======= ======= ======== ====== Weighted average shares outstanding.......... 6,135 6,588 6,644 6,602 6,689 ======= ======= ======= ======== ====== OTHER DATA: Net cash provided by operating activities.... $ 6,349 $ 7,238 $ 10,395 $ 2,680 $2,964 Capital expenditures......................... 34,401 24,229 34,531 4,043 5,745
MARCH 31, 1995 DECEMBER 31, ------------------------- 1994 ACTUAL AS ADJUSTED(3) ------------ -------- -------------- BALANCE SHEET DATA: Working capital..................................................... $(13,137) $(16,729) $ 22,871 Total assets........................................................ 135,673 135,795 144,845 Short-term bank borrowings.......................................... 27,229 30,550 -- Long-term debt...................................................... 28,750 28,750 28,750 Stockholders' equity................................................ 42,127 42,878 82,478
Footnotes on following page 5 6 - --------------- (1) Effective January 1, 1992, the Company elected to adopt SFAS No. 109. The cumulative effect of this change resulted in an increase in net income of $915,000, reflected in the first quarter of 1992. (2) In the fourth quarter of 1994, the Company adopted a new method of accounting for earned interests with respect to the limited partnerships for which it serves as general partner, effective January 1, 1994, whereby earned interests are no longer recognized as income. The effect of the change in 1994 was to increase income before cumulative effect of accounting principle by approximately $1,047,000 or $.16 per share. The cumulative effect of this change in accounting principle resulted in an adjustment of $16,772,698 or $(2.52) per share (after a reduction for income taxes of $8,640,481) in the first quarter of 1994, to apply the new method retroactively, thereby reducing net income in 1994. The Company believes the change in policy results in financial statements that better reflect its current business focus and that are more comparable to current practices in the oil and gas exploration and production business. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General" and Note 2 to the Company's Consolidated Financial Statements. (3) As adjusted to give effect to the sale of 5,000,000 shares of the Common Stock offered hereby at the offering price of $8.50 per share and the application of the net proceeds therefrom as described in "Use of Proceeds." SUMMARY OIL AND GAS RESERVE AND OPERATING DATA The following table sets forth certain summary information as of December 31, 1994 and May 31, 1995, with respect to estimates prepared by the Company, and audited by H.J. Gruy and Associates, Inc., independent petroleum engineers, of the Company's proved oil and gas reserves, the future net revenues therefrom, and their PV-10 Value. Estimates are based upon weighted average prices of $1.85 per Mcf of natural gas and $15.09 per barrel of oil at December 31, 1994, and $2.03 per Mcf of natural gas and $16.68 per barrel of oil at May 31, 1995, at each date holding prices constant throughout the life of the properties in accordance with regulations of the SEC. This information is based upon numerous assumptions and is subject to change due to numerous factors. See "Business and Properties '-- Properties' and '-- Oil and Gas Reserves' " and "Risk Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."
DECEMBER 31, 1994 MAY 31, 1995 ---------------------- ---------------------- PROVED TOTAL PROVED TOTAL DEVELOPED PROVED DEVELOPED PROVED --------- -------- --------- -------- (IN THOUSANDS) ESTIMATED NET PROVED RESERVES(1) Natural gas (MMcf)....................................... 46,406 76,264 45,687 133,336 Oil and condensate (MBbl)................................ 3,209 4,553 3,252 5,407 Total (MMcfe)............................................ 65,663 103,584 65,200 165,779 Future net revenues...................................... $81,650 $119,157 $90,226 $202,530 PV-10 Value.............................................. $47,172 $ 69,395 $51,270 $100,196
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------ --------------------- 1992 1993 1994 1994 1995 ---------- ---------- ---------- --------- --------- PRODUCTION: Oil (Bbl)...................................... 283,928 324,486 467,056 99,992 134,626 Natural gas (Mcf)(2)........................... 3,975,203 5,421,841 6,798,531 1,643,348 1,702,658 Gas equivalents (Mcfe)......................... 5,678,771 7,368,757 9,600,867 2,243,300 2,510,414 WEIGHTED AVERAGE SALES PRICES: Oil (per Bbl).................................. $ 17.19 $ 15.10 $ 14.35 $ 11.80 $ 15.61 Natural gas (per Mcf).......................... 1.90 1.96 1.93 2.21 1.63 SELECTED DATA PER MCFE: Production costs............................... $ 0.69 $ 0.62 $ 0.59 $ 0.51 $ 0.65 Depreciation, depletion and amortization....... 0.86 0.99 0.82 0.75 0.86 General and administrative (net)............... 0.88 0.69 0.54 0.53 0.52 Reserve replacement cost (Mcfe)................ 0.60 0.70 0.79 N/A N/A WELLS DRILLED (GROSS)............................ 40 34 44 12 9 GAS EQUIVALENTS (MCFE) ADDED BY: Acquisitions................................... 44,680,418 26,469,487 12,879,408 N/A N/A Exploration and development.................... 1,365,283 13,502,397 24,803,819 N/A N/A
- --------------- (1) Proved reserves exclude quantities subject to the Volumetric Production Payment. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General." (2) Natural gas production for 1992, 1993, 1994, and the three-month periods ended March 31, 1994 and 1995 includes 1,148,862, 1,581,206, 1,358,375, 386,028 and 316,745 Mcf, respectively, delivered under the Volumetric Production Payment. 6 7 RISK FACTORS In addition to the other information contained in this Prospectus, the following factors should be considered carefully in evaluating an investment in the Common Stock offered hereby. VOLATILITY OF OIL AND GAS PRICES AND MARKETS The Company's profitability is substantially dependent on prevailing prices for natural gas and oil. The amounts of and price obtainable for the Company's oil and gas production will be affected by market factors beyond the Company's control. Such factors include the extent of domestic production, the level of imports of foreign oil and gas, the general level of market demand on a regional, national and worldwide basis, domestic and foreign economic conditions that determine levels of industrial production, political events in foreign oil- producing regions, and variations in governmental regulations and tax laws or the imposition of new governmental requirements upon the oil and gas industry. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. In addition, the marketability of the Company's production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. A substantial and prolonged decline in oil and gas prices could have a material adverse effect upon the Company. The Company currently emphasizes the exploration and development of natural gas reserves. See "Business and Properties -- The Company." As a result of changes in recent years in the natural gas market regulatory structure and volatility in the market price for natural gas, most producers and purchasers are unwilling to enter into long-term purchase and sale contracts. Accordingly, most of the Company's gas production is sold on the so-called "spot market," where producers and purchasers negotiate sales on a short-term (usually a 30-day) basis. Accordingly, the stability of the Company's future revenues is vulnerable to short-term fluctuations in the price of natural gas. See "-- Effect of Price Risk Hedging." FUTURE CAPITAL REQUIREMENTS The Company will require substantial additional capital to further develop and explore its properties and to acquire additional properties. Capital expenditures are currently anticipated to be $100 million through December 31, 1996. Cash flows from operations, to the extent available, will be used to fund these expenditures. The Company intends to seek additional capital from traditional reserve base borrowings, equity and debt offerings, joint ventures, and, to a lesser degree, investment limited partnerships. Furthermore, the Company may seek to raise capital through production payment financing and vendor financing. The Company's ability to access additional capital will depend on its continued success in exploring for and developing its reserves and the status of the capital markets at the time such capital is sought. Accordingly, there can be no assurance that capital will be available to the Company from any source or that, if available, it will be on terms acceptable to the Company. Should sufficient capital not be available, the development and exploration of the Company's properties could be delayed and, accordingly, the implementation of the Company's business strategy would be adversely affected. UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES Estimates of the Company's proved developed oil and gas reserves and future net revenues therefrom appearing elsewhere herein are based on reserve reports audited by independent petroleum engineers. The estimation of reserves requires substantial judgment on the part of the petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Estimates of proved undeveloped reserves, which comprise a substantial portion of the Company's reserves, are by their nature less certain. The accuracy of any reserve estimate depends on the quality of available data as well as engineering and geological interpretation and judgment. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, geologic success, and quantities of recoverable oil and gas resources may vary substantially from those assumed in the estimates, may result in revisions to such estimates and could materially affect the estimated quantities and related PV-10 Value of reserves set forth in this Prospectus. The estimates of future net revenues reflect oil and gas prices as of the date of estimation, without escalation, 7 8 except where changes in prices were fixed under existing contracts. There can be no assurance, however, that such prices will be realized or that the estimated production volumes will be produced during the periods indicated. Future performance that deviates significantly from estimates in the reserve reports could have a material adverse effect on the Company. See "Business and Properties '-- Properties' and '-- Oil and Gas Reserves.' " RISKS OF PURCHASING INTERESTS IN PRODUCING PROPERTIES Although the Company has recently shifted its emphasis to reserve growth through drilling, it expects to continue to make acquisitions of producing properties from time to time. The Company generally focuses most of its title and valuation efforts on the more significant properties. It is generally not feasible for the Company to review in-depth every property it purchases and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit a buyer to become familiar enough with the properties to assess fully their deficiencies and capabilities. Evaluation of future recoverable reserves of oil, gas and natural gas liquids, which is an integral part of the property selection process, is a process that depends upon evaluation of existing geological, engineering and production data, some or all of which may prove to be unreliable or not indicative of future performance. See "-- Uncertainty of Estimates of Reserves and Future Net Revenues." To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and the Company may decide to assume environmental and other liabilities in connection with acquired properties. See "Business and Properties -- Oil and Gas Acreage." EXPLORATION AND DEVELOPMENT RISKS Exploration and development of oil and gas resources involve a high degree of risk that no commercial production will be obtained or that the production will be insufficient to recover drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs. See "Business and Properties -- Exploration and Development Drilling Activities." OPERATING HAZARDS AND UNINSURED RISKS In addition to the substantial risk that wells drilled will not be productive, hazards such as unusual or unexpected geologic formations, pressures, downhole fires, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, pollution and other environmental risks are inherent in oil and gas exploration and production. These hazards could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company carries insurance which it believes is in accordance with customary industry practices, but, as is common in the oil and gas industry, the Company does not fully insure against all risks associated with its business either because such insurance is not available or because the cost thereof is considered prohibitive. REPLACEMENT OF RESERVES The Company's success will be largely dependent on its ability to replace and expand its oil and gas reserves through the acquisition of producing properties and the exploration for and development of oil and gas reserves, both of which involve substantial risks. Without successful acquisition or drilling ventures, the Company will be unable to replace the reserves being depleted by production, and its assets and revenues, including the reserves, will decline. There can be no assurance that the Company's acquisition and exploration and development activities will result in the replacement of, or additions to, the Company's reserves. Successful acquisition of producing properties generally requires accurate assessments of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact, and as estimates their accuracy is inherently uncertain. 8 9 The estimates of future net revenues and their present values assume that some portion of the limited partnerships in which the Company owns interests will achieve payout status. At payout, the Company's percentage ownership of the limited partnerships' reserves increases. None of the limited partnerships in which the Company owns an interest had achieved payout status at May 31, 1995. Achievement of payout status is largely dependent on the market prices of oil and natural gas. See "-- Volatility of Oil and Gas Prices and Markets." EFFECT OF PRICE RISK HEDGING To the extent that price floors or caps are purchased for a portion of the Company's production but are not needed, or to the extent that future sales are made at prices below ultimate future market prices, funds so spent will have been lost or income realized from sale of production may be reduced. Therefore, the Company intends to expend only limited amounts to hedge pricing risks. FOREIGN ACTIVITIES The Company has recently entered into an agreement to develop and produce reserves in two fields in Western Siberia. The Company will receive a minimum 5% net profits interest in return for an initial budgeted capital expenditure of up to $5.0 million. This region has experienced and continues to experience social, political and economic instability. Additionally, Swift is pursuing opportunities in Venezuela. There can be no assurance that future developments in these regions, over which the Company has no control, will not impair the Company's operations in these regions, or result in a loss of all of the Company's investment. EFFECTS OF GOVERNMENTAL REGULATION The Company's operations are affected by extensive regulation pursuant to various federal, state and local laws and regulations relating to the exploration for and development, production, gathering and marketing of oil and gas. Operations of the Company are also subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Although the Company believes that it is in material compliance with all such laws and regulations, there is no assurance that new laws or regulations or new interpretations of existing laws and regulations will not increase substantially the cost of compliance or otherwise adversely affect the Company's exploration for and development, production, gathering and marketing of oil and gas. See "Business and Properties -- Regulations." DEPENDENCE ON KEY PERSONNEL The Company depends, and will continue to depend in the foreseeable future, on the services of A. Earl Swift, its President and Chairman, and certain of its other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and marketing oil and gas production. The ability of the Company to retain its officers and key employees is important to the continued success and growth of the Company. The loss of key personnel could have a material adverse effect on the Company. See "Management." LIABILITY AS GENERAL PARTNER; CONFLICTS OF INTEREST The Company serves as the managing general partner of 95 limited partnerships, which have invested over $440.0 million in oil and gas activities. Although these limited partnerships had less than $2.5 million of indebtedness at March 31, 1995, the Company remains contingently liable for their obligations as general partner, including responsibility for their day-to-day operations, and liabilities which cannot be repaid from partnership assets or insurance proceeds. In the future, the Company might be exposed to litigation in connection with partnership activities, or find it necessary to advance funds on behalf of certain partnerships to protect the value of their oil and gas assets. Conversely, Swift might be prohibited from acquiring certain property interests if to do so would conflict with the interests of limited partnerships which it manages. See "Business and Properties -- Conflicts of Interest Between the Company and Limited Partnerships." 9 10 USE OF PROCEEDS The net proceeds to the Company from the sale of 5,000,000 shares offered hereby will be approximately $39.6 million ($45.6 million assuming exercise of the Underwriters' over-allotment option) after deducting estimated underwriting discounts and expenses of the offering payable by the Company. Approximately $30 million of such net proceeds will be utilized to reduce outstanding indebtedness under the Company's outstanding credit facilities. The remaining net proceeds will be added to working capital to fund some or all of the following: (i) exploration and development projects, (ii) acquisition of oil and gas properties, including the purchase of outstanding limited partnership interests and/or general partner's contributions to the Company's acquisition partnerships (see "Business and Properties -- Partnerships"), and (iii) other general corporate purposes. The Company's current capital expenditure budget through December 31, 1996, anticipates expenditures of approximately $100.0 million (of which approximately $5.7 million has been spent in the first three months of 1995) allocated as follows: approximately $70.0 million for exploration and development drilling projects, approximately $25.0 million for the acquisition of producing properties, including interests from limited partnerships and approximately $5.0 million for equipment and other capital expenditures. The allocation of the Company's net proceeds from this offering, together with other available capital, among these categories of anticipated expenditures is discretionary and will depend upon future events that cannot be predicted, including the actual results and costs of future exploration and development drilling and other activities, the availability and cost of oil and gas properties meeting the Company's acquisition criteria and other matters beyond the control of the Company. The Company is continually evaluating and pursuing potential property acquisitions, however, the Company has no material commitments, contracts, understanding or arrangements at the present time with respect to any particular acquisition. The Company has two credit facilities. The Company has, through a two-bank group, a revolving line of credit of $35.0 million which bears interest at the lead bank's base rate plus 0.5% (9.5% at March 31, 1995) with an option to set interest at the London Interbank Offered Rate ("LIBOR") plus 2.25% (8.49% at March 31, 1995). The outstanding amount under this facility at March 31, 1995 was $24.6 million, $9.6 million of which was bearing interest under the base rate option and the remaining $15.0 million of which was bearing interest under the LIBOR rate option. Such funds were borrowed primarily to finance the Company's working capital and capital expenditures needs and to finance the advance purchase of producing properties on behalf of limited partnerships and/or joint ventures to be subsequently reimbursed. The Company's other credit facility is a $5.0 million revolving line of credit bearing interest at the bank's base rate (9% at March 31, 1995). At March 31, 1995, $5.0 million was outstanding under this facility, which has been used for the same purposes. Both of these credit facilities extend through May 1, 1996. The $35.0 million credit facility is secured by substantially all of the Company's oil and gas properties and the $5.0 million credit facility is secured by certain of the Company's accounts receivable. Until net proceeds of this offering are utilized for purposes described above, they will be invested in interest bearing bank accounts, U.S. government securities, other investment grade debt securities and other short-term investments. 10 11 PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY The Common Stock trades on the New York and Pacific Stock Exchanges under the symbol "SFY." At July 24, 1995, the Company had approximately 650 stockholders of record. The following table sets forth the range of high and low quarterly closing sales prices for the Common Stock as reported by the New York Stock Exchange for the periods indicated.
LOW HIGH --- ---- 1995 Third Quarter (through July, 25, 1995).............................. $8 1/2 $ 9 1/8 Second Quarter...................................................... 8 1/2 10 1/8 First Quarter....................................................... 8 9 7/8 1994 Fourth Quarter...................................................... $9 1/2 $11 3/8 Third Quarter....................................................... 9 1/4 10 1/2 Second Quarter...................................................... 9 10 1/8 First Quarter....................................................... 8 1/2 11 1/4 1993 Fourth Quarter...................................................... $8 3/8 $11 7/8 Third Quarter....................................................... 9 1/2 12 3/4 Second Quarter...................................................... 9 1/2 11 1/4 First Quarter....................................................... 7 7/8 10
The above prices have been revised to reflect the 10% common stock dividend declared and paid in September 1994. On July 25, 1995, the last reported sale price for the Common Stock on the New York Stock Exchange was $8.625 per share. Since the Company's inception, no cash dividends have been declared on its Common Stock, and the Company does not expect to declare cash dividends in the foreseeable future. The Company currently intends to continue a policy of using retained earnings for expansion of its business. Under its current credit arrangements, the Company may not declare cash dividends on its Common Stock that exceed $424,000 in any fiscal year. 11 12 CAPITALIZATION The following table sets forth the capitalization of the Company at March 31, 1995, and as adjusted to give effect to the sale by the Company of the shares of Common Stock offered hereby and the application of the net proceeds as described under "Use of Proceeds." This information should be read in conjunction with the Company's Consolidated Financial Statements and the Notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations" presented elsewhere in this Prospectus.
MARCH 31, 1995 ----------------------- ACTUAL AS ADJUSTED ------- ----------- (IN THOUSANDS) Short-term bank borrowings(1).......................................... $30,550 $ -- ======= ========= Long-term debt 6 1/2% Convertible Subordinated Debentures........................... $28,750 $ 28,750 Stockholders' equity: Preferred Stock -- $.01 par value; 5,000,000 authorized shares; no shares issued and outstanding..................................... -- -- Common Stock -- $.01 par value; 35,000,000 authorized shares; 6,710,412 issued and outstanding shares, 11,710,412 as adjusted(2)....................................................... 67 117 Additional paid-in capital........................................... 25,112 64,662 Retained earnings.................................................... 17,699 17,699 ------- --------- Total stockholders' equity........................................... 42,878 82,478 ------- --------- Total capitalization................................................... $71,628 $ 111,228 ======= =========
- --------------- (1) See Note 4 to the Company's Consolidated Financial Statements for additional information concerning the Company's short-term bank borrowings. (2) Excludes (a) 8,330 shares issued between March 31, 1995 and May 31, 1995 pursuant to stock benefit plans, (b) 1,324,288 shares issuable upon exercise of employee and director stock options outstanding as of May 31, 1995, (c) 68,750 shares issuable upon the exercise of stock options granted to other individuals outstanding as of May 31, 1995, and (d) 2,343,113 shares issuable upon conversion of the outstanding $28.75 million of 6 1/2% Convertible Subordinated Debentures due 2003. See "Management" and the Company's Consolidated Financial Statements and the Notes thereto. 12 13 SELECTED CONSOLIDATED FINANCIAL DATA The following selected consolidated financial data of the Company for each of the five years in the period ended December 31, 1994, are derived from the Company's Consolidated Financial Statements, which have been audited. The selected consolidated financial data for the three-month periods ended March 31, 1994 and 1995 are unaudited, and, in the opinion of management, include all adjustments (consisting of only normal recurring adjustments, except as disclosed below) necessary for a fair presentation of the results for such interim periods. Results for the interim periods are not necessarily indicative of results to be expected for the entire year. The selected consolidated financial data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and the Notes thereto included elsewhere herein.
THREE MONTHS YEAR ENDED DECEMBER 31, ENDED MARCH 31, ---------------------------------------------------- ------------------- 1990 1991 1992 1993 1994 1994 1995 -------- -------- -------- -------- -------- -------- -------- (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA: Revenues: Oil and gas sales............................. $ 7,328 $ 8,362 $ 12,420 $ 15,536 $ 19,802 $ 4,817 $ 4,876 Earned interests and fees(1).................. 9,883 2,232 2,716 4,072 702 109 113 Supervision fees.............................. 2,149 3,363 3,444 3,719 3,751 943 905 Interest income............................... 706 192 113 202 48 19 8 Other, net.................................... 324 541 516 604 1,072 251 357 -------- -------- -------- -------- -------- -------- -------- Total revenues.......................... 20,390 14,690 19,209 24,133 25,375 6,139 6,259 -------- -------- -------- -------- -------- -------- -------- COSTS AND EXPENSES: General and administrative (net).............. 3,943 4,656 4,977 5,065 5,198 1,196 1,307 Depreciation, depletion and amortization...... 3,556 3,843 4,906 7,301 7,905 1,689 2,168 Oil and gas production........................ 2,080 2,442 3,934 4,540 5,639 1,142 1,629 Interest expense.............................. -- -- 76 598 1,795 359 478 Other expenses................................ -- -- 628 -- -- -- -- -------- -------- -------- -------- -------- -------- -------- Total costs and expenses................ 9,579 10,941 14,521 17,504 20,537 4,386 5,582 -------- -------- -------- -------- -------- -------- -------- Income before income taxes...................... 10,811 3,749 4,688 6,629 4,838 1,753 677 Provision for income taxes...................... 3,640 1,236 1,518 1,732 1,112 542 152 -------- -------- -------- -------- -------- -------- -------- Income before cumulative effect of changes in accounting principle.......................... 7,171 2,513 3,170 4,897 3,726 1,211 525 Cumulative effect of change in accounting principle(1).................................. -- -- 915 -- (16,773) (16,773) -- -------- -------- -------- -------- -------- -------- -------- Net income (loss)............................... $ 7,171 $ 2,513 $ 4,085 $ 4,897 $(13,047) $(15,562) $ 525 ======== ======== ======== ======== ======== ======== ======== Per share data: Primary: Income before cumulative effect of changes in accounting principle.......................... $ 1.36 $ 0.47 $ 0.52 $ 0.74 $ 0.56 $ 0.18 $ 0.08 Cumulative effect of changes in accounting principle................................. -- -- 0.15 -- (2.52) (2.54) -- -------- -------- -------- -------- -------- -------- -------- Net income (loss)........................... $ 1.36 $ 0.47 $ 0.67 $ 0.74 $ (1.96) $ (2.36) $ 0.08 ======== ======== ======== ======== ======== ======== ======== Fully diluted: Income before cumulative effect of changes in accounting principle................... $ 1.36 $ 0.47 $ 0.52 $ 0.70 $ 0.56 $ 0.17 $ 0.08 Cumulative effect of changes in accounting principle................................. -- -- 0.15 -- (2.52) (2.54) -- -------- -------- -------- -------- -------- -------- -------- Net income (loss)........................... $ 1.36 $ 0.47 $ 0.67 $ 0.70 $ (1.96) $ (2.36) $ 0.08 ======== ======== ======== ======== ======== ======== ======== Weighted average shares outstanding............. 5,279 5,363 6,135 6,588 6,644 6,602 6,689 ======== ======== ======== ======== ======== ======== ======== CASH FLOW STATEMENT DATA: Net cash flows provided by operating activities.................................... $ 4,813 $ 5,912 $ 6,349 $ 7,238 $ 10,395 $ 2,680 $ 2,964 Capital expenditures............................ 8,600 7,985 34,401 24,229 34,531 4,043 5,745 BALANCE SHEET DATA: Working capital................................. $ 1,023 $ (2,992) $ 2,953 $ 9,742 $(13,137) $ 8,058 $(16,729) Total assets.................................... 118,227 101,422 100,243 160,893 135,673 147,536 135,795 Short-term bank borrowings...................... 12,985 23,380 -- 2,650 27,229 14,000 30,550 Long-term debt.................................. -- -- -- 28,750 28,750 28,750 28,750 Stockholders' equity............................ 35,668 38,660 49,281 54,466 42,127 55,288 42,878
- --------------- (1) In the fourth quarter of 1994, the Company adopted a new method of accounting for earned interests with respect to the limited partnerships for which it serves as general partner, effective January 1, 1994, whereby earned interests are no longer recognized as income. The current year effect of the change was to increase income before cumulative effect of accounting principle by approximately $1,047,000 or $.16 per share. The cumulative effect of this change in accounting principle resulted in an adjustment of $16,772,698 or $(2.52) per share (after reduction for income taxes of $8,640,481), to apply the new method retroactively, thereby reducing net income in 1994. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General." See also Note 2 to the Company's Consolidated Financial Statements. Additionally, effective January 1, 1992, the Company elected to adopt SFAS No. 109. The cumulative effect of this change resulted in an increase in net income of $915,000, reflected in the first quarter of 1992. See Note 3 to the Company's Consolidated Financial Statements. 13 14 SELECTED OIL AND GAS RESERVE AND OPERATING DATA The following selected oil and gas reserve and operating data sets forth certain data as of December 31, 1994 and May 31, 1995, with respect to estimates prepared by the Company, and audited by H.J. Gruy and Associates, Inc., independent petroleum engineers, of the Company's proved oil and gas reserves, the future net revenues therefrom, and their PV-10 Value. Estimates are based upon weighted average prices of $1.85 per Mcf of natural gas and $15.09 per barrel of oil at December 31, 1994, and $2.03 per Mcf of natural gas and $16.68 per barrel of oil at May 31, 1995, at each date holding prices constant throughout the life of the properties in accordance with regulations of the SEC. This information is based upon numerous assumptions and is subject to change due to numerous factors. See "Business and Properties '-- Properties' and '-- Oil and Gas Reserves' " and "Risk Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."
DECEMBER 31, 1994 MAY 31, 1995 ---------------------- ---------------------- PROVED TOTAL PROVED TOTAL DEVELOPED PROVED DEVELOPED PROVED --------- -------- --------- -------- (IN THOUSANDS) ESTIMATED NET PROVED RESERVES(1) Natural gas (MMcf)....................................... 46,406 76,264 45,687 133,336 Oil and condensate (MBbl)................................ 3,209 4,553 3,252 5,407 Total (MMcfe)............................................ 65,663 103,584 65,200 165,779 Future net revenues...................................... $81,650 $119,157 $90,226 $202,530 PV-10 Value.............................................. $47,172 $ 69,395 $51,270 $100,196
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------ --------------------- 1992 1993 1994 1994 1995 ---------- ---------- ---------- --------- --------- PRODUCTION: Oil (Bbl)...................................... 283,928 324,486 467,056 99,992 134,626 Natural gas (Mcf)(2)........................... 3,975,203 5,421,841 6,798,531 1,643,348 1,702,658 Gas equivalents (Mcfe)......................... 5,678,771 7,368,757 9,600,867 2,243,300 2,510,414 WEIGHTED AVERAGE SALES PRICES: Oil (per Bbl).................................. $ 17.19 $ 15.10 $ 14.35 $ 11.80 $ 15.61 Natural gas (per Mcf).......................... 1.90 1.96 1.93 2.21 1.63 SELECTED DATA PER MCFE: Production costs............................... $ 0.69 $ 0.62 $ 0.59 $ 0.51 $ 0.65 Depreciation, depletion and amortization....... 0.86 0.99 0.82 0.75 0.86 General and administrative (net)............... 0.88 0.69 0.54 0.53 0.52 Reserve replacement cost (Mcfe)................ 0.60 0.70 0.79 N/A N/A WELLS DRILLED (GROSS)............................ 40 34 44 12 9 GAS EQUIVALENTS (MCFE) ADDED BY: Acquisitions................................... 44,680,418 26,469,487 12,879,408 N/A N/A Exploration and development.................... 1,365,283 13,502,397 24,803,819 N/A N/A
- --------------- (1) Proved reserves exclude quantities subject to the Volumetric Production Payment. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General." (2) Natural gas production for 1992, 1993, 1994, and the three-month periods ended March 31, 1994 and 1995 includes 1,148,862, 1,581,206, 1,358,375, 386,028 and 316,745 Mcf, respectively, delivered under the Volumetric Production Payment. 14 15 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the Company's Consolidated Financial Statements and Notes thereto and the Selected Consolidated Financial Data included elsewhere in this Prospectus. GENERAL The Company intends to continue to increase its reserves, cash flow and underlying net asset value through a balanced strategy that includes an expanded exploration and development drilling program, strategic acquisitions and the application of advanced technologies. The Company's proved reserve base, production and cash flow from operations have increased at annualized compounded rates of 35%, 38% and 30%, respectively, over the last five years. The Company has historically financed most of its growth with capital raised through limited partnership financing, having raised approximately $440 million from 1979 through 1994. Beginning in 1985, the Company increasingly emphasized this financing vehicle thereby enabling the Company to accelerate its growth and purchase larger producing properties. Commencing in 1991, the Company began to reduce its reliance on limited partnership financing as its reserve base expanded and its strategy shifted to re-emphasize internally-generated exploration and development activities. The Company intends to continue to reduce its dependence on limited partnership financing. As a result of its limited partnership activities, the Company developed the expertise and infrastructure to manage oil and gas properties significantly in excess of its current reserve base. At December 31, 1994, the Company owned proved reserves of over 103.6 Bcfe and managed approximately 200 Bcfe on behalf of limited partnerships. In 1991, the Company began to increase its inventory of exploration and development drilling prospects. Drilling locations were selected through intensive geological and geophysical studies of the Company's undeveloped acreage and other prospects. The Company has recently begun to realize benefits from its drilling program with 24.8 Bcfe of proved reserves added in 1994 through exploration and development drilling at an approximate cost of $0.51 per Mcfe. In 1994, the Company's additions to proved reserves from drilling were almost twice the proved reserves added from producing property acquisitions and represented approximately 250% of production in that year. The Company's revenue is primarily comprised of the following components: oil and gas sales attributable to properties in which the Company owns a direct or indirect interest and supervision fees generated by the Company's role as operator of approximately 750 producing and drilling wells. Additionally, prior to 1994, the Company also recorded earned interests and fees from limited partnerships and joint ventures. Effective January 1, 1994, the Company changed its revenue recognition policy for earned interests. The cumulative effect in 1994 of this change in accounting principle resulted in a one-time accounting adjustment of $16.8 million, or a loss of $2.52 per share (after reduction for income taxes of $8.6 million), from applying the new method retroactively. Earned interests represented revenues in the form of interests in proved developed oil and gas properties conveyed to limited partnerships and joint ventures formed in connection with the Company's organization and management of limited partnerships and joint ventures, representing the difference between the Company's capital contributions to each limited partnership or joint venture and its earned revenue interest in the limited partnership's or venture's properties (based upon the expected levels of cash distributions to the limited partners or joint venturers). Under the Company's newly adopted method of accounting for earned interests, such amounts will not be recognized as income, thereby reducing the Company's investment in oil and gas property. On a pro forma basis, after considering the retroactive application of the Company's change in accounting for earned interests, revenues would have been reduced by 14%, to $20.8 million and 9%, to $17.5 million for 1993 and 1992, respectively. The Company believes the change in policy results in financial statements that better reflect its current business focus and that are more comparable to current practices in the oil and gas exploration and production industry. 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 the Volumetric Production Payment in these properties to a subsidiary of Enron Corp. Net proceeds from the sale of the production were recorded as deferred 15 16 revenues. Deliveries under the Volumetric Production Payment are recorded as oil and gas sales revenues which are offset by a corresponding reduction of deferred revenues. Under this arrangement, the Company is required to deliver a fixed quantity of hydrocarbons produced from the properties over a specified period. Volumes remaining to be delivered under the Volumetric Production Payment are not included in the Company's proved reserves. Under the Volumetric Production Payment, hydrocarbons produced in excess of the amount required to be delivered are sold by the Company for its own account. The amounts delivered under the Volumetric Production Payment were 1,148,862, 1,581,206 and 1,358,375 Mcf in 1992, 1993 and 1994, respectively, representing oil and gas sales revenues of $1.7 million, $2.3 million and $2.0 million. These amounts represented the amortization of deferred revenues in each respective period. At March 31, 1995, approximately 5.1 Bcf of gas remain to be delivered under this arrangement through October 2000, when it expires. RESULTS OF OPERATIONS COMPARISON OF THREE MONTHS ENDED MARCH 31, 1995 AND 1994 Revenues The Company's revenues increased 2% during the first quarter of 1995 from the first quarter of 1994, due primarily to the increase in oil and gas sales. Oil and Gas Sales Oil and gas sales increased approximately 1% to $4.9 million in the first three months of 1995, as compared to $4.8 million for the same period in 1994. Oil and gas sales comprised approximately 78% of total revenue in both periods. The Company's net equivalent production volumes increased by 12% to 2.51 Bcfe in the first quarter of 1995 as compared to the same period in 1994. Oil production increased 35% and gas production increased 4% in the first quarter of 1995, primarily as the result of (i) increased production from exploratory and development wells drilled in late 1994 and in the first quarter of 1995, and (ii) the acquisition of interests in producing properties by the Company in the third quarter of 1994. Although net equivalent production volumes grew by 12% and oil prices increased by 32% during the first quarter of 1995, oil and gas sales revenue increased only 1% due to a 26% decline in gas prices. Supervision Fees Supervision fees decreased 4% in the first three months of 1995 compared to the same period in 1994 due primarily to a reduction in the number of wells the Company operated, as it disposed of certain marginal wells between the two periods. Costs and Expenses General and administrative expenses for the first quarter of 1995 increased 9% as compared to the same period in 1994, due primarily to increased staffing levels required to support the Company's increased reserve base and drilling activities. The Company's general and administrative expenses declined from $0.53 per Mcfe for the first quarter of 1994 to $0.52 per Mcfe for the same period in 1995 as a result of increased production volumes. Depreciation, depletion and amortization ("DD&A") increased 28%, due primarily to the increase in the Company's producing properties and the related sale of increased quantities of oil and gas therefrom. DD&A grew from $0.75 per Mcfe in the 1994 period to $0.86 per Mcfe in the 1995 period, reflecting variations in the per unit cost of property additions and changes in the mix of reserves between oil and gas. Oil and gas production costs increased 43% in the first quarter of 1995 (such costs increased from $0.51 per Mcfe in 1994 to $0.65 per Mcfe in 1995) due to the growth in the Company's production volumes, certain one-time remedial well expenses, and higher well insurance costs and ad valorem taxes. Interest expense totaled $1.1 million for the first three months of 1995 (of which $671,000 was capitalized) and $686,000 for the first three months of 1994 (of which $327,000 was capitalized). The 16 17 Company capitalizes that portion of interest related to its exploration, partnership and foreign business development activities. The increase in interest expense in 1995 is attributable to an increase in the average balance under the Company's credit lines necessary to finance the Company's capital expenditures discussed below. Net Income (Loss) Net income decreased 57% in the first quarter of 1995 to $525,000, or $0.08 per share, as compared to income before the cumulative effect of change in accounting principle of $1.2 million, or $0.18 per share, in the same period of 1994. The decrease in net income primarily reflected the substantially lower gas prices realized in 1995. The net loss of $15.6 million in the first quarter of 1994 included the cumulative effect of a change in accounting principle of $16.8 million discussed above. COMPARISON OF YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 Revenues Company revenues increased by 5% during 1994 and 26% during 1993, principally due to increases in oil and gas sales revenues. In addition to the components of revenues discussed below, 1992 and 1993 revenues included the recognition of earned interests (excluded in 1994 due to a change in accounting principle) which amounted to $1.7 and $3.3 million, respectively. Oil and Gas Sales Oil and gas sales increased by $4.3 million, or 27%, in 1994 compared to 1993 due to increased production generated from acquired properties and the Company's expanded exploration and drilling programs. As a percentage of total revenues, oil and gas sales rose from 65% of total revenues in 1992 to 78% of total revenues in 1994. Average prices for oil dropped from $17.19 per Bbl in 1992, to $15.10 per Bbl in 1993, to $14.35 per Bbl in 1994, while average gas prices increased from $1.90 per Mcf in 1992, to $1.96 per Mcf in 1993, and back down to $1.93 per Mcf in 1994. The Company's net volumes increased by 30% to 9.6 Bcfe in 1994 as compared to 1993. This volume increase was offset by a decrease in oil and gas prices. Average gas prices declined from $2.21 in the first quarter of 1994 to $1.63 in the fourth quarter of 1994, which significantly impacted 1994 revenues and accordingly, net income. In 1993, oil and gas sales revenues increased by 25% or $3.1 million, over 1992 revenues, primarily due to increased production volumes. Cash Fees The Company receives cash fees in connection with the formation and continuing management of limited partnerships and, to a lesser extent, fees paid by joint venture partners. Cash fees received were $764,000, $763,000 and $702,000 in 1992, 1993 and 1994, respectively. These amounts vary due to differences in the level of limited partnership subscriptions, ongoing limited partnership net revenues, and the amount and terms of joint venture fees. Supervision Fees Supervision fees increased from $3.4 million in 1992, to $3.7 million in 1993 to $3.8 million in 1994. These increases were due to a higher level of drilling wells operated by the Company and the annual escalation of producing well overhead rates. Costs and Expenses General and administrative expenses, net of reimbursement to the Company for the services performed on behalf of limited partnerships, increased 2% and 3% during 1993 and 1994, respectively. These increases were primarily the result of the Company receiving its general partner share of expenses in a larger number of limited partnerships. These expenses decreased from $0.88 per Mcfe in 1992 to $0.69 per Mcfe in 1993 to $0.54 per Mcfe in 1994. 17 18 DD&A has steadily increased due to significant growth in the Company's interests in production volumes. The Company's DD&A rate per Mcfe has fluctuated from $0.86 in 1992 to $0.99 in 1993 to $0.82 in 1994, reflecting variations in the per unit cost of property additions and changes in the mix of reserves between oil and gas over the years. The 1994 DD&A amount was also favorably impacted (by approximately $2.3 million) as a result of the change in accounting principle relating to earned interests as discussed. The accounting principle change will continue to have a favorable impact on DD&A in the future. See "-- General." The Company's oil and gas production costs increased 24% during 1994 and 15% during 1993 due to increased production volumes. The Company's production costs decreased from $0.69 per Mcfe in 1992 to $0.62 per Mcfe in 1993 to $0.59 per Mcfe in 1994, reflecting higher net equivalent production volumes in each period. Total interest expense was $1.4 million, $1.6 million, and $3.7 million for 1992, 1993, and 1994, respectively, of which $1.3 million, $1.0 million, and $1.9 million related to the Company's exploration, partnership and foreign business development activities and was capitalized. The increase in interest expense for 1994 was attributable to payment of a full year's interest on the Debentures, as opposed to payment of six months' interest on the Debentures in 1993, and no interest on the Debentures in 1992. Net Income (Loss) The Company incurred a net loss for 1994 of $13.0 million, which included the cumulative effect of a change in accounting principle (as discussed above) of $16.8 million. Income before the cumulative effect of a change in accounting principle for 1994 was 24% less than net income for 1993, primarily due to the elimination in 1994 of recording earned interest as an item of revenue ($3.4 million in 1993) and the 1994 increase of $1.2 million in interest expense, partially offset by a $2.6 million increase in oil and gas income activities (sales revenues net of the associated increases in production costs and DD&A). Net income for 1993 increased 20% as compared to 1992, principally due to increased production volumes. The Company's consolidated effective tax rate was 32.4%, 26.1% and 23.0% in 1992, 1993 and 1994, respectively. During 1992, the Company also recognized a $915,000 income benefit as a result of the cumulative effect of adopting Statement No. 109 of the Financial Accounting Standards Board as described in Note 3 to the Company's Consolidated Financial Statements, which increased first quarter 1992 income by $0.15 per share. RECENT DEVELOPMENTS Oil and gas sales volumes for the second quarter of 1995 are currently estimated to be comparable to sales volumes during the first quarter of 1995. Management currently estimates that its weighted average gas sales price has improved approximately 10% during the second quarter when compared to the $1.63 weighted average sales price for the first quarter of 1995, while its weighted average oil sales price has declined slightly for the period. Preliminary estimates indicate that its related costs and expenses for the second quarter of 1995 will increase slightly over the levels in the first quarter of 1995. In the fourth quarter of 1994, the Company acquired a leasehold position in 8,830 net acres immediately adjacent to its existing AWP Olmos Field. The Company subsequently extended its geological and engineering studies to cover this area, and has drilled four new wells on this acreage. As a result of these efforts, Swift has identified 89 proved undeveloped locations, and currently plans to drill up to 70 development wells through year-end 1996. At May 31, 1995, the Company had estimated proved reserves of 133.3 Bcf of natural gas and 5.4 MMBbls of oil (totalling approximately 165.8 Bcfe) with a PV-10 Value of approximately $100.2 million. The proved reserves at May 31, 1995 represent an increase of 60% over estimated amounts at December 31, 1994, reflecting recent reserve additions comprised primarily of proved undeveloped reserves in newly acquired areas of the AWP Olmos Field, as well as higher oil and gas prices at May 31, 1995. 18 19 LIQUIDITY AND CAPITAL RESOURCES The Company historically has relied on limited partnerships as its principal financing vehicle to fund its acquisitions. Since 1991, the Company's strategy has shifted toward increased reliance on exploration and development activities, and it has significantly expanded reserves added through these efforts. As a result, the Company has reduced its reliance on cash flow generated from, and capital raised through, limited partnerships. Supplemental cash and working capital are provided through internally generated cash flow and debt and equity financing. NET CASH FROM OPERATIONS For the three-month period ended March 31, 1995, cash flows from operating activities increased to $2.9 million compared to $2.7 million during the first three months of 1994. This increase was primarily due to increased production volumes and higher oil prices, offset by lower average gas prices as discussed above. In 1992, 1993, and 1994, the Company generated net cash from operating activities of $6.3 million, $7.2 million and $10.4 million, respectively. The 1994 increase was primarily due to increased production volumes, partially offset by lower oil and gas prices and an increase in interest expense. The 1993 increase of $889,000 in net cash from operations was substantially due to increased production, offset by lower oil prices and an increase in interest expense. WORKING CAPITAL The Company's working capital has decreased from $9.7 million at December 31, 1993, to working capital deficits of $13.1 million and $16.7 million at December 31, 1994, and at March 31, 1995, respectively. The working capital deficits are primarily the result of borrowings under short-term facilities to fund a portion of the increases in the Company's oil and gas property assets as described below under "-- Capital Expenditures." At December 31, 1994 and March 31, 1995, the Company's borrowings were $27.2 million and $30.5 million, respectively. Due to the nature of the Company's business, the individual components of working capital fluctuate considerably from period to period. Balance sheet changes in receivables, producing oil and gas properties held for transfer and payables related to producing oil and gas property acquisitions principally arise from the timing of property purchases and payments made by and to the Company related to the Company's management of limited partnerships. The Company incurs significant working capital requirements in connection with its role as operator of approximately 750 producing wells 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. As a result, significant balances in the Company's receivable and payable accounts exist in the normal course of its business. The Company receives certain fees in connection with these activities. FINANCING ACTIVITIES The Company raised $34.7 million, $44.1 million and $50.2 million in limited partnership subscriptions in 1994, 1993, and 1992, respectively, reflecting the Company's reduced reliance on limited partnership financing. On June 30, 1993, the Company issued $28.75 million of Debentures in a public offering. Proceeds of the offering have been used primarily to acquire producing oil and gas properties and to finance the Company's expanding exploration and development programs. See Note 5 to the Company's Consolidated Financial Statements. In May 1992, the Company received proceeds of $14.0 million from the sale of certain properties from its oil and gas property account and $6.4 million from the sale of 990,000 shares of common stock through an institutional offering, and used the Volumetric Production Payment to acquire $13.8 million of properties from the Manville Corporation. See "-- General" and Note 8 to the Company's Consolidated Financial Statements. 19 20 CREDIT FACILITIES The Company has established credit facilities which have been 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 limited partnerships and joint ventures, and to provide working capital. More recently the Company's credit facilities have been used to fund a portion of the Company's exploration and development activities. See Note 4 to the Company's Consolidated Financial Statements. At March 31, 1995, the Company had $30.5 million outstanding under its borrowing arrangements. Up to an additional $10.5 million was available under these lines at March 31, 1995. These facilities included three lines: (i) a $35.0 million revolving line of credit at the lead bank's base rate plus 0.5%, with an option to set interest at the London Interbank Offered Rate ("LIBOR") plus 2.25%; (ii) a $5.0 million accounts receivable line bearing interest at the bank's base rate; and (iii) a line for the acquisition of producing oil and gas properties (the "Acquisition Line") at the bank's base rate plus 1.0%. The $35.0 million credit facility is secured by substantially all of the Company's oil and gas properties and the $5.0 million credit facility is secured by certain of the Company's accounts receivable. The Company has since terminated the Acquisition Line, retaining the two lines totalling $40.0 million. See "Use of Proceeds" and Note 4 to the Company's Consolidated Financial Statements. CAPITAL EXPENDITURES Additions to property, plant and equipment during the first three months of 1995 were $5.7 million which include $2.0 million for exploratory and development drilling costs; $1.8 million of prospect costs (principally prospect leasehold, seismic and geological costs of unproven prospects); $1.0 million to fund the Company's general partner capital contribution to the limited partnerships formed under its SEDV offering (see "Business and Properties -- Partnerships"); $600,000 invested in foreign business opportunities ($530,000 in Russia and $70,000 in Venezuela); and $300,000 spent for furniture and fixtures, primarily computer equipment. The Company's capital expenditures were $34.4 million $24.2 million and $34.5 million in 1992, 1993 and 1994, respectively. In 1994 approximately $6.9 million was spent on the purchase of producing oil and gas property interests. The Company expended approximately $6.6 million for prospect costs; approximately $5.7 million for the Company's general partner capital contribution to limited partnerships; $4.1 million in development drilling; and $4.0 million for exploratory drilling. The Company also purchased $3.5 million of limited partnership interests in previously formed limited partnerships through its acceptance, at its option, of the right of presentment provided in those limited partnerships. In its foreign activities, the Company invested another $3.0 million and $300,000, in its Russia and Venezuela initiatives, respectively, and $500,000 on fixed assets consisting primarily of computer equipment. The Company anticipates capital expenditures of approximately $100.0 million (of which approximately $5.7 million was spent during the first three months of 1995) for currently planned projects in 1995 and 1996, including approximately $70.0 million for exploration and development drilling projects and approximately $25.0 million for the acquisition of producing properties, including the purchase of interests from limited partnerships and $5.0 million for equipment and other capital expenditures. Actual expenditures for planned exploration and development activities may vary significantly, depending upon many factors, including drilling results, oil and gas prices, industry conditions and general economic factors. In addition, the Company's exploration and development expenditures may be increased as additional prospects or wells are generated, acquired or developed. The Company believes that internally-generated cash flows (expected to increase as the Company's production base increases as a result of its accelerated drilling program) together with the proceeds of this offering and its existing credit facilities, will be sufficient to finance the costs associated with its currently budgeted capital expenditures at least through 1996. Further liquidity needs may also be met by the additional availability under its credit facilities based upon the value of the Company's proved reserves, as management continually evaluates future use of debt and/or equity to finance its capital needs. See "Risk Factors -- Future Capital Requirements." 20 21 QUARTERLY RESULTS OF OPERATIONS The following table sets forth certain unaudited quarterly financial information for each of the Company's last five quarters. The data has been prepared on a basis consistent with the Company's audited consolidated combined financial statements included elsewhere in this Prospectus and includes all necessary adjustments, consisting only of normal recurring accruals that management considers necessary for a fair presentation. The operating results for any quarter are not necessarily indicative of results for any future period.
QUARTERS ENDED -------------------------------------------------------------------- MARCH 31, JUNE 30, SEPT. 30, DEC. 31, MARCH 31, 1994 1994 1994 1994 1995 ------------ ---------- ---------- ---------- ---------- Revenues(1).................... $ 6,138,535 $6,106,954 $6,962,612 $6,167,191 $6,258,588 Depreciation, depletion and amortization................. 1,688,938 1,802,483 2,143,652 2,269,728 2,168,229 Income before income taxes(1)..................... 1,753,003 1,462,980 1,439,620 182,226 676,434 Income before cumulative effect of change in accounting principle(1)................. 1,210,722 1,076,077 1,130,398 308,474 524,600 Net income (loss) (as restated)(1)................. $(15,561,976) $1,076,077 $1,130,398 $ 308,474 $ 524,600 Primary: Income before cumulative effect of change in accounting principle...... $ 0.18 $ 0.16 $ 0.17 $ 0.05 $ 0.08 Net income (loss)(1)......... (2.36) 0.16 0.17 0.05 0.08 Fully diluted: Income before cumulative effect of change in accounting principle...... $ 0.17 $ 0.15 $ 0.16 $ 0.05 $ 0.08 Net income (loss)(1)......... (2.36) 0.15 0.16 0.05 0.08 Net cash provided by operating activities................... $ 2,679,971 $2,256,457 $3,355,621 $1,902,465 $2,964,097
- --------------- (1) In the fourth quarter of 1994, the Company changed its revenue recognition policy for earned interests. See Note 2 to the Company's Consolidated Financial Statements for further discussion. This change was effective beginning January 1, 1994, and, accordingly, the cumulative effect of this change resulted in an adjustment of $16,772,698 or $(2.52) per share, which has been reflected in the first quarter of 1994, and the first three quarters of 1994 have been restated to reflect the basis of the newly adopted accounting principle. Net Income, Primary Income Per Share, and Fully Diluted Income Per Share were previously reported as $814,325, $0.14, and $0.14, respectively, for the first quarter of 1994; $1,140,197, $0.19, and $0.17, respectively, for the second quarter of 1994; and $768,161, $0.12, and $0.12, respectively, for the third quarter of 1994. 21 22 BUSINESS AND PROPERTIES THE COMPANY The Company is engaged in the exploration, development, acquisition and operation of oil and gas properties with a primary focus on U.S. onshore natural gas reserves. The Company has interests in approximately 4,100 oil and gas wells located in 15 states, with over 80% of its proved reserve base concentrated in Texas, Oklahoma and Louisiana. The Company was formed in 1979 and, since 1985, has grown primarily through the acquisition of producing properties funded through limited partnership financing. Commencing in 1991, the Company began to re-emphasize the addition of reserves through increased exploration and development drilling activity while significantly reducing its reliance on limited partnership financing. In 1994, the Company added approximately 24.8 Bcfe of proved reserves through exploration and development drilling, at a cost of $0.51 per Mcfe, representing approximately 250% of 1994 production. The Company's proved reserve base, production and cash flow from operations have increased at annualized compounded rates of 35%, 38% and 30%, respectively, over the last five years. At May 31, 1995, the Company had estimated proved reserves of 133.3 Bcf of natural gas and 5.4 MMBbls of oil (totalling approximately 165.8 Bcfe) with a PV-10 Value of approximately $100.2 million. Approximately 80% of the Company's proved reserve base at that date was natural gas. The proved reserves at May 31, 1995 represent an increase of 60% over estimated amounts at December 31, 1994. The Company's reserve replacement cost over the last three years has averaged $0.79 per Mcfe, which it believes is better than industry averages. As of December 31, 1994, the Company operated 750 wells which represented 61% of its proved reserve base and managed reserves on behalf of limited partnerships which, exclusive of the Company's interests, had proved reserves of approximately 200 Bcfe. Five oil and gas fields accounted for 54% of the Company's PV-10 Value at December 31, 1994, of which the two largest were the AWP Olmos Field and the Giddings Field. The AWP Olmos Field, located in McMullen County, Texas, and the Giddings Field, located in Fayette County, Texas, accounted for 25% and 12%, respectively, of the Company's PV-10 Value as of such date. The Company believes that the Giddings Field's prolific but short-lived wells complement the long-lived reserves of the AWP Olmos Field. The application of advanced technologies and achievement of operating efficiencies have enabled the Company to reduce costs and enhance reserve recoveries in these fields. BUSINESS STRATEGY The Company intends to continue to increase its reserves, cash flow and underlying net asset value through a balanced strategy that includes an expanded exploration and development drilling program, strategic acquisitions and the application of advanced technologies. Key elements of the Company's strategy include the following: - Increased exploration and development drilling activities. The Company believes that its existing properties, including its substantial inventory of undeveloped acreage, provide significant future exploration and development potential. The Company anticipates expenditures of approximately $70.0 million on currently planned drilling activities during 1995 and 1996 (of which approximately $3.8 million was spent in the first quarter of 1995). Through December 31, 1996, the Company currently anticipates expenditures of approximately $55 million on development drilling activities, including approximately $30.0 million in the AWP Olmos and Giddings fields in Texas. Swift expects to spend approximately $15.0 million on exploratory drilling in the Yegua, Frio, Lobo, Wilcox and Austin Chalk trends in the Gulf Coast Basin, the Smackover trend in the North Louisiana Salt Dome Basin, the Red Fork formation in the Anadarko Basin in Oklahoma and the Minnelusa trend in Wyoming. - Strategic acquisitions. Through December 31, 1994, the Company had acquired approximately $460.0 million of producing oil and natural gas properties on behalf of itself and its co-investors in 120 separate transactions. Approximately $108.0 million of this amount, representing approximately 139.7 Bcfe, was acquired for the Company's own account, including 12.9 Bcfe purchased in 1994. The Company is continuously reviewing acquisition opportunities, with a particular emphasis on identifying 22 23 properties in close proximity to the Company's current reserves, where reserves can be increased through development drilling and improved operating efficiencies can be achieved. Using these criteria, the Company employs a disciplined, market-driven approach to acquisitions that can result in varying levels of annual spending on acquisitions. Through 1996, the Company anticipates spending approximately $25.0 million for the acquisition of producing property interests, including the purchase of interests from limited partnerships. - Application of advanced technologies. To minimize the risks associated with exploration and development drilling and improve operating results, the Company has devoted considerable resources to development of advanced technological expertise. These technologies include 2-D and 3-D seismic analysis, AVO studies and detailed formation depletion studies. The Company has attained substantial expertise in horizontal well technology, having participated in 17 such wells in the past two years with a 100% success rate. Additionally, the use of innovative fracturing methods and coiled tubing technology in the AWP Olmos Field has enabled the Company to achieve improved production yields. EXPLORATION AND DEVELOPMENT DRILLING ACTIVITIES In 1991, the Company began to increase its inventory of exploration and development drilling prospects. Drilling locations were selected through intensive geological and geophysical studies of the Company's undeveloped acreage and other prospects. The Company has recently begun to realize benefits from its drilling program with 24.8 Bcfe of proved reserves added in 1994 through exploration and development drilling at an approximate cost of $0.51 per Mcfe. Proved reserves added through exploration and development drilling were approximately double the amount added through the acquisition of producing properties in 1994, and represented approximately 250% of that year's annual production. The Company's success rate for 1994 drilling activity was 43% for exploratory wells (6 out of 14 drilled) and 87% for development wells (26 out of 30 drilled), which management believes are above industry averages. The Company pursues a "controlled risk" approach to exploratory drilling. The Company focuses its exploration activities on specific regions in the U.S. where its technical staff has considerable experience and near proved productive properties where the potential for significant reserves exists. The Company seeks to minimize its exploration risk by investing in multiple prospects, farming out interests to industry partners and drilling funds, utilizing advanced technologies and drilling in different types of geological formations. The Company's development strategy is designed to maximize the value and productivity of its existing properties through development drilling and recovery methods, enhancing production results through improved field production techniques, lowering production costs, and applying the Company's technical expertise and resources to exploit producing properties efficiently. The Company employs various recovery techniques which include water flooding, fracturing reservoir rock through the injection of high-pressure fluid, inserting coiled tubing velocity strings to speed gas flow and acid treatments. The Company believes that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in drilling and operating costs in several of its fields, including the Company's largest single property, the AWP Olmos Field. See "-- Properties -- AWP Olmos Field." The Company's exploration and development activities are conducted by its in-house exploration staff, assisted by professionals from other departments, including reservoir engineers, geologists, geophysicists, petrophysicists, landmen, and drilling and operations engineers. The Company believes that one of the keys to its success has been its team approach which integrates multiple disciplines to maximize utilization of the information provided by modern seismic techniques. The Company has increasingly utilized advanced seismic technology to enhance the quality of its drilling efforts, including 2-D and 3-D seismic analysis, AVO studies, and detailed formation depletion studies. Utilizing the Company's computer workstations, seismic data is analyzed and enhanced with advanced software programs, many of which are proprietary. As a result, the Company has developed a significant internal seismic expertise and has compiled an extensive library of seismic data. 23 24 AWP Olmos Field. The Company has extensive expertise in the AWP Olmos Field where it drilled four successful development wells in 1994. The Company has a long history of experience with low-permeability tight-sand formations typical of its AWP Olmos Field properties. Since acquiring its first AWP Olmos Field acreage in 1988, the Company has made detailed studies of drainage patterns in the formation and has introduced innovations in fracture design and implementation methods and coiled tubing technology that substantially reduce drilling costs and improve recoveries. In the fourth quarter of 1994, the Company acquired a leasehold position in 8,830 net acres immediately adjacent to its existing AWP Olmos Field. The Company subsequently extended its geological and engineering studies to cover this area, and to date has drilled and completed four new wells on this acreage. As a result of these efforts, Swift has identified 89 proved undeveloped locations in this field, where it currently plans to drill up to 70 development wells through 1996. Giddings Field. Wells in the Giddings Field initially have high deliverability rates, with strong cash flows that decline rapidly. The Company believes these reserves complement its long-lived reserves in the AWP Olmos Field. Since 1992, the Company has participated in 17 horizontal wells in the Giddings Field with a 100% success rate, including six successful development wells in 1994. The Company believes its success is attributable to its ability to identify hydrocarbon-bearing fractures, relying on its expertise in seismic data analysis, and its ability to drill and operate horizontal wells. In 1994, the Company acquired a 2-D swath of seismic data covering approximately 6,500 acres. In addition, the Company acquired undeveloped leasehold interests to provide additional flexibility in designing its development program. The Company currently plans an additional 12 development wells in the Giddings Field through December 31, 1996. Gulf Coast Basin. The Company's drilling program in the Gulf Coast Basin in 1994 consisted of three successful exploratory wells and five successful development wells, primarily in the Yegua trend. These locations were selected utilizing traditional geologic studies combined with analyses of available 2-D seismic data. To further reduce exploration and development risk in the Gulf Coast Basin, the Company conducted a 3-D seismic survey in Jackson County, Texas in 1994. The processing and interpretation has identified a number of potential drilling locations which have been further refined through AVO analysis. The Company owns interests in the South Louisiana East Mud Lake and Second Bayou fields with significant proved undeveloped reserves. The Company plans to conduct additional 3-D seismic surveys in these fields in 1995. Up to 12 exploratory wells and four development wells are scheduled for drilling in the Gulf Coast Basin through 1995, principally focusing on the Yegua, Frio, Lobo and Wilcox trends. Anadarko Basin. The Company plans to continue exploration and development activities in the Anadarko Basin in Oklahoma principally focusing on the Red Fork formation. The Company participated in five successful development wells in this area in 1994. The Company's geologists and geophysicists search for the Red Fork formation's narrow channel sands using interactive software to integrate geologic and seismic data. By correlating the two sets of information, the presence of potential hydrocarbon accumulations is determined and optimum drilling sites are selected. For 1995, two exploratory locations and one development location have been identified. Wyoming Powder River Basin. In early 1995, the Company drilled a discovery well in the Minnelusa trend in Campbell County, Wyoming, which tested at an initial production rate of 415 barrels of oil per day. The Company has a 50% working interest in the well. Two development wells offsetting the new discovery and four additional exploratory wells are planned for this area in 1995. The Minnelusa trend has been the subject of extensive study by the Company's multidisciplinary teams, in order to identify the location of stratigraphic hydrocarbon traps. The Company's staff has evaluated over 5,000 wells drilled in the area, utilizing 2-D and 3-D seismic data, and has conducted petrophysical studies to determine the hydrocarbon-bearing capacity of the rock. To increase the production in some areas, the Company has instituted secondary and tertiary recovery through water or polymer flooding in the Minnelusa fields. North Louisiana Salt Dome. The North Louisiana Salt Dome covers the neighboring corners of Arkansas, Louisiana and Texas. The Company has studied the Smackover trend for several years and has drilled two successful exploratory wells in southwest Arkansas during 1993 and 1994. The Smackover formation is a prolific hydrocarbon producer from multiple levels and from a variety of structures, including 24 25 fault traps, salt anticlines, basement structures and stratigraphic traps. The Company currently has access to a 7,000-mile seismic data base in the area, and plans to conduct two additional 3-D seismic surveys in the Smackover formation during 1995. The Company plans to drill five exploratory wells and one development well in the region in 1995 and is currently evaluating the implementation of a water flood project in Arkansas. ACQUISITION ACTIVITIES Since 1979, the Company has acquired approximately $460.0 million of producing oil and natural gas properties on behalf of itself and its co-investors in 120 separate transactions. The Company has acquired for its own account approximately $108.0 million of producing properties, with proved reserves estimated at 139.7 Bcfe. The Company's acquisition activities have declined over the past three years, with approximately $27.0 million, $18.5 million and $13.1 million of properties acquired in 1992, 1993 and 1994, respectively. The Company's acquisition costs have averaged $0.70 per Mcfe over this three year period, which it believes is better than industry averages. Through 1996, the Company anticipates spending approximately $25.0 million for acquisitions of producing property interests, including the purchase of interests from limited partnerships. The Company uses a disciplined, market-driven approach to acquisitions. The Company generally seeks acquisition of properties for its own account that are in close proximity to its current reserves and provide the potential to add reserves through additional development efforts. As the market for acquisitions has become more competitive in recent years, the Company has taken the initiative in creating acquisition opportunities by directly soliciting property owners who have not placed their properties on the market. Properties are acquired after the Company has analyzed and evaluated available reservoir engineering, geological, and geophysical data. In evaluating producing properties prior to purchase, the Company assesses many factors, including estimated reserves, anticipated cash flow from production, production costs and various factors affecting the marketing of production. See "Risk Factors '-- Uncertainty of Estimates of Reserves and Future Net Revenues' and '-- Risks of Purchasing Interests in Producing Properties.' " PROPERTIES The Company's proved reserves have been relatively concentrated, with approximately 54% of the Company's PV-10 Value at December 31, 1994, attributable to its five largest properties. The following table presents data regarding the number of gross producing wells, the estimated quantities of proved oil and gas reserves and the PV-10 Value attributable to these properties, as of December 31, 1994.
DECEMBER 31, 1994 --------------------------------------------------------------- ESTIMATED PROVED RESERVES GROSS --------------------------- PV-10 PRODUCING OIL GAS VALUE PERCENT PROPERTY STATE WELLS (MBBL) (MMCF) MMCFE (000'S) OF PV-10 - ------------------------------- ----- --------- ------ ------ ------- ------- -------- AWP Olmos...................... TX 85 1,159 31,068 38,022 $17,651 25.4% Giddings....................... TX 54 512 5,375 8,447 8,242 11.9 Second Bayou/E. Mud Lake....... LA 43 70 5,518 5,938 4,924 7.1 Weatherford.................... OK 144 92 6,070 6,622 3,637 5.2 West Bernard................... TX 7 32 3,032 3,224 2,952 4.3 Chunchula...................... AL 47 302 3,026 4,838 2,552 3.7 North Creole................... LA 5 54 1,790 2,114 2,369 3.4 West Fouke..................... AK 1 95 2,000 2,570 1,948 2.8 Estes Cove..................... TX 7 211 488 1,754 1,405 2.0 Appalachian.................... WV 287 -- 1,664 1,664 1,241 1.8 Other Fields................... 3,492 2,026 16,233 28,389 22,474 32.4 ----- ----- ------ ------- ------- ----- Total................ 4,172 4,553 76,264 103,582 $69,395 100.0% ===== ===== ====== ======= ======= =====
25 26 The Company focuses its activities in four main geographical basins: the Gulf Coast Basin, the Oklahoma Anadarko Basin in Oklahoma, the Wyoming Powder River Basin and the North Louisiana Salt Dome Basin. The AWP Olmos Field, the Giddings Field and the East Mud Lake and Second Bayou fields (located in the Gulf Coast Basin) and the Weatherford Area (located in the Anadarko Basin in Oklahoma) were the Company's most significant oil and gas properties at December 31, 1994. AWP Olmos Field The AWP Olmos Field, including an adjacent 8,830-acre leasehold acquired in 1994, located in McMullen County, Texas, represented approximately 30% of the Company's production and 25% of its PV-10 Value at December 31, 1994. The Company owns interests in, and is the operator of, 85 wells producing natural gas from the Olmos Sand formation at a depth of approximately 10,000 feet. Working interests owned by the Company and limited partnerships in this field range from 86.5% to 100%. During 1994, the Company drilled four successful development wells in this field. The Company has engaged in extensive fracturing operations to increase the permeability of the formation and flow of gas from the wells. In addition, the Company has used coiled tubing velocity strings in several wells to improve production rates. In the fourth quarter of 1994, the Company successfully acquired a leasehold position in 8,830 net acres immediately adjacent to its existing AWP Olmos Field. The Company subsequently extended its geological and engineering studies to cover this area, and has drilled four new wells on this acreage. As a result of these efforts, Swift has identified 89 proved undeveloped locations, and currently plans to drill up to 70 development wells through 1996. Giddings Field The Giddings Field represented approximately 12% of the Company's PV-10 Value at December 31, 1994. Swift owns interests in 54 wells producing from the Austin Chalk formation, 17 of which are horizontal. The Giddings Field wells are all horizontally produced natural gas and oil wells that deliver high initial flow rates and strong initial cash flows which decline rapidly. The Company owns drilling and production rights to over 12,000 acres and has a substantial amount of undeveloped proved reserves in this area. Therefore, the Company believes the Giddings Field will be an increasing area of activity in the future. South Louisiana East Mud Lake and Second Bayou Fields The East Mud Lake and Second Bayou fields located adjacently in Cameron Parish, Louisiana, represented approximately 7% of the Company's PV-10 Value at December 31, 1994. The Company owns working interests ranging from 4% to 14% in 43 wells which are operated by third parties. This field produces primarily natural gas from the Planulina and Abbeville Series formations at depths ranging from 10,000 to 13,000 feet. The Oklahoma Weatherford Area The Oklahoma Weatherford Area, located in Caddo, Custer, and Washita Counties in southwestern Oklahoma, represented approximately 5% of the Company's PV-10 Value at December 31, 1994. The Company owns interests in 144 wells producing primarily from the Red Fork and Springer (Britt) formations at average depths of 12,500 and 15,000 feet, respectively. The Company is the operator of 40 wells which represent approximately 75% of its proved reserves in the field. The Company also manages a gas gathering system, including pipelines and compressors and two condensate recovery systems in the field. OPERATIONS The Company generally seeks to be named as operator for wells in which it or limited partnerships and joint ventures have acquired a significant interest, although this typically occurs only when the Company or limited partnerships and joint ventures own the major portion of the working interest in a particular well or field. The Company acts as operator of approximately 750 wells, which comprise approximately 61% of the Company's total proved reserves. 26 27 As operator, the Company is able to exercise substantial influence over development and enhancement of a well, and supervises operation and maintenance activities on a day-to-day basis. The Company does not conduct the actual drilling of wells on properties for which it acts as operator. Drilling operations are conducted by independent contractors engaged and supervised by the Company. The Company employs petroleum engineers, geologists, and other operations and production specialists who attempt to improve production rates, increase reserves and/or lower the cost of operating its oil and gas properties. Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator's direct expenses and monthly per-well supervision fees. Per-well supervision fees vary widely, depending on geographic location and producing formation of the well, whether the well produces oil or gas, and other factors. Such fees received by the Company in 1994 ranged from $50 to $1,372 per well per month. MARKETING OF PRODUCTION The Company typically sells its gas production at or near the wellhead, although in some cases it must be gathered by the Company or other operators and delivered to a central point. Gas production is generally sold in the spot market at prevailing prices. The Company generally sells its oil production at posted prices. The Company does not refine any oil it produces. No single oil or gas purchaser accounted for 10% or more of the Company's consolidated revenues during the three years ended December 31, 1994. The Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales. The following table summarizes sales volume, sales price, and production cost information for the Company's net oil and gas production for the three-year period ended December 31, 1994. "Net" production is production that is owned by the Company either directly or indirectly through limited partnerships or joint venture interests and produced to its interest after deducting royalty, limited partner, and other similar interests.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------ ----------------------- 1992 1993 1994 1994 1995 ---------- ---------- ---------- ---------- ---------- Production Oil (Bbl).......................... 283,928 324,486 467,056 99,992 134,626 Natural gas (Mcf)(1)............... 3,975,203 5,421,841 6,798,531 1,643,348 1,702,658 Weighted average sales price Oil (per Bbl)...................... $ 17.19 $ 15.10 $ 14.35 $ 11.80 $ 15.61 Natural gas (per Mcf).............. 1.90 1.96 1.93 2.21 1.63 Average production cost (per Mcfe)... $ 0.69 $ 0.62 $ 0.59 $ 0.51 $ 0.65
- --------------- (1) Natural gas production for 1992, 1993, 1994, and for the three-month periods ended March 31, 1994 and 1995 includes 1,148,862, 1,581,206, 1,358,378, 386,028 and 316,745 Mcf, respectively, delivered under the Volumetric Production Payment. Under the Volumetric Production Payment arrangement entered into in 1992, as of March 31, 1995, the Company has a remaining commitment to deliver approximately 5.1 Bcf of gas meeting certain heating equivalent and quality standards through October 2000, when such agreement expires. Since entering into this agreement, these properties have produced in excess of the required monthly delivery requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General." During 1994, the Company entered into three natural gas price hedging contracts covering a small portion of the Company's and limited partnerships' natural gas production. Two contracts covered 300,000 MMBtu, one for the first two months of 1994 and one for the last two months, providing for minimum prices of $2.25 and $1.58 per MMBtu, respectively. The third contract covered 1,000,000 MMBtu for July, August and September production with a floor price of $1.77. See "Risk Factors -- Effect of Price Risk Hedging." 27 28 FOREIGN ACTIVITIES During 1993, the Company entered into a Participation Agreement (the "Participation Agreement") with a Russian Federation joint stock company (in which the Company has an indirect interest of less than 1%) to develop and produce reserves in two fields in Western Siberia. Under this Participation Agreement, the Company would receive a minimum 5% net profits interest in return for an initial budgeted capital expenditure of up to $5.0 million. The Company also is pursuing opportunities in the oil and gas industry in Venezuela. These activities are described in greater detail in Note 10 to the Company's Consolidated Financial Statements. See "Risk Factors -- Foreign Activities." OIL AND GAS RESERVES All information set forth in this Prospectus regarding proved reserves, related future net revenues and PV-10 Value is taken from reports prepared by the Company and audited by H.J. Gruy and Associates, Inc. ("Gruy"), Houston, Texas, independent petroleum engineers. Gruy's estimates were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company, and their report is contained as an exhibit to the Registration Statement of which this Prospectus is a part. In accordance with SEC guidelines, the Company's estimates of future net revenues from the Company's proved reserves and the present value thereof (PV-10 Value) are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. Proved reserves at December 31, 1994, were estimated based upon weighted average prices of $1.85 per Mcf of natural gas and $15.09 per barrel of oil, compared to $2.50 and $2.45 per Mcf of natural gas and $12.87 and $17.52 per barrel of oil as of December 31, 1993 and 1992, respectively. Proved reserves at May 31, 1995 were estimated based on weighted average prices of $2.03 per Mcf of natural gas and $16.68 per barrel of oil. See "Risk Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues." The Company's total proved developed and undeveloped reserve volumes have increased at an annualized compounded rate of approximately 35% over the last five years. In 1994, the Company's proved natural gas reserves increased over 1993 year-end amounts by 18% or 11.8 Bcf and its proved oil reserves increased 7% or 282,198 Bbl. At May 31, 1995, natural gas reserves had increased over year-end 1994 amounts by 75% and oil reserves by 19%. The composition of these reserves has shifted substantially, with proved developed reserves comprising 77% of total proved reserves at year end 1993, 63% at year end 1994 and 39% at May 31, 1995. This shift reflects the recent reserve additions comprised of proved undeveloped reserves in newly acquired areas of the AWP Olmos Field. Additional reserves have also been added due to May 31, 1995 prices being higher than those at year-end 1994, which has the effect of changing quantities estimates and the estimated present value of such proved reserves. The table also sets forth estimates of future net revenues, presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC, and the PV-10 Value. Operating costs and development costs and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in the Notes to the Consolidated Financial Statements of the Company, which is calculated after provision for future income taxes. In cases where producing properties are subject to gas purchase contracts and the amount of gas purchased thereunder was reduced during 1994, gas projections used to estimate future net revenues were based on the reduced gas purchases for the affected producing properties. The assumption was made that purchases in 1995 and thereafter will be made at an unrestricted level. The Company has interests in certain tracts which are estimated to have additional hydrocarbon reserves which cannot be classified as proved and are not reflected in the following table. The proved reserves presented for all periods also exclude any reserves attributed to the Volumetric Production Payment. See "Management's Discussion of and Analysis of Financial Condition and Results of Operations -- General." There can be no assurance that these estimates are accurate predictions of future net revenues from oil and gas reserves or their present value. 28 29 ESTIMATED PROVED OIL AND GAS RESERVES
AT DECEMBER 31, ------------------------------------------- AT MAY 31, 1992 1993 1994 1995 ---------- ---------- ----------- ----------- NET NATURAL GAS RESERVES (MCF): Proved developed.................. 32,955,080 50,936,942 46,406,448 45,686,959 Proved undeveloped................ 8,683,020 13,525,863 29,857,516 87,648,967 ---------- ---------- ----------- ----------- Total proved natural gas reserves................ 41,638,100 64,462,805 76,263,964 133,335,926 ========== ========== =========== =========== NET OIL RESERVES (BBL): Proved developed.................. 2,082,885 3,110,505 3,209,387 3,252,151 Proved undeveloped................ 818,736 1,160,564 1,343,880 2,155,055 ---------- ---------- ----------- ----------- Total proved oil reserves................ 2,901,621 4,271,069 4,553,267 5,407,206 ========== ========== =========== =========== TOTAL PROVED RESERVES (MCFE)........ 59,047,826 90,089,219 103,583,566 165,779,162 ========== ========== =========== ===========
ESTIMATED PRESENT VALUE OF PROVED RESERVES
AT DECEMBER 31, -------------------------------------------- AT MAY 31, 1992 1993 1994 1995 ----------- ----------- ----------- ------------ ESTIMATED PV-10 VALUE: Proved developed.................. $45,192,000 $66,309,471 $47,172,093 $ 51,269,819 Proved undeveloped................ 10,248,000 17,451,305 22,222,511 48,926,612 ----------- ----------- ----------- ------------ Total..................... $55,440,000 $83,760,776 $69,394,604 $100,196,431 =========== =========== =========== ============
Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. A portion of the Company's proved reserves has been accumulated through the Company's interests in the limited partnerships for which it serves as general partner. The estimates of future net cash flows and their present values, based on period end prices, assume that some of the limited partnerships in which the Company owns interests will achieve payout status in the future. None of the limited partnerships had achieved payout status at May 31, 1995. 29 30 DRILLING ACTIVITY The following table sets forth the results of the Company's drilling activities during the three fiscal years ended December 31, 1994:
GROSS WELLS NET WELLS(1) --------------------------------- --------------------------------- YEAR TYPE OF WELL(2) TOTAL PRODUCING(3) DRY(4) TOTAL PRODUCING(3) DRY(4) - ---- --------------- ----- ------------ ------ ----- ------------ ------ 1992 Exploratory 7 2 5 2.2 0.7 1.5 Development 33 32 1 5.5 5.4 0.1 1993 Exploratory 12 5 7 5.6 2.5 3.1 Development 22 21 1 3.8 3.4 0.4 1994 Exploratory 14 6 8 9.2 4.7 4.5 Development 30 26 4 6.9 5.0 1.9
- --------------- (1) Represents the aggregate of the Company's direct or indirect fractional working interests in the gross wells drilled. (2) An exploratory well is a well drilled either in search of a new, as-yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. (3) A producing well is an exploratory or development well found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. (4) A dry well is an exploratory or development well that is not a producing well. OIL AND GAS WELLS The following table sets forth the number of oil and gas wells in which the Company had a working interest at December 31, 1994. All of these wells are located within the U.S.
OIL WELLS GAS WELLS TOTAL WELLS(1) --------- --------- -------------- Gross(2)......................................... 3,141.0 1,000.0 4,141.0 Net(3)........................................... 79.3 109.1 188.4
- --------------- (1) Excludes 31 service wells in 1994. (2) A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. (3) A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. 30 31 OIL AND GAS ACREAGE As is customary in the industry, the Company generally acquires oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although the Company has title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in the Company's judgment it would be uneconomical or impractical to do so. See "Risk Factors -- Risks of Purchasing Interests in Producing Properties." The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31, 1994:
DEVELOPED UNDEVELOPED ------------------------- ------------------------ GROSS(1) NET(2) GROSS(1) NET(2) ---------- ---------- ---------- --------- Alabama.................................... 7,075.72 820.82 372.00 61.17 Arkansas................................... 8,359.45 2,786.80 4,212.60 2,607.63 Kansas..................................... 1,750.00 691.67 5,450.00 2,268.55 Louisiana.................................. 33,364.35 13,841.90 4,943.64 4,401.75 Mississippi................................ 11,153.82 4,260.69 5,476.34 1,011.74 Nebraska................................... -- -- 1,867.04 1,169.53 New Mexico................................. 2,574.47 655.36 422.46 124.60 North Dakota............................... 1,276.19 147.25 9,157.23 957.30 Oklahoma................................... 56,018.81 21,792.40 5,842.08 2,757.14 Texas...................................... 108,368.32 44,662.46 35,651.07 24,622.95 West Virginia.............................. 16,048.20 10,484.50 -- -- Wyoming.................................... 9,306.64 2,780.34 23,085.01 7,111.05 All other states........................... 477.64 128.66 4,690.44 272.81 ---------- ---------- ---------- --------- TOTAL............................ 255,773.61 103,052.85 101,169.91 47,366.22 ========== ========== ========== =========
- --------------- (1) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. (2) A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. A material portion of the Company's acreage is owned by virtue of its interests derived from limited partnerships. The net acreage reflected on this table shows the Company's interests assuming that an after payout status is achieved in these limited partnerships. At May 31, 1995, none of the limited partnerships had achieved payout status. PARTNERSHIPS The Company has historically relied on limited partnerships as its principal financing vehicle to fund its activities. The Company has formed 95 limited partnerships which have raised a total of approximately $440.0 million at March 31, 1995. However, as the Company has increasingly shifted its emphasis to exploration and development activities and its reserve base has grown, the Company has significantly reduced its reliance on limited partnership financing. The Company intends to continue to reduce its reliance on limited partnerships in the future. Approximately 20 of the limited partnerships formed and managed by the Company have been in operation for nine years or more, and have produced a substantial majority of their reserves. Given the age of these limited partnerships, the Company currently intends to propose that the limited partners in these limited partnerships vote to sell their remaining properties and liquidate the limited partnerships. The Company may acquire some or all of the remaining property interests owned by these limited partnerships. At this time, the Company intends to propose to purchase such properties only after third party industry members are solicited to purchase such properties, and then only at prices based upon prices offered for the properties by such third parties. The Company currently offers two primary types of limited partnerships: Swift Depositary Interests ("SDI"), a publicly offered partnership program under which partnerships are formed to acquire interests in 31 32 producing oil and gas properties, and Swift Energy Drilling Ventures ("SEDV"), privately offered partnerships formed to engage in the drilling of development and exploratory wells. The Company does not intend to extend the SDI Program past its current offering period, which ends April 30, 1996, and will continue to evaluate the market for the SDI Program in the interim period. Under the SDI program, partnerships are formed on a sequential basis, typically at quarterly intervals. In 1994, the Company raised approximately $32.1 million under the SDI program. The SDI partnerships acquire, manage, and ultimately sell interests in properties that are producing oil and gas in commercial quantities or which contain shut-in wells capable of such production. The SDI partnerships seek to profit primarily from the sale of oil and gas produced from the properties in which they own interests, and from the proceeds of the eventual sale of their interests. In September of 1993, the Company began offering interests in SEDV. As of March 15, 1995, three partnerships (one in each of 1993, 1994 and 1995) with aggregate investor contributions of approximately $9.0 million had been formed under this program. The Company anticipates formation of at least one additional private drilling partnership in 1995. Both the SDI and SEDV partnerships are offered on a no-load basis under which the Company pays all selling and offering expenses of the offering. Amounts paid by the Company are treated as a capital contribution to each partnership. The Company does not bear any of the costs incurred in acquiring or drilling properties. In the SDI partnerships, the Company bears 14.25% of all other continuing costs (approximately 24.25% after payout) and in exchange, the Company is entitled to receive net revenues in the same percentages. In the SEDV partnerships, the Company pays approximately 20% of all continuing costs (approximately 30% after payout and 35% after 200% payout) and the Company is entitled to receive 20% of net revenues distributed by each SEDV partnership prior to payout, 30% distributed after payout, and 35% distributed after 200% payout. In both the SDI and SEDV partnerships, the Company is also entitled to a general and administrative overhead allowance and an incentive amount. CONFLICTS OF INTEREST BETWEEN THE COMPANY AND LIMITED PARTNERSHIPS Under the terms of the Company's limited partnership programs, the Company generally retains the right to engage in oil and gas exploration and production through other limited partnerships and joint ventures and for its own account. The partnership agreement for each limited partnership contains detailed provisions regarding the terms upon which a variety of transactions between the Company and the limited partnerships may be carried out, including (i) sales of properties by the Company to the limited partnerships, (ii) operation of limited partnership properties by the Company, (iii) rendering of oil field or drilling services by the Company to an limited partnership, (iv) handling of limited partnership funds by the Company, and (v) loans between the Company and an limited partnership. These restrictions, which may limit the ability of the Company to take certain actions, are intended to ensure that transactions between the Company and the limited partnerships are fair to such limited partnerships. RISK MANAGEMENT The Company's operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property, or individual injuries. The oil and gas exploration business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharges of toxic substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of limited partnerships, the Company is solely responsible for the day-to-day conduct of the limited partnerships' affairs and accordingly has liability for expenses and liabilities of the limited partnerships. The Company maintains comprehensive insurance coverage, including general liability insurance in an amount not less than $20.0 million, as well as general partner liability insurance. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in comparable operations, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. 32 33 COMPETITION The oil and gas industry is highly competitive in all its phases. The Company encounters strong competition from many other oil and gas producers, including many that possess substantial financial resources, in acquiring economically desirable producing properties and exploratory drilling prospects, and in obtaining equipment and labor to operate and maintain its properties. In marketing its partnership programs, the Company competes with other oil and gas companies sponsoring similar programs and with numerous other investment opportunities. REGULATIONS ENVIRONMENTAL REGULATIONS The federal government and various state and local governments have adopted laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas or where pollution arises, and impose substantial liabilities for pollution resulting from drilling operations particularly operations in offshore waters or on submerged lands. These laws and regulations may also increase the costs of drilling and operation of wells. However, the Company does not believe that it is affected in a significantly different manner by these regulations than are its competitors in the oil and gas industry. See "Risk Factors -- Effects of Governmental Regulation." FEDERAL REGULATION OF NATURAL GAS The transportation and sale of natural gas in interstate commerce is heavily regulated by agencies of the federal government. The following discussion is intended only as a brief summary of the principal statutes, regulations, and orders that may affect the production and sale of the Company's natural gas. This summary should not be relied upon as a complete review of applicable natural gas regulatory provisions. See "Risk Factors -- Volatility of Oil and Gas Prices and Markets." PRICE CONTROLS Prior to January 1, 1993, the sale of natural gas production was subject to regulation under the Natural Gas Act and the Natural Gas Policy Act of 1978 ("NGPA"). However, under the Natural Gas Wellhead Decontrol Act of 1989 all price regulation under the NGPA and Natural Gas Act of rate, certificate and abandonment requirements were phased out effective as of January 1, 1993. FERC ORDERS Several major regulatory changes have been implemented by the Federal Energy Regulatory Commission ("FERC") from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC's jurisdiction. In April 1992 the FERC issued Order No. 636 pertaining to pipeline restructuring. This rule requires interstate pipelines to unbundle transportation and sales services by separately stating the price of each service and by providing customers only the particular service desired, without regard to the source for purchase of the gas. The rule also requires pipelines to (i) provide nondiscriminatory "no-notice" service allowing firm commitment shippers to receive delivery of gas on demand up to certain limits without penalties, (ii) establish a basis for release and reallocation of firm upstream pipeline capacity, and (iii) provide non-discriminatory access to capacity by firm transportation shippers on a downstream pipeline. The rule requires interstate pipelines to use a straight fixed variable rate design. FERC Order No. 500 affects the transportation and marketability of natural gas. Traditionally, natural gas has been sold by producers to pipeline companies, which then resold the gas to end-users. FERC Order No. 500 alters this market structure by requiring interstate pipelines that transport gas for others to provide transportation service to producers, distributors and all other shippers of natural gas on a nondiscriminatory, 33 34 "first-come, first-served" basis ("open access transportation"), so that producers and other shippers can sell natural gas directly to end-users. FERC Order No. 500 contains additional provisions intended to promote greater competition in natural gas markets. It is not anticipated that the marketability of and price obtainable for the Company's natural gas production will be significantly affected by FERC Order No. 500. Gas produced normally will be sold to intermediaries who have entered into transportation arrangements with pipeline companies. These intermediaries will accumulate gas purchased from a number of producers and sell the gas to end-users through open access transportation. STATE REGULATIONS Production of any oil and gas by the Company will be affected to some degree by state regulations. Many states in which the Company operates have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit. FEDERAL LEASES Some of the Company's properties are located on federal oil and gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and orders affect the terms of leases, exploration and development plans, methods of operation, and related matters. EMPLOYEES At December 31, 1994, the Company employed 209 persons, including 28 engineers, 14 geologists and 11 landmen. None of the Company's employees are represented by a union. Relations with employees are considered to be good. FACILITIES The Company occupies approximately 73,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring in 2005 which provides for various expansion options. The payment obligations under the lease range from $12.50 per square foot in the first two years up to $18.50 per square foot in the last two years. A subsidiary of the Company maintains an office in Denver, Colorado. The Company has field offices in various locations from which Company employees supervise local oil and gas operations. LEGAL PROCEEDINGS No legal proceedings are pending other than ordinary routine litigation incidental to the Company's business. 34 35 MANAGEMENT EXECUTIVES AND CERTAIN OTHER OFFICERS AND DIRECTORS
NAME TITLE - --------------------------------------------- --------------------------------------------- A. Earl Swift................................ Chairman of the Board, President and Chief Executive Officer Virgil N. Swift.............................. Vice Chairman of the Board and Executive Vice President -- Business Development Terry E. Swift............................... Executive Vice President and Chief Operating Officer John R. Alden................................ Senior Vice President -- Finance, Chief Financial Officer and Secretary Bruce H. Vincent............................. Senior Vice President -- Funds Management James M. Kitterman........................... Senior Vice President -- Operations James R. Stewart............................. Vice President -- Drilling and Production Alton D. Heckaman, Jr........................ Vice President and Controller Joseph A. D'Amico............................ Vice President -- Exploration and Development G. Robert Evans.............................. Director Raymond O. Loen.............................. Director Henry C. Montgomery.......................... Director Clyde W. Smith, Jr........................... Director Harold J. Withrow............................ Director
A. Earl Swift, 61, is President, Chief Executive Officer and Chairman of the Board of Directors of the Company and has served in such capacity since its founding in 1979. For the 17 years prior to 1979, he was employed by affiliates of American Natural Resources Company, serving his last three years as Vice President of Exploration and Production for Michigan-Wisconsin Pipe Line Company and American Natural Gas Production Company. Mr. Swift is a registered professional engineer and holds a degree in Petroleum Engineering, a Juris Doctor degree and a Master's degree in Business Administration. He is the brother of Virgil N. Swift and the father of Terry E. Swift. Virgil N. Swift, 66, has been a director of the Company since 1981, and has acted as Vice Chairman of the Board and Executive Vice President -- Business Development since November 1991. He previously served as Executive Vice President and Chief Operating Officer from 1982 to November 1991. Mr. Swift joined the Company in 1981 as Vice President -- Drilling and Production. For the preceding 28 years he held various production, drilling and engineering positions with Gulf Oil Corporation and its subsidiaries, last serving as General Manager -- Drilling for Gulf Canada Resources, Inc. Mr. Swift is a registered professional engineer and holds a degree in Petroleum Engineering. Terry E. Swift, 39, was appointed Executive Vice President and Chief Operating Officer of the Company in November 1991. He served as Senior Vice President -- Exploration and Joint Ventures from 1990 to November 1991, as Vice President -- Exploration and Joint Ventures from 1988 to 1990 and as Assistant Vice President -- Engineering from 1986 to 1988. Mr. Swift is a registered professional engineer and holds a degree in Chemical Engineering and a Master's degree in Business Administration. John R. Alden, 49, Senior Vice President -- Finance, Chief Financial Officer and Secretary, joined the Company in 1981. Mr. Alden was appointed to his current offices in 1990. Prior to that time he served the Company as its principal financial officer under a variety of titles. Mr. Alden holds a degree in Accounting and a Master's degree in Business Administration. Bruce H. Vincent, 47, joined the Company as Senior Vice President--Funds Management in 1990. Mr. Vincent acted as Chief Operating Officer of Energy Assets International Corp. from 1986 to 1988, and as President of Vincent & Company, an investment banking firm, from 1988 to 1990. Mr. Vincent holds a degree in Business Administration and a Master's degree in Finance. 35 36 James M. Kitterman, 51, was appointed Senior Vice President -- Operations in May 1993. He had previously served as Vice President -- Operations since joining the Company in 1983 with 16 years of prior experience in oil and gas exploration, drilling and production. Mr. Kitterman holds a degree in Petroleum Engineering and a Master's degree in Business Administration. James R. Stewart, 59, was appointed Vice President -- Drilling and Production in August 1993. He joined the Company as Manager of Operations in 1990. He has 30 years experience in drilling, production, reservoir engineering, and geology. During his 30 years in the oil and gas industry, Mr. Stewart has held a variety of management level positions. Mr. Stewart holds a degree in Petroleum Engineering. Alton D. Heckaman, Jr., 38, was appointed Vice President and Controller in May 1993. He had previously served as Assistant Vice President -- Finance and Controller since 1986. Mr. Heckaman joined the Company in 1982. He is a Certified Public Accountant and holds a degree in Accounting. Joseph A. D'Amico, 47, has been Vice President -- Exploration and Development of the Company since August 1993. He served in the funds management division and as Director of Exploration and Development of the Company from 1988 to 1993. Mr. D'Amico holds a degree in Petroleum Engineering and Master's degrees in Petroleum Engineering and Finance. G. Robert Evans, 64, has been a director of the Company since 1994. Since 1991, he has been Chairman and Chief Executive Officer of Material Sciences Corporation of Elk Grove Village, a corporation that develops and commercializes continuously processed, coated materials technologies. He is also currently serving as a director of three other public companies: Consolidated Freightways, Inc. (transportation), Fibreboard Corporation (wood products, insulation and resort operations) and Elco Industries (manufacturing). From 1990 until 1991, he served as President, Chief Executive Officer and a Director of Corporate Finance Associates of Illinois, Inc., a financial intermediary and consulting firm. From 1987 until 1990, he served as President, Chief Executive Officer and a Director of Bemrose Group USA, a British holding company engaged in value-added manufacturing and sale of products to the advertising specialty industry. Raymond O. Loen, 71, has served as a director of the Company since its founding in 1979. Since 1963, he has been President of R.O. Loen Company, a privately held management consulting firm headquartered in Lake Oswego, Oregon. Henry C. Montgomery, 59, has served as a director of the Company since 1987. Since 1980, Mr. Montgomery has been the Chairman of the Board of Montgomery Financial Services Corporation, a management consulting and financial services firm. Mr. Montgomery also currently serves as a director of Catalyst Semiconductor, Inc., a public company engaged in the design and manufacture of semiconductors. Mr. Montgomery previously served as Chairman of the Board of each of Private Financial Services Corporation, a management consulting and financial services firm (1986 to 1989), and Aquanautics Corporation, a public company involved in the extraction of oxygen from water and air (1986 to 1991). Clyde W. Smith, Jr., 46, has served as a director of the Company since 1984. He has served as President of Somerset Properties, Inc., a real estate and investment company, since 1985, as President of AdVision, Inc., which markets video display merchandising systems, since 1988 and as President of H&R Precision, Inc., a general contractor, since 1994. Mr. Smith formerly acted as Chief Executive Officer of California Video Sales, Inc. from 1987 to 1990. Harold J. Withrow, 67, has been a director of the Company since 1988. Mr. Withrow is an independent oil and gas consultant. From 1975 until 1988, Mr. Withrow served as Senior Vice President -- Gas Supply for Michigan Wisconsin Pipe Line Company and its successor, ANR Pipeline Company. COMPENSATION TO DIRECTORS STANDARD ARRANGEMENTS During 1995, nonemployee members of the board of directors will receive $1,750 per board meeting attended, an annual fee of $5,000 for serving on committees of the board, and an additional annual fee of 36 37 $5,000 for services as a director. Board members are reimbursed for travel expenses they incur in attending board of directors meetings. Employees of the Company are not compensated for serving as directors. STOCK OPTIONS GRANTED TO NONEMPLOYEE DIRECTORS Under the Company's 1990 Nonqualified Stock Option Plan, as amended (the "Nonqualified Plan"), each nonemployee director is granted options to purchase 10,000 shares of the Common Stock on the date he first becomes a nonemployee director. Additionally, on the day after each annual meeting of the Company's shareholders, each individual who is a nonemployee director on that date is granted, subject to an option maximum, options to purchase 5,000 shares of the Common Stock. A grant of options to a nonemployee director is reduced to the extent that it would cause him to hold unexercised options to purchase more than 60,000 shares of the Common Stock. Options granted under the Nonqualified Plan (i) have an exercise price equal to the highest closing price of the Common Stock on any established national exchange on the date of grant, (ii) are for a term of 10 years from the date of grant, and (iii) become exercisable for 20% of the shares covered thereby on each of the first five anniversaries of the date of grant. None of the nonemployee directors exercised options during the year ended December 31, 1994. EXECUTIVE COMPENSATION SUMMARY OF CASH AND CERTAIN OTHER COMPENSATION The following table sets forth certain summary information regarding compensation paid or accrued by the Company to or on behalf of the Company's Chief Executive Officer and each of the other four most highly compensated executive officers of the Company (determined as of the end of the last fiscal year) for the fiscal years ended December 31, 1992, 1993 and 1994. SUMMARY COMPENSATION TABLE(1)
LONG TERM COMPENSATION ------------ AWARDS ANNUAL COMPENSATION ------------ --------------------------------- SECURITIES ALL OTHER COMPENSATION BONUS UNDERLYING ------------------------ NAME AND ------------------- OPTIONS/SARS LIFE 401(K) PRINCIPAL POSITION YEAR SALARY CASH STOCK (2) INSURANCE (3) (4) - ----------------------------------- ---- ---------- -------- ------- ------------ --------------- ------ A. EARL SWIFT...................... 1994 $278,400 $128,000 $32,000 12,100(5) $102,240 $7,500 Chief Executive Officer, 1993 260,180 136,000 34,000 23,980(6) 47,941 7,925 President 1992 240,000 120,000 30,000 19,800 39,905 7,530 VIRGIL N. SWIFT.................... 1994 190,600 23,898 5,975 12,100(5) 29,019 7,500 Executive Vice 1993 178,180 31,350 7,839 21,340(6) 22,369 7,816 President -- Business Development 1992 168,000 20,164 5,041 16,500 17,072 6,280 TERRY E. SWIFT..................... 1994 158,300 21,117 5,279 52,756 6,138 7,500 Chief Operating Officer, 1993 145,180 27,100 6,775 16,390 5,573 7,580 Executive Vice President 1992 125,000 16,172 4,043 13,750 1,464 4,871 JOHN R. ALDEN...................... 1994 142,500 17,296 4,324 37,730 11,419 7,500 Chief Financial Officer, 1993 133,180 23,430 5,859 13,640 8,781 7,512 Senior Vice President -- Finance 1992 123,000 15,092 3,773 11,000 4,374 4,727 JAMES M. KITTERMAN................. 1994 138,400 17,353 4,338 46,750 12,328 7,500 Senior Vice President -- Operations 1993 128,180 22,720 5,682 11,000 10,294 7,350 1992 118,000 13,848 3,462 8,800 5,000 4,571
- --------------- (1) Full executive compensation disclosure is set forth in the Company's definitive proxy statement mailed to shareholders in connection with the Company's May 9, 1995 annual meeting, incorporated herein by reference. See "Incorporation of Certain Information by Reference." (2) The numbers of securities underlying options granted in 1992, 1993 and 1994 reflect the 10% stock dividend that occurred in September 1994. (3) Represents insurance premiums paid by the Company during the covered fiscal year with respect to life insurance for the benefit of the named executive officer. (4) Contributions by the Company (one-half in cash and one-half in Company stock) for the account of the named executive officer to the Swift Energy Company Employee Savings Plan. (5) Includes for each of Messrs. A. E. Swift and V. N. Swift, respectively, previously granted options for 12,100 shares that were extended and repriced in 1994. (6) Includes for each of Messrs. A. E. Swift and V. N. Swift, respectively, previously granted options for 3,300 shares that were extended and repriced in 1993. 37 38 PRINCIPAL SHAREHOLDERS The following table sets forth information concerning the shareholdings, as of May 31, 1995, of the seven current members of the board of directors, each of the Company's five most highly compensated executive officers, all executive officers and directors as a group, and each person who beneficially owns more than five percent of the Company's outstanding common stock.
SHARES OF COMMON STOCK BENEFICIALLY OWNED AT MAY 31, 1995(1) ------------------------- PERCENT OF CLASS NAME OF PERSON OR GROUP POSITION NUMBER OUTSTANDING - -------------------------- ----------------------------------------------- --------- ----------- A. Earl Swift............. Chairman of the Board, President, Chief 4.1% Executive Officer 304,437(2) Virgil N. Swift........... Vice Chairman of the Board, Executive Vice 4.1% President -- Business Development 302,909 G. Robert Evans........... Director 2,000 (3) Raymond O. Loen........... Director 141,356(4) 1.9% Henry C. Montgomery....... Director 29,370 (3) Clyde W. Smith, Jr. ...... Director 24,125 (3) Harold J. Withrow......... Director 27,720 (3) Terry E. Swift............ Executive Vice President, Chief Operating (3) Officer 55,987 John R. Alden............. Senior Vice President -- Finance, Chief (3) Financial Officer, Secretary 44,401(5) James M. Kitterman........ Senior Vice President -- Operations 35,041 (3) All executive officers & directors as a group (12 persons)................. 1,014,917 13.7% Foreign & Colonial Management Limited...................................... 417,216(6) 6.2% Hypo Foreign & Colonial Management (Holdings) Limited Exchange House, Primrose Street London EC2A 2NY England FMR Corp................................................................... 367,158(7) 5.5% 82 Devonshire Street Boston, Massachusetts 02109 Dimensional Fund Advisors Inc. ............................................ 344,560(8) 5.1% 1299 Ocean Avenue, 11th Floor Santa Monica, California 90401
- --------------- (1) Unless otherwise indicated below, the persons named have sole voting and investment power over the number of shares of the Company's common stock shown as being owned by them. The table includes the following shares that were acquirable within 60 days following May 31, 1995 by exercise of options granted under the Company's stock option plans: Mr. A. E. Swift -- 36,256; Mr. V. N. Swift -- 34,408; Mr. Loen -- 22,000; Mr. Smith -- 19,800; Mr. Montgomery -- 25,960; Mr. Withrow -- 25,520; Mr. T. E. Swift -- 34,575; Mr. Alden -- 30,932; Mr. Kitterman -- 21,230; and all executive officers and directors as a group -- 293,920. (2) Includes 4,858 shares held by Mr. Swift's wife. (3) Less than one percent. (4) Includes 14,300 shares as to which Mr. Loen, as co-trustee for an HR-10 Retirement Plan, shares voting and investment power with his wife; 70,000 shares held by his wife (who holds sole voting and investment power as to those shares and 3,680 shares held in her IRA), and 4,554 shares held in Mr. Loen's IRA. (5) Includes 100 shares held by Mr. Alden's mother of which he could be deemed to be the beneficial owner. (6) Based on a Schedule 13D dated April 26, 1993 filed with the SEC. (7) Based on a Schedule 13G dated February 13, 1995 filed with the SEC, Fidelity Management & Research Company ("Fidelity"), a wholly-owned subsidiary of FMR Corp., an investment adviser registered under Section 203 of the Investment Advisers Act of 1940, is deemed to be the beneficial owner of 367,158 shares of the Company's shares as a result of acting as an investment adviser to several investment companies registered under Section 8 of the Investment Company Act of 1940 (the "Funds"). Edward C. Johnson 3d and Abigail P. Johnson each own 24.9% of the outstanding voting common stock of FMR Corp., and various Johnson family members and trusts for the benefit of Johnson family members own FMR Corp. voting common stock. Edward C. Johnson 3d, FMR Corp. (through its control of Fidelity) and the Funds each have sole power to dispose of the 367,158 shares owned by the Funds, but neither FMR Corp. nor Edward C. Johnson 3d, Chairman of FMR Corp., has any power to vote or direct the voting of the shares owned directly by the Funds, which power resides with the Funds' Boards of Trustees. (8) Based on a Schedule 13G dated January 31, 1995 filed with the SEC. Dimensional Fund Advisors Inc. ("Dimensional") is deemed to have beneficial ownership of 344,560 shares of the Company's stock as of December 31, 1994, all of which shares are held in portfolios of DFA Investment Dimensions Group Inc., a registered open-end investment company, or in series of the DFA Investment Trust Company, a Delaware business trust, or the DFA Group Trust and DFA Participation Group Trust, investment vehicles for qualified employee benefit plans, for all of which Dimensional serves as investment manager. Dimensional disclaims beneficial ownership of all such shares. Dimensional has sole voting power as to 257,950 shares and sole dispositive power as to all 344,560 shares. 38 39 DESCRIPTION OF CAPITAL STOCK PREFERRED STOCK The Company is authorized to issue 5,000,000 shares of preferred stock, par value $.01, of which no shares have been issued. Under the Company's Articles of Incorporation, the Company's Board of Directors is authorized, without shareholder action, to issue preferred stock in one or more series and to fix the number of shares and the rights, preferences and limitations of each series. Among the specific matters that may be determined by the Board of Directors are the dividend rate, the redemption price, if any, conversion rights, if any, the amount payable in the event of any voluntary liquidation or dissolution of the Company and voting rights, if any. COMMON STOCK The Company is authorized to issue 35,000,000 shares of Common Stock, par value $.01, of which 6,718,742 were issued and outstanding at May 31, 1995. Holders of Common Stock are entitled to one vote for each share held. Shareholders do not have preemptive rights or the right to cumulate votes for the election of directors. Shares are not subject to redemption nor to any liability for further calls. All shares of Common Stock issued and outstanding are, and all the shares offered by the Company hereby when issued will be, validly issued, fully paid and non-assessable. Holders of the Common Stock are entitled to receive dividends as they are declared by the board of directors out of funds legally available therefor and are entitled to participate in the assets of the Company available for distribution in the event of liquidation or dissolution. See "Price Range of Common Stock and Dividend Policy." At May 31, 1995, there were 2,418,697 shares, in the aggregate, reserved for issuance under the Company's stock option plans, of which 1,324,288, in the aggregate, were subject to outstanding options. In addition, 68,750 shares were reserved for issuance upon the exercise of outstanding options granted outside the Company's option plans, and 2,343,113 shares were reserved for issuance upon conversion of the outstanding $28.75 million of 6 1/2% Convertible Subordinated Debentures due 2003, based upon a conversion price of $12.27 per share. The Company does not currently have any plans to issue additional shares of Common Stock other than pursuant to its 1990 Stock Compensation Plan, its 1990 Nonqualified Plan, and its Employee Stock Purchase Plan. TRANSFER AGENT American Stock Transfer & Trust Company, New York, New York is the transfer agent and registrar for the Common Stock. BYLAW AMENDMENTS Under Texas law, the board of directors may amend the Company's bylaws to authorize a classified board, among other things, without shareholder approval. A proposal may be brought before the board of directors in the near future to amend the bylaws to include a classified board and other measures that could have an effect of delaying, deferring or preventing a change in control of the Company. 39 40 UNDERWRITING Subject to the terms and conditions set forth in the Underwriting Agreement among the Company and the Underwriters named below, for whom Oppenheimer & Co., Inc., Morgan Keegan & Company, Inc. and Southcoast Capital Corporation are acting as representatives (the "Representatives"), the Underwriters named below have severally agreed to purchase from the Company, and the Company has agreed to sell to the Underwriters, the number of shares of Common Stock set forth opposite their respective names:
NUMBER UNDERWRITER(S) OF SHARES ------------------------------------------------------------------------ ----------- Oppenheimer & Co., Inc. ................................................ 900,000 Morgan Keegan & Company, Inc. .......................................... 895,000 Southcoast Capital Corporation.......................................... 895,000 Bear, Stearns & Co. Inc. ............................................... 100,000 Dean Witter Reynolds Inc................................................ 100,000 Dillon, Read & Co. Inc. ................................................ 100,000 A.G. Edwards & Sons, Inc. .............................................. 100,000 Goldman, Sachs & Co. ................................................... 100,000 Howard, Weil, Labouisse, Friedrichs Incorporated........................ 100,000 Kemper Securities, Inc. ................................................ 100,000 Lehman Brothers Inc. ................................................... 100,000 Morgan Stanley & Co. Incorporated....................................... 100,000 Prudential Securities Incorporated...................................... 100,000 Salomon Brothers Inc ................................................... 100,000 First Albany Corporation................................................ 100,000 Advest, Inc. ........................................................... 50,000 Robert W. Baird & Co. Incorporated...................................... 50,000 J.C. Bradford & Co. .................................................... 50,000 Crowell, Weedon & Co. .................................................. 50,000 Fahnestock & Co. Inc. .................................................. 50,000 Gerard Klauer Mattison & Co. ........................................... 50,000 Janney Montgomery Scott Inc. ........................................... 50,000 Jefferies & Company, Inc. .............................................. 50,000 Ladenburg, Thalmann & Co. Inc. ......................................... 50,000 Legg Mason Wood Walker, Incorporated.................................... 50,000 McDonald & Company Securities, Inc. .................................... 50,000 Nesbitt Burns Securities Inc. .......................................... 50,000 Neuberger & Berman...................................................... 50,000 Petrie Parkman & Co. ................................................... 50,000 Principal Financial Securities, Inc. ................................... 50,000 Rauscher Pierce Refsnes, Inc. .......................................... 50,000 The Robinson-Humphrey Company, Inc. .................................... 50,000 Stephens Inc. .......................................................... 50,000 First Colonial Securities Group, Inc. .................................. 30,000 Hanifen, Imhoff Inc. ................................................... 30,000 C.L. King & Associates, Inc. ........................................... 30,000 Parker/Hunter Incorporated.............................................. 30,000 Scott & Stringfellow, Inc. ............................................. 30,000 Starr Securities, Inc. ................................................. 30,000 Wellington (H.G.) & Co. Inc. ........................................... 30,000 ------- Total......................................................... 5,000,000 =======
The Underwriting Agreement provides that the obligations of the Underwriters thereunder are subject to approval of certain legal matters by counsel and to various other conditions. The nature of the Underwriters' 40 41 obligations is such that they are committed to purchase all of the above shares of Common Stock if any are purchased. The Underwriters propose to offer the shares of Common Stock directly to the public at the offering price set forth on the cover page of this Prospectus and at such price less a concession not in excess of $0.30 per share of Common Stock to certain securities dealers, of which a concession not in excess of $0.10 per share of Common Stock may be reallowed to certain other securities dealers. After this public offering, the public offering price, allowances, concessions and other selling terms may be changed by the Representatives. The Company has granted to the Underwriters an option, exercisable within 30 days after the date of this Prospectus, to purchase from the Company up to an aggregate of 750,000 additional shares of Common Stock to cover over-allotments, if any, at the public offering price less the underwriting discount set forth on the cover page of this Prospectus. If the Underwriters exercise their over-allotment option to purchase any of the 750,000 additional shares of Common Stock, the Underwriters have severally agreed, subject to certain conditions, to purchase approximately the same percentage thereof as the number of shares of Common Stock as may be purchased by each of them bears to the 5,000,000 shares of Common Stock offered hereby. The Company will be obligated, pursuant to the over-allotment option, to sell shares to the Underwriters to the extent such over-allotment option is exercised. The Underwriters may exercise such option only to cover over-allotments made in connection with the sale of the shares of Common Stock offered hereby. All executive officers and directors of the Company, as a group, holding 1,014,917 shares in the aggregate have agreed, pursuant to lock-up agreements executed in connection with this offering, that until 120 days from the date of this Prospectus, they will not sell, make any short sale of, loan, grant any option for the purchase or otherwise dispose of any shares or any securities convertible into or exchangeable or exercisable for shares without the consent of Oppenheimer & Co., Inc. The Company has agreed that it will not, without the consent of Oppenheimer & Co., Inc., offer, sell, or dispose of any shares of Common Stock, options or warrants to acquire shares of Common Stock or securities exchangeable for or convertible into shares of Common Stock until 120 days after this offering (except for (i) shares issued pursuant to stock options outstanding on the date hereof and (ii) stock options issued pursuant to employee benefit or incentive compensation plans in effect on the date hereof). The Company has agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to certain payments that the Underwriters may be required to make in respect thereof. An affiliate of a member of the National Association of Securities Dealers, Inc. ("NASD") that is participating in the offering will receive greater than 10% of the net proceeds of the offering. Accordingly, the offering is being conducted pursuant to the provisions of Article III, Section 44(c)(8) of the NASD's Rules of Fair Practice. The Underwriters do not intend to confirm sales of the Common Stock offered hereby to any account over which they exercise discretionary authority. LEGAL MATTERS The validity of the Common Stock offered hereby will be passed upon for the Company by Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain legal matters will be passed upon for the Underwriters by Akin, Gump, Strauss, Hauer & Feld, L.L.P., Houston, Texas. EXPERTS The consolidated financial statements included in this Prospectus and elsewhere in the Registration Statement, to the extent and for the periods indicated in their reports, have been audited by Arthur Andersen LLP, independent public accountants, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. 41 42 The reference to the reports of H.J. Gruy and Associates, Inc., independent petroleum consultants, contained herein with respect to the proved reserves, the estimated future net revenues from such proved reserves, and the discounted present values of such estimated future net revenues, is made in reliance upon the authority of such firm as experts with respect to such matters. INCORPORATION OF CERTAIN INFORMATION BY REFERENCE The Company's Form 10-K as of December 31, 1994, its definitive proxy statement mailed to shareholders in connection with the May 9, 1995, annual shareholders' meeting and its Form 10-Q for the quarterly period ended March 31, 1995, are incorporated herein by reference. The Company will furnish without charge to each person to whom this Prospectus is delivered, upon written or oral request of such person, a copy of the documents referred to above, excluding exhibits thereto. Requests should be made to: John R. Alden, Secretary, Swift Energy Company, 16825 Northchase Drive, Suite 400, Houston, Texas 77060-9968. 42 43 SWIFT ENERGY COMPANY AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Public Accountants............................................... F-2 Consolidated Balance Sheets............................................................ F-3 Consolidated Statements of Income...................................................... F-4 Consolidated Statements of Stockholders' Equity........................................ F-5 Consolidated Statements of Cash Flows.................................................. F-6 Notes to Consolidated Financial Statements............................................. F-7
F-1 44 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Swift Energy Company: We have audited the accompanying consolidated balance sheets of Swift Energy Company (a Texas corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Swift Energy Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As discussed in Note 2 to the consolidated financial statements, effective January 1, 1994, the Company changed its method of accounting for earned interests. As discussed in Note 3 to the consolidated financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes. ARTHUR ANDERSEN LLP Houston, Texas February 17, 1995 F-2 45 SWIFT ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ----------------------------- MARCH 31, 1993 1994 1995 ------------ ------------ ------------ (UNAUDITED) ASSETS Current Assets: Cash and cash equivalents............................................ $ 636,349 $ 985,498 $ 1,531,762 Accounts receivable -- Oil and gas sales.................................................. 13,938,932 12,394,636 12,532,029 Associated limited partnerships and joint ventures................. 28,507,948 17,899,150 13,904,695 Joint interest owners.............................................. 2,923,797 4,335,283 4,240,136 Producing oil and gas properties held for transfer................... 15,436,853 3,525,841 3,005,520 Limited partnership formation and marketing costs.................... 2,227,100 -- -- Other current assets................................................. 1,636,141 68,010 128,255 ------------ ------------ ------------ Total Current Assets........................................... 65,307,120 39,208,418 35,342,397 ------------ ------------ ------------ Property and Equipment: Oil and gas, using full-cost accounting Proved properties being amortized.................................. 106,251,713 93,368,795 97,257,030 Unproved properties not being amortized............................ 7,932,557 14,805,479 16,318,934 ------------ ------------ ------------ 114,184,270 108,174,274 113,575,964 Furniture, fixtures and other equipment.............................. 2,969,389 3,476,695 3,819,581 ------------ ------------ ------------ 117,153,659 111,650,969 117,395,545 Less -- Accumulated depreciation, depletion and amortization........... (25,847,271) (21,364,949) (23,533,177) ------------ ------------ ------------ 91,306,388 90,286,020 93,862,368 ------------ ------------ ------------ Other Assets: Receivables from associated limited partnerships, net of current portion............................................................ -- 1,916,477 2,185,975 Limited partnership formation and marketing costs, net of current portion............................................................ 2,904,274 2,991,873 3,162,422 Deferred charges..................................................... 1,375,135 1,269,955 1,242,232 ------------ ------------ ------------ 4,279,409 6,178,305 6,590,629 ------------ ------------ ------------ $160,892,917 $135,672,743 $135,795,394 ============ ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Short-term bank borrowings........................................... $ 2,650,000 $ 27,229,000 $ 30,550,000 Accounts payable and accrued liabilities............................. 7,518,577 9,516,005 6,634,006 Payable to associated limited partnerships........................... 769,373 637,991 35,184 Payable related to producing oil and gas property acquisitions....... 27,118,706 -- -- Undistributed oil and gas revenues................................... 17,508,781 14,962,863 14,852,256 ------------ ------------ ------------ Total Current Liabilities...................................... 55,565,437 52,345,859 52,071,446 ------------ ------------ ------------ Long-Term Debt......................................................... 28,750,000 28,750,000 28,750,000 Deferred Revenues...................................................... 9,819,530 7,827,562 7,346,764 Deferred Income Taxes.................................................. 12,292,236 4,622,191 4,748,684 Commitments and Contingencies Stockholders' Equity: Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding........................................................ -- -- -- Common stock, $.01 par value, 35,000,000 shares authorized, 6,001,075, 6,685,137, and 6,710,412 shares issued and outstanding, respectively....................................................... 60,011 66,851 67,104 Additional paid-in capital........................................... 17,515,417 24,885,903 25,112,419 Retained earnings.................................................... 36,890,286 17,174,377 17,698,977 ------------ ------------ ------------ 54,465,714 42,127,131 42,878,500 ------------ ------------ ------------ $160,892,917 $135,672,743 $135,795,394 ============ ============ ============
See accompanying notes to Consolidated Financial Statements. F-3 46 SWIFT ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------------ -------------------------- 1992 1993 1994 1994 1995 ----------- ----------- ------------ ------------ ---------- (UNAUDITED) Revenues: Oil and gas sales.................. $12,420,222 $15,535,671 $ 19,802,188 $ 4,817,270 $4,876,041 Earned interests from limited partnerships and joint ventures......................... 1,692,331 3,308,623 -- -- -- Fees from limited partnerships and joint ventures................... 1,023,946 763,347 701,528 108,682 113,430 Supervision fees................... 3,443,777 3,718,829 3,751,061 943,148 904,539 Interest income.................... 113,387 201,584 47,980 18,644 7,484 Other, net......................... 515,931 604,599 1,072,535 250,791 357,094 ----------- ----------- ----------- ---------- ---------- 19,209,594 24,132,653 25,375,292 6,138,535 6,258,588 ----------- ----------- ----------- ---------- ---------- Costs and Expenses: General and administrative, net of reimbursement.................... 4,977,440 5,065,323 5,197,899 1,195,331 1,306,765 Depreciation, depletion and amortization..................... 4,906,029 7,300,967 7,904,801 1,688,938 2,168,229 Oil and gas production............. 3,934,294 4,540,290 5,639,630 1,142,288 1,629,379 Interest expense................... 76,477 597,465 1,795,133 358,975 477,781 Impairment of investment in drilling tool subsidiary......... 627,835 -- -- -- -- ----------- ----------- ----------- ---------- ---------- 14,522,075 17,504,045 20,537,463 4,385,532 5,582,154 ----------- ----------- ----------- ---------- ---------- Income Before Income Taxes........... 4,687,519 6,628,608 4,837,829 1,753,003 676,434 Provision for Income Taxes........... 1,517,759 1,732,355 1,112,158 542,281 151,834 ----------- ----------- ----------- ---------- ---------- Income Before Cumulative Effect of Change in Accounting Principle..... 3,169,760 4,896,253 3,725,671 1,210,722 524,600 Cumulative Effect of Change in Accounting Principle............... 915,000 -- (16,772,698) (16,772,698) -- ----------- ----------- ----------- ---------- ---------- Net Income (Loss).................... $ 4,084,760 $ 4,896,253 $(13,047,027) $(15,561,976) $ 524,600 =========== =========== =========== ========== ========== Per Share Amounts -- Primary: Income Before Cumulative Effect of Change in Accounting Principle... $ 0.52 $ 0.74 $ 0.56 $ 0.18 $ 0.08 =========== =========== =========== ========== ========== Cumulative Effect of Change in Accounting Principle............. $ 0.15 $ -- $ (2.52) $ (2.54) $ -- =========== =========== =========== ========== ========== Net Income (Loss).................. $ 0.67 $ 0.74 $ (1.96) $ (2.36) $ 0.08 =========== =========== =========== ========== ========== Fully Diluted: Income Before Cumulative Effect of Change in Accounting Principle... $ 0.52 $ 0.70 $ 0.56 $ 0.17 $ 0.08 =========== =========== =========== ========== ========== Cumulative Effect of Change in Accounting Principle............. $ 0.15 $ -- $ (2.52) $ (2.54) $ -- =========== =========== =========== ========== ========== Net Income (Loss).................. $ 0.67 $ 0.70 $ (1.96) $ (2.36) $ 0.08 =========== =========== =========== ========== ========== Weighted Average Shares Outstanding........................ 6,135,044 6,588,076 6,644,248 6,601,733 6,689,350 =========== =========== =========== ========== ========== Pro forma amounts assuming change in accounting for earned interests is applied retroactively (see Note 2) -- Net Income......................... $ 3,729,851 $ 4,322,478 $ 3,725,671 $ 1,210,722 $ 524,600 Per Share Amounts -- Primary.......................... $ 0.61 $ 0.66 $ 0.56 $ 0.18 $ 0.08 Fully Diluted.................... $ 0.61 $ 0.63 $ 0.56 $ 0.17 $ 0.08
See accompanying notes to Consolidated Financial Statements. F-4 47 SWIFT ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
ADDITIONAL COMMON PAID-IN RETAINED STOCK(1) CAPITAL EARNINGS TOTAL ------- ----------- ------------ ------------ Balance, December 31, 1991............. $49,551 $10,701,532 $ 27,909,273 $ 38,660,356 Stock issued for benefit plans (23,445 shares)................... 235 138,059 -- 138,294 Stock issued in institutional placement (990,000 shares)........ 9,900 6,387,976 -- 6,397,876 Net Income........................... -- -- 4,084,760 4,084,760 ------- ----------- ------------ ------------ Balance, December 31, 1992............. $59,686 $17,227,567 $ 31,994,033 $ 49,281,286 Stock issued for benefit plans (19,096 shares)................... 191 170,059 -- 170,250 Stock options exercised (13,400 shares)........................... 134 117,791 -- 117,925 Net Income........................... -- -- 4,896,253 4,896,253 ------- ----------- ------------ ------------ Balance, December 31, 1993............. $60,011 $17,515,417 $ 36,890,286 $ 54,465,714 Stock issued for benefit plans (26,488 shares)................... 265 271,176 -- 271,441 Stock options exercised (21,472 shares)........................... 214 176,808 -- 177,022 Employee stock purchase plan (29,840 shares)........................... 298 259,683 -- 259,981 10% stock dividend (606,262 shares)........................... 6,063 6,662,819 (6,668,882) -- Net Loss............................. -- -- (13,047,027) (13,047,027) ------- ----------- ------------ ------------ Balance, December 31, 1994............. $66,851 $24,885,903 $ 17,174,377 $ 42,127,131 Stock issued for benefit plans (22,782 shares)................... 228 207,587 -- 207,815 Stock options exercised (2,493 shares)........................... 25 18,929 -- 18,954 Net Income........................... -- -- 524,600 524,600 ------- ----------- ------------ ------------ Balance, March 31, 1995................ $67,104 $25,112,419 $ 17,698,977 $ 42,878,500 ======= =========== ============ ============
- --------------- (1) $.01 par value. See accompanying notes to Consolidated Financial Statements. F-5 48 SWIFT ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------------ -------------------------- 1992 1993 1994 1994 1995 ------------ ------------ ------------ ------------ ----------- (UNAUDITED) Cash Flows from Operating Activities: Net income (loss)............................... $ 4,084,760 $ 4,896,253 $(13,047,027) $(15,561,976) $ 524,600 Adjustments to reconcile net income to net cash provided by operating activities -- Depreciation, depletion and amortization...... 4,906,029 7,300,967 7,904,801 1,688,938 2,168,229 Deferred income taxes......................... 468,097 1,199,057 963,324 398,935 126,493 Earned interests from limited partnerships and joint ventures.............................. (1,692,331) (3,308,623) -- -- -- Deferred revenue amortization related to production payment.......................... (1,666,390) (2,304,080) (1,993,863) (570,629) (464,731) Impairment of investment in drilling tool subsidiary.................................. 627,835 -- -- -- -- Cumulative effect of change in accounting principle................................... (915,000) -- 16,772,698 16,772,698 -- Other......................................... 530,492 49,865 105,180 25,830 27,723 Change in assets and liabilities -- (Increase) decrease in accounts receivable............. (398,676) (412,960) (762,789) (625,829) 27,181 Increase in accounts payable and accrued liabilities, excluding income taxes payable..................................... 204,602 110,324 142,883 457,909 522,280 Increase (decrease) in income taxes payable... 199,662 (292,463) 309,307 94,095 32,322 ------------ ------------ ------------ ------------ ----------- Net Cash Provided by Operating Activities.............................. 6,349,080 7,238,340 10,394,514 2,679,971 2,964,097 ------------ ------------ ------------ ------------ ----------- Cash Flows from Investing Activities: Additions to property and equipment............. (34,401,410) (24,229,103) (34,531,180) (4,042,728) (5,744,576) Proceeds from the sale of property and equipment..................................... 14,303,800 157,972 861,073 -- -- Proceeds from volumetric production payment..... 13,790,000 -- -- -- -- Net cash received (distributed) as operator of oil and gas properties........................ 2,836,149 (2,556,483) (229,351) 1,264,268 (4,219,442) Property acquisition costs (incurred on behalf of) reimbursed by partnerships and joint ventures...................................... 14,726,897 (10,252,142) (1,408,031) (11,310,786) 4,245,278 Limited partnership formation and marketing costs......................................... (1,089,614) (103,871) -- (381,779) (170,549) Prepaid drilling costs.......................... -- (1,100,076) -- 780,217 (60,245) Other........................................... (35,117) (98,437) (25,320) (7,263) (16,068) ------------ ------------ ------------ ------------ ----------- Net Cash Provided by (Used in) Investing Activities.............................. 10,130,705 (38,182,140) (35,332,809) (13,698,071) (5,965,602) ------------ ------------ ------------ ------------ ----------- Cash Flows from Financing Activities: Proceeds from long-term debt.................... -- 28,750,000 -- -- -- Net proceeds from (payments of) short-term bank borrowings.................................... (23,380,000) 2,650,000 24,579,000 11,350,000 3,321,000 Net proceeds from issuances of common stock..... 6,536,170 288,175 708,444 7,750 226,769 Payment of debt issuance costs.................. -- (1,425,000) -- -- -- ------------ ------------ ------------ ------------ ----------- Net Cash Provided by (Used in) Financing Activities.............................. (16,843,830) 30,263,175 25,287,444 11,357,750 3,547,769 ------------ ------------ ------------ ------------ ----------- Net Increase (Decrease) in Cash and Cash Equivalents..................................... $ (364,045) $ (680,625) $ 349,149 $ 339,650 $ 546,264 ------------ ------------ ------------ ------------ ----------- Cash and Cash Equivalents at Beginning of Period.......................................... 1,681,019 1,316,974 636,349 636,349 985,498 ------------ ------------ ------------ ------------ ----------- Cash and Cash Equivalents at End of Period........ $ 1,316,974 $ 636,349 $ 985,498 $ 975,999 $ 1,531,762 ============ ============ ============ ============ =========== Supplemental Disclosures of Cash Flow Information: Cash paid during period for interest, net of amounts capitalized............................. $ 93,869 $ 605,063 $ 1,691,400 $ 111 $ -- Cash paid during period for income taxes.......... $ 850,000 $ 756,761 $ 97,200 $ 11,951 $ 3,019
See accompanying notes to Consolidated Financial Statements. F-6 49 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 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"). 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. UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS AND NOTES The interim consolidated financial statements as of March 31, 1995 and for the three months ended March 31, 1995 and 1994 and notes thereto are unaudited. In the opinion of management, these interim financial statements include all adjustments necessary for a fair presentation and all such adjustments are of a normal recurring nature. Results of the interim periods are not necessarily indicative of the results for the entire year. PROPERTY AND EQUIPMENT 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 extraordinary transactions. Instead, the proceeds from the sale of oil and gas properties are 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, 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, 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 F-7 50 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) properties using current prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects. 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 Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the issuance of the Company's Convertible Subordinated Debentures in June 1993 have been capitalized and are being amortized over the life of the Debentures, which mature on June 30, 2003. The balance at March 31, 1995, is net of accumulated amortization of $182,768. LIMITED PARTNERSHIPS AND JOINT VENTURES The Company forms 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. Under the Swift Depositary Interests limited partnership offering ("SDI Offering") which commenced in March 1991, the Company receives a reimbursement of certain costs and a fee, both payable out of revenues. The Company bears all front-end costs of the offering and partnership formations for which it receives an interest in the partnerships. Prior to 1994, the Company recognized as revenue fees (earned interests) received in the form of additional interests in producing oil and gas properties acquired by these entities. As described in Note 2, effective January 1, 1994, the Company changed its revenue recognition policy for earned interests and under its newly adopted policy, will no longer recognize earned interests as revenue. The Company acquires and transfers producing oil and gas 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 $4,100,000, $3,200,000, and $2,600,000 in 1994, 1993, and 1992, respectively. Certain designated oil and gas properties acquired in advance of formation of partnerships or joint ventures and held by the Company pending resale to those partnerships or joint ventures are classified as "Producing oil and gas properties held for transfer." Commencing September 15, 1993, the Company began offering, on a private placement basis, general and limited partnership interests in Swift Energy Drilling Ventures ("SEDV Offering"), a series of limited partnerships to be formed, and under which approximately $9,000,000 had been raised through March 31, 1995. As managing general partner, the Company pays for all front-end costs incurred in connection with this offering, for which the Company receives an interest in the partnerships. The proceeds are to be invested in development drilling (approximately 50%) and exploratory drilling (approximately 25%), with the remaining 25% dependent upon the results of the initial drilling activities. The first three partnerships closed December 8, 1993, July 18, 1994, and March 15, 1995. The Company anticipates formation of at least one additional SEDV partnership in 1995. Costs of syndication, registration, and qualification of the SDI and SEDV limited partnerships incurred by the Company have been deferred. Under the current SDI and SEDV limited partnership offering, selling F-8 51 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) and formation costs borne by the Company serve as the Company's general partner contribution to such partnerships. HEDGING ACTIVITIES 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. Costs and/or benefits derived from these price floors are accordingly recorded as a reduction or increase in oil and gas sales revenue and is not significant for any year presented. 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 an effect on primary income (loss) per share. The Company's Convertible Subordinated Debentures 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. On September 6, 1994, the Company declared a 10% stock dividend to shareholders of record on September 19, 1994, which was distributed on September 29, 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 Convertible Subordinated 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. The conversion price of the Convertible Subordinated Debentures was revised to reflect the 10% stock dividend declared September 6, 1994. The original conversion price was $13.50 per common share and the revised conversion price per common share is $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 were 9,053,736, 7,797,660, and 6,135,044 for the respective years ended December 31, 1994, 1993, and 1992, and 8,981,799 for the three-month period ended March 31, 1994. For the three-month period ended March 31, 1995, such amounts were antidilutive. 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. Prior to the adoption of SFAS No. 109, the Company accounted for income taxes using Accounting Principles Board Opinion No. 11. Income taxes for the interim periods have been provided using the estimated annualized effective tax rate. DEFERRED REVENUES In May 1992, as discussed in Note 10 "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 F-9 52 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 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. Noncash investing activities for the year ended December 31, 1993, included approximately $27,100,000 associated with producing oil and gas acquisitions that were paid for in early 1994. Of this amount, approximately $5,100,000 related to property acquisitions made for the Company's own account. See Note 10 "Oil and Gas Producing Activities" for further discussion. 2. CHANGE IN ACCOUNTING PRINCIPLE In the fourth quarter of 1994, the Company changed its revenue recognition policy for earned interests, effective January 1, 1994. Under the Company's newly adopted method of accounting for earned interests, such amounts will not be recognized as income, thereby reducing the Company's investment in oil and gas property. This change was made as the result of a transition in the Company's current business activities and changes in the oil and gas limited partnership syndication markets. The Company feels the change in policy results in more comparable financial statements in relation to its current business focus and in comparison to its current peers and competitors in the oil and gas exploration and production industry. The current year effect of the change was to increase income before cumulative effect of change in accounting principle by approximately $1,047,000 or $.16 per share. This current year increase was a result of the decrease in current year depletion expense more than offsetting the decrease in revenues as a result of not recognizing earned interests. The cumulative effect of this change in accounting principle resulted in an adjustment of $16,772,698 or $(2.52) per share (after reduction for income taxes of $8,640,481), to retroactively apply the new method, thereby reducing net income in 1994. See Note 10 to the Company's Consolidated Financial Statements for the effect this change had on oil and gas properties and accumulated depreciation, depletion and amortization. The pro forma amounts shown on the income statement have been adjusted for the effect of retroactive application, had the new method been in effect during the periods presented. 3. PROVISION FOR INCOME TAXES In the fourth quarter of 1992, the Company elected to adopt SFAS No. 109, "Accounting for Income Taxes." The adoption was effective beginning January 1, 1992, and accordingly the cumulative effect of this change resulted in an increase in net income for 1992 of $915,000 or $.15 per share. The Omnibus Budget Reconciliation Act of 1993 (the "Act") was enacted on August 10, 1993. The Act contains several changes to federal income tax provisions, including an increase in the highest corporate tax rate from 34% to 35%, for companies with taxable income in excess of $10,000,000. The effect of the Act on income tax expense for the year ended December 31, 1993, and the Company's net deferred tax liability was not material. F-10 53 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) The following is an analysis of the consolidated income tax provision:
YEAR ENDED DECEMBER 31, ------------------------------------------ 1992 1993 1994 ----------- ----------- ---------- Current...................................... $ 1,049,662 $ 533,298 $ 148,834 Deferred..................................... 468,097 1,199,057 963,324 ----------- ----------- ---------- Total........................................ $ 1,517,759 $ 1,732,355 $1,112,158 =========== =========== ==========
There are differences between income taxes computed using the statutory rate (34% for 1994, 1993, and 1992) and the Company's effective income tax rates (23%, 26.1%, and 32.4% for 1994, 1993, and 1992, respectively), primarily as the result of certain tax credits available to the Company. Reconciliations of income taxes computed using the statutory rate to the effective income tax rates are as follows:
1992 1993 1994 ----------- ----------- ---------- Income taxes computed at Federal statutory rate....................................... $ 1,593,756 $ 2,253,727 $1,644,862 State tax provisions, net of Federal benefits................................... 44,880 149,002 46,525 Nonconventional fuel source credit........... (211,066) (553,651) (435,016) Depletion deductions in excess of basis...... (14,014) (98,596) (30,895) Other, net................................... 104,203 (18,127) (113,318) ----------- ----------- ---------- Provision for income taxes................... $ 1,517,759 $ 1,732,355 $1,112,158 =========== =========== ==========
The tax effects of significant temporary differences representing the net deferred tax liability at December 31, 1994, 1993, and 1992 were as follows:
1992 1993 1994 ----------- ----------- ---------- Deferred tax assets: Alternative minimum tax credits............ $ 654,697 $ 786,774 $ 900,562 Other...................................... 76,736 231,292 7,112 ----------- ----------- ---------- Total deferred tax assets.......... $ 731,433 $ 1,018,066 $ 907,674 Deferred tax liabilities: Oil and gas properties..................... $11,217,376 $12,576,208 $4,811,886 Other...................................... 510,669 637,527 614,300 ----------- ----------- ---------- Total deferred tax liabilities..... $11,728,045 $13,213,735 $5,426,186 ----------- ----------- ---------- Net deferred tax liability(1)................ $10,996,612 $12,195,669 $4,518,512 =========== =========== ==========
- --------------- (1) This amount includes a current deferred tax liability amount of $34,726 for 1992 and current deferred tax asset amounts of $96,567 and $103,679 for 1993 and 1994. The Company did not record any valuation allowances against deferred tax assets at December 31, 1994, 1993, and 1992. At December 31, 1994, the Company had an alternative minimum tax carryforward of $900,562 indefinitely available to reduce future regular tax liability to the extent it exceeds the related tentative minimum tax otherwise due. F-11 54 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 4. SHORT-TERM BANK BORROWINGS The Company had available, through a two-bank group, a revolving line of credit of $35,000,000 at March 31, 1995, $29,000,000 at the end of 1994, and $20,000,000 at the end of 1993 bearing interest at the bank's base rate plus 0.5% (9.5% at March 31, 1995, 9% at December 31, 1994, and 6.5% at December 31, 1993), secured by the Company's interests in certain oil and gas properties and general partner interests. This facility also allows, at the Company's option, draws which bear interest for specific periods at the London Interbank Offered Rate ("LIBOR") plus 2.25%. Of the $24,600,000 balance outstanding at March 31, 1995, $15,000,000 was at the LIBOR plus 2.25% rate (8.49%). At December 31, 1994, $14,000,000 of the $18,600,000 outstanding was at the LIBOR plus 2.25% rates (7.875% on $3,000,000), (8.1875% on $6,000,000), and (8.5% on $5,000,000). The outstanding amounts under this facility at March 31, 1995 ($24,600,000) and at December 31, 1994 ($18,600,000) were borrowed primarily to fund the advance purchase of producing properties on behalf of limited partnerships and/or joint ventures to be subsequently reimbursed and to fund the Company's working capital and capital expenditures needs. The $2,650,000 outstanding amount under this facility at December 31, 1993, was primarily borrowed for the same purposes. The terms of the revolving line of credit include, among other restrictions, a limitation on the level of cash dividends (not to exceed $424,000 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 March 31, 1995, the Company was in compliance with the provisions of these agreements. The revolving line of credit extends through May 1, 1996. During 1993, the Company also had available with the same two-bank group a line of credit for producing oil and gas property acquisitions, to be secured by producing oil and gas properties acquired and held for transfer. There were no outstanding amounts under this facility at December 31, 1993. This facility was terminated on January 18, 1994 at the request of the Company. On June 21, 1994, the Company entered into a new Acquisition Advance Agreement with the same two-bank group, bearing interest at the greater of (a) the bank's base rate plus 1% (10% at March 31, 1995 and 9.5% at December 31, 1994) or (b) the Federal Funds rate plus 1.5%, to be secured by producing oil and gas properties acquired and held for transfer. The outstanding amounts under this facility at March 31, 1995 ($950,000) and at December 31, 1994 ($3,629,000) had been borrowed under this agreement to fund the advance purchase of producing properties on behalf of limited partnerships and/or joint ventures to be subsequently reimbursed. This credit agreement expired June 15, 1995. The Company's third credit facility is an amended and restated revolving line of credit with the lead bank for $5,000,000, bearing interest at the bank's base rate (9% at March 31, 1995, 8.5% at December 31, 1994, and 6% at December 31, 1993), secured by certain Company receivables. There were no outstanding amounts under this facility at December 31, 1993. At both March 31, 1995 and December 31, 1994, $5,000,000 was outstanding under this facility. This credit facility extends through May 1, 1996. 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 letters of credit outstanding during the period. The fee on the Acquisition Advance Agreement is .5% of the amount of the advance. The aggregate amounts of commitment fees paid by the Company were $23,000 for the first three months of 1995, $150,000 in 1994, and $112,000 in 1993. F-12 55 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 5. LONG-TERM DEBT The Company's long-term debt consists of $28,750,000 of 6.5% Convertible Subordinated Debentures ("Debentures"). The Debentures were issued on June 30, 1993, and will mature on June 30, 2003. The Debentures are convertible into common stock of the Company by the holders at any time prior to maturity at a conversion price of $12.27 per share, subject to adjustment upon the occurrence of certain events. The conversion price reflects an adjustment of the original conversion price of $13.50 per share to reflect the 10% stock dividend declared September 6, 1994, and distributed September 29, 1994. Interest on the Debentures is payable semi-annually on June 30 and December 31, commencing with the payment made at December 31, 1993. After June 30, 1997 (or in certain circumstances after June 30, 1996), the Debentures are redeemable for cash at the option of the Company, with certain restrictions, at 104.55% of principal, declining to 100.65% in 2002. Upon certain changes in control of the Company, if the price of the Company's common stock is not above certain levels each holder of Debentures will have the right to require the Company to repurchase the Debentures at the principal amount thereof, together with accrued and unpaid interest to the date of repurchase but after the repayment of any Senior Indebtedness, as defined. Interest expense on the Debentures, including amortization of debt issuance costs, totaled $494,910 for the three-month period ending March 31, 1995. Interest expense on the Debentures, including amortization of debt issuance costs, totaled $1,973,931 for 1994. Interest expense on the Debentures, including amortization of debt issuance costs, totaled $984,239 for the six-month period ending December 31, 1993. 6. COMMITMENTS AND CONTINGENCIES Total rental and lease expenses charged to earnings before reimbursements were $1,159,673 in 1994, $1,155,564 in 1993, and $1,005,276 in 1992. The Company's remaining minimum annual obligations under non-cancellable operating lease commitments are $375,917 for 1995, $66,825 for 1996, $41,136 for 1997, $37,555 for 1998, and $6,259 thereafter. As of March 31, 1995, the Company is the managing general partner of 95 limited partnerships. 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, which liabilities are not material for any of the periods presented in relation to the partnerships' respective assets. These partnerships' liabilities generally consist of third party borrowings from time to time to fund capital expenditures for development of oil and gas properties, and will be repaid from oil and gas sales proceeds of the partnerships in future periods. In the ordinary course of business, the Company has been party to various legal actions, which arise primarily from its activities as operator of oil and gas wells. In management's opinion, the outcome of any such currently pending actions will not have a material adverse effect on the financial position or results of operations of the Company. The Company extends credit to various companies in the oil and gas industry, which results in a concentration of credit risk. This 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, management believes that the risk is mitigated by the size, reputation, and nature of the companies to which they extend credit. In addition, the Company generally does not require collateral or other security to support customer receivables. 7. STOCKHOLDERS' EQUITY COMMON STOCK On September 6, 1994, the Company declared a 10% stock dividend to shareholders of record on September 19, 1994, which was distributed on September 29, 1994. The transaction was valued based on the F-13 56 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) closing price ($11.00) of the Company's common stock on the New York Stock Exchange on September 6, 1994. As a result of the issuance of 606,262 shares of the Company's common stock as a dividend, retained earnings were reduced by $6,668,882, with the common stock and additional paid-in capital accounts increased by the same amount. Primary and fully diluted income (loss) per share has been restated for all periods to reflect the effect of the stock dividend. STOCK OPTIONS AND WARRANTS The Company has an employee option plan under which incentive stock options and other options and awards may be granted to employees to purchase shares of common stock and a nonqualified stock option plan under which non-employee members of the Company's Board of Directors may be granted options to purchase shares of common stock. The plans provide that the exercise prices equal 100% of the fair value of the common stock on the date of grant. Options become exercisable for 20% of the shares on the first anniversary of the grant of the option and are exercisable for an additional 20% per year thereafter. Options granted expire 10 years after the date of grant or earlier in the event of the optionee's separation from employment. No accounting entries are required until the stock options are exercised, at which time the option price is credited to the common stock and additional paid-in capital accounts. The effect of the 10% stock dividend increased the number of shares and decreased the price according to the respective agreements. The following is a summary of stock options under these plans:
YEAR ENDED DECEMBER 31, ------------------------------------- 1993 1994 ---------------- ---------------- Options outstanding, beginning of period.......... 698,525 899,650 Options granted................................... 216,400 202,760 Options terminated................................ (1,875) (20,658) Options exercised................................. (13,400) (21,472) Options adjusted for stock dividend............... -- 106,640 ------- --------- Options outstanding, end of period................ 899,650 1,166,920 ======= ========= Options exercisable, end of period................ 375,270 546,172 ======= ========= Options available for future grant, end of period.......................................... 152,281 498,909 ======= ========= Option price range: Options granted................................. $ 10.50 - $11.625 $ 9.091 - $ 10.25 Options terminated.............................. $ 7.75 - $10.75 $ 7.045 - $ 12.386 Options exercised............................... $ 6.75 - $10.75 $ 7.045 - $ 9.773 Options outstanding, end of period.............. $ 6.00 - $13.625 $ 5.455 - $ 12.386
The Company also has granted certain stock options to individuals who are neither employees, officers, nor directors, for specific services rendered to the Company. At December 31, 1994, options granted in 1991 covering 68,750 shares at $9.773 (after adjustment for the September 1994 stock dividend) remain outstanding. During the three years ended December 31, 1994, the only other activity has been the cancellation of 5,350 option shares in 1993. The Company also has a plan which provides eligible employees the opportunity to acquire shares of Company common stock at a discount through payroll deductions. This plan was approved at the May 11, 1993, shareholders meeting. The plan year is from June 1 to the following May 31, with the first year of the plan commencing June 1, 1993. Employees may authorize payroll deductions of up to 10% of their base salary during the plan year by making an election to participate prior to the start of a plan year. The purchase price F-14 57 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) for stock acquired under the plan will be 85% of the lower of the closing price of the Company's common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. During 1994, the Company issued 29,840 shares under this plan at a price of $8.71. As of December 31, 1994, there were 517,176 shares available for issuance under this plan. There are no charges or credits to income in connection with this plan. 8. RELATED-PARTY TRANSACTIONS In 1991, Swift purchased all of the capital stock of a marketing company from a former significant stockholder and director of Swift and a separate minority interest owner ("sellers"). This acquired company has marketing responsibilities for the current and future Swift limited partnership offerings. The sellers entered into a management agreement to manage and supervise the sales activities of the Swift marketing entity under which they provided services and for which they were reimbursed certain fixed expenses and compensated on a sliding scale basis, dependent upon the number of partnership units sold. Management fees paid under this management agreement totaled approximately $21,000, $240,000, and $335,000 in 1994, 1993, and 1992, respectively. This arrangement was terminated in January 1994, whereby Swift will now assume all such management responsibilities. The Company is the operator of a substantial number of properties owned by limited partnerships and joint ventures and accordingly charges these entities and third party joint interest owners operating fees. The Company is also reimbursed for direct, administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $4,400,000, $4,200,000, and $3,900,000, in 1994, 1993, and 1992, respectively. The Company was also reimbursed by the limited partnerships and joint ventures for costs incurred in the screening, evaluation, and acquisition of producing oil and gas properties on their behalf. Such costs totaled approximately $1,400,000, $2,500,000, and $900,000 in 1994, 1993, and 1992, respectively. During 1992, the Company sold certain oil and gas properties, previously held in "producing oil and gas properties held for transfer" and the Company's oil and gas property accounts, to partnerships formed under the SDI offering. The properties were sold to the limited partnerships for proceeds equal to the properties' fair market value, $30,500,000, as determined by an independent petroleum engineer. Approximately $14,000,000 of the total proceeds from the sale were attributed to properties held in the Company's oil and gas property accounts with the remainder attributable to "producing oil and gas properties held for transfer." The $14,000,000 of proceeds attributable to properties held in the Company's oil and gas property account were treated as a reduction of the Company's proved oil and gas properties with no gain or loss recognized in accordance with the full-cost accounting method. 9. INVESTMENT IN PET-TECH TOOLS, INC. The Company, together with another 50% co-venturer, owned Pet-Tech Tools, Inc. ("Pet-Tech"), a company formed in 1982 to manufacture and lease a drilling safety tool. In the fourth quarter of 1992, as a result of the continuing depressed state of the domestic oil and gas drilling services industry, the Company decided to impair its entire 50% investment in Pet-Tech. The $627,835 effect of that impairment has been reflected in the statements of income for 1992 included herein. The Company's investment in Pet-Tech consisted primarily of advances and Debentures. F-15 58 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 10. OIL AND GAS PRODUCING ACTIVITIES CAPITALIZED COSTS The following table presents the Company's aggregate capitalized costs relating to oil and gas producing activities and the related depreciation, depletion and amortization:
DECEMBER 31, ----------------------------- 1993 1994 ------------ ------------ Oil and Gas Properties: Proved................................................ $106,251,713 $ 93,368,795(1) Unproved (not being amortized)........................ 7,932,557 14,805,479 ------------ ------------ 114,184,270 108,174,274 Accumulated Depreciation, Depletion and Amortization.... (24,527,693) (19,758,662)(1) ------------ ------------ $ 89,656,577 $ 88,415,612 ============ ============
- --------------- (1) The effect of the 1994 change in accounting principle (see Note 2) was to decrease proved property costs by $37,773,087 and accumulated depreciation, depletion and amortization by $12,359,908. Of the $14,805,479 of net unproved property costs (primarily seismic and lease acquisition costs) at December 31, 1994, being excluded from the amortizable base, $8,232,207 was incurred in 1994, $3,293,351 was incurred in 1993, $911,060 was incurred in 1992, and $2,368,861 was incurred in prior years. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two to three years. CAPITAL EXPENDITURES The following table sets forth capital expenditures related to the Company's oil and gas operations:
YEAR ENDED DECEMBER 31, ------------------------------------------- 1992 1993 1994 ----------- ----------- ----------- Acquisition of proved properties, including earned interests in limited partnerships and joint ventures(1)..................... $28,686,874 $21,832,157 $13,078,242 Lease acquisitions(2),(3)................... 2,886,024 5,388,243 9,905,237 Exploration................................. 527,761 2,195,473 4,003,400 Development................................. 3,034,513 3,164,803 5,637,285 ----------- ----------- ----------- Total(4).......................... $35,135,172 $32,580,676 $32,624,164 =========== =========== ===========
- --------------- (1) Earned interests amounts included in 1992 and 1993, respectively, are $1,692,331 and $3,308,623. There are no earned interests in 1994. (2) Lease acquisitions for 1993 and 1994 include expenditures of $1,032,656 and $2,973,971, respectively, relating to the Company's initiatives in Russia and include 1993 and 1994 expenditures of $456,681 and $356,136, respectively, relating to initiatives in Venezuela. (3) These amounts are actuals as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties (being amortized) for 1992, 1993, and 1994, respectively, were $2,155,526, $4,198,429, and $3,032,315, respectively. F-16 59 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) (4) Includes capitalized general and administrative costs directly associated with the acquisition, development, and exploration efforts of approximately $1,800,000, $8,300,000, and $5,800,000 in 1992, 1993, and 1994. In addition, total includes $466,460, $389,352, and $766,572 in 1992, 1993, and 1994, respectively, of capitalized interest on unproved properties. RESULTS OF OPERATIONS The following table sets forth results of the Company's oil and gas operations:
YEAR ENDED DECEMBER 31, ------------------------------------------- 1992 1993 1994 ----------- ----------- ----------- Oil and gas sales........................... $12,420,222 $15,535,671 $19,802,188 Production costs............................ (3,934,294) (4,540,290) (5,639,630) Depreciation, depletion and amortization.... (4,685,780) (7,067,636) (7,590,877) ----------- ----------- ----------- 3,800,148 3,927,745 6,571,681 Income taxes................................ (1,230,439) (1,025,141) (1,511,487) ----------- ----------- ----------- Results of producing activities............. $ 2,569,709 $ 2,902,604 $ 5,060,194 =========== =========== =========== Amortization per physical unit of production (equivalent Mcf of gas)................... $ 0.83 $ 0.96 $ 0.79 =========== =========== ===========
PROPERTY PURCHASE AND PRODUCTION PAYMENT AGREEMENT In May 1992, the Company purchased from a subsidiary of Manville Corporation ("Manville") additional interests in certain wells in McMullen County, Texas, in which the Company had owned interests for over three years. The funds for this purchase were provided by the Company's sale of a volumetric production payment in the Manville properties to Enron Reserve Acquisition Corp. ("Enron") for net proceeds of $13,790,000. These proceeds were recorded as deferred revenues and are amortized as the required deliveries are made. Under the production payment agreement, the Company continues to own the properties purchased from Manville, but is required to deliver to Enron approximately 9.5 Bcf over an eight year period, or for such longer period as is necessary to deliver a specified heating equivalent quantity at an average price of $1.115 per MMBtu. The Company is responsible for all production related costs associated with operating these properties. The amount to be delivered varies from month to month in generally decreasing quantities. To the extent monthly gas production from the properties exceeds the agreed upon deliverable quantities (as in 1994, 1993 and 1992), the Company receives all proceeds from sale of such excess gas at current market prices, plus the proceeds from sale of oil or condensate. During 1992, 1993, 1994, and the three-month period ended March 31, 1995, the Company met all scheduled deliveries to Enron under this production payment agreement. FOREIGN ACTIVITIES 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. The Company will receive a minimum 5% net profits interest from the sale of hydrocarbon products from the fields for providing managerial, technical and financial support to Senega limited to an initial budgeted capital expenditure of less than $5,000,000. At December 31, 1994 and March 31, 1995, respectively, the Company's investment in Russia was approximately $4,010,000 and $4,540,000 and is included in the unproved properties portion of oil and gas properties. F-17 60 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 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 on the Quiriquire Unit located in Northeastern Venezuela. Swift (together with a minority interest holder) was one of six bidders on the Quiriquire Unit. The Company did not win the bid for the Quiriquire Unit; however, other fields and opportunities are continuing to be evaluated in Venezuela. At December 31, 1994 and March 31, 1995, respectively, the Company's investment in Venezuela was approximately $810,000 and $880,000 and is included in the unproved properties portion of oil and gas properties net of impairments of $45,668. ACQUISITION OF PROPERTIES BY SWIFT During the fourth quarter of 1993, the Company acquired approximately $43,300,000 of producing oil and gas properties in five separate acquisitions. Approximately $32,700,000 of the properties were transferred to limited partnerships formed under the Company's SDI offering, and approximately $10,600,000 of the properties were retained by the Company for its own account. During the second quarter of 1994, the Company acquired approximately $18,100,000 of producing oil and gas properties in a single acquisition transaction. Approximately $12,700,000 of the properties were transferred to limited partnerships formed under the Company's SDI offering, approximately $1,900,000 of the properties were retained by the Company for its own account and the remaining amount of approximately $3,500,000 is included as a current asset in "producing oil and gas properties held for transfer" at December 31, 1994. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) The following information presents estimates of the Company's proved oil and gas reserves, which are all located onshore in the United States. All of the Company's reserves were determined by company personnel and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy's summary report dated February 17, 1995, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 1994, and includes definitions and assumptions that served as the basis for the estimates of proved reserves and future net cash flows. Such definitions and assumptions should be referred to in connection with the following information: F-18 61 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) Estimates of Proved Reserves
OIL AND NATURAL GAS CONDENSATE (MCF) (BBLS) ----------- ---------- Proved reserves as of December 31, 1991..................... 36,685,881 1,950,209 Revisions of previous estimates(1)........................ 2,702,911 88,141 Purchases of minerals in place............................ 35,042,474 1,606,324 Sales of minerals in place................................ (31,083,750) (500,518) Extensions, discoveries and other additions............... 1,116,925 41,393 Production(2)............................................. (2,826,341) (283,928) ----------- --------- Proved reserves as of December 31, 1992(3).................. 41,638,100 2,901,621 Revisions of previous estimates(1)........................ (1,800,178) (200,906) Purchases of minerals in place............................ 17,892,709 1,429,463 Sales of minerals in place................................ (61,996) (12,555) Extensions, discoveries and other additions............... 10,634,805 477,932 Production(2)............................................. (3,840,635) (324,486) ----------- --------- Proved reserves as of December 31, 1993(3).................. 64,462,805 4,271,069 Revisions of previous estimates(1)........................ (10,570,138) (714,246) Purchases of minerals in place............................ 8,136,270 790,523 Sales of minerals in place................................ (881,770) (34,834) Extensions, discoveries and other additions............... 20,556,953 707,811 Production(2)............................................. (5,440,156) (467,056) ----------- --------- Proved reserves as of December 31, 1994(3).................. 76,263,964 4,553,267 =========== ========= Proved developed reserves, December 31, 1991......................................... 26,712,921 1,512,264 December 31, 1992......................................... 32,955,080 2,082,885 December 31, 1993......................................... 50,936,942 3,110,505 December 31, 1994......................................... 46,406,448 3,209,387
- --------------- (1) Revisions of previous quantity estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil and natural gas prices at each year end. Proved reserves as of December 31, 1994, were based upon $1.85 per Mcf and $15.09 per barrel of oil, compared to $2.50 per Mcf and $12.87 per barrel of oil as of December 31, 1993. (2) Natural gas production for 1992, 1993, and 1994 excludes 1,148,862, 1,581,206, and 1,358,375 Mcf, respectively, delivered under the Company's volumetric production payment agreement. (3) Proved reserves for these periods exclude quantities subject to the Company's volumetric production payment agreement. F-19 62 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:
YEAR ENDED DECEMBER 31, ---------------------------------------------- 1992 1993 1994 ------------ ------------ ------------ Future gross revenues.................... $155,111,299 $218,321,639 $211,210,430 Future production and development costs.................................. (59,871,337) (75,769,590) (92,053,163) ------------ ------------ ------------ Future net cash flows before income taxes.................................. 95,239,962 142,552,049 119,157,267 Future income taxes...................... (20,955,655) (26,303,502) (14,143,796) ------------ ------------ ------------ Future net cash flows after income taxes.................................. 74,284,307 116,248,547 105,013,471 Discount at 10% per annum................ (27,701,313) (41,280,376) (38,541,504) ------------ ------------ ------------ Standardized measure of discounted future net cash flows relating to proved oil and gas reserves....................... $ 46,582,994 $ 74,968,171 $ 66,471,967 ============ ============ ============
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: 1. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. 2. The estimated future gross revenues of proved reserves are priced on the basis of year-end prices, except in those instances where fixed and determinable gas price escalations are covered by contracts, limited to the price the Company reasonably expects to receive. 3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year-end cost estimates and the estimated effect of future income taxes. 4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and gas producing activities and tax carryforwards. The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly "ceiling test" calculations, using prices in effect as of the period end date presented (see Note 1). Application of these rules during periods of relatively low oil and gas prices, even if of short-term seasonal duration, may result in write-downs. The standardized measure of discounted future net cash flows is not intended to present the fair market value of the Company's oil and gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserve estimates. F-20 63 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) The following are the principal sources of change in the standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, ------------------------------------------- 1992 1993 1994 ------------ ----------- ------------ Beginning balance........................... $ 37,174,904 $46,582,994 $ 74,968,171 ------------ ----------- ------------ Revisions to reserves proved in prior years -- Net changes in prices, production costs and future development costs........... 431,415 (4,140,177) (21,326,677) Net changes due to revisions in quantity estimates.............................. 3,634,778 (2,860,642) (11,644,586) Accretion of discount..................... 4,925,028 5,543,984 8,376,078 Other..................................... (2,965,631) (4,485,723) (5,631,646) ------------ ----------- ------------ Total revisions................... 6,025,590 (5,942,558) (30,226,831) New field discoveries and extensions, net of future production and development costs... 1,265,681 13,972,435 15,585,767 Purchases of minerals in place.............. 49,583,438 27,074,564 7,964,821 Sales of minerals in place.................. (44,346,750) (85,174) (574,651) Sales of oil and gas produced, net of production costs.......................... (6,819,538) (8,691,301) (12,168,695) Previously estimated development costs incurred.................................. 481,141 1,992,967 5,053,417 Net change in income taxes.................. 3,218,528 64,244 5,869,968 ------------ ----------- ------------ Net change in standardized measure of discounted future net cash flows.......... 9,408,090 28,385,177 (8,496,204) ------------ ----------- ------------ Ending balance.................... $ 46,582,994 $74,968,171 $ 66,471,967 ============ =========== ============
F-21 64 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 11. QUARTERLY RESULTS (UNAUDITED) The following table presents summarized quarterly financial information for the years ended December 31, 1992, 1993, and 1994, and the three months ended March 31, 1995:
FULLY DILUTED NET INCOME PRIMARY INCOME INCOME BEFORE (LOSS) INCOME (LOSS) (LOSS) REVENUES INCOME TAXES (AS RESTATED) PER SHARE(3) PER SHARE(3) ----------- ------------- ------------- ------------- ------------- 1992 First Quarter....... $ 3,452,071 $ 873,902 $ 1,491,775(2) $ 0.27 $ 0.27 Second Quarter...... 4,948,329 1,550,423 1,023,279 0.17 0.17 Third Quarter....... 5,760,656 2,039,670 1,346,182 0.21 0.21 Fourth Quarter...... 5,048,538 223,524 223,524 0.03 0.03 ----------- ----------- ------------- ------- ------- Total....... $19,209,594 $ 4,687,519 $ 4,084,760 $ 0.67 $ 0.67 =========== =========== ============= ======= ======= 1993 First Quarter....... $ 5,325,054 $ 1,411,809 $ 988,266 $ 0.15 $ 0.15 Second Quarter...... 6,012,174 1,743,606 1,220,524 0.19 0.19 Third Quarter....... 6,603,605 1,905,880 1,441,549 0.22 0.19 Fourth Quarter...... 6,191,820 1,567,313 1,245,914 0.19 0.17 ----------- ----------- ------------- ------- ------- Total....... $24,132,653 $ 6,628,608 $ 4,896,253 $ 0.74 $ 0.70 =========== =========== ============= ======= ======= 1994 First Quarter....... $ 6,138,535 $ 1,753,003(1) $ (15,561,976)(1) $ (2.36)(1) $ (2.36)(1) Second Quarter...... 6,106,954(1) 1,462,980(1) 1,076,077(1) 0.16(1) 0.15(1) Third Quarter....... 6,962,612 1,439,620(1) 1,130,398(1) 0.17(1) 0.16(1) Fourth Quarter...... 6,167,191 182,226 308,474 0.05 0.05 ----------- ----------- ------------- ------- ------- Total....... $25,375,292 $ 4,837,829 $ (13,047,027) $ (1.96) $ (1.96) =========== =========== ============= ======= ======= 1995 First Quarter....... $ 6,258,588 $ 676,434 $ 524,600 $ 0.08 $ 0.08 =========== =========== ============= ======= =======
- --------------- (1) In the fourth quarter of 1994, the Company changed its revenue recognition policy for earned interests. See Note 2 "Change in Accounting Principle" for further discussion. This change was effective beginning January 1, 1994, and, accordingly, the cumulative effect of this change ($(16,772,698) or $(2.52) per share) has been reflected in the first quarter of 1994, and the first three quarters have been restated to reflect the basis of the newly adopted accounting principle. Net Income, Primary Income Per Share, and Fully Diluted Income Per Share were previously reported as $814,325, $0.14, and $0.14, respectively, for the first quarter of 1994; $1,140,197, $0.19, and $0.17, respectively, for the second quarter of 1994; and $768,161, $0.12, and $0.12, respectively, for the third quarter of 1994. (2) In the fourth quarter of 1992, the Company elected to adopt SFAS No. 109 which changed the accounting for deferred income taxes. The adoption is effective beginning January 1, 1992, and, accordingly, the cumulative effect of this change has been reflected in the first quarter of 1992. Net Income and Primary Income Per Share, previously reported as $576,775 and $0.11, respectively, have been restated. See Note 3, "Provision for Income Taxes" for further discussion. F-22 65 SWIFT ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) (3) Amounts prior to the fourth quarter of 1994 have been retroactively restated to give recognition to an equivalent change in capital structure as a result of the 10% stock dividend. See Note 1, "Summary of Significant Accounting Policies-Income (Loss) Per Share" for further discussion. Pro forma amounts assuming the new earned interest recognition policy is applied retroactively:
PRIMARY FULLY DILUTED INCOME INCOME NET INCOME PER SHARE PER SHARE ---------- --------- ------------- 1992 First Quarter.................................. $ 886,401 $0.16 $0.16 Second Quarter................................. 978,411 0.16 0.16 Third Quarter.................................. 1,401,953 0.21 0.21 Fourth Quarter................................. 463,086 0.07 0.07 ---------- ----- ----- Total.................................. $3,729,851 $0.61 $0.61 ========== ===== ===== 1993 First Quarter.................................. $ 917,895 $0.14 $0.14 Second Quarter................................. 1,247,263 0.19 0.19 Third Quarter.................................. 1,113,049 0.17 0.15 Fourth Quarter................................. 1,044,271 0.16 0.15 ---------- ----- ----- Total.................................. $4,322,478 $0.66 $0.63 ========== ===== ===== 1994 First Quarter.................................. $1,210,722 $0.18 $0.17 Second Quarter................................. 1,076,077 0.16 0.15 Third Quarter.................................. 1,130,398 0.17 0.16 Fourth Quarter................................. 308,474 0.05 0.05 ---------- ----- ----- Total.................................. $3,725,671 $0.56 $0.56 ========== ===== ===== 1995 First Quarter.................................. $ 524,600 $0.08 $0.08 ========== ===== =====
F-23 66 - ------------------------------------------------------------ - ------------------------------------------------------------ NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THIS OFFERING OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH DATE. --------------------- TABLE OF CONTENTS
PAGE ---- Available Information....................... 2 Defined Terms............................... 2 Prospectus Summary.......................... 3 Risk Factors................................ 7 Use of Proceeds............................. 10 Price Range of Common Stock and Dividend Policy.................................... 11 Capitalization.............................. 12 Selected Consolidated Financial Data........ 13 Selected Oil and Gas Reserve and Operating Data...................................... 14 Management's Discussion and Analysis of Financial Condition and Results of Operations................................ 15 Business and Properties..................... 22 Management.................................. 35 Principal Shareholders...................... 38 Description of Capital Stock................ 39 Underwriting................................ 40 Legal Matters............................... 41 Experts..................................... 41 Incorporation of Certain Information by Reference................................. 42 Index to Consolidated Financial Statements................................ F-1
- ------------------------------------------------------------ - ------------------------------------------------------------ - ------------------------------------------------------------ - ------------------------------------------------------------ 5,000,000 SHARES (LOGO) SWIFT ENERGY COMPANY COMMON STOCK -------------------- PROSPECTUS -------------------- OPPENHEIMER & CO., INC. MORGAN KEEGAN & COMPANY, INC. SOUTHCOAST CAPITAL CORPORATION JULY 26, 1995 - ------------------------------------------------------------ - ------------------------------------------------------------ -----END PRIVACY-ENHANCED MESSAGE-----