10-K405 1 ee4q2000-10.txt 4TH QTR 2000 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended December 31, 2000 Commission File Number 1-8754 SWIFT ENERGY COMPANY (Exact Name of Registrant as Specified in Its Charter) Texas 74-2073055 (State of Incorporation) (I.R.S. Employer Identification No.) 16825 Northchase Dr., Suite 400 Houston, Texas 77060 (281) 874-2700 (Address and telephone number of principal executive offices) Securities registered pursuant to Section 12(b) of the Act: Title of Class: Exchanges on Which Registered: Common Stock, par value $.01 per share New York Stock Exchange Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ---- ---- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the voting stock held by non-affiliates at March 1, 2001 was approximately $781,687,000. The number of shares of common stock outstanding as of December 31, 2000 was 24,608,344 shares of common stock, $.01 par value. Documents Incorporated by Reference Document Incorporated as to Notice and Proxy Statement for the Part III, Items 10, 11, 12, and 13 Annual Meeting of Shareholders to be held May 8, 2001 1 Form 10-K Swift Energy Company and Subsidiaries 10-K Part and Item No. Page Part I Item 1. Business 3 Item 2. Properties 4 Item 3. Legal Proceedings 16 Item 4. Submission of Matters to a Vote of Security Holders 16 Part II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 16 Item 6. Selected Financial Data 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 19 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 24 Item 8. Financial Statements and Supple- mentary Data 26 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 50 Part III Item 10. Directors and Executive Officers of the Registrant (1) 50 Item 11. Executive Compensation (1) 50 Item 12. Security Ownership of Certain Bene- ficial Owners and Management (1) 50 Item 13. Certain Relationships and Related Transactions (1) 50 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 51 (1) Incorporated by reference from Notice and Proxy Statement for the Annual Meeting of Shareholders to be held May 8, 2001. 2 PART I Items 1 and 2. Business and Properties See pages 14 and 15 for explanations of abbreviations and terms used herein. General Swift Energy Company, a Texas corporation formed in October 1979, engages in the development, exploration, acquisition, and operation of oil and gas properties, with a focus on U.S. onshore natural gas reserves located in Texas and Louisiana as well as onshore oil and natural gas reserves in New Zealand. As of December 31, 2000, we had interests in 1,528 wells located domestically in eight states and in federal offshore waters as well as in New Zealand. We operated 817 of these wells representing 91% our proved reserves. At year-end 2000, we had estimated proved reserves of 629.4 Bcfe, of which approximately 67% was natural gas and 45% was proved developed. Our proved reserves are concentrated 54% in Texas, 22% in Louisiana, and 20% in New Zealand. We currently focus primarily on development and exploration in four domestic core areas as well as New Zealand: % of Year-End % of 2000 Area Location 2000 Proved Reserves Production ---------------- --------------------- -------------------- ---------- AWP Olmos South Texas 37% 32% Brookeland East Texas 11% 11% Giddings South-Central Texas 3% 7% Masters Creek West Louisiana 21% 44% New Zealand New Zealand 20% -- -------------------- ---------- % of Total 92% 94% The AWP Olmos area is characterized by long-lived reserves that we expect to be steadily produced over a long period of time. The Brookeland, Giddings, and Masters Creek areas are characterized by shorter-lived reserves with high initial rates of production that decline rapidly. We believe these shorter-lived reserves complement our long-lived reserves in the AWP Olmos area. Based on 2000 year-end domestic proved reserves and 2000 domestic production, our average reserve life was 12.0 years. We purchased interests in the Brookeland and Masters Creek areas from Sonat Exploration Company in the third quarter of 1998 for approximately $85.8 million in cash. Of this purchase price, $55.5 million was spent for producing properties, $15.0 million for 20% interests in two natural gas processing plants, and $15.3 million for leasehold properties. This acquisition generated two new core areas and extended our holdings in the Austin Chalk formation. Then in late December 1999, we purchased additional working interests in the Masters Creek area from Dominion Reserves, Inc., for approximately $14.0 million and purchased additional working interests in the S. Burr Ferry portion of the Masters Creek area for approximately $1.9 million from Union Pacific. We expect to use our operating expertise in this geological trend to continue to successfully develop and exploit these properties. In addition to our continuing production, development, and exploration in the AWP Olmos, Brookeland, Giddings, and Masters Creek areas, we are currently pursuing development and exploration activities in the Gulf Coast Basin and in New Zealand. Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. In addition, we seek to enhance the results of our drilling and production efforts through the implementation of advanced technologies. During 1998, as a result of lower oil and gas prices, we reduced capital expenditures for drilling and redirected a portion of those expenditures to the acquisition of producing properties, primarily the Brookeland and Masters Creek areas. In 1998, development and exploration drilling expenditures for the year, concentrated in the first half of the year, totaled $67.4 million. We spent $59.5 million for the acquisition of producing properties in 1998, almost all in the third quarter of 1998. For 1999, again in response to lower oil and gas prices in 1998 that continued in the first half of 1999, we decreased our capital expenditures budget to $54.2 million, of which $36.0 million was targeted for drilling, $31.3 million for development drilling, and $4.7 million for exploratory drilling. The remaining $18.2 million was targeted principally for leasehold, seismic, and geological costs of 3 prospects. After oil and gas prices rebounded in the second half of the year, we increased our capital expenditures during the fourth quarter. We funded the $78.1 million of capital expenditures spent in 1999 primarily through our internally generated cash flows of $73.6 million, while the remainder was funded with net proceeds from our third quarter 1999 public offering of common stock and Senior Notes that remained after paying off our bank debt. For 2000, in response to the strengthening of oil and gas prices and the resulting increase in cash flows generated from these commodity prices, we increased our capital expenditures to $173.3 million, of which $105.8 million was targeted for drilling in the United States, with $90.3 million for development drilling, and $15.5 million for exploratory drilling. We spent $9.7 million in drilling to further delineate our Rimu discovery in New Zealand. Additionally, $33.4 million was spent for producing property acquisitions. The remaining $24.4 million was used principally for leasehold, seismic, and geological costs of prospects. We funded the $173.3 million of capital expenditures in 2000 primarily through our internally generated cash flows of $128.2 million, while the remainder was funded with net proceeds from our third quarter 1999 public offering of common stock and Senior Notes that remained after paying off our bank debt and funding capital expenditures in 1999. We have increased our proved reserves from 176.1 Bcfe at year-end 1995 to 629.4 Bcfe at year-end 2000, which has resulted in the replacement of 375% of our production during the same five-year period. In 2000, we increased our proved reserves by 38%, which replaced 517% of our 2000 production. Our five-year average reserves replacement costs were $0.94 per Mcfe. While 2000 production was relatively flat in relation to 1999 production, we have increased our production from 11.2 Bcfe at year-end 1995 to 42.4 Bcfe at year-end 2000. Primarily due to increased production, along with strong 2000 commodity prices, this has resulted in average annual growth in net cash provided by operating activities of 55% per year from year-end 1995 to year-end 2000. Properties AWP Olmos Area. As of December 31, 2000, we owned approximately 31,162 net acres in South Texas. We have extensive expertise in this area and a long history of experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage there in 1988. These reserves are approximately 92% gas. At year-end 2000, we owned interests in and were the operator of 483 wells in this area producing gas from the Olmos Sand formation at a depth of approximately 10,000 to 11,500 feet. We own nearly 100% of the working interests in all wells in which we have an interest there. In 2000, we drilled 27 development wells in the AWP Olmos area, 25 of which were successful. At year-end 2000, we had 160 proved undeveloped locations. Also in 2000, we purchased interests in the AWP Olmos area from partnerships we manage. Our planned 2001 capital expenditures of $13.2 million in this area will focus on drilling 12 wells and on wells currently on production, performing fracture extensions and installing coiled tubing velocity strings. Brookeland Area. As of December 31, 2000, we owned drilling and production rights in 130,180 gross acres, 82,080 net acres, and 15,000 fee mineral acres containing substantial proved undeveloped reserves. This area was part of the acquisition from Sonat in 1998. The Brookeland area is located in southeast Texas near the border of Louisiana in Jasper and Newton counties. This area primarily contains horizontal wells producing gas from the Austin Chalk formation. The reserves are approximately 65% gas. In 2000, we drilled or participated in the drilling of five development wells there, all of which were successful. At year-end 2000, we had 25 proved undeveloped locations. We plan to drill or participate in 17 development wells in 2001, 10 to be operated by us. Our planned 2001 capital expenditures in this area are $21.8 million. Giddings Area. As of December 31, 2000, we owned drilling and production rights in 67,595 net acres in the Giddings area. This area is located in Washington, Colorado, Fayette, and Austin counties in southeast Texas. The reserves are approximately 84% gas. In 2000, seven development wells were drilled, four successfully. One of the seven development wells drilled was to the Edwards formation and was unsuccessful, while the other six drilled were to the Austin Chalk formation. Also four exploratory wells were drilled, with one success. One of the four exploratory wells drilled was to the Edwards formation and was unsuccessful, while the other three drilled were to the Austin Chalk formation. At year-end 2000, we had two proved undeveloped locations. No drilling in this area is planned for 2001. Masters Creek Area. As of December 31, 2000, we owned drilling and production rights in 182,356 gross acres, 137,188 net acres, and 141,000 fee mineral acres in this area containing substantial proved undeveloped reserves. This area was also part of the acquisition from Sonat in 1998. It is located near the Texas-Louisiana border in the two parishes of Vernon and Rapides in Louisiana. The Masters Creek area 4 contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 40% gas. In 2000, we drilled or participated in the drilling of 12 development wells, 11 of which were successful. Also two successful exploratory wells were drilled, both targeting the Saratoga formation. At year-end 2000, we had 27 proved undeveloped locations. We plan to drill or participate in 10 development wells in 2001, all to be operated by us. Three of these development wells are in the S. Burr Ferry portion of this area. One development well will target the Saratoga formation. The other six are in the Masters Creek field targeting the Austin Chalk formation. Our planned 2001 capital expenditures in this area are $39.3 million. Exploration and Development Drilling Activities We pursue a "controlled risk" approach to exploratory and development drilling, focusing our domestic activities on specific regions in which our technical staff has considerable experience and which are located close to known producing horizons. In our foreign operations, we chose New Zealand based on its hydrocarbon potential combined with its political and economic attributes. We seek to minimize our exploration risk by investing in multiple prospects, farming out interests to third parties, using advanced technologies, and drilling in diverse types of geological formations, often in areas with multiple objectives. We use basin studies to analyze targeted formations based on their potential size, risk profile, and economic characteristics. In 1991, we began an intensive effort to develop an inventory of exploration and development drilling prospects, identifying drilling locations through integrated geological and geophysical studies of our undeveloped acreage and other prospects. As a result, we added 73.9 Bcfe of proved reserves through drilling in 1998, 64.9 Bcfe in 1999, and 184.7 Bcfe in 2000 (122.5 Bcfe from New Zealand). In the second half of 1998, in response to lower oil and gas prices, we deferred drilling projects scheduled for the second half of the year and continued into 1999 with a conservative drilling budget. Accordingly, reserves added by drilling were lower in 1998 and 1999 compared to previous years and to 2000, when market conditions were more favorable for drilling. The 2000 additions were a result of our development success rate of 89%, as 54 of 61 development wells drilled were successful, and of five of nine exploratory wells being successful. Our development strategy is designed to maximize the value and productivity of our existing properties through development drilling and recovery methods, enhancing production results through improved field production techniques, lowering production costs, and applying our technical expertise and resources to exploit producing properties efficiently. We utilize various recovery techniques, which include employing water flooding and acid treatments, fracturing reservoir rock through the injection of high-pressure fluid, and inserting coiled tubing velocity strings to enhance and maintain gas flow. We believe that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP Olmos area. Our exploration and development activities are conducted by our staff of professionals, including reservoir engineers, geologists, geophysicists, petrophysicists, landmen, and drilling and production engineers. We believe that one of the keys to our success has been our team approach, which integrates multiple disciplines to maximize efficient utilization of information leading to drillable projects. We have increasingly used advanced seismic technology to enhance the results of our drilling and production efforts, including 2-D and 3-D seismic analysis, amplitude versus offset studies, and detailed formation depletion studies. We have a number of computer workstations from which seismic data is analyzed and enhanced with advanced software programs, including Landmark, Geographix, and SMT workstations. As a result, we have maintained internal seismic expertise and have compiled an extensive database. During 1997, we completed our first international seismic acquisition program in two key areas of our block in New Zealand. In the Rimu prospect, we acquired 30 kilometers (18.7 miles) of 2-D cross-swath data, as well as 14.5 kilometers (9 miles) of 2-D line data in the Tawa prospect, complementing existing 2-D seismic coverage. Following our 1999 Rimu discovery, we conducted a second seismic acquisition in March 2000 in which we obtained 42 kilometers (26 miles) of 2-D lines to more fully identify the extent of the Rimu structure. We also obtained approximately 72.5 kilometers (45 miles) of data from a number of 2-D transitional zone seismic lines tied to existing marine and land seismic grids in order to study the Kauri structure to the southeast of Rimu. Based on interpretation of these data, a location has been selected to drill the first well on the Kauri prospect in 2001. Further processing and analysis of the data will continue in 2001. Also in 1997, we acquired 21 miles of 2-D data in the AWP Olmos area in south Texas and 51 miles of data in the Fayette County portion of the Giddings area. Two more prospects in the North Louisiana Salt Basin were shot in the form of 2-D swaths of approximately 16 miles each. During 1998, we performed two additional 2-D acquisitions in Fayette County, Texas. In all our current and future projects, we have an on-going program 5 in which we license existing seismic data for reprocessing with available new technologies. In certain areas we also complement existing data with proprietary seismic data designed for specific geologic targets. This results in an integrated approach to exploration (multidiscipline data analysis and interpretation) that has helped identify a number of exploration prospects for 2001. In addition to development and exploration activities in the AWP Olmos, Brookeland, and Masters Creek areas, we are currently pursuing development and exploration activities in the Gulf Coast Basin and in New Zealand. Gulf Coast Basin. This area includes all the Texas counties and Louisiana parishes along the Gulf Coast and extending into Mississippi and Alabama. In 2000, we drilled four successful development wells out of five and two successful exploratory wells out of three in this area. In 2001, 10 exploratory wells are scheduled for drilling in the Gulf Coast Basin, primarily in Texas. Our planned 2001 capital expenditures in this area are $11.9 million. New Zealand. We operate a permit with a 90% working interest. After working several years and analyzing extensive seismic data, a successful exploratory well, the Rimu-A1, commenced drilling in July 1999. In 2000, we drilled two successful Rimu development wells with a third in progress. Our permit contains 100,652 gross acres, including 12,800 adjacent offshore acres. In 2001, four wells are scheduled for drilling, with one well being an exploratory test of the Kauri prospect. Plans also include the building of production facilities. We are also participating as a non-operator in three other exploration permits which at year-end 2000 contained 143,773 gross acres. An exploratory well on one of these permits was temporarily abandoned in January 2001, pending further evaluation. The following table sets forth the results of our drilling activities during the three years ended December 31, 2000:
Gross Wells Net Wells --------------------------------------- ---------------------------------- Temporarily Temporarily Year Type of Well Total Producing Dry Abandoned Total Producing Dry Abandoned --------------------------------------------------------------------------- ---------------------------------- 1998 Exploratory-Domestic 13 5 8 -- 8.2 2.7 5.5 -- Exploratory-New Zealand 1 -- 1 -- 0.5 -- 0.5 -- Development-Domestic 61 53 8 -- 37.7 32.8 4.9 -- 1999 Exploratory-Domestic 3 1 2 -- 1.5 0.3 1.2 -- Exploratory-New Zealand 2 1 -- 1 1.0 0.9 -- 0.1 Development-Domestic 22 19 3 -- 10.7 9.4 1.3 -- 2000 Exploratory-Domestic 9 5 4 -- 6.2 3.4 2.8 -- Development-Domestic 59 52 7 -- 42.4 37.1 5.3 -- Development-New Zealand 2 2 -- -- 1.8 1.8 -- --
Operations We generally seek to be operator in the wells in which we have significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide all the equipment and personnel. We employ drilling, production and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and gas properties. Oil and gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator's direct expenses and for payment of monthly per-well supervision fees. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or gas. The fees for these activities paid to us in 2000 ranged from $200 to $2,091 per well per month and totaled $6.9 million. 6 Marketing of Production We typically sell our oil and gas production at market prices near the wellhead, although in some cases it must be gathered and delivered to a central point. Gas production is sold in the spot market on a monthly basis, while we sell our oil production at prevailing market prices. We do not refine any oil we produce. Two oil or gas purchasers accounted for 10% or more of our total revenues during the year ended December 31, 2000, with those purchasers accounting for approximately 37% of revenues in the aggregate. For the year ended December 31, 1999, one purchaser accounted for approximately 19% of our total revenues. However, due to the availability of other purchasers, we do not believe that the loss of any single oil or gas purchaser or contract would materially affect our revenues. In 1998, we entered into gas processing and gas transportation agreements for our gas production in the AWP Olmos area with PG&E Energy Trading Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to 75,000 Mcf per day, which provided for a ten-year term with automatic one-year extensions unless earlier terminated. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future. Additionally, the gas processed and transported under these agreements may be sold to El Paso based upon current natural gas prices. Much of our Giddings area production from Fayette and Washington counties, Texas, is currently dedicated under long-term gas purchase and gas processing contracts with Aquila Southwest Pipeline Corporation ("Aquila"). We believe that these contracts adequately provide for the gas purchase and processing needs of our Giddings area production, subject to practical limitations inherent in gas field operations. The prices received are redetermined monthly to reflect the current natural gas price. Our oil production from the Brookeland and Masters Creek areas is sold to various purchasers at prevailing market prices. Our gas production from these areas is processed under long-term gas processing contracts with Duke Energy Field Services, Inc. The processed liquids and residue gas production are sold in the spot market. The following table summarizes sales volumes, sales prices, and production cost information for our net oil and gas production for the three-year period ended December 31, 2000. All of our oil and gas operations are domestic. New Zealand operations are expected to commence in 2001. "Net" production is production that is owned by us either directly or indirectly through partnerships or joint venture interests and is produced to our interest after deducting royalty, limited partner, and other similar interests.
Year Ended December 31, ------------------------------------------------------------------ 2000 1999 1998 ------------------ --------------------- ------------------ Net Sales Volume: Oil (Bbls) 2,472,014 2,564,924 1,800,676 Gas (Mcf)(1) 27,524,621 27,484,759 28,225,974 Gas equivalents (Mcfe) 42,356,705 42,874,303 39,030,030 Average Sales Price: Oil (Per Bbl) $ 29.35 $ 16.75 $ 11.86 Gas (Per Mcf) $ 4.24 $ 2.40 $ 2.08 Average Production Cost (per Mcfe) $ 0.69 $ 0.46 $ 0.34
(1) Natural gas production for 2000, 1999, and 1998 includes 405,130, 728,235 and 866,232 Mcf, respectively, delivered under the volumetric production payment agreement pursuant to which we were obligated to deliver certain monthly quantities of natural gas (see Note 1 to the Consolidated Financial Statements). Under the volumetric production payment entered into in 1992, we delivered the last remaining commitment of gas in October 2000, when such agreement expired. Acquisition Activities We use a disciplined, market-driven approach to acquisitions. Generally we seek to acquire properties with the potential for additional reserves and production through development and exploration efforts. In 140 7 transactions since 1979, we have acquired approximately $590.2 million of producing oil and gas properties on behalf of ourselves and our co-investors. We acquired, for our own account, approximately $233.7 million of producing properties, with original proved reserves estimated at 339.7 Bcfe. Our producing property acquisition expenditures in the past three years were $34.2 million in 2000, $18.5 million in 1999, and $59.5 million in 1998. Our acquisition costs have averaged $0.71 per Mcfe over this three-year period. Our acquisition cost in 2000 averaged $0.86 per Mcfe. Foreign Activities New Zealand Swift Operated Permit. Our activity in New Zealand began in 1995 with the issuance of the first of two petroleum exploration permits. After a 1998 surrendering of a portion of our permit acreage, a combining of the two permits, and a 1999 expansion of the permit, as of year-end 2000 our permit 38719 covers approximately 100,700 acres in the Taranaki Basin of New Zealand's North Island, with all but 12,800 acres onshore. We have a 90% working interest in this permit and have fulfilled all current obligations under this permit. In late 1999, we completed our first exploratory well on this permit, the Rimu-A1, and a production test was performed. During the second half of 2000, we drilled and successfully tested two delineation wells, the Rimu-B1 and the Rimu-B2. We commenced drilling our third delineation well, the Rimu-A2, during December 2000. The Rimu-A2 has been drilled with casing set. Logging results indicate that the well encountered the Upper Tariki sands also present in the Rimu-A1. Completion activity will take place on this zone following the drilling of the Rimu-A3. Our portion of the drilling, completion, and testing costs incurred on the wells within our permit area during 2000 was approximately $10.7 million. Our portion of prospect costs on our permit area during 2000 was approximately $4.4 million, which included obtaining 2-D seismic data in the first half of the year. We incurred $1.1 million on the initial phases of production facilities. In 2001, we plan to drill four wells, one exploratory well on our Kauri prospect to the southeast of the Rimu discovery and three wells to further delineate the Rimu area, and to build production facilities with $35.9 million budgeted to be spent, compared to $17.4 million spent in 2000 and $7.0 million spent in 1999. Our New Zealand production is subject to a royalty which is a hybrid consisting of a 5% ad valorem royalty, or "AVR," and a 20% accounting profits royalty, or "APR." Until a mining permit is obtained for our producing area, only the AVR will apply to all production, and thereafter the royalty will be the greater of the AVR or APR, calculated on an annual basis. The AVR is based on net sales revenues. The APR is based on the excess of net sales revenues over allowable deductions which deductions include production, capital and indirect costs, but not for interest or income tax expense or "head office costs" above 2.5% of other costs. Operating losses and capital costs may be carried forward to subsequent periods until fully utilized. Non-Operated Permits. In 1998, we entered into agreements for a 25% working interest in an exploration permit held by Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5% working interest held by Antrim Oil and Gas Limited, a Canadian company in a permit operated by Marabella. In turn, Bligh and Antrim each became 5% working interest owners in our permit. Unsuccessful exploratory wells were drilled on these two permits, and we charged $400,000 against earnings in 1998 and $290,000 in 1999. All of the acreage on the permit we had a 25% working interest in was surrendered in 2000. The exploratory well on the 7.5% working interest permit has been temporarily abandoned pending a further evaluation. In 2000, we entered into agreements with Fletcher Challenge Energy Limited whereby we will earn a 20% participating interest in petroleum exploration permit 38718 containing approximately 57,400 acres and a 25% participating interest in permit 38730 with approximately 48,900 acres. In January 2001, the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718 pending further analysis. The permit now contains approximately 28,700 acres after a scheduled surrender during December 2000. Costs Incurred. During 2000 our portion of all costs incurred in New Zealand totaled $17.4 million, including $11.8 million for drilling, $4.5 million for prospect costs, and $1.1 million for production facilities. These costs included $1.2 million of costs incurred on permits operated by others: $1.1 million of drilling costs and $0.1 million of prospect costs. As of December 31, 2000, our investment in New Zealand totaled approximately $29.8 million. At year-end we recorded proved undeveloped reserves relating to our successful drilling activities. Accordingly, $21.1 million of our investment costs have been included in the proved properties portion of oil and gas properties and $8.7 million is included as unproved properties. The development strategy includes marketing oil and gas, with the intent of having production on line for oil and gas sales in New Zealand in 2001. 8 Russia In 1993, we entered into a Participation Agreement with Senega, a Russian Federation joint stock company, to assist in the development and production of reserves from two fields in Western Siberia and received a 5% net profits interest. We also purchased a 1% net profits interest. Our investment in Russia, prior to its impairment in the third quarter of 1998, was approximately $10.8 million. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment. We retain a minimum 6% net profits interest from the sale of hydrocarbon products from the fields, the value of which depends upon the successful development of production from the fields by others, which may or may not occur. Venezuela In 1993, we formed a wholly owned subsidiary, Swift Energy de Venezuela, C. A., for the purpose of submitting a bid under the Venezuelan Marginal Oil Field Reactivation Program and entered into an agreement with two Venezuelan companies to jointly formulate and submit a proposal to Petroleos de Venezuela, S. A., for the construction and operation of a methane pipeline. Our investment in Venezuela, prior to its impairment in the third quarter of 1998, was approximately $2.8 million. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment. Oil and Gas Reserves The following table presents information regarding proved reserves of oil and gas attributable to our interests in producing properties as of December 31, 2000, 1999, and 1998. The information set forth in the table regarding Domestic Reserves is based on proved reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy's domestic audit was based upon review of production histories and other geological, economic, ownership, and engineering data provided by us. The information set forth in the table regarding New Zealand reserves is based on gross proved reserves reports independently estimated by Gruy. Gruy's New Zealand estimates were based on volumetric calculations, equation-of-state compositional simulation models, and production forecasting methods. The net reserves and cash flows for New Zealand were prepared by us. In accordance with Securities and Exchange Commission guidelines, estimates of future net revenues from our proved reserves and the PV-10 Value must be 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 as of December 31, 2000, were estimated based upon prices in effect at year-end. The weighted averages of such year-end prices domestically were $11.25 per Mcf of natural gas and $25.50 per barrel of oil, compared to $2.58 and $23.69 in 1999 and $2.23 and $11.23 in 1998. The weighted averages of such year-end 2000 prices for New Zealand were $0.71 per Mcf of natural gas and $22.30 per barrel of oil. The weighted averages of such year-end 2000 prices for all our reserves, both domestically and in New Zealand, were $9.86 per Mcf of natural gas and $24.62 per barrel of oil. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following table. The proved reserves presented for all periods also exclude any reserves attributable to the volumetric production payment. The table sets forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the Securities and Exchange Commission and their PV-10 Value. Operating costs, 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 Supplemental Information to our Consolidated Financial Statements, which is calculated after provision for future income taxes. 9
Year Ended December 31, 2000 ------------------------------------------------------------ Total Domestic New Zealand ------------------- ---------------- ----------------- Estimated Proved Oil and Gas Reserves Net natural gas reserves (Mcf): Proved developed 215,169,833 215,169,833 -- Proved undeveloped 203,444,143 148,130,666 55,313,477 ------------------- ---------------- ----------------- Total 418,613,976 363,300,499 55,313,477 =================== ================ ================= Net oil reserves (Bbl): Proved developed 10,980,196 10,980,196 -- Proved undeveloped 24,153,400 12,962,513 11,190,887 ------------------- ---------------- ----------------- Total 35,133,596 23,942,709 11,190,887 =================== ================ ================= Estimated Present Value of Proved Reserves Estimated present value of future net cash flows from proved reserves discounted at 10% annum: Proved developed $ 1,257,570,764 $ 1,257,570,764 $ -- Proved undeveloped 1,055,684,045 919,388,009 136,296,036 ------------------- ---------------- ----------------- Total $ 2,313,254,809 $ 2,176,958,773 $ 136,296,036 =================== ================ ================= Year Ended December 31, 1999 ------------------------------------------------------------ Total Domestic New Zealand ------------------- ---------------- ----------------- Estimated Proved Oil and Gas Reserves Net natural gas reserves (Mcf): Proved developed 174,046,096 174,046,096 -- Proved undeveloped 155,913,654 155,913,654 -- ------------------- ---------------- ----------------- Total 329,959,750 329,959,750 -- =================== ================ ================= Net oil reserves (Bbl): Proved developed 8,437,299 8,437,299 -- Proved undeveloped 12,368,964 12,368,964 -- ------------------- ---------------- ----------------- Total 20,806,263 20,806,263 -- =================== ================ ================= Estimated Present Value of Proved Reserves Estimated present value of future net cash flows from proved reserves discounted at 10% annum: Proved developed $ 301,199,660 $ 301,199,660 $ -- Proved undeveloped 262,854,849 262,854,849 -- ------------------- ---------------- ----------------- Total $ 564,054,509 $ 564,054,509 $ -- =================== ================ ================= Year Ended December 31, 1998 ------------------------------------------------------------ Total Domestic New Zealand ------------------- ---------------- ----------------- Estimated Proved Oil and Gas Reserves Net natural gas reserves (Mcf): Proved developed 197,105,963 197,105,963 -- Proved undeveloped 155,294,872 155,294,872 -- ------------------- ---------------- ----------------- Total 352,400,835 352,400,835 -- =================== ================ ================= Net oil reserves (Bbl): Proved developed 7,142,566 7,142,566 -- Proved undeveloped 6,815,359 6,815,359 -- ------------------- ---------------- ----------------- Total 13,957,925 13,957,925 -- =================== ================ ================= Estimated Present Value of Proved Reserves Estimated present value of future net cash flows from proved reserves discounted at 10% annum: Proved developed $ 243,124,194 $ 243,124,194 $ -- Proved undeveloped 97,660,811 97,660,811 -- ------------------- ---------------- ----------------- Total $ 340,785,005 $ 340,785,005 $ -- =================== ================ =================
10 At year-end 2000, 55% of the proved reserves were undeveloped reserves. This reflects the increased emphasis on development and exploration activities. In 1999, 51% of proved reserves were undeveloped and 49% were proved developed. Changes in quantity estimates and the estimated present value of proved reserves are affected by the change in crude oil and natural gas prices at the end of each year. While our total proved reserves quantities, on an equivalent Bcfe basis, at year-end 2000 increased by 38% over reserves quantities a year earlier, the PV-10 Value of those reserves increased 310% from the PV-10 Value at year-end 1999. Our total proved reserves quantities at year-end 1999 increased by 4% over reserves quantities a year earlier, while the PV-10 Value of those reserves increased 66% from the PV-10 Value at year-end 1998. These PV-10 Value increases were heavily influenced by pricing increases at year-end 2000 as compared to year-end 1999, and also from year-end 1999 as compared to year-end 1998. Product prices for natural gas increased 282% during 2000, from $2.58 per Mcf at December 31, 1999, to $9.86 per Mcf at year-end 2000, while oil prices increased 4% between the two dates, from $23.69 to $24.62 per barrel. Product prices for natural gas increased 16% during 1999, from $2.23 per Mcf at December 31, 1998, to $2.58 per Mcf at year-end 1999, while oil prices increased 111% between the two dates, from $11.23 to $23.69 per barrel. Conversely, while our total proved reserves quantities at year-end 1998 increased by 21% over reserves quantities a year earlier, the PV-10 Value of those reserves decreased 3% from the PV-10 Value at year-end 1997. This decrease was due almost entirely to pricing declines at year-end 1998 as compared to year-end 1997, which more than offset the 21% Bcfe increase in reserves quantities. Product prices for natural gas declined 20% during 1998, from $2.78 per Mcf at December 31, 1997, to $2.23 per Mcf at year-end 1998, matched by a 29% decrease in the price of oil between the two dates, from $15.76 to $11.23 per barrel. 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. Reserves 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, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and gas reserves. A portion of our proved reserves has been accumulated through our interests in the limited partnerships for which we serve 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 we own interests will achieve payout status in the future. At December 31, 2000, 27 of the limited partnerships managed by us had achieved payout status. No other reports on our reserves have been filed with any federal agency. Oil and Gas Wells The following table sets forth the gross and net wells in which we owned an interest at the following dates: Total Oil Wells Gas Wells Wells(1) ----------- ----------- ----------- December 31, 2000 Gross 599 904 1,503 Net 165.2 484.7 949.9 December 31, 1999 Gross 577 947 1,524 Net 105.5 449.2 554.7 December 31, 1998 Gross 657 1,060 1,717 Net 89.4 494.5 583.9 (1) Excludes 25 service wells in 2000, 33 service wells in 1999, and 36 service wells in 1998. Also excludes 3 wells in New Zealand, temporarily shut-in awaiting marketing and processing arrangements. 11 Oil and Gas Acreage As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have 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 our judgment it would be uneconomical or impractical to do so. The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2000: Developed (1) Undeveloped (1) Gross Net Gross Net ------------ ------------ ------------ ------------ Alabama 7,876.08 3,337.43 625.50 382.40 Arkansas 762.00 557.57 2,040.15 679.48 Kansas -- -- 4,520.00 1,908.80 Louisiana 111,212.14 74,071.90 106,490.95 71,393.70 Mississippi 2,084.19 1,397.45 2,379.75 599.46 Oklahoma 24,060.42 11,526.54 2,372.13 537.74 Texas 237,513.37 148,209.50 131,594.52 76,359.47 Wyoming 1,161.96 621.37 87,748.01 76,697.63 All other states -- -- 5,928.45 981.43 Offshore Louisiana 4,609.37 276.56 49,351.00 2,793.78 Offshore Texas 6,210.00 320.85 14,400.00 1,600.79 ------------ ------------ ------------ ------------ Total-Domestic 395,489.53 240,319.17 407,450.46 233,934.68 New Zealand 1,500.00 1,350.00 242,925.47 112,165.83 ------------ ------------ ------------ ------------ Total 396,989.53 241,669.17 650,375.93 346,100.51 ============ ============ ============ ============ (1) Fee minerals acquired in the Brookeland and Masters Creek areas acquisition are not included in the above leasehold acreage table. We have 26,345 developed fee mineral acres and 114,655 undeveloped fee mineral acres for a total of 141,000 fee mineral acres. Partnerships Prior to 1995, we funded a substantial portion of our operations through 109 limited partnerships which we formed and for which we have served as managing general partner. These partnerships raised a total of $509.5 million of capital, with the largest portion (81%) raised to acquire interests in producing properties. Eight of the earliest partnerships and 13 of the most recently formed partnerships were created to drill for oil and gas. In all of these partnerships Swift paid for varying percentages of the capital or front-end costs and continuing costs of the partnerships and, in return, received differing percentage ownership interests in the partnerships, along with reimbursement of costs and/or payment of certain fees. At year-end 2000, we continued to serve as managing general partner of 80 of these various partnerships, of which 67 are production purchase partnerships that have been in existence from five to fourteen years and the remainder are drilling partnerships that have been in existence from two to seven years. During 1997 and 1998, eight drilling partnerships formed between 1979 and 1985 and 21 of the production purchase partnerships sold their properties and were dissolved, in each case following a vote of the investors in the particular partnerships approving such liquidations. Between 1999 and 2001, the investors in all but six of the remaining partnerships voted to sell the properties or their interests in the partnership and dissolve. We anticipate that the liquidation and dissolution of these 74 partnerships should be substantially completed by the end of 2001. The remaining six partnerships will continue to operate. 12 Risk Management Our 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 us to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of limited partnerships, we are solely responsible for the day-to-day conduct of the limited partnerships' affairs and accordingly have liability for expenses and liabilities of the limited partnerships. We maintain comprehensive insurance coverage, including general liability insurance in an amount not less than $35.0 million, as well as general partner liability insurance. We believe that our 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. Competition The oil and gas industry is highly competitive in all its phases. We encounter 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 our properties. Regulations Environmental Regulations The federal government and various state and local governments have adopted laws and regulations regarding the protection of human health and 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, wetlands, or where pollution might cause serious harm, and impose substantial liabilities for pollution resulting from drilling operations, particularly with respect to operations in onshore and offshore waters or on submerged lands. These laws and regulations may increase the costs of drilling and operating wells. Because these laws and regulations change frequently, the costs of compliance with existing and future environmental regulations cannot be predicted with certainty. Federal and State Regulation of Oil and Natural Gas The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government. Production of any oil and gas by us will be affected to some degree by state regulations. Many states in which we operate 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 our 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, 2000, we employed 181 persons. None of our employees are represented by a union. Relations with employees are considered to be good. 13 Facilities We occupy approximately 75,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten year lease expiring in 2005. The lease requires payments of approximately $106,000 per month. We have field offices in various locations from which our employees supervise local oil and gas operations. Glossary of Abbreviations and Terms The following abbreviations and terms have the indicated meanings when used in this report: Bbl - Barrel or barrels of oil. Bcf - Billion cubic feet of natural gas. Bcfe - Billion cubic feet of natural gas equivalent (see Mcfe). Development Well - A well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. Discovery Cost - With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions. Dry Well - An exploratory or development well that is not a producing well. Exploratory Well - A well drilled either in search of a new, as yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir. Gross Acre - 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. Gross Well - 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. MBbl - Thousand barrels of oil. Mcf - Thousand cubic feet of natural gas. Mcfe - Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas. MMBbl - Million barrels of oil. MMBtu - 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. MMcf - Million cubic feet of natural gas. MMcfe - Million cubic feet of natural gas equivalent (see Mcfe). NetAcre - 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. 14 NetWell - 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. Producing Well - An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. Proved Developed Oil and Gas Reserves - Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Oil and Gas Reserves - The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Proved Undeveloped Oil and Gas Reserves - Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved Undeveloped (PUD) Locations - A location containing proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. PV-10 Value - The estimated future net revenues 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. Reserves Replacement Cost - With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred acquisition, exploration, and development costs (exclusive of future development costs) by net reserves added during the period. Volumetric Production Payment - The 1992 agreement pursuant to which we financed the purchase of certain oil and natural gas interests and committed to deliver certain monthly quantities of natural gas. 15 Item 3. Legal Proceedings No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company's business. Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted during the fourth quarter of 2000 to a vote of security holders. PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters COMMON STOCK, 1999 AND 2000 Our common stock is traded on the New York Stock Exchange and the Pacific Exchange, Inc., under the symbol "SFY." The high and low quarterly sales prices for the common stock for 1999 and 2000 were as follows: 1999 2000 ----------------------------------- ----------------------------------- First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter ----------------------------------- ----------------------------------- Low $5.69 $8.25 $10.25 $10.31 $9.75 $15.00 $20.38 $28.81 High $8.63 $13.13 $13.13 $13.31 $17.88 $29.56 $41.88 $43.50 Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements, as discussed in Note 4 to the Consolidated Financial Statements, and we presently intend to continue a policy of using retained earnings for expansion of our business. We had approximately 477 stockholders of record as of December 31, 2000. 16 Item 6. Selected Financial Data
2000 1999 1998 1997 1996 Revenues Oil and Gas Sales $189,138,947 $108,898,696 $80,067,837 $69,015,189 $52,770,672 Fees and Earned Interests(2) $331,497 $229,749 $333,940 $745,856 $937,238 Interest Income $1,339,386 $833,204 $107,374 $2,395,406 $433,352 Other, Net $815,116 $709,358 $1,960,070 $2,555,729 $2,156,764 Total Revenues $191,624,946 $110,671,007 $82,469,221 $74,712,180 $56,298,026 Operating Income (Loss) $93,079,346 $29,736,151 ($73,391,581) $33,129,606 $28,785,783 Net Income (Loss) $59,184,008 $19,286,574 ($48,225,204) $22,310,189 $19,025,450 Net Cash Provided by Operating Activities $128,197,227 $73,603,426 $54,249,017 $55,255,965 $37,102,578 Per Share Data Weighted Average Shares Outstanding(3) 21,244,684 18,050,106 16,436,972 16,492,856 15,000,901 Earnings (Loss) per Share--Basic(3) $2.79 $1.07 ($2.93) $1.35 $1.27 Earnings (Loss) per Share--Diluted(3) $2.51 $1.07 ($2.93) $1.26 $1.25 Shares Outstanding at Year-End 24,608,344 20,823,729 16,291,242 16,459,156 15,176,417 Book Value per Share $13.50 $8.18 $6.71 $9.69 $9.41 Market Price(3) High $43.50 $13.31 $21.00 $34.20 $28.86 Low $9.75 $5.69 $6.94 $16.93 $9.89 Year-End Close $37.63 $11.50 $7.38 $21.06 $27.16 Pro forma amounts assuming 1994 change in accounting principle is applied retroactively(2) Net Income (Loss) $59,184,008 $19,286,574 ($48,225,204) $22,310,189 $19,025,450 Earnings (Loss) per Share--Basic (3) $2.79 $1.07 ($2.93) $1.35 $1.27 Earnings (Loss) per Share--Diluted (3) $2.51 $1.07 ($2.93) $1.26 $1.25 Assets Current Assets $41,872,879 $50,605,488 $35,246,431 $29,981,786 $101,619,478 Oil and Gas Properties, Net of Accumulated Depreciation, Depletion, and Amortization $524,052,828 $392,986,589 $356,711,711 $301,312,847 $200,010,375 Total Assets $572,387,001 $454,299,414 $403,645,267 $339,115,390 $310,375,264 Liabilities Current Liabilities $64,324,771 $34,070,085 $31,415,054 $28,517,664 $32,915,616 Long-Term Debt $134,729,485 $239,068,423 $261,200,000 $122,915,000 $115,000,000 Total Liabilities $240,232,846 $283,895,297 $294,282,628 $179,714,470 $167,613,654 Stockholders' Equity $332,154,155 $170,404,117 $109,362,639 $159,400,920 $142,761,610 Number of Employees 181 173 203 194 191 Producing Wells Swift Operated 817 769 836 650 842 Outside Operated 711 788 917 917 986 Total Producing Wells 1,528 1,557 1,753 1,567 1,828 Wells Drilled (Gross) 70 27 75 182 153 Proved Reserves Natural Gas (Mcf) 418,613,976 329,959,750 352,400,835 314,305,669 225,758,201 Oil & Condensate (barrels) 35,133,596 20,806,263 13,957,925 7,858,918 5,484,309 Total Proved Reserves (Mcf equivalent) 629,415,552 454,797,327 436,148,385 361,459,177 258,664,055 Production (Mcf equivalent)(4) 42,356,705 42,874,303 39,030,030 25,393,744 19,437,114 Average Sales Price Natural Gas (per Mcf) $4.24 $2.40 $2.08 $2.68 $2.57 Oil (per barrel) $29.35 $16.75 $11.86 $17.59 $19.82
(1) Additional 1994 Data: Income Before Cumulative Effect of Change in Accounting Principle-$3,725,671; Cumulative Effect of Change in Accounting Principle-$(16,772,698); Per Share Amounts-Basic-Income Before Cumulative Effect of Change in Accounting Principle-$0.51, Cumulative Effect of Change in Accounting Principle-$(2.29); Per Share Amounts-Diluted-Income Before Cumulative Effect of Change in Accounting Principle-$0.51, Cumulative Effect of Change in Accounting Principle-$(2.29). (2) As of January 1, 1994, we changed our revenue recognition policy for earned interests. Accordingly, in 1994 to 1999, "Fees and Earned Interests" does not include earned interests revenues. (3) Amounts have been retroactively restated in all periods presented to give recognition to: (a) an equivalent change in capital structure as a result of two 10% stock dividends, one in September 1994, the other in October 1997 (see Note 2 to the Consolidated Financial Statements); and (b) the adoption in 1998 of Statement of Financial Accounting Standards No. 128, "Earnings per Share" (see Note 2 to the Consolidated Financial Statements). (4) Natural gas production for 1992, 1993, 1994, 1995, 1996, 1997, 1998, 1999, and 2000 includes 1,148,862, 1,581,206, 1,358,375, 1,211,255, 1,156,361, 1,015,226, 866,232, 728,235, and 405,130 Mcf, respectively, delivered under our volumetric production payment agreement (see Note 1 to the Consolidated Financial Statements). 17
1995 1994(1) 1993 1992 1991 1990 $22,527,892 $19,802,188 $15,535,671 $12,420,222 $8,361,771 $7,328,190 $590,441 $701,528 $4,071,970 $2,716,277 $2,231,729 $9,882,953 $212,329 $47,980 $201,584 $113,387 $192,694 $705,786 $1,761,568 $1,072,535 $604,599 $515,931 $541,502 $323,981 $25,092,230 $21,624,231 $20,413,824 $15,765,817 $11,327,696 $18,240,910 $6,894,537 $4,837,829 $6,628,608 $4,687,519 $3,748,741 $10,811,044 $4,912,512 ($13,047,027) $4,896,253 $4,084,760 $2,512,815 $7,170,642 $14,376,463 $10,394,514 $7,238,340 $6,349,080 $5,911,588 $4,813,435 10,035,143 7,308,673 7,246,884 6,748,548 5,899,629 5,806,436 $0.49 ($1.79) $0.68 $0.61 $0.43 $1.23 $0.49 ($1.79) $0.64 $0.61 $0.43 $1.23 12,509,700 6,685,137 6,001,075 5,968,579 4,955,134 4,848,315 $7.46 $6.30 $9.08 $8.26 $7.80 $7.36 $11.48 $10.35 $11.57 $7.85 $9.09 $10.65 $7.05 $7.75 $7.14 $4.65 $4.34 $6.93 $10.91 $8.86 $7.85 $7.55 $4.95 $8.57 $4,912,512 $3,725,671 $4,322,478 $3,729,851 $2,950,245 $3,107,451 $0.49 $0.51 $0.60 $0.55 $0.50 $0.54 $0.49 $0.51 $0.57 $0.55 $0.50 $0.54 $43,380,454 $39,208,418 $65,307,120 $30,830,173 $47,859,278 $72,537,521 $125,217,872 $88,415,612 $89,656,577 $64,301,509 $47,655,917 $41,952,212 $175,252,707 $135,672,743 $160,892,917 $100,243,469 $101,421,573 $118,227,480 $40,133,269 $52,345,859 $55,565,437 $27,876,687 $50,851,447 $71,514,938 $28,750,000 $28,750,000 $28,750,000 $0 $0 $0 $81,906,742 $93,545,612 $106,427,203 $50,962,183 $62,761,217 $82,559,406 $93,345,965 $42,127,131 $54,465,714 $49,281,286 $38,660,356 $35,668,074 176 209 188 178 171 164 767 750 795 688 674 691 3,316 3,422 3,407 1,978 2,331 2,228 4,083 4,172 4,202 2,666 3,005 2,919 76 44 34 40 27 23 143,567,520 76,263,964 64,462,805 41,638,100 36,685,881 30,731,741 5,421,981 4,553,237 4,271,069 2,901,621 1,950,209 1,690,520 176,099,406 103,583,566 90,089,219 59,047,824 48,387,138 40,874,862 11,186,573 9,600,867 7,368,757 5,678,772 3,980,460 3,303,750 $1.77 $1.93 $1.96 $1.90 $1.58 $1.72 $15.66 $14.35 $15.10 $17.19 $18.26 $22.70
18 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes thereto. General Over the last several years, we have emphasized adding reserves through drilling activity. We also add reserves through strategic purchases of producing properties when oil and gas prices are at lower levels and other market conditions are appropriate, as we did in the third quarter of 1998 with the purchase of the Brookeland and Masters Creek areas. During the past three years, we have used this flexible strategy of employing both drilling and acquisitions to add more reserves than we depleted through production. Proved Oil and Gas Reserves. At year-end 2000, our total proved reserves were 629.4 Bcfe with a PV-10 Value of $2.3 billion. In 2000, our proved natural gas reserves increased 88.7 Bcf, or 27%, while our proved oil reserves increased 14.3 MMBbl, or 69%, for a total equivalent increase of 174.6 Bcfe, or 38%. From 1998 to 1999, our proved natural gas reserves decreased by 22.4 Bcf, or 6%, while our proved oil reserves increased by 6.8 MMBbl, or 49%, for a total equivalent increase of 18.6 Bcfe, or 4%. We added reserves from 1999 to 2000 through our drilling activity and to a lesser extent through purchases of minerals in place. Through drilling we added 184.7 Bcfe (122.5 Bcfe of which came from New Zealand) of proved reserves in 2000, 64.9 Bcfe in 1999, and 73.9 Bcfe in 1998. Through acquisitions we added 39.7 Bcfe of proved reserves in 2000, 20.1 Bcfe in 1999, and 97.6 Bcfe in 1998. At year-end 2000, 55% of our total proved reserves were proved undeveloped, compared with 51% at year-end 1999 and 45% at year-end 1998. While our total proved reserves quantities increased by 38% during 2000, the PV-10 Value of those reserves increased 310%, due to increased prices between year-end 1999 and year-end 2000. Between those two dates, there was a 282% increase in natural gas prices and a 4% increase in oil prices. Gas prices were $9.86 per Mcf at year-end 2000, compared to $2.58 per Mcf at year-end 1999. Oil prices were $24.62 per Bbl at year-end 2000, compared to $23.69 a year earlier. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant throughout the life of the properties. Subsequent changes to such year-end oil and gas prices could have a significant impact on the calculated PV-10 Value. The year-end 2000 gas price of $9.86 was significantly higher than the average gas price of $4.24 we received during 2000. Natural gas prices have declined since December 31, 2000, although through February 2001 they remain above the 2000 average gas price received. Had year-end reserves been calculated using the average 2000 prices we received, $29.35 for oil and $4.24 for gas, the PV-10 Value would have been approximately $1,125,000,000 compared to the $2,313,254,809 reported using year-end prices. Liquidity and Capital Resources During 2000, we primarily relied upon internally generated cash flows of $128.2 million to fund capital expenditures of $173.3 million. These capital expenditures were also funded with part of the remaining net proceeds from our third quarter 1999 issuance of Senior Notes and common stock. During 1999, we primarily used internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million. Net Cash Provided by Operating Activities. In 2000, net cash provided by our operating activities increased by 74% to $128.2 million, as compared to $73.6 million in 1999 and $54.2 million in 1998. The 2000 increase of $54.6 million was primarily due to $80.2 million of additional oil and gas sales, partially offset by $12.2 million of increases in oil and gas production costs, interest expense, and general and administrative expense. The 1999 increase of $19.4 million was primarily due to $28.8 million of additional oil and gas sales, partially offset by $12.2 million of increases in oil and gas production costs and interest expense. Existing Credit Facilities. At December 31, 2000, we had $10.6 million in outstanding borrowings under our credit facility. Our credit facility consists of a $250.0 million revolving line of credit with a $200.0 million borrowing base at year-end 2000. The borrowing base is redetermined at least every six months. Our revolving credit facility includes, among other restrictions, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios) and limitations on incurring other debt. We are in compliance with the provisions of this agreement. The credit facility extends until August 2002. At December 31, 1999, we had no outstanding borrowings under this facility. 19 Working Capital. Our working capital has decreased from $16.5 million at December 31, 1999, to a working capital deficit of $22.5 million at December 31, 2000, primarily due to our using the remaining proceeds from our third quarter 1999 public offering of Senior Notes and common stock to fund capital expenditures in 2000. Capital Expenditures. In 2000, our capital expenditures of approximately $173.3 million were spent as follows: Domestic Activities: o $90.3 million, or 52%, on developmental drilling; o $33.4 million, or 19%, for producing properties acquisitions, approximately half of which was for the purchase of property interests from partnerships managed by us, with the other half purchased from a third party; o $16.3 million, or 9%, on domestic prospect costs, principally leasehold, seismic, and geological costs; o $15.5 million, or 9%, on exploratory drilling; o $1.4 million, or 1%, for fixed assets; o $0.8 million, or less than 1%, on two gas processing plants in the Brookeland and Masters Creek areas; and o $0.2 million, or less than 1%, on field compression facilities. New Zealand Activities: o $7.6 million, or 4%, on developmental drilling to further delineate the Rimu area; o $4.5 million, or 3%, on prospect costs, principally seismic and geological costs; o $2.1 million, or 1%, for exploratory drilling; o $1.1 million, or 1%, on the initial stages of production facilities; and o $0.1 million, or less than 1%, for fixed assets, principally a field office and warehouse. In 2000, we participated in drilling 61 development wells and nine exploratory wells, of which 54 development wells and five exploratory wells were successes. Two of the development wells were drilled in New Zealand to delineate the Rimu area, both of which were successful. Our $55.5 million of unproved property costs not being amortized is indicative of our inventory of developmental and exploratory acreage to sustain drilling activity for future growth. Capital expenditures for 2001 are estimated to be approximately $173.8 million. Approximately $97.8 million of the 2001 budget is allocated to domestic drilling, primarily development drilling in the AWP Olmos, Brookeland, and Masters Creek areas, and exploratory drilling in the Gulf Coast Basin. In New Zealand, approximately $17.7 million of the 2001 budget is allocated to development and exploration drilling, with another $14.5 million expected to be spent primarily for production facilities. In 2001, we anticipate drilling 39 development wells and 10 exploratory wells domestically, along with four wells in New Zealand. Approximately $33.8 million is targeted towards the acquisition of producing properties. The remaining $20.1 million will be used primarily for domestic leasehold, seismic, and geological costs, while approximately $3.7 million is budgeted for such costs in New Zealand. Dispositions of approximately $13.8 million are anticipated. We believe that the anticipated internally generated cash flows for 2001, together with bank borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted 2001 capital expenditures. Our capital expenditures were approximately $78.1 million in 1999 and $183.8 million in 1998. During 1998, we used $138.3 million of bank borrowings, along with internal cash flows of $54.2 million, to fund capital expenditures. During 1999, we primarily used internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million. Our capital expenditures in 1999 included: o $34.0 million, or 44%, on developmental drilling; o $20.6 million, or 26%, on producing properties acquisitions, almost all of which was for the purchase of additional working interests in the Masters Creek area; o $10.4 million, or 13%, on prospect costs, principally leasehold, seismic, and geological costs; o $10.0 million, or 13%, on exploratory drilling, $5.9 million of which was in New Zealand; o $1.6 million, or 2%, on two gas processing plants in the Brookeland and Masters Creek areas; o $1.3 million, or 2%, on fixed assets; and o $0.2 million, or less than 1%, on field compression facilities. 20 In 1999, we participated in drilling 22 development wells and five exploratory wells, of which 19 development wells and two exploratory wells were successes. Two of the exploratory wells were drilled in New Zealand. The first well in New Zealand, in which we had a 7.5% working interest, was drilled by another operator and was temporarily abandoned. The second well, the Rimu-A1, which Swift drilled as operator with a 90% working interest, was successful. Results of Operations Revenues. Our revenues in 2000 increased by 73% over revenues in 1999 due to increases in oil and gas sales. Oil and gas sales revenues in 2000 increased by 74%, or $80.2 million, over those revenues for 1999. Our net sales volumes in 2000, including the volumetric production payment associated with each year's production, decreased by 1%, or 0.5 Bcfe, over net sales volumes in 1999. Average prices received for oil increased from $16.75 per Bbl in 1999 to $29.35 per Bbl in 2000. Average gas prices received increased from $2.40 per Mcf in 1999 to $4.24 per Mcf in 2000. In 2000, our $80.2 million increase in oil and gas sales resulted from: o Price variances that had an $81.7 million favorable impact on sales, $31.1 million of which was attributable to the 75% increase in average oil prices received and $50.6 million of which was attributable to the 77% increase in average gas prices received; and o Volume variances that had a $1.5 million unfavorable impact on sales, with $1.6 million of decreases coming from the 93,000 Bbl decrease in oil sales volumes, partially offset by an increase of $0.1 million from the 40,000 Mcf increase in gas sales volumes. Revenues in 1999 increased by 34% over 1998 revenues. In 1999, oil and gas sales revenues increased by 36%, or $28.8 million, over those revenues in 1998. In 1999, net sales volumes increased by 10%, or 3.8 Bcfe, over net sales volumes in 1998. Average oil prices received went from $11.86 per Bbl in 1998 to $16.75 per Bbl in 1999, and average gas prices received increased from $2.08 per Mcf in 1998 to $2.40 per Mcf in 1999. In 1999, our $28.8 million increase in oil and gas sales resulted from: o Price variances that had a $21.3 million favorable impact on sales, $12.6 million of which was attributable to the 41% increase in average oil prices received and $8.7 million of which was attributable to the 15% increase in average gas prices received; and o Volume variances that added $7.5 million of sales, with $9.0 million of increases coming from the 0.8 MMBbl increase in oil sales volumes, partially offset by a decline of $1.5 million from the 0.7 Bcf decrease in gas sales volumes. The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our four domestic core areas in 2000 and 1999: Revenues Net Sales Volume (In millions) (Bcfe) ------------------- -------------------- Area 2000 1999 2000 1999 ---------------- ------- ------- -------- ------- AWP Olmos $56.6 $31.5 13.5 13.1 Brookeland $20.3 $14.6 4.5 5.6 Giddings $12.5 $ 8.7 3.1 3.8 Masters Creek $89.2 $48.5 18.7 17.6 We scaled back our budgeted 1999 capital expenditures from budgeted amounts in prior years in response to commodity price decreases experienced in the latter part of 1998 and first half of 1999. Drilling activity then resumed at an increased pace as commodity prices rebounded in 2000. However, due to the decrease in the 1999 capital expenditures budget and the resulting curtailment of drilling, we drilled 27 gross wells in 1999 as compared to 75 in 1998 and 70 in 2000. Thus, the natural production declines in the Giddings and the Brookeland areas were not offset by newly developed production. 21 The following table provides additional information regarding our oil and gas sales:
Net Sales Volume Average Sales Price ------------------------------------ --------------------- Oil Gas Combined Oil Gas (MBbl) (Bcf) (Bcfe) (Bbl) (Mcf) -------- -------- ----------- -------- ------- 1998: First Qtr. 195 5.8 7.0 $12.61 $2.28 Second Qtr. 190 6.2 7.3 $11.20 $2.20 Third Qtr. 696 8.1 12.2 $11.94 $1.93 Fourth Qtr. 720 8.1 12.5 $11.74 $2.00 -------- -------- ----------- 1998 1,801 28.2 39.0 $11.86 $2.08 1999: First Qtr. 728 7.2 11.6 $10.87 $1.82 Second Qtr. 644 6.7 10.6 $15.25 $2.05 Third Qtr. 612 6.9 10.5 $18.46 $2.84 Fourth Qtr. 581 6.7 10.2 $23.99 $2.91 -------- -------- ----------- 1999 2,565 27.5 42.9 $16.75 $2.40 2000: First Qtr. 653 6.6 10.6 $27.35 $2.93 Second Qtr. 650 6.9 10.8 $27.55 $3.99 Third Qtr. 591 7.0 10.5 $30.68 $4.39 Fourth Qtr. 578 7.0 10.5 $32.26 $5.55 -------- -------- ----------- 2000 2,472 27.5 42.4 $29.35 $4.24
Revenues from our oil and gas sales comprised 99% of total revenues for 2000, 98% of total revenues for 1999, and 97% of total revenues for 1998. Natural gas production made up 65% of our production volumes in 2000, 64% in 1999, and 72% in 1998. Costs and Expenses. Our general and administrative expenses in 2000 increased $1.1 million, or 24%, from the level of such expenses in 1999, while 1999 general and administrative expenses increased $0.6 million, or 17%, over 1998 levels. These increases reflect the increase in our corporate activities. Our general and administrative expenses per Mcfe produced increased to $0.13 per Mcfe in 2000 from $0.10 per Mcfe in both 1999 and 1998. The portion of supervision fees netted from general and administrative expenses was $3.4 million for 2000, $3.2 million for 1999, and $2.7 million for 1998. Depreciation, depletion, and amortization of our assets, or DD&A, increased $5.4 million, or 13%, in 2000 from 1999, while 1999 DD&A increased $3.0 million, or 8%, from 1998 levels. This was primarily due to additions in our reserves and increased associated costs in 2000 over 1999, while in the 1999 period it was primarily due to the 10% increase in production over 1998. Our DD&A rate per Mcfe of production was $1.13 in 2000, $0.99 in 1999, and $1.01 in 1998, reflecting variations in per unit cost of reserves additions. Our production costs in 2000 increased $9.6 million, or 49%, over such expenses in 1999, while those expenses in 1999 increased $6.5 million, or 50%, over 1998 costs. Our production costs per Mcfe produced were $0.69 in 2000, $0.46 in 1999, and $0.34 in 1998. The portion of supervision fees netted from production costs was $3.4 million for 2000, $3.2 million for 1999, and $2.7 million for 1998. While our production costs increased 49% in 2000, our oil and gas sales increased 74%. That increase in oil sales had a direct impact on the increase in production costs, as severance taxes have a direct correlation to sales and were $4.9 million higher in 2000. Also, the increase in commodity prices brought increased demand, and therefore competition, for field services that resulted in an increase in the cost of those services. Remedial well work and workover costs increased $1.2 million over 1999 levels. In the Masters Creek area, salt-water disposal charges, which increased $0.4 million over 1999 charges, increased as the volume of water associated with that production increased. Also in the Masters Creek area, production chemical costs increased $0.6 million as we began our scale inhibitor program in that area. The 50% increase in our production costs during 1999 relates to the 10% increase in production volumes in 1999 over 1998. The higher percentage increase in costs was due to planned increases in remedial well work, increased severance taxes, and increased ad valorem taxes. The increase in severance taxes was partially due to the increase in oil and gas prices received in 1999 when compared to 1998. Also, severance taxes increased on certain wells in the Masters Creek area as the gas severance tax exemption they had 22 received from Louisiana expired once they had been in production for more than two years or once payout of the well occurred. The ad valorem tax increase resulted from wells we drilled in the first half of 1998 and wells drilled in 1998 that we acquired in the Brookeland and Masters Creek acquisition as those wells were subject to ad valorem taxes for the first time at the beginning of 1999. Interest expense on our Senior Notes issued in July 1999, including amortization of debt issuance costs, totaled $13.1 million in 2000 and $5.3 million in 1999. Interest expense on our Convertible Notes due 2006, including amortization of debt issuance costs, totaled $7.4 million in 2000 and $7.5 million in each of the years 1999 and 1998. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.7 million in 2000, $6.1 million in 1999, and $5.6 million in 1998. The total interest expense in 2000 was $21.2 million, of which $5.2 million was capitalized. The 1999 total interest expense was $18.9 million, of which $4.5 million was capitalized. The 1998 total interest expense was $13.1 million, of which $4.4 million was capitalized. We capitalize that portion of interest related to our exploration, partnership, and foreign business development activities. The increase in interest expense in 2000 was attributed to the replacement of our bank borrowings in August 1999 with the Senior Notes that carry a higher interest rate. The increase in interest expense in 1999 was attributed to the increase in amounts outstanding to fund our 1998 capital expenditures, which included the Brookeland and Masters Creek areas acquisition in the third quarter of 1998, and to the higher interest rate on our new Senior Notes when compared to our credit facility. In the fourth quarter of 2000, we took a $0.6 million non-recurring loss on the early extinguishment of debt (net of taxes), as discussed in Note 4 to the Consolidated Financial Statements. We called our Convertible Notes for redemption effective December 26, 2000. Holders of approximately $100.0 million of the Convertible Notes elected to convert their notes into shares of our common stock. Holders of the remaining $15.0 million of the Convertible Notes elected to redeem their notes for cash plus accrued interest. This cash redemption resulted in this non-recurring item. In the third quarter of 1998, we took a non-cash write-down of oil and gas properties, as discussed in Note 1 to the Consolidated Financial Statements. Lower prices for both oil and natural gas at September 30, 1998, necessitated a pre-tax domestic full-cost ceiling write-down of $77.2 million, or $50.9 million after tax. Also, in the third quarter of 1998, we re-evaluated the capitalized unproved properties costs in Russia of $10.8 million and in Venezuela of $2.8 million, which resulted in a separate non-cash pre-tax charge to earnings of $13.6 million, or $9.0 million after tax. The combination of the non-cash domestic full-cost ceiling write-down and the non-cash foreign impairment charges resulted in a combined non-cash charge to earnings of $90.8 million pre-tax, or $59.9 million after tax. Net Income. Our income before extraordinary item in 2000 of $59.8 million was 210% higher, and Basic earnings per share ("Basic EPS") before extraordinary item of $2.82 were 164% higher than our 1999 net income of $19.3 million and Basic EPS of $1.07. These increases reflected the effect of the 75% increase in average oil prices received and 77% increase in average gas prices received. Oil and gas prices rose each quarter and resulted in quarterly sequential increases in earnings. The lower percentage increase in Basic EPS reflects an 18% increase in weighted average shares outstanding in 2000, primarily due to our third-quarter 1999 public sale of 4.6 million shares of common stock. Our net income in 1999 of $19.3 million was 65% higher and Basic EPS of $1.07 was 51% higher than 1998 income before the non-cash write-down of oil and gas properties of $11.7 million and Basic EPS of $0.71. These increases reflected the effect of the 10% increase in production volumes, the 41% increase in oil prices, and the 15% increase in gas prices. Oil and gas prices rose rapidly in the third and fourth quarters of 1999, as reflected by last half net income making up 77% of net income for the year. The lower percentage increase in Basic EPS reflected a 10% increase in weighted average shares outstanding in 1999, primarily due to our third-quarter public sale of 4.6 million shares of common stock. Forward Looking Statements The statements contained in this report that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended. Such forward-looking statements may pertain to, among other things, financial results, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, and competition. Such forward-looking statements generally are accompanied by words such as "plan," "future," "estimate," "expect," "budget," "predict," "anticipate," "projected," "should," "believe," or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates, and 23 assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to change and to a number of risks and uncertainties, and, therefore, actual results may differ materially. Among the factors that could cause actual results to differ materially are: volatility in oil and natural gas prices, internationally or in the United States; availability of services and supplies; fluctuations of the prices received or demand for our oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; changes in geologic or engineering information; changes in market conditions; competition and government regulations; as well as the risks and uncertainties discussed herein, and set forth from time to time in our other public reports, filings, and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of such pricing volatility are discussed above, and such volatility is expected to continue. Our price risk program permits the utilization of agreements and financial instruments (such as futures, forward and options contracts, and swaps) to mitigate price risk associated with fluctuations in oil and natural gas prices. Below is a description of the financial instruments we have utilized to hedge our exposure to price risk. o Price Floors - Costs and any benefits derived from price floors were recorded as a reduction or increase, as applicable, in oil and gas sales revenues. The costs to purchase put options were amortized over the option period. Below is a summary of the utilization of price floors for the years ending December 31, 2000, 1999, and 1998. o The costs related to 2000 hedging activities totaled approximately $1,083,000, with benefits of approximately $579,000 being received, resulting in a net cash outlay of approximately $504,000, or $0.012 per Mcfe. The costs related to the open contracts as of December 31, 2000, totaled approximately $823,000, which is our maximum exposure under these contracts. These open contracts covering production for 2001, had a fair market value of approximately $209,000 at that date. Each of these contracts expire on or before March 31, 2001. o The costs related to 1999 hedging activities totaled approximately $909,000, with benefits of approximately $348,000 being received, resulting in a net cash outlay of approximately $561,000, or $0.013 per Mcfe. The costs related to the open contracts as of December 31, 1999, totaled approximately $98,000 and had a fair market value of $112,500. o The costs related to 1998 hedging activities totaled approximately $377,000, with benefits of approximately $101,000 being received, resulting in a net cash outlay of approximately $276,000, or $0.007 per Mcfe. o Participating Collars - During the fourth quarter of 1999, we entered into participating collars to hedge oil production through June 2000. Below is a summary of the collar arrangements for 2000. The participating collars were designated as hedges, and realized losses were recognized in oil and gas revenues when the associated production occurred. o We hedged 100,000 Bbls of oil per month for the months January through June 2000, with a floor price of $19.00 per Bbl and a ceiling price of $23.60 per Bbl, whereby we participate in 75% of any amount above the $23.60 ceiling price. These participating collars closed with our recording a loss of approximately $610,000, or $0.014 per Mcfe produced. There were no open participating collars at year-end 2000. Our adoption of SFAS No. 133, as amended, is discussed in Note 1 to the Consolidated Financial Statements. Interest Rate Risk. Our Senior Notes have a fixed interest rate, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on our Senior Notes. At December 31, 2000, we had $10.6 million borrowed under our credit facility, which is subject to floating rates, and therefore susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank's base rate would constitute 95 basis points and would impact 2001 cash flows by approximately $0.1 million. 24 Financial Instruments & Debt Maturities. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2000 and 1999, and were determined based upon interest rates currently available to us for borrowings with similar terms. Based on quoted market prices as of the respective dates, the fair value of our Senior Notes was $115.1 million at December 31, 2000 and $117.9 million at December 31, 1999, and the fair value of our Convertible Notes was $89.7 million at December 31, 1999. Our credit facility with the banks expires August 18, 2002. Our $125.0 million Senior Notes mature on August 1, 2009. 25 Item 8. Financial Statements and Supplementary Data Report of Independent Public Accountants..................................27 Consolidated Balance Sheets...............................................28 Consolidated Statements of Income.........................................29 Consolidated Statements of Stockholders' Equity...........................30 Consolidated Statements of Cash Flows.....................................31 Notes to Consolidated Financial Statements................................32 1. Summary of Significant Accounting Policies..........................32 2. Earnings Per Share..................................................35 3. Provision for Income Taxes..........................................36 4. Long-Term Debt .....................................................37 5. Commitments and Contingencies.......................................38 6. Stockholders' Equity................................................38 7. Related-Party Transactions..........................................41 8. Foreign Activities..................................................41 9. Acquisition of Properties...........................................42 Supplemental Information (Unaudited)......................................43 26 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, 2000 and 1999, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2000. 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 auditing standards generally accepted in the United States. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Houston, Texas February 19, 2001 27 Consolidated Balance Sheets Swift Energy Company and Subsidiaries
December 31, 2000 1999 --------------- ---------------- ASSETS Current Assets: Cash and cash equivalents $ 1,986,932 $ 22,685,648 Accounts receivable- Oil and gas sales 26,939,472 15,634,019 Associated limited partnerships and joint ventures 2,685,003 5,359,596 Joint interest owners 7,181,974 5,550,048 Other current assets 3,079,498 1,376,177 --------------- ---------------- Total Current Assets 41,872,879 50,605,488 --------------- ---------------- Property and Equipment: Oil and gas, using full-cost accounting Proved properties 753,426,124 573,360,199 Unproved properties 55,512,872 57,662,739 --------------- ---------------- 808,938,996 631,022,938 Furniture, fixtures, and other equipment 8,873,266 7,778,571 --------------- ---------------- 817,812,262 638,801,509 Less - Accumulated depreciation, depletion, and amortization (290,725,112) (242,966,019) --------------- ---------------- 527,087,150 395,835,490 --------------- ---------------- Other Assets: Receivables from associated limited partnerships, net of current portion -- 628,228 Deferred charges 3,426,972 7,230,208 --------------- ---------------- 3,426,972 7,858,436 --------------- ---------------- $ 572,387,001 $ 454,299,414 =============== ================ LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 54,977,397 $ 25,674,143 Payable to associated limited partnerships 1,291,787 609,967 Undistributed oil and gas revenues 8,055,587 7,785,975 --------------- ---------------- Total Current Liabilities 64,324,771 34,070,085 --------------- ---------------- Long-Term Debt 134,729,485 239,068,423 Deferred Revenues -- 576,658 Deferred Income Taxes 41,178,590 10,180,131 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, 25,452,148 and 21,683,185 shares issued, and 24,608,344 and 20,823,729 shares outstanding, respectively 254,521 216,832 Additional paid-in capital 293,396,723 191,092,851 Treasury stock held, at cost, 843,804 and 859,456 shares, respectively (12,101,199) (12,325,668) Retained earnings (deficit) 50,604,110 (8,579,898) --------------- ---------------- 332,154,155 170,404,117 --------------- ---------------- $ 572,387,001 $ 454,299,414 =============== ================
See accompanying Notes to Consolidated Financial Statements. 28 Consolidated Statements of Income Swift Energy Company and Subsidiaries
Year Ended December 31, 2000 1999 1998 -------------------------------------------------------- Revenues: Oil and gas sales $ 189,138,947 $ 108,898,696 $ 80,067,837 Fees from limited partnerships and joint ventures 331,497 229,749 333,940 Interest income 1,339,386 833,204 107,374 Other, net 815,116 709,358 1,960,070 ---------------- ----------------- -------------- 191,624,946 110,671,007 82,469,221 ---------------- ----------------- -------------- Costs and Expenses: General and administrative, net of reimbursement 5,585,487 4,497,400 3,853,812 Depreciation, depletion, and amortization 47,771,393 42,348,901 39,343,187 Oil and gas production 29,220,315 19,645,740 13,138,980 Interest expense, net 15,968,405 14,442,815 8,752,195 Write-down of oil and gas properties -- -- 90,772,628 ---------------- ----------------- -------------- 98,545,600 80,934,856 155,860,802 ---------------- ----------------- -------------- Income (Loss) Before Income Taxes and Extraordinary Item 93,079,346 29,736,151 (73,391,581) Provision (Benefit) for Income Taxes 33,265,480 10,449,577 (25,166,377) ---------------- ----------------- -------------- Income (Loss) Before Extraordinary Item $ 59,813,866 $ 19,286,574 $ (48,225,204) Extraordinary Loss on Early Extinguishment of Debt (net of taxes) 629,858 -- -- ---------------- ----------------- -------------- Net Income (Loss) $ 59,184,008 $ 19,286,574 $ (48,225,204) ================ ================= ============== Per Share Amounts- Basic: Income (Loss) Before Extraordinary Item $ 2.82 $ 1.07 $ (2.93) Extraordinary Loss 0.03 -- -- ---------------- ----------------- -------------- Net Income (Loss) $ 2.79 $ 1.07 $ (2.93) ================ ================= ============== Diluted: Income (Loss) Before Extraordinary Item $ 2.53 $ 1.07 $ (2.93) Extraordinary Loss 0.02 -- -- ---------------- ----------------- -------------- Net Income (Loss) $ 2.51 $ 1.07 $ (2.93) ================ ================= ============== Weighted Average Shares Outstanding 21,244,684 18,050,106 16,436,972 ================ ================= ==============
See accompanying Notes to Consolidated Financial Statements. 29 Consolidated Statements of Stockholders' Equity Swift Energy Company and Subsidiaries
Unearned Additional ESOP Retained Common Paid-in Treasury Compen- Earnings Stock (1) Capital Stock sation (Deficit) Total ---------- -------------- ------------- ------------- -------------- -------------- Balance, December 31, 1997 $ 168,470 $ 147,542,977 $ (8,519,665) $ (150,055) $ 20,359,193 $ 159,400,920 Stock issued for benefit plans (20,032 shares) 200 367,058 -- -- -- 367,258 Stock options exercised (84,757 shares) 847 735,746 -- -- -- 736,593 Employee stock purchase plan (20,756 shares) 208 317,340 -- -- -- 317,548 Stock dividend adjustment (16 shares) -- 461 -- -- (461) -- Allocation of ESOP shares -- (62,312) -- 150,055 -- 87,743 Purchase of 293,475 shares as treasury stock -- -- (3,322,219) -- -- (3,322,219) Net loss -- -- -- -- (48,225,204) (48,225,204) ---------- --------------- -------------- -------------- -------------- -------------- Balance, December 31, 1998 $ 169,725 $ 148,901,270 $ (11,841,884) $ -- $ (27,866,472) $ 109,362,639 Stock issued for benefit plans (90,738 shares) 224 (366,408) 978,956 -- -- 612,772 Stock options exercised (65,477 shares) 655 461,102 -- -- -- 461,757 Employee stock purchase plan (22,771 shares) 228 181,577 -- -- -- 181,805 Public stock offering (4,600,000 shares) 46,000 41,915,310 -- -- -- 41,961,310 Purchase of 246,500 shares as treasury stock -- -- (1,462,740) -- -- (1,462,740) Net income -- -- -- -- 19,286,574 19,286,574 ---------- -------------- ------------- ------------- -------------- -------------- Balance, December 31, 1999 $ 216,832 $ 191,092,851 $ (12,325,668) $ -- (8,579,898) $ 170,404,117 Stock issued for benefit plans (46,632 shares) 310 297,060 224,469 -- -- 521,839 Stock options exercised (543,450 shares) 5,434 4,316,446 -- -- -- 4,321,880 Employee stock purchase plan (29,889 shares) 299 297,414 -- -- -- 297,713 Subordinated notes conversion (3,164,644 shares) 31,646 97,392,952 -- -- -- 97,424,598 Net income -- -- -- -- 59,184,008 59,184,008 ---------- -------------- ------------- ------------- -------------- -------------- Balance, December 31, 2000 $ 254,521 $ 293,396,723 $ (12,101,199) $ -- $ 50,604,110 $ 332,154,155 ========== ============== ============= ============= ============== ============== (1)$.01 par value.
See accompanying Notes to Consolidated Financial Statements. 30 Consolidated Statements of Cash Flows Swift Energy Company and Subsidiaries
Year Ended December 31, ------------------------------------------------------ 2000 1999 1998 ----------------- ----------------- --------------- Cash Flows from Operating Activities: Net income (loss) $ 59,184,008 $ 19,286,574 $ (48,225,204) Adjustments to reconcile net income (loss) to net cash provided by operating activities- Depreciation, depletion, and amortization 47,771,393 42,348,901 39,343,187 Write-down of oil and gas properties -- -- 90,772,628 Deferred income taxes 33,413,626 10,435,115 (25,609,134) Deferred revenue amortization related to production payment (587,629) (1,056,284) (1,248,800) Other 1,075,848 628,614 478,470 Change in assets and liabilities- Increase in accounts receivable (14,308,274) (2,889,530) (2,129,360) Increase in accounts payable and accrued liabilities, excluding income taxes payable 1,601,042 4,850,036 689,347 Increase in income taxes payable 47,213 -- 177,883 ----------------- ----------------- --------------- Net Cash Provided by Operating Activities 128,197,227 73,603,426 54,249,017 ----------------- ----------------- --------------- Cash Flows from Investing Activities: Additions to property and equipment (173,277,356) (78,112,550) (183,815,927) Proceeds from the sale of property and equipment 3,844,375 4,531,935 1,533,112 Net cash received (distributed) as operator of oil and gas properties 19,769,213 5,995,842 (5,933,171) Net cash received (distributed) as operator of partnerships and joint ventures 2,674,593 (433,114) (1,559,537) Limited partnership formation and marketing costs -- -- (619,970) Other (1,329) (131,135) (113,716) ----------------- ----------------- --------------- Net Cash Used in Investing Activities (146,990,504) (68,149,022) (190,509,209) ----------------- ----------------- --------------- Cash Flows from Financing Activities: Proceeds from (payments of) of long-term debt (15,203,000) 124,045,000 -- Net proceeds from (payments of) bank borrowings 10,600,000 (146,200,000) 138,285,000 Net proceeds from issuances of common stock 2,697,561 42,719,776 1,421,399 Purchase of treasury stock -- (1,462,740) (3,322,219) Payments of debt issuance costs -- (3,501,441) (540,671) ----------------- ----------------- --------------- Net Cash Provided by (Used in) Financing Activities (1,905,439) 15,600,595 135,843,509 ----------------- ----------------- --------------- Net Increase (Decrease) in Cash and Cash Equivalents $ (20,698,716) $ 21,054,999 $ (416,683) Cash and Cash Equivalents at Beginning of Year 22,685,648 1,630,649 2,047,332 ----------------- ----------------- --------------- Cash and Cash Equivalents at End of Year $ 1,986,932 $ 22,685,648 $ 1,630,649 ================= ================= =============== Supplemental Disclosures of Cash Flows Information: Cash paid during year for interest, net of amounts capitalized $ 15,528,280 $ 8,618,020 $ 8,343,445 Cash paid during year for income taxes $ -- $ -- $ 36,286 Non-Cash Financing Activity: Conversion of convertible notes to common stock $ 99,797,000 $ -- $ --
See accompanying Notes to Consolidated Financial Statements. 31 Notes to Consolidated Financial Statements Swift Energy Company and Subsidiaries 1. Summary of Significant Accounting Policies Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company (Swift) and our wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on U.S. onshore natural gas reserves as well as onshore oil and natural gas reserves in New Zealand. Our investments in associated oil and gas partnerships and joint ventures are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity's assets, liabilities, revenues, and expenses are 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 current year presentation. Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates. Property and Equipment. We follow 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. Under the full-cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. Interest costs related to unproved properties are also capitalized to unproved oil and gas properties. General and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions involving a significant amount of reserves. The proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. Fees from associated oil and gas exploration and development limited partnerships are credited to oil and gas property costs to the extent they do not represent reimbursement of general and administrative expenses currently charged to expense. Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis, based on current economic conditions, and are amortized to expense as our capitalized oil and gas property costs are amortized. The vast majority of our properties are onshore, and historically the salvage value of the tangible equipment offsets our site restoration and dismantlement and abandonment costs. We expect that this relationship will continue in the future. We compute the provision for depreciation, depletion, and amortization of oil and gas properties on the unit-of-production method. Under this method, we compute 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. This calculation is done on a country-by-country basis for those countries with oil and gas production. We currently have production in the United States only. 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. The cost of unproved properties not being amortized is assessed quarterly, on a country-by-country basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, our management evaluates, among other factors, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, the political stability in the countries in which we have an investment, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized, if any. To the extent costs accumulated in countries where there are no proved reserves, any costs determined by management to be impaired are charged to income. 32 Domestic Properties. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using period-end prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Test"). This calculation is done on a country-by-country basis for those countries with proved reserves. The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. In 1998, as a result of low oil and gas prices at September 30, 1998, we reported a non-cash write-down on a before-tax basis of $77.2 million ($50.9 million after tax) on our domestic properties. Russia and Venezuela Write-downs. During the third quarter of 1998, as we do every reporting period, we evaluated all of our foreign unevaluated properties (a detailed description of which is included in Note 8 to the Consolidated Financial Statements), especially in light of the then increased volatility in the oil and gas markets, international uncertainty, and turmoil in the world capital markets. The increased volatility in the oil and gas markets affected our cash flows available for further exploration and forced us to scale back our capital expenditures budget. All of this was further accentuated in Venezuela by the economic crisis there, the results of which were to diminish the availability of financing in international markets for Venezuelan projects and to worsen Venezuelan currency problems. Petroleos de Venezuela, S.A., layoffs, threatened oil worker strikes, reduced OPEC production allocations, and other third-quarter 1998 events highlighted the problems that the oil and gas industry was encountering in Venezuela. As a result of these and other factors, in the third quarter of 1998 we charged to income all $2.8 million of costs related to our Venezuelan oil and gas exploration activities. In addition, in the third quarter of 1998, we charged to income all $10.8 million of costs relating to our Russian activities. This impairment was attributed not only to the volatility in the oil and gas markets and the severe tightening of international credit markets discussed above, but also to the increased political instability in Russia and the August 1998 collapse of the Russian currency. We believed that the economic and political situation would result in the lack of capital to develop the reserves underlying our net profits interest in the near term. Although we continue to believe that our net profits interest is legally enforceable under international law, for all these reasons we did not believe that realistically we would be able to recover our investment in Russia in the foreseeable future. Because of this, we determined that we no longer had a reasonable basis to continue capitalization of the costs in our Russia cost center. The combination of the third-quarter 1998 domestic full-cost ceiling write-down and foreign activities impairment charges reduced before-tax earnings by $90.8 million ($59.9 million after tax). New Zealand. During the fourth quarter of 1998 and the second quarter of 1999, we charged to income as additional depreciation, depletion, and amortization costs our portion of drilling costs associated with an unsuccessful exploratory well in each quarter drilled by other operators in New Zealand. These costs were $400,000 in 1998 and $290,000 in 1999. Because of the delineation of our 1999 Rimu discovery with two successful delineation wells drilled in 2000, proved reserves have been recognized in New Zealand at December 31, 2000. Commencing in the fourth quarter of 2000, at the end of each quarterly reporting period, a separate calculation of the Ceiling Test will be made for New Zealand in the same manner as the calculation for domestic properties as described above. Once production is established in New Zealand, the provision for depreciation, depletion, and amortization of oil and gas properties will be calculated on the unit-of-production method as described above. Oil and Gas Revenues. Gas revenues are reported using the entitlement method in which we recognize our ownership interest in natural gas production as revenue. If our sales exceed our ownership share of production, the differences are reported as deferred revenues. Natural gas balancing receivables are reported when our ownership share of production exceeds sales. As of December 31, 2000, we did not have any material natural gas imbalances. 33 Deferred Charges. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the public offering in November 1996 of our 6.25% Convertible Subordinated Notes (the "Convertible Notes") and with the public offering in August 1999 of our 10.25% Senior Subordinated Notes (the "Senior Notes") were capitalized and are amortized over the life of each of the respective note offerings. The Convertible Notes were called for redemption effective December 26, 2000, and the balance of their unamortized issuance costs at that time of $3,046,181 was either transferred to the common stock equity accounts ($2,643,476) for the portion of the Convertible Notes converted into common stock at the election of those note holders, or recorded, net of taxes, as Extraordinary Loss on Early Extinguishment of Debt ($402,705) for the portion of the Convertible Notes redeemed for cash. The Senior Notes mature on August 1, 2009, and the balance of their issuance costs at December 31, 2000, was $3,199,214, net of accumulated amortization of $302,227. The issuance costs associated with our revolving credit facility, which closed in August 1998, have been capitalized and are being amortized over the life of the facility, which will extend until August 2002. The balance of these issuance costs at December 31, 2000, was $227,758, net of accumulated amortization of $330,936. Limited Partnerships and Joint Ventures. We formed 88 limited partnerships between 1984 and 1995 to acquire interests in producing oil and gas properties and 13 partnerships between 1993 and 1998 to drill for oil and gas. In all of these partnerships, Swift paid for varying percentages of the capital or front-end costs and continuing costs of the partnerships and, in return, received differing percentage ownership interests in the partnerships, along with reimbursement of costs and/or payment of certain fees. At year-end 2000, we continue to serve as managing general partner of 80 of these various partnerships, and during fiscal 2000 approximately 4.7% of our total oil and gas sales was attributable to our interests in those partnerships. During 1997 and 1998, eight drilling partnerships formed between 1979 and 1985 and 21 of the production purchase partnerships sold their properties and were dissolved, in each case following a vote of the investors in the particular partnerships approving such liquidations. Between 1999 and 2001, the investors in all but six of the remaining partnerships voted to sell the properties or their interests in the partnership and dissolve. We anticipate that the liquidation and dissolution of these 74 partnerships should be substantially completed by the end of 2001. The remaining six partnerships will continue to operate. Price Risk Management Activities. Our revenues are derived from sales of our oil and natural gas production. Market prices of oil and natural gas may fluctuate and adversely affect operating results. To mitigate some of this risk, we do engage periodically in certain limited hedging activities, which include buying protection price floors and entering into participating collars for portions of our oil and natural gas production. These derivative financial instruments are placed with major financial institutions that we believe present minimum credit risk. Costs and any benefits derived from the price floors were recorded as a reduction or an increase, as applicable, in oil and gas sales revenues. The costs to purchase put options were amortized over the option period. The participating collars were designated as hedges and realized gains or losses were recognized in oil and gas revenues when the associated production occurred. The costs relating to 2000 hedging activities on the price floors totaled approximately $1,083,000 with benefits of approximately $579,000 being received, resulting in a net cash outflow of $504,000, or $0.012 per Mcfe produced. Participating collars covering oil for the first six months of 2000 closed with a loss of approximately $610,000, or $0.014 per Mcfe produced. The costs related to open price floor contracts as of December 31, 2000, totaled approximately $823,000, which is our maximum exposure under these contracts. These open contracts, covering 2001 production, had a fair market value of approximately $209,000 at that date. These contracts expire on or before March 31, 2001. There are no open participating collars at this time. Beginning January 1, 2001, our adoption of SFAS No. 133, as amended, is described below. Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax bases of assets and liabilities, given the provisions of the enacted tax laws. Deferred Revenues. In May 1992, we purchased interests in certain wells using funds provided by our sale of a volumetric production payment in these properties to Enron. We delivered the last remaining volumes under this arrangement in October 2000. Under the production payment agreement, we were required to deliver to Enron approximately 9.5 Bcf at an average price of $1.115 per MMBtu. We received all proceeds from the sale of excess gas at current market prices plus all proceeds from the sale of oil or condensate. In fiscal periods where volumes remained to be delivered under this arrangement, those volumes were not included in our proved reserves. Net proceeds from the sale of the production payment were recorded as 34 deferred revenues. Deliveries under the production payment agreement were recorded as oil and gas sales revenues with a corresponding reduction of deferred revenues. Cash and Cash Equivalents. We consider all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents. Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of monthly oil and gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2000, oil and gas sales to subsidiaries of Eastex Crude Company were $47.4 million, or 25.7% of our oil and gas sales, while sales to subsidiaries of PG&E Energy Trading Corporation were $21.2 million, or 11.5% of oil and gas sales. During 1999, oil and gas sales to subsidiaries of Eastex Crude Company were $21.7 million, or 19.4% of our oil and gas sales. During 1998, oil and gas sales to subsidiaries of PG&E Energy Trading Corporation were $13.0 million, or 16.2% of oil and gas sales, and to Aquila Southwest Pipeline Corporation were $8.0 million, or 10.0% of sales. Beginning in December 2000, the subsidiaries of PG&E Energy Trading Corporation to which we make sales were sold to subsidiaries of El Paso Corporation. All receivables from PG&E have been collected. Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2000 and 1999, and were determined based upon interest rates currently available to us for borrowings with similar terms. Based on quoted market prices as of the respective dates, the fair values of our Senior Notes were $115.1 million and $117.9 million at December 31, 2000 and 1999, respectively, and the fair value of our Convertible Notes was $89.7 million at December 31, 1999. The carrying value of our Senior Notes was $124.1 million at both December 31, 2000 and 1999, and the carrying value of our Convertible Notes was $115.0 million at December 31, 1999. New Accounting Pronouncements. In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, is effective for fiscal years beginning after June 15, 2000. We have a policy to use derivative instruments, mainly the buying of protection price floors, to protect against price declines in oil and gas prices. We currently believe that such derivatives would qualify for hedge accounting under SFAS No.133, as amended. We do not plan to designate our open contracts at December 31, 2000, for special hedge accounting treatment, and instead plan to mark them to market through earnings. The adoption of this standard beginning January 1, 2001, will result in a Cumulative Effect of a Change in Accounting Principle of approximately $0.4 million, net of taxes, in the first quarter of 2001. This results from the change between the costs of those contracts when purchased and their fair market value at December 31, 2000. We feel that there will not be a material change in our financial position and results of operations as a result of this new standard, since the costs to purchase such floors are our maximum loss exposure. However, the market value and timing of accounting for such costs under SFAS No. 133, as amended, may result in increased earnings volatility between interim reporting periods. 2. Earnings Per Share Basic earnings per share ("Basic EPS") has been computed using the weighted average number of common shares outstanding during the respective periods. The calculation of diluted earnings per share ("Diluted EPS") for all periods assumes conversion of our Convertible Notes as of the beginning of the respective periods and the elimination of the related after-tax interest expense and assumes, as of the beginning of the period, exercise of stock options and warrants using the treasury stock method. The assumed conversion of our Convertible Notes has been excluded from the calculation of Diluted EPS for the 1999 and 35 1998 periods, as they would have been antidilutive. Certain of our stock options that would potentially dilute Basic EPS in the future were also antidilutive for the 1999 and 1998 periods. The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the years ended December 31, 2000, 1999, and 1998:
2000 1999 1998 --------------------------------- --------------------------------- ------------------------------------ Per Per Per Net Share Net Share Net Share Income Shares Amount Income Shares Amount Loss Shares Amount ------------ ----------- ------- ------------ ----------- ------- ------------- ----------- -------- Basic EPS: Net Income (Loss) and Share Amounts $ 59,184,008 21,244,684 $ 2.79 $ 19,286,574 18,050,106 $ 1.07 $ (48,225,204) 16,436,972 $ (2.93) Dilutive Securities: 6.25% Convertible Notes 4,772,418 3,546,933 -- -- -- -- Stock Options -- 713,112 -- 42,365 -- -- ------------ ----------- ------------ ----------- ------------- ----------- Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 63,956,426 25,504,729 $ 2.51 $ 19,286,574 18,092,471 $ 1.07 $ (48,225,204) 16,436,972 $ (2.93) ============ =========== ============ =========== ============= ===========
3. Provision for Income Taxes The following is an analysis of the consolidated income tax provision (benefit): Year Ended December 31, -------------------------------------------------------- 2000 1999 1998 ---------------- -------------- -------------- Current $ (29,000) $ (11,819) $ 214,169 Deferred 33,294,480 10,461,396 (25,380,546) ---------------- -------------- -------------- Total $ 33,265,480 $ 10,449,577 $ (25,166,377) ================ ============== ============== There are differences between income taxes computed using the federal statutory rate (35% for 2000, 1999, and 1998) and our effective income tax rates (35.7%, 35.1%, and 34.3% for 2000, 1999, and 1998, respectively), primarily as the result of state income taxes and certain tax credits available to us. Reconciliations of income taxes computed using the statutory rate to the effective income tax rates are as follows:
2000 1999 1998 --------------- ------------- --------------- Income taxes computed at federal statutory rate $ 32,577,772 $ 10,407,653 $ (25,687,053) State tax provisions, net of federal benefits 775,850 (7,801) 23,949 Nonconventional fuel source credit -- -- (287,000) Depletion deductions in excess of basis -- -- (42,500) Other, net (88,142) 49,725 826,227 --------------- ------------- --------------- Provision (benefit) for income taxes $ 33,265,480 $ 10,449,577 $ (25,166,377) =============== ============= ===============
36 The tax effects of temporary differences representing the net deferred tax liability (asset) at December 31, 2000 and 1999, were as follows: 2000 1999 ----------------- ---------------- Deferred tax assets: Alternative minimum tax credits $ (1,979,399) $ (1,979,399) Net operating loss carry forward (16,194,060) (11,560,000) Other -- (237,587) ----------------- ---------------- Total deferred tax assets $ (18,173,459) $ (13,776,986) Deferred tax liabilities: Oil and gas properties $ 59,097,793 $ 23,520,417 Other 254,256 436,700 ----------------- ---------------- Total deferred tax liabilities $ 59,352,049 $ 23,957,117 ----------------- ---------------- Net deferred tax liability $ 41,178,590 $ 10,180,131 ================= ================ As of December 31, 2000, we had $47.5 million of net operating loss carry forwards, which expire as follows: $26.2 million, $20.1 million, and $1.2 million in 2013, 2014, and 2015, respectively. We did not record any valuation allowances against deferred tax assets at December 31, 2000 and 1999. At December 31, 2000, we had alternative minimum tax credits of $1,979,399 that carry forward indefinitely and are available to reduce future regular tax liability to the extent they exceed the related tentative minimum tax otherwise due. 4. Long-Term Debt Our long-term debt as of December 31, 2000 and 1999, is as follows: 2000 1999 ---------------- ---------------- Bank Borrowings $ 10,600,000 $ -- Convertible Notes -- 115,000,000 Senior Notes 124,129,485 124,068,423 ---------------- ---------------- Long-Term Debt $ 134,729,485 $ 239,068,423 ================ ================ Bank Borrowings. At December 31, 2000, we had outstanding borrowings of $10.6 million under our $250.0 million credit facility with a syndicate of eight banks which has a borrowing base of $200 million. At December 31, 1999, we had no borrowings under our credit facility. The interest rate is either (a) the lead bank's prime rate (9.5% at December 31, 2000) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the ratio of the outstanding balance to the last calculated borrowing base. Of the $10.6 million borrowed at December 31, 2000, $5.0 million was borrowed at the LIBOR rate plus applicable margin (7.8875% at December 31, 2000). The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $2.0 million 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 our common stock. We are currently in compliance with the provisions of this agreement. The credit facility extends until August 2002. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $654,936 in 2000, $6,107,270 in 1999, and $5,575,505 in 1998. 37 Convertible Notes. In November 1996, we sold $115 million of 6.25% Convertible Subordinated Notes due 2006. The Convertible Notes were unsecured and convertible into common stock of Swift at the option of the holders at an adjusted conversion price of $31.534 per share. Interest on the notes was payable semiannually, on May 15 and November 15. On December 11, 2000, we called for the redemption of our Convertible Notes effective December 26, 2000 at 103.75% of their principal amount. Holders of approximately $100.0 million of the Convertible Notes elected to convert their notes into 3,164,644 shares of our common stock. Holders of the remaining $15.0 million of the Convertible Notes elected to redeem their notes for cash plus accrued interest. This cash redemption resulted in our recognizing an Extraordinary Loss on the Early Extinguishment of Debt (net of taxes) of $0.6 million, or $1.0 million before taxes. Interest expense on the Convertible Notes, including amortization of debt issuance costs, totaled $7,426,599 in 2000, $7,569,361 in 1999, and $7,544,650 in 1998. Senior Notes. Our Senior Notes consist of $125,000,000 of 10.25% Senior Subordinated Notes due 2009. The Senior Notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The Senior Notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on the Senior Notes is payable semiannually, on February 1 and August 1, and commenced with the first payment on February 1, 2000. On or after August 1, 2004, the Senior Notes are redeemable for cash at the option of Swift, with certain restrictions, at 105.125% of principal, declining to 100% in 2007. In addition, prior to August 1, 2002, we may redeem up to 33.33% of the Senior Notes with the proceeds of qualified offerings of our equity at 110.25% of the principal amount of the Senior Notes, together with accrued and unpaid interest. Upon certain changes in control of Swift, each holder of Senior Notes will have the right to require us to repurchase the Senior Notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. Interest expense on the Senior Notes, including amortization of debt issuance costs and discount, totaled $13,092,127 in 2000 and $5,303,266 in 1999. 5. Commitments and Contingencies Total rental and lease expenses were $1,255,474 in 2000, $1,272,497 in 1999, and $1,117,351 in 1998. Our remaining minimum annual obligations under non-cancelable operating lease commitments are $1,151,249 for 2001, $1,273,007 for 2002, $1,358,238 for 2003, $1,370,414 for 2004, and $228,402 for 2005. As of December 31, 2000, we were the managing general partner of 80 limited partnerships. Because we serve as the general partner of these entities, under state partnership law we are 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. In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on the financial position or results of operations of Swift. 6. Stockholders' Equity Common Stock. During the third quarter of 1999, we issued 4.6 million shares of common stock at a price of $9.75 per share. Gross proceeds from this offering were $44,850,000 with issuance costs of $2,888,690. In December 2000, the holders of approximately $100 million of our Convertible Notes converted such notes into 3,164,644 shares of our common stock, which resulted in an increase in our common stock capital accounts of approximately $97.4 million. Stock-Based Compensation Plans. We have two current stock option plans, the 2001 Omnibus Stock Compensation Plan, which was adopted by our board of directors in February 2001 and which is being submitted for shareholder approval at the 2001 Annual Meeting of Shareholders, and the 1990 non-qualified plan, as well as an employee stock purchase plan. No further grants will be made under the 1990 stock compensation plan. 38 Under the 2001 plan, incentive stock options and other options and awards may be granted to employees to purchase shares of common stock. Under the 1990 plan, non-employee members of our board of directors may be granted options to purchase shares of common stock. Both plans provide that the exercise prices equal 100% of the fair value of the common stock on the date of grant. Unless otherwise provided, 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. At the time the stock options are exercised, the option price is credited to common stock and additional paid-in capital. On December 9, 1998, we canceled certain previously issued options under the 1990 stock compensation plan and reissued them at an option price that reflected current market value of our common stock as of that date. No compensation expense was recognized in 1998 as a result of this transaction. The employee stock purchase plan provides eligible employees the opportunity to acquire shares of Swift common stock at a discount through payroll deductions. The plan year is from June 1 to the following May 31. The first year of the plan commenced June 1, 1993. To date, employees have been allowed to 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 for stock acquired under the plan is 85% of the lower of the closing price of our 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. Under this plan, we have issued 29,889 shares at a price range of $8.40 to $10.57 in 2000, 22,771 shares at a price range of $5.21 to $11.00 in 1999, and 20,756 shares at a price range of $13.65 to $18.06 in 1998. The estimated weighted average fair value of shares issued under this plan was $4.25 in 2000, $4.74 in 1999, and $6.86 in 1998. As of December 31, 2000, 384,788 shares remained available for issuance under this plan. There are no charges or credits to income in connection with this plan. We account for our stock option plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." As all options were issued at a price equal to market price, no compensation expense has been recognized. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, "Accounting for Stock-Based Compensation," our net income (loss) and earnings per share would have been reduced to the following pro forma amounts: 2000 1999 1998 ----------- ----------- ------------ Net Income (Loss) As Reported $59,184,008 $19,286,574 $(48,225,204) Pro Forma $56,531,665 $16,869,122 $(49,985,171) Basic EPS: As Reported $2.79 $1.07 $(2.93) Pro Forma $2.66 $0.93 $(3.04) Diluted EPS: As Reported $2.51 $1.07 $(2.93) Pro Forma $2.40 $0.93 $(3.04) Pro forma compensation cost reflected above may not be representative of the cost to be expected in future years. 39 The following is a summary of our stock options under these plans as of December 31, 2000, 1999, and 1998:
2000 1999 1998 ------------------------ ----------------------- ------------------------- Wtd. Avg. Wtd. Avg. Wtd. Avg. Shares Exer. Price Shares Exer. Price Shares Exer. Price ------------------------ ----------------------- ------------------------- Options outstanding, beginning of period 2,148,511 $ 9.08 2,266,146 $ 9.03 1,761,512 $ 14.71 Options granted 645,944 $ 16.88 25,000 $ 12.50 1,319,881 $ 9.72 Options canceled (174,412) $ 8.71 (77,158) $ 8.95 (730,490) $ 24.15 Options exercised (543,450) $ 8.48 (65,477) $ 8.55 (84,757) $ 7.54 ----------- ----------- ----------- Options outstanding, end of period 2,076,593 $ 11.70 2,148,511 $ 9.08 2,266,146 $ 9.03 =========== =========== =========== Options exercisable, end of period 897,711 $ 9.35 1,280,156 $ 8.87 888,695 $ 8.64 =========== =========== =========== Options available for future grant, end of period 181,235 950,735 915,236 =========== =========== =========== Estimated weighted average fair value per share of options granted during the year $10.90 $7.10 $3.82 =========== =========== ===========
The fair value of each option grant, as opposed to its exercise price, is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions in 2000, 1999, and 1998, respectively: no dividend yield; expected volatility factors of 46.7%, 44.2%, and 42.3%; risk-free interest rates of 6.61%, 5.60%, and 4.69%; and expected lives of 6.7, 7.5, and 7.0 years. The following table summarizes information about stock options outstanding at December 31, 2000:
Options Outstanding Options Exercisable -------------------------------------------------- ---------------------------- Range of Number Wtd. Avg. Wtd. Avg. Number Wtd. Avg. Exercise Outstanding Remaining Exercise Exercisable Exercise Prices at 12/31/00 Contractual Life Price At 12/31/00 Price ----------------------- --------------- ---------------- ---------------- --------------- ------------ $ 4.00 to $ 13.99 1,687,901 6.7 $ 9.18 808,071 $ 8.51 $ 14.00 to $ 27.99 298,760 7.1 $ 20.10 89,640 $ 16.96 $ 28.00 to $ 41.00 89,932 6.1 $ 31.11 -- $ -- --------------- --------------- $ 4.00 to $ 41.00 2,076,593 6.7 $ 11.70 897,711 $ 9.35 =============== ===============
Employee Stock Ownership Plan. In 1996, we established an Employee Stock Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of 21 with one year of service are participants. This plan has a five-year cliff vesting, and service is recognized after the ESOP effective date. The ESOP is designed to enable our employees to accumulate stock ownership. While there will be no employee contributions, participants will receive an allocation of stock that has been contributed by Swift. Compensation expense is reported when such shares are released to employees. The plan may also acquire common stock of Swift purchased at fair market value. The ESOP can borrow money from Swift to buy Swift stock. This was done in September 1996 to purchase 25,000 shares (adjusted to 27,500 shares after the October 1, 1997, 10% stock dividend) from our chairman. Benefits will be paid in a lump sum or installments, and the participants generally have the choice of receiving cash or stock. At December 31, 2000, 1999 and 1998, all of the ESOP compensation was earned. Employee Savings Plan. We have a savings plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make voluntary contributions into the 401(k) savings plan with Swift contributing on behalf of the eligible employee an amount equal to 100% of the first 2% of compensation and 75% of the next 4% of compensation based on the contributions made by the eligible employees. Our contribution to the 401(k) savings plan totaled $483,000, $474,000, and $498,000 for the years ended December 31, 2000, 1999, and 1998, respectively. The contributions in 2000 and 1999 were made half in common stock and half in cash, while the 1998 contribution was made all in common stock. The shares of common stock contributed to the 401(k) savings plan totaled 7,175, 21,810, and 68,318 shares for the 2000, 1999, and 1998 contributions, respectively. The 1998 shares contributed were shares held as treasury stock and were contributed in early 1999. 40 Common Stock Repurchase Program. In March 1997, our board of directors approved a common stock repurchase program that terminated as of June 30, 1999. Under this program, we spent approximately $13.3 million to acquire 927,774 shares in the open market at an average cost of $14.34 per share. At December 31, 2000, 843,804 shares remain in treasury (net of 83,970 shares used to fund ESOP and 401(k) contributions) with a total cost of $12,101,199 and are included in "Treasury stock held, at cost" on the balance sheet. Shareholder Rights Plan. In August 1997, the board of directors declared a dividend of one preferred share purchase right on each outstanding share of Swift common stock. The rights are not currently exercisable but would become exercisable if certain events occurred relating to any person or group acquiring or attempting to acquire 15% or more of our outstanding shares of common stock. Thereafter, upon certain triggers, each right not owned by an acquirer allows its holder to purchase Swift securities with a market value of two times the $150 exercise price. 7. Related-Party Transactions We are the operator of a substantial number of properties owned by our affiliated limited partnerships and joint ventures and, accordingly, charge these entities and third-party joint interest owners operating fees. We are also reimbursed for direct, administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $4,465,000, $4,000,000, and $5,000,000 in 2000, 1999, and 1998, respectively. In partnerships in which the limited partners have voted to sell their remaining properties and liquidate their limited partnerships, we are also reimbursed for direct, administrative, and overhead costs incurred in the disposition of such properties, which costs totaled approximately $1,220,000, $850,000, and $580,000 in 2000, 1999, and 1998, respectively. 8. Foreign Activities New Zealand Swift Operated Permit. Our activity in New Zealand began in 1995 with the issuance of the first of two petroleum exploration permits. After a 1998 surrendering of a portion of our permit acreage, a combining of the two permits, and a 1999 expansion of the permit, as of year-end 2000 our permit 38719 covers approximately 100,700 acres in the Taranaki Basin of New Zealand's North Island, with all but 12,800 acres onshore. We have a 90% working interest in this permit and have fulfilled all current obligations under this permit. In late 1999, we completed our first exploratory well on this permit, the Rimu-A1, and a production test was performed. During the second half of 2000, we drilled and successfully tested two delineation wells, the Rimu-B1 and the Rimu-B2. We commenced drilling our third delineation well, the Rimu-A2, during December 2000. Our portion of the drilling, completion, and testing costs incurred on the wells within our permit area during 2000 was approximately $10.7 million. Our portion of prospect costs on our permit area during 2000 was approximately $4.4 million, which included obtaining 2-D seismic data in the first half of the year. We incurred $1.1 million on the initial phases of production facilities. In 2001, we plan to drill four wells, one exploratory well on our Kauri prospect to the southeast of the Rimu discovery and three wells to further delineate the Rimu area. Non-Operated Permits. In 1998, we entered into agreements for a 25% working interest in an exploration permit held by Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5% working interest held by Antrim Oil and Gas Limited, a Canadian company in a permit operated by Marabella. In turn, Bligh and Antrim each became 5% working interest owners in our permit. Unsuccessful exploratory wells were drilled on these two permits, and we charged $400,000 against earnings in 1998 and $290,000 in 1999. All of the acreage on the permit we had a 25% working interest in was surrendered in 2000. The exploratory well on the 7.5% working interest permit has been temporarily abandoned pending a further evaluation. In 2000, we entered into agreements with Fletcher Challenge Energy Limited whereby we will earn a 20% participating interest in petroleum exploration permit 38718 containing approximately 57,400 acres and a 25% participating interest in permit 38730 with approximately 48,900 acres. In January 2001, the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718 pending further analysis. The permit now contains approximately 28,700 acres after a scheduled surrender during December 2000. 41 Costs Incurred. During 2000 our portion of all costs incurred in New Zealand totaled $17.4 million, including $11.8 million for drilling, $4.5 million for prospect costs, and $1.1 million for production facilities. These costs included $1.2 million of costs incurred on permits operated by others: $1.1 million of drilling costs and $0.1 million of prospect costs. As of December 31, 2000, our investment in New Zealand totaled approximately $29.8 million. At year-end we recorded proved undeveloped reserves relating to our successful drilling activities. Accordingly, $21.1 million of our investment costs have been included in the proved properties portion of oil and gas properties and $8.7 million is included as unproved properties. The development strategy includes marketing oil and gas, with the intent of having production on line for oil and gas sales in New Zealand in 2001. Russia In 1993, we entered into a Participation Agreement with Senega, a Russian Federation joint stock company, to assist in the development and production of reserves from two fields in Western Siberia and received a 5% net profits interest. We also purchased a 1% net profits interest. Our investment in Russia, prior to its impairment in the third quarter of 1998, was approximately $10.8 million. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment. We retain a minimum 6% net profits interest from the sale of hydrocarbon products from the fields, the value of which depends upon the successful development of production from the fields by others, which may or may not occur. Venezuela In 1993, we formed a wholly owned subsidiary, Swift Energy de Venezuela, C. A., for the purpose of submitting a bid under the Venezuelan Marginal Oil Field Reactivation Program and entered into an agreement with two Venezuelan companies to jointly formulate and submit a proposal to Petroleos de Venezuela, S. A., for the construction and operation of a methane pipeline. Our investment in Venezuela, prior to its impairment in the third quarter of 1998, was approximately $2.8 million. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment. 9. Acquisition of Properties We purchased oil and gas interests in the Brookeland and Masters Creek areas from Sonat Exploration Company in the third quarter of 1998 for approximately $85.8 million in cash. Of this purchase price, $55.5 million was allocated to producing properties, $15.0 million to 20% interests in two natural gas processing plants, and $15.3 million to leasehold properties. This acquisition was accounted for by the purchase method and was incorporated into our results of operations in the third quarter of 1998. The following unaudited pro forma supplemental information presents consolidated results of operations as if this acquisition had occurred on January 1, 1998: Year Ended December 31, ------------------------------- Pro forma: 1998 ------------------------------- (Thousands, except per share amounts) (Unaudited) Revenue $ 115,394 Net Income Before Non-Cash Charge $ 19,098 Net Loss $ (40,812) Net Loss Per Share Amounts- Basic $ (2.48) Diluted $ (2.48) 42 Supplemental Information (Unaudited) Swift Energy Company and Subsidiaries Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and gas producing activities and the related depreciation, depletion, and amortization:
Total Domestic New Zealand -------------------- ---------------- ---------------- December 31, 2000 Proved oil and gas properties $ 753,426,124 $ 732,265,674 $ 21,160,450 Unproved oil and gas properties 55,512,872 46,833,274 8,679,598 -------------------- --------------- ---------------- 808,938,996 779,098,948 29,840,048 Accumulated depreciation, depletion, and amortization (284,886,168) (284,886,168) -- -------------------- --------------- ---------------- Net capitalized costs $ 524,052,828 $ 494,212,780 $ 29,840,048 ==================== =============== ================ December 31, 1999 Proved oil and gas properties $ 573,360,199 $ 573,360,199 $ -- Unproved oil and gas properties 57,662,739 45,902,357 11,760,382 -------------------- --------------- ---------------- 631,022,938 619,262,556 11,760,382 Accumulated depreciation, depletion, and amortization (238,036,349) (238,036,349) -- -------------------- --------------- ---------------- Net capitalized costs $ 392,986,589 $ 381,226,207 $ 11,760,382 ===================== =============== ================
Of the $46,833,274 of domestic unproved property costs (primarily seismic and lease acquisition costs) at December 31, 2000, excluded from the amortizable base, $15,426,247 was incurred in 2000, $7,937,074 was incurred in 1999, $18,845,964 was incurred in 1998, and $4,623,989 was incurred in prior years. When we are in an active drilling mode, we evaluate the majority of these unproved costs within a two to four year time frame. In response to market conditions in 1998, we decreased our 1999 drilling expenditures when compared to prior years, which, when coupled with the $15.3 million of leasehold properties acquired in the Brookeland and Masters Creek areas in 1998, may extend the evaluation timeframe of such costs. Of the $8,679,598 of net New Zealand unproved property costs at December 31, 2000, being excluded from the amortizable base, $5,177,122 was incurred in 2000, $925,623 was incurred in 1999, $417,521 was incurred in 1998, and $2,159,332 was incurred in prior years. We expect to continue drilling in New Zealand to delineate our prospects there, with four wells planned for drilling in 2001. We expect to complete our evaluation of current unevaluated costs over the next two to three years. 43 Costs Incurred. The following table sets forth costs incurred related to our oil and gas operations:
Year Ended December 31, 2000 ---------------------------------------------------------- Total Domestic New Zealand -------------------- --------------- ---------------- Acquisition of proved properties $ 34,191,883 $ 34,191,883 $ -- Lease acquisitions (1) 20,842,103 16,315,749 4,526,354 Exploration 20,150,834 18,524,883 1,625,951 Development 104,083,409 93,931,500 10,151,909 -------------------- ---------------- ---------------- Total acquisition, exploration, and development (2) $ 179,268,229 $ 162,964,015 $ 16,304,214 -------------------- ---------------- ---------------- Processing plants $ 1,819,464 $ 755,119 $ 1,064,345 Field compression facilities 203,789 203,789 -- -------------------- --------------- ---------------- Total plants and facilities $ 2,023,253 $ 958,908 $ 1,064,345 -------------------- --------------- ---------------- Total costs incurred $ 181,291,482 $ 163,922,923 $ 17,368,559 ==================== =============== ================ Year Ended December 31, 1999 ---------------------------------------------------------- Total Domestic New Zealand -------------------- --------------- ---------------- Acquisition of proved properties $ 18,526,939 $ 18,526,939 $ -- Lease acquisitions (1) 10,382,672 9,251,658 1,131,014 Exploration 11,019,430 5,101,330 5,918,100 Development 39,891,868 39,891,868 -- -------------------- --------------- ---------------- Total acquisition, exploration, and development (2) $ 79,820,909 $ 72,771,795 $ 7,049,114 -------------------- --------------- ---------------- Processing plants $ 1,607,559 $ 1,607,559 $ -- Field compression facilities 171,535 171,535 -- -------------------- --------------- ---------------- Total plants and facilities $ 1,779,094 $ 1,779,094 $ -- -------------------- --------------- ---------------- Total costs incurred $ 81,600,003 $ 74,550,889 $ 7,049,114 ==================== =============== ================ Year Ended December 31, 1998 ---------------------------------------------------------- Total Domestic New Zealand -------------------- --------------- ---------------- Acquisition of proved properties $ 59,487,524 $ 59,487,524 $ -- Lease acquisitions (1,3) 39,078,914 38,193,773 885,141 Exploration 12,578,124 10,520,637 2,057,487 Development 54,821,131 54,821,131 -- -------------------- --------------- ---------------- Total acquisition, exploration, and development (2) $ 165,965,693 $ 163,023,065 $ 2,942,628 -------------------- --------------- ---------------- Processing plants $ 15,000,000 $ 15,000,000 $ -- Field compression facilities 2,228,101 2,228,101 -- -------------------- --------------- ---------------- Total plants and facilities $ 17,228,101 $ 17,228,101 $ -- -------------------- --------------- ---------------- Total costs incurred $ 183,193,794 $ 180,251,166 $ 2,942,628 ==================== =============== ================
(1) These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties in 2000, 1999, and 1998 were $16,791,834, $14,389,680, and $11,409,108, respectively. (2) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $10,300,000, $8,500,000, and $12,300,000 in 2000, 1999, and 1998, respectively. In addition, total includes $5,043,206, $4,142,098, and $3,849,665 in 2000, 1999, and 1998, respectively, of capitalized interest on unproved properties. (3) Lease acquisitions for 1998 include expenditures of $421,602 relating to initiatives in Venezuela and $592,841 relating to initiatives in Russia. 44 Results of Operations. All of our oil and gas operations are domestic. New Zealand operations are expected to commence in 2001. The following table sets forth results of our domestic oil and gas operations:
Year Ended December 31, -------------------------------------------------- 2000 1999 1998 -------------- --------------- --------------- Oil and gas sales $ 189,138,947 $ 108,898,696 $ 80,067,837 Oil and gas production costs (29,220,315) (19,645,740) (13,138,980) Depreciation and depletion (46,849,819) (41,410,106) (38,490,222) Write-down of oil and gas properties -- -- (90,772,628) -------------- --------------- --------------- 113,068,813 47,842,850 (62,333,993) Provision (benefit) for income taxes 40,365,566 16,792,840 (21,380,560) -------------- --------------- --------------- Results of producing activities $ 72,703,247 $ 31,050,010 $ (40,953,433) ============== =============== =============== Amortization per physical unit of production (equivalent Mcf of gas) $ 1.11 $ 0.97 $ 0.99 ============== =============== ===============
45 Supplemental Reserve Information. The following information presents estimates of our proved oil and gas reserves. Domestic reserves were determined by us and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. New Zealand gross reserves were independently estimated by Gruy. The net reserves and cash flows for New Zealand were prepared by us. Gruy's summary report dated February 7, 2001, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 2000, and includes definitions and assumptions that served as the basis for the audit of proved reserves and future net cash flows. Such definitions and assumptions should be referred to in connection with the following information:
Estimates of Proved Reserves Total Domestic New Zealand ------------------------- ---------------------------- ------------------------ Oil, NGL, Oil, NGL, Oil, NGL, Natural and Natural and Natural and Gas Condensate Gas Condensate Gas Condensate (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) ------------ ----------- ------------- ----------- ---------- ----------- Proved reserves as of December 31, 1997 (1) 314,305,669 7,858,918 314,305,669 7,858,918 -- -- Revisions of previous estimates (2) (42,958,447) (2,291,223) (42,958,447) (2,291,223) -- -- Purchases of minerals in place 54,189,901 7,237,298 54,189,901 7,237,298 -- -- Sales of minerals in place (1,727,878) (39,932) (1,727,878) (39,932) -- -- Extensions, discoveries, and other additions 55,951,332 2,993,540 55,951,332 2,993,540 -- -- Production (3) (27,359,742) (1,800,676) (27,359,742) (1,800,676) -- -- ------------ ----------- ------------- ----------- ---------- ----------- Proved reserves as of December 31, 1998 (1) 352,400,835 13,957,925 352,400,835 13,957,925 -- -- Revisions of previous estimates (2) (31,189,450) 2,058,725 (31,189,450) 2,058,725 -- -- Purchases of minerals in place 9,159,780 1,822,858 9,159,780 1,822,858 -- -- Sales of minerals in place (3,762,799) (260,287) (3,762,799) (260,287) -- -- Extensions, discoveries, and other additions 30,107,908 5,791,966 30,107,908 5,791,966 -- -- Production (3) (26,756,524) (2,564,924) (26,756,524) (2,564,924) -- -- ------------ ----------- ------------- ----------- ---------- ----------- Proved reserves as of December 31, 1999 (1) 329,959,750 20,806,263 329,959,750 20,806,263 -- -- Revisions of previous estimates (2) (4,300,787) (455,606) (4,300,787) (455,606) -- -- Purchases of minerals in place 26,567,925 2,196,547 26,567,925 2,196,547 -- -- Sales of minerals in place (363,262) (76,288) (363,262) (76,288) -- -- Extensions, discoveries, and other additions 93,869,841 15,134,694 38,556,364 3,943,807 55,313,477 11,190,887 Production (3) (27,119,491) (2,472,014) (27,119,491) (2,472,014) -- -- ------------ ----------- ------------- ----------- ----------- ------------ Proved reserves as of December 31, 2000 418,613,976 35,133,596 363,300,499 23,942,709 55,313,477 11,190,887 ============ =========== ============= =========== ========== =========== Proved developed reserves: December 31, 1997 191,108,214 4,288,696 191,108,214 4,288,696 -- -- December 31, 1998 197,105,963 7,142,566 197,105,963 7,142,566 -- -- December 31, 1999 174,046,096 8,437,299 174,046,096 8,437,299 -- -- December 31, 2000 215,169,833 10,980,196 215,169,833 10,980,196 -- --
(1) Proved reserves exclude quantities subject to our volumetric production payment agreement, which expired with the last required delivery of volumes in October 2000. (2) Revisions of previous 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, 2000, were based upon prices in effect at year-end. The weighted average of such year-end prices for total, domestic, and New Zealand were $9.86, $11.25, and $0.71 per Mcf of natural gas and $24.62, $25.50, and $22.30 per barrel of oil, respectively. This compares to $2.58 per Mcf and $23.69 per barrel as of December 31, 1999, all reserves of which were domestic. (3) Natural gas production for 1998, 1999, and 2000 excludes 866,232, 728,235, and 405,130 Mcf, respectively, delivered under our volumetric production payment agreement. 46 Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:
Year Ended December 31, 2000 --------------------------------------------------------- Total Domestic New Zealand ------------------ ---------------- ---------------- Future gross revenues $ 4,995,951,799 $ 4,737,560,630 $ 258,391,169 Future production costs (817,127,348) (807,436,139) (9,691,209) Future development costs (204,620,116) (180,320,116) (24,300,000) ------------------ ---------------- ---------------- Future net cash flows before income taxes 3,974,204,335 3,749,804,375 224,399,960 Future income taxes (1,321,061,952) (1,243,731,594) (77,330,358) ------------------ ---------------- ---------------- Future net cash flows after income taxes 2,653,142,383 2,506,072,781 147,069,602 Discount at 10% per annum (1,075,183,917) (1,017,995,158) (57,188,759) ------------------ ---------------- ---------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,577,958,466 $ 1,488,077,623 $ 89,880,843 ================== ================ ================ Year Ended December 31, 1999 --------------------------------------------------------- Total Domestic New Zealand ------------------ ---------------- ---------------- Future gross revenues $ 1,371,541,850 $ 1,371,541,850 $ -- Future production costs (353,594,258) (353,594,258) -- Future development costs (156,738,446) (156,738,446) -- ------------------ ---------------- ---------------- Future net cash flows before income taxes 861,209,146 861,209,146 -- Future income taxes (226,725,033) (226,725,033) -- ------------------ ---------------- ---------------- Future net cash flows after income taxes 634,484,113 634,484,113 -- Discount at 10% per annum (195,540,279) (195,540,279) -- ------------------ ---------------- ---------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 438,943,834 $ 438,943,834 $ -- ================== ================ ================ Year Ended December 31, 1998 --------------------------------------------------------- Total Domestic New Zealand ------------------ ---------------- ---------------- Future gross revenues $ 972,852,038 $ 972,852,038 $ -- Future production costs (294,307,549) (294,307,549) -- Future development costs (118,420,782) (118,420,782) -- ------------------ ---------------- ---------------- Future net cash flows before income taxes 560,123,707 560,123,707 -- Future income taxes (123,875,660) (123,875,660) -- ------------------ ---------------- ---------------- Future net cash flows after income taxes 436,248,047 436,248,047 -- Discount at 10% per annum (145,974,944) (145,974,944) -- ------------------ ---------------- ---------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 290,273,103 $ 290,273,103 $ -- ================== ================ ================
The standardized measure of discou9nted 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 a9re 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 we reasonably expect to receive. 47 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 carry forwards. The estimates of cash flows and reserves quantities shown above are based on year-end oil and gas prices for each period. Subsequent changes to such year-end oil and gas prices could have a significant impact on discounted future net cash flows. Natural gas prices have declined since December 31, 2000. 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 to the Consolidated Financial Statements). 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 our 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. The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Year Ended December 31, ------------------------------------------------------ 2000 1999 1998 ----------------- ----------------- -------------- Beginning balance $ 438,943,834 $ 290,273,103 $ 292,838,340 ----------------- ----------------- -------------- Revisions to reserves proved in prior years-- Net changes in prices, production costs, and future development costs 1,523,487,598 123,447,890 (107,301,930) Net changes due to revisions in quantity estimates (36,102,814) (23,746,974) (47,924,995) Accretion of discount 56,405,451 34,078,501 35,034,478 Other (220,119,873) 2,032,696 (34,966,058) ----------------- ----------------- -------------- Total revisions 1,323,670,362 135,812,113 (155,158,505) New field discoveries and extensions, net of future production and development costs 359,265,150 102,582,467 73,956,430 Purchases of minerals in place 160,240,785 39,282,292 87,628,829 Sales of minerals in place (598,021) (5,360,428) (1,928,900) Sales of oil and gas produced, net of production costs (159,331,003) (88,196,672) (65,680,050) Previously estimated development costs incurred 65,953,028 39,149,732 51,622,419 Net change in income taxes (610,185,669) (74,598,773) 6,994,540 ----------------- ----------------- -------------- Net change in standardized measure of discounted future net cash flows 1,139,014,632 148,670,731 (2,565,237) ----------------- ----------------- -------------- Ending balance $ 1,577,958,466 $ 438,943,834 $ 290,273,103 ================= ================= ==============
48 Quarterly Results. The following table presents summarized quarterly financial information for the years ended December 31, 1999 and 2000:
Basic EPS Diluted EPS Income Income Income Income Basic Diluted Before Before Before Before EPS EPS Income Extraordinary Net Extraordinary Extraordinary Net Net Revenues Taxes Item Income Item Item Income Income -------------- ------------- --------------- ------------ -------------- ------------- --------- --------- 1999 First Quarter $ 21,488,087 $ 1,905,419 $ 1,281,755 $ 1,281,755 $ 0.08 $ 0.08 $ 0.08 $ 0.08 Second Quarter 23,928,734 4,786,405 3,152,027 3,152,027 0.20 0.20 0.20 0.20 Third Quarter 31,279,295 10,934,826 7,107,637 7,107,637 0.37 0.36 0.37 0.36 Fourth Quarter 33,974,891 12,109,501 7,745,155 7,745,155 0.37 0.36 0.37 0.36 ------------- ------------- -------------- ------------ Total $ 110,671,007 $ 29,736,151 $ 19,286,574 $ 19,286,574 $ 1.07 $ 1.07 $ 1.07 $ 1.07 ============= ============= ============== ============ 2000 First Quarter $ 37,747,645 $ 14,919,044 $ 9,589,828 $ 9,589,828 $ 0.46 $ 0.43 0.46 0.43 Second Quarter 46,127,375 22,218,358 14,213,274 14,213,274 0.68 0.61 0.68 0.61 Third Quarter 49,525,166 24,748,163 15,832,348 15,832,348 0.74 0.66 0.74 0.66 Fourth Quarter 58,224,760 31,193,781 20,178,416 19,548,558 0.93 0.82 0.90 0.80 ------------- ------------- -------------- ------------ Total $ 191,624,946 $ 93,079,346 $ 59,813,866 $ 59,184,008 $ 2.82 $ 2.53 $ 2.79 $ 2.51 ============= ============= ============== ============
49 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. PART III Item 10. Directors and Executive Officers of the Registrant The information required under Item 10 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 8, 2001, annual shareholders' meeting is incorporated herein by reference. Item 11. Executive Compensation The information required under Item 11 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 8, 2001, annual shareholders' meeting is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management The information required under Item 12 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 8, 2001, annual shareholders' meeting is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions The information required under Item 13 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 8, 2001, annual shareholders' meeting is incorporated herein by reference. 50 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. The following consolidated financial statements of Swift Energy Company together with the report thereon of Arthur Andersen LLP dated February 19, 2001, and the data contained therein are included in Item 8 hereof: Report of Independent Public Accountants........................27 Consolidated Balance Sheets.....................................28 Consolidated Statements of Income...............................29 Consolidated Statements of Stockholders' Equity.................30 Consolidated Statements of Cash Flows...........................31 Notes to Consolidated Financial Statements......................32 2. Financial Statement Schedules None 3. Exhibits 3(a).1(1) Articles of Incorporation, as amended through June 3, 1988. 3(a).2(3) Articles of Amendment to Articles of Incorporation filed on June 4, 1990. 3(b)(6) By-Laws, as amended through August 14, 1995. 4(a).1(11) Indenture dated as of July 29, 1999, between Swift Energy Company and Bank One, N.A., as Trustee. 4(a).2(12) First Supplemental Indenture dated as of August 4, 1999, between Swift Energy Company and Bank One, N.A., including the form of 10.25% Senior Subordinated Notes due 2009. 10.1(1)+ Indemnity Agreement dated July 8, 1988, between Swift Energy Company and A. Earl Swift (plus schedule of other persons with whom Indemnity Agreements have been entered into). 10.2(2)+ Swift Energy Company 1990 Nonqualified Stock Option Plan. 10.3(7)+ Amended and Restated Swift Energy Company 1990 Stock Compensation Plan, as of May 1997. 10.4(6)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy Company and Terry E. Swift. 10.5(6)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy Company and James M. Kitterman. 10.6(6)+ Employment Agreement dated as of November 1, 1995, by and between Swift Energy Company and Bruce H. Vincent. 10.7(8)+ Employment Agreement dated as of February 1, 1998, by and between Swift Energy Company and Joseph A. D'Amico. 10.8(9) Amended and Restated Rights Agreement between Swift Energy Company and American Stock Transfer & Trust Company, dated March 31, 1999. 51 10.9(10)+ Employment Agreement dated as of May 11, 1999, by and between Swift Energy Company and Alton D. Heckaman, Jr. 10.10(12) Letter Agreement among Swift Energy Company, Bank One, Texas, N.A. and other Lenders party to the Credit Agreement, dated August 18, 1999. 10.11(13) Amended and Restated Credit Agreement among Swift Energy Company and Bank One, Texas, National Association as administrative agent, ABN-AMRO Bank N.V. as syndication agent, and CIBC Inc. as documentation agent and the lenders signatory hereto dated March 10, 2000. 10.12(*)+ Amended and Restated Employment Agreement between Swift Energy Company and A. Earl Swift, dated November 15, 2000. 10.13(*)+ Fourth Amended and Restated Agreement and Release, by and between Swift Energy Company and Virgil Neil Swift, dated November 20, 2000. 12(*) Swift Energy Company Ratio of Earnings to Fixed Charges. 18(4) Letter from Arthur Andersen LLP dated February 17, 1995, regarding change in accounting principle. 21(5) List of Subsidiaries of Swift Energy Company. 23(a)(*) The consent of H. J. Gruy and Associates, Inc. 23(b)(*) The consent of Arthur Andersen LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration Statements. 99(*) The summary of H. J. Gruy and Associates, Inc. report, dated February 7, 2001. (b) No reports on Form 8-K were filed during the year 2000. (1)Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-8754. (2)Incorporated by reference from Registration Statement No. 33-36310 on Form S-8 filed on August 10, 1990. (3)Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 1992. (4)Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 1994. (5)Incorporated by reference from Registration Statement No. 33-60469 on Form S-2 filed on June 22, 1995. (6)Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q filed for the quarterly period ended September 30, 1995. (7)Incorporated by reference from Swift Energy Company definitive proxy statement for annual shareholders meeting filed April 14, 1997. (8)Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q filed for the quarterly period ended June 30, 1998. (9)Incorporated by reference from Swift Energy Company Amendment No. 1 to Form 8-A, filed April 7, 1999. (10)Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999. (11)Incorporated by reference from Exhibit 4.2 to Pre-Effective Amendment No. 1 to Form S-3 Registration Statement No. 33-81651 of Swift Energy Company, filed July 9, 1999, which Exhibit 4.2 is the form of such Indenture. (12)Incorporated by reference from Swift Energy Company Report on Form 8-K dated August 4, 1999. (13)Incorporated by reference from Swift Energy Company Annual Report on Form 10-K from the fiscal year ended December 31, 1999. (*)Filed herewith. +Management contract or compensatory plan or arrangement. 52 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SWIFT ENERGY COMPANY By /S/ A. Earl Swift ------------------------------ A. Earl Swift Chairman of the Board, Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant, Swift Energy Company, and in the capacities and on the dates indicated: Signatures Title Date ---------- ----- ----- /S/ A. Earl Swift Chairman of the Board --------------------------- Chief Executive Officer March 25, 2001 A. Earl Swift /S/ Terry E. Swift Director --------------------------- President March 25, 2001 Terry E. Swift /S/ Alton D. Heckaman Jr. Sr. Vice-President--Finance --------------------------- Principal Financial Officer March 25, 2001 Alton D. Heckaman Jr. /S/ David W. Wesson Controller --------------------------- Principal Accounting Officer March 25, 2001 David W. Wesson 53 /S/ G. Robert Evans ----------------------------- Director March 25, 2001 G. Robert Evans /S/ Henry C. Montgomery ----------------------------- Director March 25, 2001 Henry C. Montgomery /S/ Clyde W. Smith, Jr. ----------------------------- Director March 25, 2001 Clyde W. Smith, Jr. /S/ Virgil N. Swift ----------------------------- Director March 25, 2001 Virgil N. Swift /S/ Harold J. Withrow ----------------------------- Director March 25, 2001 Harold J. Withrow 54 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 EXHIBITS TO FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2000 SWIFT ENERGY COMPANY 16825 NORTHCHASE DRIVE, SUITE 400 HOUSTON, TEXAS 77060 55 EXHIBITS 10.12 Amended and Restated Employment Agreement between Swift Energy Company and A. Earl Swift, dated November 15, 2000. 10.13 Fourth Amended and Restated Agreement and Release, by and between Swift Energy Company and Virgil Neil Swift dated November 20, 2000. 12 Swift Energy Company Ratio of Earnings to Fixed Charges. 23 (a) The consent of H.J. Gruy and Associates, Inc. 23 (b) The consent of Arthur Andersen LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration Statements. 99 The summary of H.J. Gruy and Associates, Inc. report, dated February 7, 2001. 56 Exhibit 10.12 57 AMENDED AND RESTATED EMPLOYMENT AGREEMENT THIS EMPLOYMENT AGREEMENT ("Agreement") originally dated as of November 1, 1995, and previously amended February 15, 1999, is further amended this 15th day of November 2000, and is by and between Swift Energy Company, a Texas corporation (the "Company"), and A. Earl Swift ("Mr. Swift"). W I T N E S S E T H: - - - - - - - - - - WHEREAS, Mr. Swift is employed as the Chairman of the Board and Chief Executive Officer of the Company; and WHEREAS, the Company and Mr. Swift wish to document certain terms of employment of Mr. Swift in such capacity; NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the Company and Mr. Swift hereby agree as follows: 1. Employment and Term of Employment. Subject to the terms and conditions of this Agreement, the Company hereby agrees to employ Mr. Swift, and Mr. Swift hereby agrees to serve as Chairman of the Board and Chief Executive Officer of the Company, or in such other position as is mutually acceptable to both Mr. Swift and the Company, for a period (depending on the length of the "Initial Term" as hereinafter defined) of up to twelve years, herein referred to as the "Term of Employment," commencing on November 1, 1995. The "Initial Term" of the Term of Employment shall commence on November 1, 1995, and shall continue thereafter for a period of seven years, unless earlier terminated (i) by Mr. Swift, at his option, upon 180 days prior written notice of termination given to the Board of Directors of the Company specifying the date of such termination; or (ii) by the Board of Directors of the Company by 180 days prior written notice given to Mr. Swift enclosing a true copy of a formal, resolution of the Board of Directors of the Company duly adopted in accordance with Section 7(a) hereof, specifying the date of such termination. The "Subsequent Term" of the Term of Employment shall be a five-year period commencing upon the date of termination of the Initial Term. 2. Scope of Employment. During the Initial Term, (i) Mr. Swift will serve as Chairman of the Board and Chief Executive Officer of the Company with the powers and responsibilities of such position set forth in the bylaws of the Company, or in such other position as is mutually acceptable to both Mr. Swift and the Company, and Mr. Swift will perform diligently to the best of his ability those duties set forth therein and in this Agreement in a manner that promotes the interests and goodwill of the Company and (ii) the Company shall not require Mr. Swift to relocate from Houston, Texas. During the Subsequent Term, Mr. Swift will be available for up to 46 weeks per year for consultation regarding specific matters designated by, or particular assignments agreed upon with, the Executive Committee of the Board of Directors or the Board of Directors of the Company, together with serving in those specific executive or director's positions to which Mr. Swift is elected by either the Board of Directors or by the shareholders of the Company, which assignments may be performed from locations that are linked by computer to the Company's principal executive offices in Houston, Texas. At any time during both the Initial Term and the Subsequent Term, it is specifically agreed that Mr. Swift is entitled to be paid his accumulated vacation and sick leave, without regard to any Company policies to the contrary, with payment to be made at such times as requested by Mr. Swift. 3. Compensation and Change of Control. (a) During Initial Term. (i) Basic Compensation. During the Initial Term, the Company shall compensate Mr. Swift for his services hereunder in such amount as shall be determined by the Compensation Committee of the Board of Directors of the Company from time to time, according to policies current in effect or as modified from time to time by the Board of Directors or the Compensation Committee of the Board of Directors. 58 (ii) Compensation upon Change of Control. Upon a "Change of Control" (as defined in Section 7(b)(2) below) during the Initial Term, Mr. Swift shall be paid a lump sum (discounted according to Section 7(b)(i) below) equal to the total compensation which would otherwise be payable to Mr. Swift if he worked during both the remainder of the Initial Term and the entire Subsequent Term, plus the amounts payable under Section 3(c) below. For purposes of calculating the lump sum total compensation amount, each year's annual compensation shall be equal to Mr. Swift's annual compensation actually paid during the last preceding full fiscal year of the Initial Term during which he was paid both base salary and a bonus. (b) During Subsequent Term. (i) Basic Compensation. During the Subsequent Term, Mr. Swift's annual base compensation will be one-half of his annual base compensation at the end of the Initial Term, plus an annual inflation adjustment of 4% per annum. At the end of the Initial Term, the Board of Directors or Compensation Committee of the Board of Directors of the Company will enter into a new bonus arrangement with Mr. Swift covering the Subsequent Term, which takes into account anticipated activity levels and duties. (ii) Compensation Upon Change of Control. In the event of a Change of Control during the Subsequent Term, Mr. Swift shall be paid a lump sum (discounted according to Section 7(b)(i) below) equal to the total compensation which would otherwise be payable to Mr. Swift if he worked during the remainder of the Subsequent Term, plus the amounts payable under Section 3(c) below. For purposes of calculating the lump sum total compensation amount, each year's annual compensation shall be equal to Mr. Swift's total annual compensation actually paid during (x) the last preceding full fiscal year of the Subsequent Term during which he was paid both base salary and a bonus or (y) if no bonus has been paid for any fiscal year during the Subsequent Term, the last preceding full fiscal year of the Subsequent Term. (c) Non-Competition Payment. In consideration of Mr. Swift's continued compliance with Section 6 of this Agreement (whether or not he continues as an employee of the Company hereunder), the Company shall pay to Mr. Swift five equal annual installments of the amount shown as the "Non-Competition Payment" on Exhibit A hereto less normal federal withholding tax deductions, if any, related thereto, which annual amount shall be payable on the first day of each year of the Subsequent Term hereunder; provided that if Mr. Swift should die prior to the end of the Initial Term or the Subsequent Term, any remaining unpaid installments to be paid under this Section 3(c) (or the entire amount) shall be paid to Mr. Swift's spouse, if she is then living, or otherwise shall be paid to his estate. In the event of Mr. Swift's death, this payment shall be made in the year of death or the year thereafter at the direction of Mr. Swift's spouse or estate, as applicable. 4. Additional Compensation and Benefits. As additional compensation for Mr. Swift's services under this Agreement, during the Term of Employment the Company agrees to provide Mr. Swift with the following reimbursements and benefits: (a) The Company shall reimburse Mr. Swift for reasonable and necessary expenses incurred by Mr. Swift in furtherance of the Company's business, including a mileage allowance for all business-related travel on a per-mile basis at a rate equivalent to that allowed by the Internal Revenue Service, provided that such expenses are incurred in accordance with the Company's policies and upon presentation of documentation in accordance with expense reimbursement policies of the Company as they may exist from time to time, and submission to the Company of adequate documentation in accordance with federal income tax regulations. 59 (b) Mr. Swift may participate in any non-cash benefits provided by the Company to its employees as they may exist from time to time. During both the Initial Term and the Subsequent Term, the Company will provide Mr. Swift at the Company's expense, benefits which shall include leave or vacation time, medical and dental insurance, life insurance, accidental death and dismemberment insurance, retirement benefits and disability benefits, as such benefits may hereafter be provided by the Company in accordance with its policies in force from time to time. In addition, in the event of Mr. Swift's death during the Term of Employment, for a twelve-month period after his death the Company shall make available to Mr. Swift's spouse and his dependents under the age of 20, at the expense of the Company, medical and dental insurance comparable to that provided under the Company's then existing medical and dental insurance policies, and thereafter for the remainder of the period covered by the Term of Employment such medical and dental insurance shall be provided to Mr. Swift's spouse and dependents under the age of 20, with Mr. Swift's spouse to reimburse the Company for the cost for comparable family coverage under the Company's medical and dental insurance policies, unless otherwise prohibited by applicable law. 5. Confidentiality. (a) Mr. Swift recognizes that the Company's business involves the handling of confidential information of both the Company and the Company's affiliates and subsidiaries and requires a confidential relationship between the Company and its affiliates and subsidiaries and the Company and Mr. Swift. The Company's business requires the fullest practical protection and confidential treatment of unique and proprietary business and technical information, including but not limited to inventions, trade secrets, patents, proprietary and confidential data and knowledge of both the Company's affiliates and subsidiaries and the Company (collectively, hereinafter called "Confidential Information") which is conceived or obtained by Mr. Swift in the course of his employment. Accordingly, during and after termination of employment by the Company, Mr. Swift agrees: (i) to not disclose to any third party any such Confidential Information; (ii) not to use for Mr. Swift's own benefit any of the Company's Confidential Information, and (iii) not to aid others in the use of such Confidential Information in competition with the Company or its affiliates and subsidiaries. These obligations shall exist during and after any termination of employment hereunder. Notwithstanding anything else contained herein, the term "Confidential Information" shall not be deemed to include any general knowledge, skills or experience acquired by Mr. Swift or any knowledge or information known to the public in general. (b) Mr. Swift agrees that every item of Confidential Information referred to in this Section 5 which relates to the Company's present business or which arises or is contemplated to arise out of use of the Company's time, facilities, personnel or funds prior to Mr. Swift's termination, is the property of the Company. (c) Mr. Swift further agrees that upon termination of his employment for any reason, he will surrender to the Company all reports, manuals, procedures, guidelines, documents, writing, illustrations, models and other such materials produced by him or coming into his possession by virtue of his employment with the Company during the period of his employment and agrees that all such materials are at all times the property of the Company. Mr. Swift shall be entitled to review, inspect and copy any of the Company information or material necessary for legal or other proceedings to which Mr. Swift is a party defendant by reason of the fact that he is or was an employee or director of the Company. 6. Covenant Not to Compete. (a) Subject to the provisions of (c) of this section, without the express prior written consent of the Company, Mr. Swift will not serve as an employee, officer, director or consultant, or in any other similar capacity or make investments (other than open market investments in no more than five percent (5%) of the outstanding stock of any publicly traded company) in or on behalf of any person, firm, corporation, association or other entity whose activities directly compete with the activities of the Company existing or contemplated as of the date Mr. Swift last worked on the Company's behalf pursuant to this Agreement, in those oil and gas basins in which the Company is active or as to which it has begun study or analysis, where such employment may involve working for or with, or assisting, such competitor with activities that are the same as or similar to activities Mr. Swift performed on behalf of the Company; provided, however, the Company recognizes that any investment made by Mr. Swift in oil and gas properties owned by the Company which investments are made on the same terms (or terms more favorable 60 to the Company) as those offered to unaffiliated third parties are specifically excluded from this section; and (b) Subject to the provisions of (c) of this Section, without the express prior written consent of the Company, he will not solicit, recruit or hire, or assist any person, firm, corporation, association or other entity in the solicitation, recruitment or hiring of any person engaged by the Company as an employee, officer, director or consultant. (c) Mr. Swift's obligations under (a) and (b) of this section shall continue in force only while he is receiving payments from the Company under this Agreement after termination, provided that if there has been a "Change in Control," as defined below, then the provisions of (a) and (b) of this section shall have no further force and effect after the date that such Change of Control occurs. 7. Termination. (a) Mr. Swift may terminate his employment during the Term of Employment upon 180 days' written notice, and the Company, upon 180 days' written notice, may terminate Mr. Swift's employment by the Company solely for Cause. "Cause" shall be defined as (i) a final non-appealable judgment that Mr. Swift has committed fraud against the Company, its subsidiaries or customers, or (ii) final conviction of a felony. Any such termination by the Company shall require the affirmative vote of a majority of the members of the Board of Directors of the Company then in office who have been or will have been directors for the two-year period ending on the date notice of the meeting or written consent to take such action is first provided to shareholders or directors, as the case may be, or those directors who have been nominated for election or elected to succeed such directors by a majority of such directors (the "Continuing Directors"). (i) In the case of termination during the Initial Term due to Mr. Swift's resignation, except in those circumstances covered by Section 7(b) below, Mr. Swift shall continue to receive his then current salary (based upon the salary being paid to Mr. Swift immediately prior to termination) (x) for a period of six months from the date of termination of his employment hereunder, and (y) for a period beginning in the seventh month thereafter and ending once the amounts paid under this clause (y) equal the total of two weeks' then current salary for every year of service to the Company prior to that date (rounded up to the nearest month of service); and (ii) In the case of termination during the Subsequent Term due to Mr. Swift's resignation, except in those circumstances covered by Section 7(b) below, Mr. Swift will continue to receive his then current salary (x) for a period of one year from the date of termination of his employment hereunder, and (y) for a period beginning in the thirteenth month thereafter and ending once the amounts paid under this clause (y) equal the total of four weeks' then current salary for every year of service to the Company prior to that date (rounded up to the nearest month of service). Notwithstanding anything to the contrary contained in this Agreement, no termination by Mr. Swift of his employment under this Agreement during the Subsequent Term shall cause the payments to be made during the Subsequent Term based upon continuation of Mr. Swift's base salary to be made for more than a five-year period. Upon termination of Mr. Swift's employment hereunder, Mr. Swift will receive payments only under the provisions of either Section 7(a)(i) or Section 7(a)(ii), but not under both sections. In addition to the amounts payable under Section 7(a)(i) or Section 7(a)(ii) above, in the event of either such termination, the Company shall continue at its expense such medical and dental coverage as then in effect for the period during which Mr. Swift is being paid under either Section 7(a)(i) or 7(a)(ii), and shall pay all scheduled premium payments on the universal life insurance policy covering Mr. Swift as in force immediately prior to his termination of employment hereunder, in addition to the Non-Competition Payments set out in Section 3(c) hereof. In the event of Mr. Swift's termination for Cause, he shall not be entitled to receive any further salary payments, but he shall be entitled to receive the Non-Competition Payments set out in Section 3(c) hereof. 61 (b) Change of Control. (i) In the event of a "Change in Control," as defined below, on the date of such Change of Control, the Company: (x) shall pay Mr. Swift a lump sum equal to the amounts to be paid under this Agreement as set out in either Section 3(a)(ii) or Section 3(b)(ii), plus amounts set out in Section 3(c), which amounts provide compensation for each remaining year of the Term of Employment, discounted to present value at a rate of 8% per annum; (y) shall continue at the Company's expense such medical and dental coverage as then in effect for a twelve month period; and (z) and shall pay all scheduled premium payments on the universal life insurance policy covering Mr. Swift as in force immediately prior to his termination of employment hereunder, or any successor to, or replacement of, such policies, together with assignment of ownership (if possible under the terms thereof) of any universal life policy to Mr. Swift within one year following such Change of Control, such assignment to take place on a date designated by Mr. Swift. Effective as of the day prior to such Change of Control, all outstanding unexercised stock options to purchase shares of common stock of the Company held by Mr. Swift as of such date will immediately become 100% vested. (ii) Change of Control: "Change of Control," for purposes of this Agreement, shall be deemed to have occurred upon the occurrence of any one (or more) of the following events, other than a transaction with another person controlled by, or under common control with, the Company: (A) Any person, including a "group" as defined in Section (3)(d)(3) of the Securities Exchange Act of 1934, as amended, becomes the beneficial owner of shares of the voting stock of the Company with respect to which 40% or more of the total number of votes for the election of the Board may be cast; (B) As a result of, or in connection with, any cash tender offer, exchange offer, merger or other business combination, sale of assets or contested election, or combination of the above, persons who were directors of the Company immediately prior to such event shall cease to constitute a majority of the Board; (C) The stockholders of the Company shall approve an agreement providing either for a transaction in which the Company will cease to be an independent publicly owned corporation or for a sale or other disposition of all or substantially all the assets of the Company; or (D) A tender offer or exchange offer is made for shares of the Company's Common Stock (other than one made by the Company), and shares of Common Stock are acquired thereunder ("Offer"). (iii) Notwithstanding anything to the contrary in this Agreement, in the event that any payment, distribution, or other benefit provided by the Company to or for the benefit of Mr. Swift, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended, or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest or penalties, are hereinafter collectively referred to as the "Excise Tax"), the Company shall pay to Mr. Swift an additional payment (a "Gross-up Payment") in an amount such that after payment by Mr. Swift of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax imposed on any Gross-up Payment, Mr. Swift retains an amount of the Gross-up Payment equal to the Excise Tax imposed upon the Payments. The Company and Mr. Swift shall make an initial determination as to whether a Gross-up Payment is required and the amount of any such Gross-up Payment. Mr. Swift shall notify the Company immediately in writing of any claim by the Internal Revenue Service which, if successful, would require the Company to make a Gross-up Payment (or a Gross-up Payment in excess of that, if any, initially determined by the Company and Mr. Swift) within fifteen days of the receipt of such claim. The Company shall notify Mr. Swift in writing at least ten days prior to the due date of any response required with respect to such claim if it plans to contest such claim. If the Company decides to contest such claim, Mr. Swift shall 62 cooperate fully with the Company in such action; provided, however, the Company shall bear and pay directly or indirectly all costs and expenses (including additional interest and penalties) incurred in connection with such action and shall indemnify and hold Mr. Swift harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of the Company's action. If, as a result of the Company's action with respect to a claim, Mr. Swift receives a refund of any amount paid by the Company with respect to such claim, Mr. Swift shall promptly pay such refund to the Company. If the Company fails to timely notify Mr. Swift whether it will contest such claim or the Company determines not to contest such claim, then the Company shall immediately pay to Mr. Swift the portion of such claim, if any, which it has not previously paid to Mr. Swift. (c) In the event of termination due to Mr. Swift's death or as a result of sickness or disability of a permanent nature rendering Mr. Swift unable to perform his duties hereunder for a period of six (6) consecutive months ("Permanent Disability") during the Term of Employment, the Company shall pay to Mr. Swift or to Mr. Swift's spouse, if she is then living, or otherwise shall pay to the estate of Mr. Swift, as applicable, in the year of death or Permanent Disability or the year thereafter (at the direction of Mr. Swift's estate or guardian), a lump sum payment equal to the amounts to be paid under this Agreement as set out in Section 3 hereof (including the amounts set out in Section 3(c) hereof), discounted to present value at a rate of 8% per annum. On the date of his death or Permanent Disability, the unvested portions of all outstanding stock options issued to Mr. Swift to purchase shares of common stock of the Company held by Mr. Swift immediately prior to such date will immediately become 100% vested and shall remain exercisable by Mr. Swift's estate or by Mr. Swift, as applicable, for one year following such death or Permanent Disability. (d) Immediately prior to the date of termination of Mr. Swift's employment under this Agreement by either party, all outstanding unexercised options to purchase shares of common stock of the Company held by Mr. Swift (as of the day prior to such termination) shall immediately vest or be deemed to have vested, and otherwise Mr. Swift shall retain such options with no change in the number of shares covered by such options, the date such options first become exercisable, the period over which they are exercisable, or their exercise price. 8. Governing Law. This Agreement shall be governed by and construed under the laws of the State of Texas. Venue and jurisdiction of any action relating to this Agreement shall lie in Houston, Harris County, Texas. 9. Notice. Any notice, payment, demand or communication required or permitted to be given by this Agreement shall be deemed to have been sufficiently given or served for all purposes if delivered personally to and signed for by the party or to any officer of the party to whom the same is directed or if sent by registered or certified mail, return receipt requested, postage and charges prepaid, addressed to such party at its address set forth below such party's signature to this Agreement or to such other address as shall have been furnished in writing by such party for whom the communication is intended. Any such notice shall be deemed to be given on the date so delivered. 10. Severability. In the event any provisions hereof shall be modified or held ineffective by any court, such adjudication shall not invalidate or render ineffective the balance of the provisions hereof. 11. Entire Agreement. This Agreement constitutes the sole agreement between the parties and supersedes any and all other agreements, oral or written, relating to the subject matter covered by the Agreement with the exception of certain Indemnity Agreements which may exist between the Company and Mr. Swift, and which remain in force independent of this Agreement. This Agreement may be executed in multiple counterparts with the same effect as one original document. 12. Waiver. Any waiver or breach of any of the terms of this Agreement shall not operate as a waiver of any other breach of such terms or conditions, or any other terms or conditions, nor shall any failure to enforce any provisions hereof operate as a waiver of such provision or any other provision hereof. 13. Assignment. This Agreement is a personal employment contract and the rights and interests of Mr. Swift hereunder may not be sold, transferred, assigned or pledged. 63 14. Successors. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, representatives, successors and assigns. 15. Disputes. If a dispute arises out of or related to this Agreement and the dispute cannot be settled through direct discussions, the Company and Mr. Swift agree that if it then becomes necessary in Mr. Swift's judgment for him to sue the Company in order to collect amounts to be paid to him under this Agreement or otherwise enforce his rights under this Agreement, then the Company will be obligated to pay both its own and Mr. Swift's legal fees in such litigation, including the obligation of the Company to pay Mr. Swift's legal fees within thirty days of receiving invoices therefor from Mr. Swift. 16. Lump Sum Payments. If payments to be made under any portion of this Agreement provide for such payments to be made over a period of time, Mr. Swift and the Company's Board of Directors may agree for such payments to be made in a lump sum, which shall be determined by discounting the periodic payments using a discount factor of 8% per annum. IN WITNESS WHEREOF, the parties hereto affixed their signatures hereunder as of the date first above written. SWIFT ENERGY COMPANY By ------------------------------------------ Name: Clyde W. Smith, Jr. Title: Chairman of the Compensation Committee of the Board of Directors A. EARL SWIFT -------------------------------------------- Address: 2715 S. Southern Oaks Houston, Texas 77068 64 EXHIBIT A The Annual Non-Competition Payment to be paid on the first day of each of the five years of the Subsequent Term to Mr. Swift (or to Mr. Swift's spouse, if she is then living, or otherwise to be paid to the estate of Mr. Swift) under Section 3(c) of the Amended and Restated Employment Agreement last amended during November 2000 (the "Agreement") by and between Swift Energy Company and A. Earl Swift is to be the sum of (a) and (b) below, calculated as follows: (a) An amount equal to: (i) $360,220 (in lieu of Company contributions to a 401(k) plan for periods prior to adoption of such a plan by the Company), increased at the rate of 8% per annum from December 31, 1999, until the first day of the Subsequent Term, divided by: (ii) 4.31212684, (b) An amount equal to: (i) 1.5 times Mr. Swift's total annual compensation paid during the last preceding full fiscal year of the Initial Term during which he was paid both base salary and a bonus, divided by: (ii) 4.31212684. 65 Exhibit 10.13 66 FOURTH AMENDED AND RESTATED AGREEMENT AND RELEASE THE STATE OF TEXAS KNOW ALL MEN BY THESE PRESENTS: COUNTY OF HARRIS This Fourth Amended and Restated Agreement and Release is made and entered into between Virgil Neil Swift (hereinafter referred to as "Mr. Swift"), whose current address is 5000 Prairie Dunes, Austin, Texas 78747 and Swift Energy Company (hereinafter referred to as "Company"), a Texas corporation, with current business address at 16825 Northchase Drive, Suite 400, Houston, Texas 77060. This Fourth Amended and Restated Agreement and Release is made in light of the following: RECITALS: WHEREAS, Mr. Swift and the Company entered into that certain Agreement and Release, dated June 1, 1994, for the gradual separation of Mr. Swift from the Company as an employee, as amended by (i) First Amendment, dated December 1, 1995, (ii) Second Amendment, executed by the Company on January 14, 1997, and (iii) Third Amendment, executed by the Company on May 11, 1999 ("Agreement and Release"); WHEREAS, Mr. Swift has now freely and voluntarily terminated his employment with the Company under the terms and provisions of the Agreement and Release, effective at the end of business on June 30, 2000; but Mr. Swift retains his membership on the Board of Directors of the Company and, at the request of the Company, his position as a member of the Board of Directors of Swift Energy International, Inc. ("Swift International"), a wholly owned subsidiary of the Company; and WHEREAS, the Company has requested Mr. Swift, and Mr. Swift has agreed, to become a consultant to the Company (as an independent contractor and not as an employee), effective July 1, 2000 (hereinafter sometimes referred to as the "effective date"), by modifying and restating the terms and provisions of the Agreement and Release by this Fourth Amended and Restated Agreement and Release ("Agreement"). NOW, THEREFORE, in consideration of the above recitals and the promises to be kept hereunder, Mr. Swift and Company agree as follows: AGREEMENT: 1. Upon execution hereof, the parties agree to do the following: 67 A. Duties: Effective July 1, 2000, Mr. Swift will provide advisory and consultation services to the key employees, officers and directors of the Company, concentrating his efforts in the area of the Company's New Zealand oil and gas exploration and production operations, and such other activities as may be designated from time to time by the President or Chairman of the Board of the Company, hereinafter collectively referred to as "services." Mr. Swift will report directly to the President of the Company. B. Retainer: As consideration and retainer for said services and the promises to be kept by Mr. Swift herein, the Company will pay Mr. Swift Five Thousand Dollars and No Cents ($5,000.00) on the last day of the month for each month this Agreement is in force and effect. Mr. Swift need not work any specific number of hours, but will make himself reasonably available upon request of the President or Chairman of the Board of Directors of the Company or when Mr. Swift deems it necessary or advisable. C. Termination: Either party may terminate this Agreement at the end of any month, for any or no reason, upon at least two weeks prior written notice of termination given to the other party. D. Expenses and COBRA Reimbursement. Mr. Swift will be entitled to reimbursement, upon presentation of his itemized invoice, for any reasonable out of pocket expenses incurred by Mr. Swift, such as (i) airline tickets when required to fly solely for the purpose of providing services hereunder, (ii) meals and lodging, should Mr. Swift be required to provide services hereunder away from home overnight. In such case, mileage for the use of his personal vehicle to provide services hereunder will be charged at a rate of Thirty Two and One Half Cents (32.5(cent)) per mile, which shall be adjusted annually to the applicable per mile rate equivalent to that allowed by the Internal Revenue Service. A copy of Mr. Swift's proof of automobile liability insurance is required hereunder. The Company will reimburse Mr. Swift the amount paid by him to continue medical and dental coverage for a 12 month period after July 1, 2000 under COBRA. E. Independent Contractor. It is expressly understood that Mr. Swift is performing services as an independent contractor under this Agreement, that Mr. Swift is the sole judge of the manner in which he performs such services, that Mr. Swift is not an employee of Company, nor an agent of Company, nor does Mr. Swift have authority to bind the Company or speak for, or on behalf of Company, under this Agreement, unless specifically directed to do so in writing by an officer of the Company of at least Vice President rank, or Chairman of the Board of the Company, with the exception of Mr. Swift's duties and authority as a member of the Board of Directors of the Company. It is fully understood that, as an independent contractor, Mr. Swift is solely responsible for payment of his own income taxes, FICA, self-employment taxes, workers' compensation, unemployment taxes, and any other taxes that may be due as a result of the consideration that is being paid hereunder. There will be no withholding for taxes from any payments made to Mr. Swift by Company under this Agreement. It is further understood that Mr. Swift will not be eligible to participate in any of Company's employee benefit plans or programs, other than programs provided to directors, except as may be otherwise provided herein. It shall be Mr. Swift's sole responsibility to carry any insurance for Mr. Swift or his beneficiaries, such as worker compensation, life, accident, disability, and medical insurance to cover Mr. Swift or his employees or dependents. F. Stock Options. In the event of a "Change of Control" as defined below, effective as of the day prior to such Change of Control, all outstanding stock options issued to Mr. Swift to purchase shares of common stock of the Company held by Mr. Swift as of such date will immediately become 100% vested. G. Change of Control: "Change of Control," for purposes of this Agreement, shall be deemed to have occurred upon the occurrence of any one (or more) of the following events, other than a transaction with another person controlled by, or under common control with, the Company or its officers: 68 (i) Any person, including a group as defined in Section (3)(d) (3) of the Securities Exchange Act of 1934, as amended, becomes the beneficial owner of shares of the voting stock of the Company with respect to which 40% or more of the total number of votes for the election of the Board may be cast. (ii) As a result of, or in connection with, any cash tender offer, exchange offer, merger or other business combination, sale of assets or contested election, or combination of the above, persons who were directors of the Company immediately prior to such event will cease to constitute a majority of the Board; (iii) The stockholders of the Company shall approve an agreement providing either for a transaction in which the Company will cease to be an independent publicly owned corporation or for a sale or other disposition of all or substantially all the assets of the Company; or (iv) A tender offer or exchange offer is made for shares of the Company's Common Stock (other than one made by the Company), and shares of Common Stock are acquired thereunder ("Offer"). 2. Mr. Swift, on behalf of himself and his successors, heirs, assigns, executors, attorneys, agents, representatives, and any other person claiming by, through or under him, unconditionally and forever RELEASES, ACQUITS and DISCHARGES Company, its owners, successors, directors, officers, employees, former employees, consultants, agents and assigns (hereinafter collectively referred to as "RELEASED PARTIES") from any and all claims, charges, causes of action, rights, damages, losses, liabilities and demands, whether based upon statute or in tort, contract, or any other legal or equitable theory of recovery, which Mr. Swift now has or may have, of any kind or character, now known, including, but not limited to, any claim for salary, compensation, benefits, expenses, compensatory and exemplary damages (statutory or common law), interest, attorney's fees, costs, and any form of declaratory or injunctive relief, arising from, attributable to, related to (i) Mr. Swift's prior employment with the Company; (ii) the entry into the Agreement and Release and this Agreement; (iii) the change of Mr. Swift's employment status from an at-will employee to having a contract of employment for a specific term subject to early termination under the Agreement and Release; (iv) the change of Mr. Swift's employment from employment for a specific term under the Agreement and Release to a non-employee independent contractor under this Agreement; (v) any alleged discriminatory, retaliatory, tortious, contractual and/or improper actions towards Mr. Swift now known; and (vi) any and all other acts or omissions related to any matter arising from the employment of Mr. Swift by Company up to and including the date of the execution of this Consulting Agreement and Release. This release includes, but is not limited to, any claims of wrongful employment actions, discrimination (based on age or any other factor), including claims brought under the Employee Retirement Income Security Act, Age Discrimination in Employment Act of 1967, Older Workers Benefit Protection Act of 1992, Title VII of the Civil Rights Act of 1964, or the Texas Commission on Human Rights Act, the Texas Workers' Compensation Act, retaliation, slander, intentional and/or negligent infliction of emotional distress, mental anguish, breach of an implied covenant of good faith and fair dealing, negligent training or supervision, conspiracy, or any other alleged unlawful or wrongful conduct, whether arising under any federal or state statutes, regulation or the common law (contract, tort or other) of any jurisdiction. 3. This Agreement and its terms shall be maintained in strict confidence by Mr. Swift, his spouse and representatives. Mr. Swift and his spouse agree that they will not disclose, directly or indirectly, the terms of this Agreement or any communications, written, verbal or otherwise, constituting or concerning the negotiation of this Agreement, to any third person, apart from each other unless required to do so by a court of competent jurisdiction, or under applicable law or under regulations of the SEC. 4. Mr. Swift agrees that as a past officer and key employee of the Company, there was and is a relationship of trust and confidence between himself and Company with respect to information applicable to the business of Company. In this regard, Mr. Swift recognizes and agrees that Company possesses and will continue to possess information that has been created, discovered or developed, or made known to the Company, by himself and others during the period of, or arising out of, his employment, which information has commercial value in the business in which the Company is engaged. All of this information is proprietary to Company. In consideration of the promises and payments by Company as contained herein, Mr. Swift agrees: A. To keep confidential any proprietary information, including, but not limited to all trade secrets, confidential knowledge, data or other proprietary information relating to products, processes, 69 designs, formulas, developmental or experimental work, computer programs, data bases, customer lists, business plans, reserve information, geophysical and geological information, financial information, or other subject matter pertaining to any part of the business of Company or its licensees during the term of this Agreement (collectively, hereinafter called "Confidential Information"); B. To prevent the disclosure of Confidential Information to any third party; C. To prevent the use of Confidential Information for his own benefit; D. To prevent aiding others with the use of Confidential Information in competition with the Company, its affiliates or its subsidiaries. These obligations will exist during and after any termination of this Agreement by Mr. Swift or the Company. Notwithstanding anything contained in this Agreement, Confidential Information does not include any general knowledge, skills or experience acquired by Mr. Swift or any knowledge or information known to the general public; and E. While this Agreement remains in force and effect, but subject to release of Mr. Swift's obligations hereunder after a Change of Control, as herein above defined at 1.G., Mr. Swift further agrees: 1. Without the express prior written consent of the Conflicts of Interest Committee of the Board of Directors, Mr. Swift will not serve as an employee, officer, director or consultant, or in any other similar capacity or make investments (other than open market investments in no more than five percent (5%) of the outstanding stock of any publicly traded company) in or on behalf of any person, firm, corporation, association or other entity whose activities directly compete with the activities of Company then existing or contemplated in those oil and gas basins in which the Company is active or as to which it has begun study or analysis, where such employment may involve working for or with, or assisting, such competitor with such activities that are the same as or similar to activities Mr. Swift performed on behalf of the Company which directly compete with those activities of the Company; and 2. Without the express prior written consent of the Conflict of Interest Committee of the Board of Directors, Mr. Swift agrees that he will not solicit, recruit or hire, or assist any person, firm, corporation, association or other entity in the solicitation, recruitment or hiring of any person now engaged by Company as an employee, officer, director or consultant with whom Mr. Swift worked during the course of his former employment by the Company or during the period during which this Agreement is in force or effect, unless such person or entity has not been engaged by the Company for a period of at least 90 days. 5. A. The parties agree that this Agreement is not intended to (i) adversely affect, in any way, Mr. Swift's vested 401K retirement plan (provided, however, Mr. Swift will no longer be eligible to participate in the 401K retirement plan after June 30, 2000), (ii) adversely affect Mr. Swift's ability to enforce the provisions of this Agreement in the future, or (iii) affect Mr. Swift's vested portion of the Company's Employee Stock Ownership Plan. B. Notwithstanding anything to the contrary contained in this Agreement, the following provision shall govern outstanding stock options held by Mr. Swift as of the date this Agreement is executed: Immediately prior to the date of termination of Mr. Swift's service as a member of the Board of Directors of Swift Energy Company, all outstanding unexercised options to purchase shares of common stock of the Company held by Mr. Swift (as of the day prior to such termination) shall immediately vest or be deemed to have vested, and otherwise Mr. Swift shall retain such options with no change in the number of shares covered by such options, the date such options first become exercisable, the period over which they are exercisable, or their exercise price. 70 6. With the limited exception of Section 5.A(ii) above, Mr. Swift agrees not to sue or initiate against Company or the other RELEASED PARTIES, any action, proceedings or compliance review, or to participate in same as a party, individually or as a member of a class, under any contract, express or implied, law or regulation, whether federal, state or local, pertaining in any manner whatsoever to Mr. Swift's prior employment with Company, or any matter covered by the releases contained in this Agreement. 7. Mr. Swift is bound to this Agreement. Anyone who succeeds to his rights or responsibilities, such as the heirs or the executor of his estate, is also bound. 8. This Agreement may not be changed or terminated orally, and no change, termination or waiver of this Agreement or any of its provisions shall be made binding unless made in writing and signed by all parties. For any breach of this Agreement, the Parties agree to look exclusively to their rights under the terms hereof. Except as otherwise provided in Section 5, above, this Agreement succeeds, replaces, and merges all previous agreements and discussions between Mr. Swift and Company, or their respective attorneys and agents, relating to the same or similar subject matters and constitutes the entire agreement between Mr. Swift and Company with respect to its subject matter. 9. Any disputes with respect to this Agreement shall be resolved by submitting such disputes to arbitration with the American Arbitration Association in Houston, Texas. Subject to the provisions of Section 15 below, the parties shall bear equally all expenses of such arbitration unless the arbitrators determine that a different allocation would be more equitable. The award of the arbitrators will be the exclusive remedy of the parties for all claims, counterclaims, issues or accounting presented or plead to the arbitrators. Nothing in this Section shall prevent either party from seeking provisional injunctive relief pending arbitration, by applying to any court of competent jurisdiction. 10. This Agreement shall be interpreted and construed in accord with, and shall be governed by, the laws of the State of Texas. 11. In making this Agreement, no promises or representations of any kind have been made to Mr. Swift by the RELEASED PARTIES or anyone acting for them except as is expressly stated in this Agreement. 12. If any provision of this Agreement is held invalid or unenforceable, or if any provision of this Agreement is held invalid or unenforceable with respect to particular circumstances, the balance of this Agreement will remain in full force and effect in its other provisions and in all other circumstances. 13. Mr. Swift and Company acknowledge that Mr. Swift had seven (7) days following the execution of the Agreement and Release to revoke the Agreement and Release. 14. Mr. Swift fully informed himself of the terms, contents, conditions and effects of this Agreement, Mr. Swift was provided an original draft of this Agreement on or about August 9, 2000, and engaged in negotiations with the Company with respect hereto. Mr. Swift further acknowledges that he has been given at least 21 days prior to execution to consider this Agreement; that Mr. Swift has been advised to consult with an attorney prior to executing the Agreement; that he is over the age of eighteen (18) years old, of sound mind and otherwise competent to execute this Agreement; and that Mr. Swift is entering into this Agreement knowingly and voluntarily and without any undue influence or pressures. 15. Disputes. If a dispute arises out of or related to this Agreement and the dispute cannot be settled through direct discussions, the Company and Mr. Swift agree that if it then becomes necessary in Mr. Swift's judgment for him to sue the Company or take the Company to arbitration in order to collect the amounts to be paid to him under this Agreement or otherwise enforce his rights under this Agreement, then the Company will be obligated to pay both its own and Mr. Swift's legal fees in such litigation or arbitration, including the obligation of the Company to pay Mr. Swift's legal fees within thirty days of receiving invoices therefor from Mr. Swift. 16. Notwithstanding anything to the contrary herein contained, Section 1.F., G., and Sections 2 through this Section 16 hereof shall survive termination of this Agreement. EXECUTED in duplicate this 20th day of November, 2000, but effective July 1, 2000. SWIFT ENERGY COMPANY _________________________ By:_____________________________ Virgil Neil Swift A. Earl Swift Chief Executive Officer 71 Exhibit 12 72 SWIFT ENERGY COMPANY RATIO OF EARNINGS TO FIXED CHARGES
Twelve Months Ended December 31, 2000 1999 1998 ------------------ ---------------- ------------------ GROSS G&A 23,793,995 20,518,843 21,010,960 NET G&A 5,585,487 4,497,400 3,853,812 INTEREST EXPENSE 15,968,405 14,442,815 8,752,195 RENT EXPENSE 1,255,474 1,272,497 1,117,351 NET INCOME BEFORE TAXES 93,079,346 29,736,151 (73,391,581) CAPITALIZED INTEREST 5,043,206 4,142,098 3,849,665 DEPLETED CAPITALIZED INTEREST 307,249 323,124 292,267 CALCULATED DATA ------------------------------------- UNALLOCATED G&A (%) 23.47% 21.92% 18.34% NON-CAPITAL RENT EXPENSE 294,714 278,911 204,944 1/3 NON-CAPITAL RENT EXPENSE 98,238 92,970 68,315 FIXED CHARGES 21,109,849 18,677,883 12,670,175 EARNINGS 109,453,238 44,595,061 (64,278,804) RATIO OF EARNINGS TO FIXED CHARGES 5.18 2.39 -- ================== ================ ==================
For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense, capitalized interest, amortization of debt issuance costs and discounts, and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represents income before income taxes from continuing operations before fixed charges. Due to the $90.8 million non-cash charge incurred in the third quarter of 1998 caused by a write-down in the carrying value of oil and gas properties, 1998 earnings are insufficient by $76.9 million to cover fixed charges in this period. If the $90.8 million non-cash charge is excluded, the ratio of earnings to fixed charges would have been 2.09 for 1998. 73 EXHIBIT 23 (A) 74 CONSENT OF H.J. GRUY AND ASSOCIATES, INC. We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of references to H. J. Gruy and Associates, Inc. and to the inclusion of and references to our report dated February 7, 2001, (Year-End 2000 Reserves Audit) prepared for Swift Energy Company in the Swift Energy Company Annual Report on Form 10-K for the year ended December 31, 2000. H.J. GRUY AND ASSOCIATES, INC. by: ______________________________ Marilyn Wilson President & Chief Operating Officer March 7, 2001 Houston, Texas E:\S\SWIFT\CONSENTS\CONSENT.3-01.DOC 75 EXHIBIT 23 (B) 76 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 19, 2001, included in the Annual Report of Swift Energy Company on Form 10-K for the year ended December 31, 2000, into Swift Energy Company's previously filed Registration Statement File Numbers 33-14305, 33-36310, 33-80228, and 33-80240 on Form S-8 and Number 33-81651 on Form S-3. ARTHUR ANDERSEN LLP Houston, Texas March 23, 2001 77 EXHIBIT 99 78 February 7, 2001 Swift Energy Company 16825 Northchase Drive, Suite 400 Houston, Texas 77060 Re: Year-End 2000 Reserves Audit 00-003-160 Gentlemen: At your request, we have independently audited the estimates of oil, natural gas and natural gas liquid reserves and future net cash flows as of December 31, 2000, that Swift Energy Company (Swift) attributes to net interests owned by Swift. Based on our audit, we consider the Swift estimates of net reserves and net cash flows to be in reasonable agreement, in the aggregate, with those estimates that would result if we performed a completely independent evaluation effective December 31, 2000. The Swift estimated net reserves, future net cash flow, and discounted future net cash flow are summarized below:
Domestic and International Proved Reserves ------------------------------------------------------------------------------------------------------- Estimated Estimated Net Reserves Future Net Cash Flow ---------------------------- -------------------------------------------- Oil, NGL, & Discounted Condensate Gas at 10% (Barrels) (Mcf) Nondiscounted Per Year ----------- ----------- -------------------- -------------------- Proved Developed 10,980,196 215,169,833 $ 2,199,482,798 $ 1,257,570,764 Proved Undeveloped 24,153,400 203,444,143 $ 1,774,721,537 $ 1,055,684,045 ----------- ----------- -------------------- -------------------- Total Proved 35,133,596 418,613,976 $ 3,974,204,335 $ 2,313,254,809 G & A ($ 25,342,970) ($ 13,376,568) ----------- ----------- -------------------- -------------------- GRAND TOTAL 35,133,596 418,613,976 $ 3,948,861,365 $ 2,299,878,241
79
Domestic Proved Reserves ------------------------------------------------------------------------------------------------------- Estimated Estimated Net Reserves Future Net Cash Flow ---------------------------- -------------------------------------------- Oil, NGL, & Discounted Condensate Gas at 10% (Barrels) (Mcf) Nondiscounted Per Year ----------- ----------- -------------------- -------------------- Proved Developed 10,980,196 215,169,833 $ 2,199,482,798 $ 1,257,570,764 Proved Undeveloped 12,962,513 148,130,666 $ 1,550,321,576 $ 919,388,009 ----------- ----------- -------------------- -------------------- Total Proved 23,942,709 363,300,499 $ 3,749,804,374 $ 2,176,958,773 G & A ($ 25,342,970) ($ 13,376,568) ----------- ----------- -------------------- -------------------- Domestic Total 23,942,709 363,300,499 $ 3,724,461,404 $ 2,163,582,205 New Zealand Proved Reserves ------------------------------------------------------------------------------------------------------- Estimated Estimated Net Reserves Future Net Cash Flow ---------------------------- -------------------------------------------- Oil, NGL, & Discounted Condensate Gas at 10% (Barrels) (Mcf) Nondiscounted Per Year ----------- ----------- -------------------- -------------------- Proved Developed -0- -0- $ -0- $ -0- Proved Undeveloped 11,190,887 55,313,477 $ 224,399,961 $ 136,296,036 ----------- ----------- -------------------- -------------------- New Zealand Total 11,190,887 55,313,477 $ 224,399,961 $ 136,296,036
The discounted future net cash flows summarized in the above table are computed using a discount rate of 10 percent per annum. Proved reserves are estimated in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). The definitions are included, in part, as Attachment I. The reserves discussed herein are estimates only and should not be construed as exact quantities. Future economic or operating conditions may affect recovery of estimated reserves and cash flows, and reserves of all categories may be subject to revision as more performance data become available. 80 Swift represents that the future net cash flows discussed herein were computed using prices received for oil and natural gas as of December 31, 2000. Oil and condensate prices are based on a year-end 2000 reference price of $23.75 per barrel. Natural gas price is based on a year-end 2000 reference price of $10.53 per MMBtu. A differential is applied to the oil, condensate, and natural gas reference prices to adjust for transportation, geographic property location, and quality or energy content. Product prices, direct operating costs, and future capital expenditures are not escalated and therefore remain constant for the projected life of each property. Swift represents that the provided product sales prices and operating costs are in accordance with Securities and Exchange Commission guidelines. This audit has been conducted according to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information approved by the Board of Directors of the Society of Petroleum Engineers, Inc. Our audit included examination, on a test basis, of the evidence supporting the reserves discussed herein. We have reviewed the subject properties, and where we had material disagreements with the Swift reserve estimates, Swift revised its estimate to be in agreement. In conducting our audit, we investigated each property to the level of detail that we believe necessary to provide a reasonable basis for the judgements expressed herein. Based on our investigations, it is our judgement that Swift used appropriate engineering, geologic, and evaluation principles and methods that are consistent with practices generally accepted in the petroleum industry. Reserve estimates were based on extrapolation of established performance trends, material balance calculations, volumetric calculations, analogy with the performance of comparable wells, or a combination of these methods. Reserve estimates from volumetric calculations or from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserve was produced. Estimates of net cash flow and discounted net cash flow should not be interpreted to represent the fair market value for the audited reserves. The estimated reserves and cash flows discussed herein have not been adjusted for uncertainty. Future net cash flow as presented herein is defined as the future cash inflow attributable to the evaluated interest less, if applicable, future operating costs, ad valorem taxes, and future capital expenditures. Future cash inflow is defined as gross cash inflow less, if applicable, royalties and severance taxes. Future cash inflow and future net cash flow stated in this report exclude consideration of state or federal income tax. Future costs of abandoning the facilities and wells, and the restoration of producing properties to satisfy environmental standards are not deducted from cash flow. In conducting this audit, we relied on data supplied by Swift. The extent and character of ownership, oil and natural gas sales prices, operating costs, future capital expenditures, historical production, accounting, geological, and engineering data were accepted as represented. No independent well tests, property inspections, or audits of operating expenses were conducted by our staff in conjunction with this work. We did not verify or determine the extent, character, status, or liability, if any, of production imbalances or any current or possible future detrimental environmental site conditions. 81 In order to audit the reserves and future cash flows estimated by Swift, we have relied in part on geological, engineering, and economic data furnished by our client. Although we have made a best efforts attempt to acquire all pertinent data and to analyze it carefully with methods accepted by the petroleum industry, there is no guarantee that the volumes of hydrocarbons or the cash flows projected will be realized. The reserve and cash flow projections discussed in this report may require revision as additional data become available. If investments or business decisions are to be made in reliance on these judgements by anyone other than our client, such person, with the approval of our client, is invited to visit our offices at his expense so that he can evaluate the assumptions made and the completeness and extent of the data available on which our opinions are based. This report is for general guidance only, and responsibility for subsequent decisions resides with the decision maker. Any distribution or publication of this work or any part thereof must include this letter in its entirety. Yours very truly, H.J. GRUY AND ASSOCIATES, INC. Texas Registration Number F-000637 by: /s/ Marilyn Wilson 59498 ------------------------------- Marilyn Wilson, PE President and Chief Operating Officer Attachment MW:cjd E:\S\SWIFT\160\swift year end 2000.doc 82 ATTACHMENT I 83 DEFINITIONS OF PROVED OIL AND GAS RESERVES1 PROVED OIL AND GAS RESERVES Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquid which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. PROVED DEVELOPED OIL AND GAS RESERVES Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. PROVED UNDEVELOPED RESERVES Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. ------------------------ 1 Contained in Securities and Exchange Commission Regulation S-X, Rule 4-10 (a) 84