Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on onshore and inland waters oil and natural gas reserves in Texas and Louisiana and onshore oil and natural gas reserves in New Zealand. The Company was founded in 1979 and is headquartered in Houston, Texas. As of December 31, 2002, we had interests in 932 wells located domestically in three states, in federal offshore waters, and in New Zealand. We operated 820 of these wells representing 95% our proved reserves. At year-end 2002, we had estimated proved reserves of 749.4 Bcfe, of which approximately 44% was natural gas, 42% crude oil, and 14% NGLs, and overall 60% was proved developed. Our proved reserves are concentrated 41% in Texas, 35% in Louisiana, and 21% in New Zealand.

We currently focus primarily on development and exploration in four domestic core areas and two core areas in New Zealand:

We have a well-balanced portfolio of oil and gas properties and prospects. The AWP Olmos and Lake Washington areas and New Zealand are characterized by long-lived reserves that we expect to be steadily produced over a long period of time. The Masters Creek and Brookeland 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. We focus on drilling the long-lived properties during periods of decreasing commodity prices, while the shorter-lived properties provide additional drillable projects in periods of rising commodity prices. Based on 2002 year-end proved reserves and 2002 production, we calculated our average reserve life as 17.4 years domestically and 10.0 years in New Zealand.

We have increased our proved reserves from 361.5 Bcfe at year-end 1997 to 749.4 Bcfe at year-end 2002, which has resulted in the replacement of 278% of our production during the same five-year period. Our five-year average reserves replacement costs were $1.25 per Mcfe. Our average annual reserve replacement costs for the last five years, starting with 2002 were $0.96, $3.30, $0.81, $1.27 and $1.20 per Mcfe. In 2002, we increased our proved reserves by 16%, which replaced 308% of our 2002 production. Our 2002 production increased by 11% in relation to 2001 production. We have increased our production from 25.4 Bcfe at year-end 1997 to 49.8 Bcfe at year-end 2002. Primarily due to increased production, this has resulted in average annual growth in net cash provided by operating activities of 5% per year from year-end 1997 to year-end 2002, even though in 2002 net cash provided by operating activities fell 49% due to pricing changes.

Through intensive efforts, we have developed an inventory of exploration and development prospects, identifying drilling locations through integrated geological and geophysical studies of our undeveloped acreage and other prospects. As a result, we added 184.7 Bcfe of proved reserves through drilling in 2000 (122.5 Bcfe from New Zealand), 105.8 Bcfe in 2001 (17.4 Bcfe from New Zealand), and 83.9 Bcfe in 2002 (15.9 Bcfe from New Zealand). The 2002 additions were primarily a result of our development success rate, as 17 of 23 domestic development wells drilled were successful, while three of seven domestic exploratory wells were successful.

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. In the first quarter of 2001, we purchased interests in the Lake Washington field from Elysium Energy, LLC, for approximately $30.5 million in cash. In the first quarter of 2002, we purchased interests in the four TAWN fields in New Zealand for approximately $51.4 million, which also included significant infrastructure, after purchase price adjustments.

We currently plan to spend $115 to $130 million in total capital expenditures in 2003, excluding acquisition costs and net of approximately $5 million to $15 million in non-core property dispositions. The budget for 2003 is largely dependent upon our performance and commodity pricing during the year. Domestic activities account for 85% of our budgeted spending, primarily in the Lake Washington Area.

We believe that our competitive strengths, together with a balanced and comprehensive business strategy, provide us with the flexibility and capability to accomplish our goals.

When we believe the market favors increasing reserves through acquisitions, we apply our considerable experience in evaluating and negotiating prospective acquisitions. For example, in 1998, when commodity prices were relatively weak, 32% of our capital expenditures consisted of property acquisitions, with 37% committed to our drilling activities. In contrast, in 2001, when commodity prices were relatively strong in the first half of the year, only 15% of our capital expenditures were spent on property acquisitions, with our drilling expenditures increasing to 67% of total capital expended. We believe this balanced approach has resulted in our ability to grow reserves in a relatively low cost manner, while participating in the upside potential of exploration.

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. Generally, we seek to acquire properties with the potential for additional reserves and production through development and exploration efforts. In addition, we seek to enhance the results of our drilling and production efforts through the implementation of advanced technologies.

During 2002, in response to strong oil prices throughout the year, we focused our capital expenditures on the Lake Washington Area domestically and on the TAWN acquisition in New Zealand. Although oil prices remained strong in 2002, natural gas prices for most of the year were lower than prior year levels, and our cash flow generated due to these commodity prices decreased, as expected, even though production increased. As a result of lower cash flow in 2002, we reduced our capital expenditures to $155.2 million. Of this amount, $58.4 million was spent on acquisitions, mainly the TAWN acquisition in New Zealand. We spent $42.7 million on drilling in the United States, with $34.4 for development drilling and $8.3 million for exploratory drilling. In New Zealand we spent $22.9 million on drilling, with $12.6 million for development drilling and $10.3 million for exploratory drilling. We also spent $10.6 million constructing a gas processing plant in New Zealand. The remaining capital expenditures of $20.6 million were spent primarily on leasehold, seismic, and geological costs of prospects, both in the United States and New Zealand. During 2002, we principally relied upon cash flows from operations of $71.6 million, net proceeds from the issuance of long-term debt of $195.0 million, and net proceeds from our public stock offering of $30.5 million, less the repayment of bank borrowings of $134.0 million, to fund our capital expenditures.

In 145 transactions from 1979 to 2002, we have acquired approximately $695.7 million of producing oil and gas properties on behalf of our co-investors and ourselves. We acquired, for our own account, approximately $339.2 million of producing properties, with original proved reserves estimated at 468.5 Bcfe during this period. Our producing property acquisition expenditures in the past three years were $64.2 million in 2002, $41.3 million in 2001, and $34.2 million in 2000. Our acquisition costs have averaged $0.83 per Mcfe over this three-year period. Our acquisition cost in 2002 averaged $0.87 per Mcfe.

Our concentration of reserves and our significant acreage positions in our core areas allow us to realize economies of scale in drilling and production. We enhance the value of this concentration by acting as the operator of 95% of our proved reserves at year-end 2002. Our operational control allows us to better manage production, control our expenses, allocate capital and time field development. We intend to continue to acquire large acreage positions in under-explored and under-exploited areas, where, as operator, we can exploit successful discoveries to create new core areas or grow production from developed fields. In executing this strategy:

• We focus our resources on acquiring properties that we can operate, and in which we can obtain a significant working interest. With operational control, we can apply our technical and operational expertise to optimize our exploration and exploitation of the properties that we acquire.

• We acquire and operate domestic properties in a limited number of geographic areas. Operating in a concentrated area helps us to better control our overhead by enabling us to manage a greater amount of acreage with fewer employees, minimizing incremental costs of increased drilling and production.

• We continue to believe in natural gas prospects and reserves in the United States. The natural gas market in the United States has a well-developed infrastructure. Natural gas is viewed by many as the preferred fuel in North America for several reasons, including environmental concerns. We have a strong inventory of natural gas that can be developed in a higher priced environment.

• We seek to operate large acreage positions with high exploration and development potential. For example, on our original 100,000 acre New Zealand permit, only two wells had been drilled at the time that we acquired our interest. The Masters Creek, Brookeland and Lake Washington areas also had significant additional development potential when we first acquired our interest in those areas.

Our New Zealand activities provide us with long-term growth opportunities and significant potential reserves in a country with stable political and economic conditions, existing oil and gas infrastructure, and favorable tax and royalty regimes. We have completed construction of our Rimu production and gas processing facilities, which became operational in May 2002 and enabled us to begin the sale of production from the Rimu/Kauri area. We were able to bring our Rimu discovery on commercial production in a significantly shorter period than any other similar project previously undertaken in New Zealand of which we are aware.

In January 2002, we acquired the TAWN fields. In our TAWN acquisition, we also acquired extensive associated processing facilities and pipelines, which give us a competitive advantage through infrastructure that complements our existing fields, providing us with increased access to export terminals and markets and additional excess processing capacity for both oil and natural gas.

We employ oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 25 years of experience in their technical fields and have been employed by Swift for an average of over 10 years. We continually apply our extensive in-house expertise and current advanced technologies to benefit our drilling and production operations. We have developed a particular expertise in drilling horizontal wells at vertical depths below 10,000 feet, often in a high-pressure environment, involving single or dual lateral legs of several thousand feet. This results in an integrated approach to exploration using multidisciplinary data analysis and interpretation that has helped us identify a number of exploration prospects.

We use various recovery techniques, including water flooding and acid treatments, fracturing reservoir rock through the injection of high-pressure fluid, gravel packing, 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.

We have increasingly used 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.

As a result, we have maintained internal seismic expertise and have compiled an extensive database.

When appropriate, we develop new applications for existing technology. For example, in New Zealand we acquired seismic data by effectively combining marine data with the acquisition of land seismic data, an application we have not seen any other company use in New Zealand.

We practice a disciplined approach to financial management and have historically maintained a strong capital structure that preserves our ability to execute our business plan. Key components of our financial discipline include maintaining a capital budget balanced between drilling and acquisitions, establishing leverage targets that are reasonable given the volatility of the oil and gas markets, and opportunistically accessing the capital markets. As of December 31, 2002, our long-term debt comprised approximately 47% of our total capitalization. We applied the net proceeds from our common stock offering and debt offering in April 2002 in the amount of $225.5 million to reduce amounts outstanding under our credit facility. At December 31, 2002, we had $194.2 million of available borrowing capacity. By replacing indebtedness incurred under our revolving credit facility in connection with acquisition, development, and exploitation activity with the net proceeds from our common stock offering and debt offering, we implemented our strategy of matching long-lived assets with long-term financing.

In 2002, we performed four fracture extensions and installed coiled tubing velocity strings in five wells. At year-end 2002, we had 128 proved undeveloped locations. Also in 2002, we purchased interests in the AWP Olmos area from partnerships we managed. Our planned 2003 capital expenditures in this area will focus on drilling 10 wells and performing fracture extensions and installing coiled tubing velocity strings to maintain a flat production profile.

Brookeland Area. As of December 31, 2002, we owned drilling and production rights in 76,259 net acres and 3,500 fee mineral acres in this area, which contains substantial proved undeveloped reserves. This area was part of the acquisition from Sonat in 1998 and is located in East Texas near the border of Louisiana in Jasper and Newton counties. It primarily contains horizontal wells producing from the Austin Chalk formation. The reserves are approximately 55% oil and natural gas liquids. At year-end 2002, we had 13 proved undeveloped locations in this area. Our planned 2003 capital expenditures in this area include drilling one development well.

Lake Washington Field. As of December 31, 2002, we owned drilling and production rights in 11,080 net acres in the Lake Washington Field. This area is located in Plaquemines Parish in South Louisiana. The reserves are approximately 98% oil and natural gas liquids. We acquired interests in the Lake Washington Field in March 2001. This field produces oil from multiple Miocene sands ranging in depth from less than 1,700 feet to greater than 9,000 feet. The field is located on a salt dome and has produced over 300 million BOE since its inception in the 1930s. The area around the dome is heavily faulted, thereby creating a large number of potential traps. Oil and gas from approximately 38 producing wells is gathered from three platforms located in water depths from 6 to 11 feet, with drilling and workover operations performed with barge rigs. In 2002, 23 development wells and four exploratory wells were drilled in the area; 17 development and two exploratory wells were successful. At year-end 2002, we had 63 proved undeveloped locations in this field. Our planned 2003 capital expenditures in this area include drilling 50 to 60 development wells and one saltwater disposal well.

Masters Creek Area. As of December 31, 2002, we owned drilling and production rights in 77,475 net acres and 107,000 fee mineral acres in this area, which contains substantial proved undeveloped reserves. This area was also part of the acquisition from Sonat in 1998. It is located in Central Louisiana near the Texas-Louisiana border in the two parishes of Vernon and Rapides. It contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 72% oil and natural gas liquids. At year-end 2002, we had 12 proved undeveloped locations in the area. Our planned 2003 capital expenditures in this area include drilling one development well.

The Wilcox Sands. We had three discoveries in the Wilcox sands during 2001, two of which were located in Goliad County, Texas: the Nita prospect drilled to a depth of approximately 15,000 feet and the Brandon prospect drilled to a depth of about 13,000 feet. Our working interests in the two wells are 73% and 60%, respectively. The third well, in which we have a 25% working interest, was in the Falcon Ridge prospect in Zapata County, Texas. We plan to participate in one development well in this area in 2003.

The Woodbine Formation. The Woodbine formation is located in southeast Texas in San Jacinto, Polk, and Tyler counties. We drilled one well to the Woodbine formation in 2001, in the Lion prospect in San Jacinto County, Texas, to a depth of 15,000 feet. Although hydrocarbon-bearing intervals were found, the well was deemed noncommercial. The Company has two other Woodbine prospects, the Jaguar and Bobcat prospects, both located in Polk County.

The Miocene Sands. We successfully drilled our first exploratory well in the Miocene sands in our Lake Washington Area in Plaquemines Parish, Louisiana, to a depth of 3,348 feet with a retained interest of 100%. This area has substantial exploration and development potential, with sands extending from shallow depths down to 10,000 feet or more. Through 2002, we have drilled 28 wells in this area.

Our activity in New Zealand began in 1995. As of December 31, 2002, our permit 38719, which we operate, included approximately 49,800 acres in the Taranaki Basin of New Zealand’s north island. This acreage includes our Rimu and Kauri areas as well as our Tawa and Matai prospects.

We expanded our operation in New Zealand in January 2002 with our TAWN purchase of Southern Petroleum (NZ) Exploration, Limited, from Shell New Zealand, through which we acquired interests in four fields and significant infrastructure assets.

In March 2002, we completed the acquisition of all of the New Zealand assets of Antrim. These assets included a 5% working interest in the Swift-operated permit 38719, increasing the Company’s interest in this permit to 95%. An additional 7.5% interest was also acquired in permit 38716 (Huinga prospect), increasing the Company’s interest to 15%.

In August 2002, we were awarded two additional onshore permits, permits 38756 and 38759. These permits include approximately 8,100 and 20,400 gross acres, respectively, in proximity to our permit 38719.

In September 2002, we completed the acquisition of Bligh’s 5% working interest in permit 38719 and 5% interest in the Rimu petroleum mining permit 38151, along with their 3.24% working interest in the four TAWN petroleum mining licenses. The Company’s interests in permit 38719, petroleum mining permit 38151, and the TAWN petroleum mining licenses are now 100%.

In December 2002, we agreed to acquire an additional 50% interest in permit 38718 (Tuihu prospect) from Shell New Zealand through an existing pre-emptive right under the joint operating agreement. Following the transaction, SENZ will sell a 20% interest in the permit to a subsidiary of New Zealand Oil and Gas Limited. The purchase and subsequent sale, which are subject to certain government notifications, approvals and consents, will result in SENZ holding a 50% working interest in this permit. We were named operator of the permit. Permit 38718 contains the Tuihu #1 exploratory well, which was drilled in 2001 and temporarily abandoned. Our 2003 budget calls for a re-entry of this well, which will sidetrack or deepen the original well.

As of December 31, 2002, our gross investment in New Zealand totaled approximately $172.8 million. Approximately $145.0 million of our investment costs have been included in the proved properties portion of our oil and gas properties, while $27.8 million is included as unproved properties.

Rimu Area. Early in 2002, we were awarded petroleum mining permit 38151 by the New Zealand Ministry for Economic Development for the development of the Rimu discovery over an approximately 5,500 acre area for a primary term of 30 years. Commercial production from the Rimu area began in May 2002.

Kauri Area. During 2002, three wells were drilled in the Kauri area. The Kauri-A1 exploratory well was drilled to the Upper Tariki sand, the Kauri-A3 development well was drilled to the shallow Manutahi sands, and the Kauri-A4 exploratory well was drilled through the Kauri sands and on down to the Lower Tariki sand, which was found to be too wet for commercial production. After the drilling of the Kauri-A4 well was completed in October 2002, pipe was set in the well and perforated over approximately 33 feet of the Kauri sands in preparation for a hydraulic fracture stimulation in early 2003.

TAWN Area. The TAWN acquisition in January 2002 consisted of a 96.76% working interest in four petroleum mining licenses, or PML, covering producing oil and gas fields, and extensive associated hydrocarbon-processing facilities and pipelines, which give us a competitive advantage through infrastructure that complements our existing fields, providing us with increased access to export terminals and markets and additional excess processing capacity for both oil and natural gas. The TAWN assets are located approximately 17 miles north of the Rimu area.

The properties are collectively identified as the TAWN properties, an acronym derived from the first letters of the field names – the Tariki Field (PML 38138), the Ahuroa Field (PML 38139), the Waihapa Field (PML 38140), and the Ngaere Field (PML 38141). The four fields include 17 wells where the purchaser of gas, Contact Energy, has contracted to take minimum quantities and can call for higher production levels to meet electrical demand in New Zealand. Sales gas deliveries to Contact have exceeded the contract minimum during all of 2002.

Solution gas gathered from the Waihapa Production Station ("WPS") flows to the Tariki Ahuroa gas plant ("TAG"). The current processing capacity of the WPS facility is up to 15,000 barrels of oil and 40 MMcf of natural gas per day. Processing capacity tests conducted following facility modifications completed in the third quarter have confirmed a 12% increase in the gas processing capacity of the TAG plant. A 32-mile, 8-inch diameter oil export line runs from the WPS to the Omata Tank Farm at New Plymouth, where oil export facilities allow for sales into international markets. An additional 32-mile, 8-inch diameter natural gas pipeline runs from the WPS to the Taranaki Combined Cycle Electric Generation Facility near Stratford and on to the New Plymouth Power Station.

We have a service agreement with the owner of the Omata Tank Farm to utilize the blending, storage, and export capabilities of the facility. The operator of the facility provides services for a fixed fee per barrel received and other variable costs as required by the agreement. Under the terms of the agreement, crude oil produced from the TAWN and Rimu/Kauri areas have access to the Omata Tank Farm.

Our current contract with Shell Petroleum Mining (SPM), which purchases all of our New Zealand crude oil production, runs through the end of 2003. The delivery point for our crude oil sales is the ship’s flange. SPM and the Omata Tank Farm coordinate logistical issues for shipments, and thus SPM’s decisions regarding sales from the Omata Tank Farm can affect the timing of sales of that portion of our production.

The Tawa prospect is located northwest of the Rimu and Kauri areas in the same permit. Its main targets are the Kapuni sands, the Kauri sandstones, and the Tariki sandstone. Consisting of a combination of structural and stratigraphic traps, this prospect was developed based upon Swift’s analysis of existing three-dimensional seismic data plus two-dimensional seismic data acquired during Company surveys in 1997 and 2000.

The Matai prospect, located on the southeast flank of the Tawa prospect also in permit 37819, will target the Moki and Urenui sandstones. It was identified based upon the analysis of the two-dimensional seismic data Swift acquired in 2000.

The Tuihu prospect, permit 38718, is located northeast of our TAWN Area. In December 2002, we agreed to acquire an additional 50% interest in permit 38718 from Shell New Zealand though an existing pre-emptive right under the joint operating agreement. Following the transaction, SENZ will sell a 20% interest in the permit to a subsidiary of New Zealand Oil and Gas Limited. The purchase and subsequent sale, which are subject to certain government notifications, approvals and consents, will result in SENZ holding a 50% working interest in this permit. We were named operator of the permit. Permit 38718 contains the Tuihu #1 exploratory well, which was drilled in 2001 and was temporarily abandoned. Our 2003 budget calls for a re-entry of this well, which will sidetrack or deepen the original well.

The Huinga prospect, permit 38716, is located northeast of our Rimu/Kauri areas. An exploratory well was drilled on this permit, of which we own 15%, in 1998 and was temporarily abandoned. This well was re-entered in 2002 and was unsuccessful. The operator is currently re-evaluating this prospect.

The following table presents information regarding proved reserves of oil and gas attributable to our interests in producing properties as of December 31, 2002, 2001, and 2000. The information set forth in the table regarding 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 audit was based upon review of production histories and other geological, economic, ownership, and engineering data provided by Swift.

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, 2002, were estimated based upon prices in effect at year-end. The weighted averages of such year-end prices domestically were $4.23 per Mcf of natural gas, $29.36 per barrel of oil, and $17.30 per barrel of NGL, compared to $2.68, $18.51, and $11.00 at year-end 2001 and $11.25, $25.50, and $20.30 at year-end 2000, respectively. The weighted averages of such year-end 2002 prices for New Zealand were $1.48 per Mcf of natural gas, $28.80 per barrel of oil, and $12.24 per barrel of NGL, compared to $1.18, $18.25, and $8.90 in 2001, respectively. The weighted averages of such year-end 2002 prices for all our reserves, both domestically and in New Zealand, were $3.49 per Mcf of natural gas, $29.27 per barrel of oil, and $16.54 per barrel of NGL, compared to $2.51, $18.45, and $10.70 in 2001, respectively. 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 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.