SWIFT ENERGY COMPANY NEWS

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SWIFT ENERGY ANNOUNCES:

2002 Fourth Quarter Earnings of $0.12 Per Share;
2002 Full Year Earnings of $0.45 Per Share;
Record 2002 Production of 49.8 Bcfe;
$1.02 Per Mcfe Finding & Development Costs in 2002;
308% Reserve Replacement of 2002 Production

HOUSTON, February 12, 2003 - Swift Energy Company (NYSE, PCX: SFY) announced today that net income for the fourth quarter of 2002 totaled $3.4 million, or $0.12 per diluted share, compared to a loss of ($67.1) million, or ($2.71) per diluted share, in the fourth quarter of 2001. Net income for the full year 2002 totaled $11.9 million, or $0.45 per diluted share, compared to a ($22.3) million loss, or ($0.90) per diluted share, for the full year 2001.

Production for 2002 increased to an annual record of 49.8 billion cubic feet equivalent (“Bcfe”), an increase of 11% from 2001 production of 44.8 Bcfe. Production for the fourth quarter of 2002 was 12.6 Bcfe, which was a 10% increase from the 11.5 Bcfe produced in the fourth quarter of 2001, and a 3% increase from the 12.2 Bcfe produced in the preceding third quarter of 2002. Fourth quarter 2002 production included 7.6 Bcfe of domestic production and 5.0 Bcfe produced in New Zealand.

The Company increased proved reserves by 16% to 749 Bcfe at year-end 2002 and replaced 308% of 2002 production with a finding and development cost of $1.02 per thousand cubic feet equivalent (“Mcfe”). Domestic proved reserves increased by 9% to 594 Bcfe, replacing 246% of domestic production for the year with a finding and development cost of $0.80 per Mcfe. New Zealand proved reserves increased by 53% to 155 Bcfe, replacing 444% of 2002 New Zealand production at a finding and development cost of $1.28 per Mcfe.

Terry Swift, President and CEO noted that, “Our 2002 financial and operational results have positioned Swift to implement a multi-year plan focused on value creation. We plan to build upon our 2002 successes this year, particularly in Lake Washington and New Zealand. We have significantly improved the underlying reserve and production characteristics of the Company with the transition that occurred domestically and with the addition of the TAWN assets in New Zealand. In Lake Washington, we plan to double our production levels from those seen at the end of 2002. New Zealand has become a self-sufficient operating entity with significant production and cash flow. Company-wide, we have a higher quality reserve base with more geologic and geographical diversity. Our percentage of proved developed reserves has increased to 60%. We are very excited about the drilling and production opportunities that lie before us. We are equally convinced of a long-term positive shift in the pricing fundamentals of the oil and gas commodity markets.”

Revenues and Expenses

Revenues for the fourth quarter of 2002 increased 45% to $40.5 million from the $27.9 million received in the fourth quarter of 2001 due to higher commodity prices and increased levels of production. Cash flow from operations, before changes in working capital, increased 57% to $19.3 million ($0.71 per diluted share) from the $12.3 million ($0.49 per diluted share) received in the fourth quarter of 2001.

Revenues for the full year 2002 totaled $150.0 million, down 18% from $183.8 million in 2001, and cash flow from operations, before changes in working capital, totaled $67.6 million ($2.53 per diluted share) for 2002, a decline of 45% from $124.0 million ($5.01 per diluted share) in the prior year. Revenues and earnings were affected by the overall lower commodity prices received in 2002 and the planned transition that occurred during the year from high deliverability production to longer life production to improve the Company’s reserves and production profile. Revenues for 2002 included a gain of $7.3 million on the sale of the Company’s interests in the Samburg project in Western Siberia, Russia that occurred in the first quarter of the year.

Interest expense increased in 2002, resulting from the Company’s successful second quarter issuance of $200 million of senior subordinated debt, which greatly increased the financial flexibility of the Company. Also, general and administrative costs increased as expected due to the expansion of management and employees in New Zealand operations and the final liquidation of the Company’s managed public partnerships. Depreciation, depletion and amortization expenses improved 6%, and lease operating expenses were commensurate with production increases.

Reserves

The Company made significant strides in 2002 improving the quality and the quantity of its reserves. Year-end 2002 proved reserves of 749 Bcfe were 44% natural gas, 42% crude oil and 14% natural gas liquids (“NGLs”). Proved developed reserves increased to 60% of total reserves in 2002, up from 50% in the previous year. The majority of proved undeveloped reserves at year-end 2002 is located in the AWP Olmos area (11% of total reserves) and in the Lake Washington area (17% of total reserves), both of which are characterized as long reserve life fields.

Domestic reserves increased at year-end to 594 Bcfe, driven mainly by the reserves increase in the Lake Washington Field, which increased 162% to 190 Bcfe (31.7 million barrels) up from 72.5 Bcfe (12.1 million barrels) at year-end 2001. Domestic reserves at year-end were 44% crude oil, 41% natural gas and 15% NGLs. Domestic reserves, making up 79% of total reserves at year-end 2002, were those in the AWP Olmos area (30%), Lake Washington area (25%), Masters Creek area (10%), Brookeland area (6%) and other domestic properties (8%).

In New Zealand, 2002 year-end proved reserves totaled 155 Bcfe, 90% of which is categorized as proved developed reserves. New Zealand reserves constitute 21% of total Company reserves and consist 56% of natural gas, 34% crude oil and 10% NGLs. The 2002 increase in reserves was primarily attributable to the acquisition of the TAWN fields in early 2002. The year-end reserves include a downward revision in the reserves located in the Rimu/Kauri area of approximately 27 Bcfe. A recent independent study has concluded that formation damage around certain well bores has reduced deliverability from wells completed in the Tariki Sand in the Rimu/Kauri area.

Production & Pricing

For 2002, total production increased 11% to 49.8 Bcfe from 44.8 Bcfe in 2001. New Zealand operations began commercial production in 2002 with the initiation of production from the Rimu/Kauri area and the acquisition of the TAWN properties. New Zealand accounted for 31% of overall corporate production with 15.5 Bcfe produced in 2002. Domestically, production decreased as planned as the Company changed the allocation of capital away from high-deliverability natural gas areas such as the Austin Chalk and focused it toward the development of longer life oil reserves in the Lake Washington area. This transition saw domestic production decline in 2002 by 23% to 34.3 Bcfe from 44.3 Bcfe in 2001. Fourth quarter 2002 domestic production of 7.6 Bcfe decreased 6% sequentially from the 8.1 Bcfe produced in the third quarter in 2002, however, current guidance provided by the Company indicates that first quarter domestic production in 2003 will increase by at least 5% sequentially to between 8.0 to 8.5 Bcfe. Total fourth quarter production in 2002 of 12.6 Bcfe increased 10% from the 11.5 Bcfe produced in the fourth quarter of 2001 and increased 3% sequentially from third quarter production in 2002.

In 2002, the Company saw substantially lower average natural gas prices of $3.01 per thousand cubic feet (“Mcf”) domestically, a decline of 29% from the $4.23 average per Mcf in 2001. Meanwhile, average domestic crude oil prices remained relatively flat at $24.57 per barrel in 2002 compared to $24.64 per barrel in 2001. Prices for NGLs domestically averaged $13.20 per barrel in 2002, a 5% increase over the 2001 NGL price. In New Zealand, the Company received an average natural gas price of $1.32 per Mcf under the Company’s long-term reserve-based contracts. Also in New Zealand, the Company’s McKee blend crude oil averaged $24.31 per barrel and the Company’s NGL contracts saw an average price of $11.06 per barrel for the year 2002. New Zealand natural gas and the NGL price contracts are denominated in New Zealand dollars, which has significantly strengthened during 2002 as it relates to the US dollar. The currency exchange rate increased to approximately 0.53 New Zealand dollars to one U. S. dollar at the end of 2002 compared to approximately 0.42 per one U. S. dollar at the end of 2001 (a 26% increase in value).

In the fourth quarter, the Company realized an aggregate global average price of $3.15 per Mcfe, an increase of 30% from fourth quarter 2001 prices, when the price averaged $2.43 per Mcfe. Domestically, the Company realized an aggregate average price of $3.93 per Mcfe, an increase of 62% over the $2.43 seen in the fourth quarter of 2001. In New Zealand, the Company received an aggregate average price of $1.97 per Mcfe for the fourth quarter in 2002.

Operations Update

Domestically, the Company has drilled five additional wells in the Lake Washington area since the last update provided on January 21, 2003, consisting of two successful wells where pipe had been set and three dry holes that were plugged. The completion rig now operating in the Lake Washington Field has recently completed one saltwater disposal well, as well as two additional oil completions. The Company also has two drilling rigs operating in the area, and it is anticipated that they will continue operations throughout the first quarter of 2003 as part of the Company’s 50 to 60 well Lake Washington drilling program in 2003. The drilling of a series of three wells in the AWP Olmos area will commence later this month. Additionally, one development well, the Bego #1 (61% working interest) in Goliad County, Texas, will spud in March, targeting the Wilcox sands.

In New Zealand, production from the TAWN and Rimu/Kauri areas has continued as expected, averaging approximately 55 million cubic feet equivalent per day during January 2003. The Company has several operations planned in the first half of 2003 in the Rimu/Kauri area, including a CO2 injection in the Tariki Sand in the Rimu-A2A well, hydraulic fracturing of the Kauri Sand in the Kauri-A4 well and the drilling of the Kauri-F1 well, targeting the Manutahi Sand.

Hedges

Since the last update on January 21, 2003, the Company has continued to enter into additional price risk management transactions. The Company recently purchased a floor of $26.25 per barrel for 200,000 barrels for April 2003. Additionally, the Company purchased participating cashless collars for 30,000 barrels per month during the second quarter of 2003 with a floor price of $25.00 per barrel and a ceiling price of $32.42 per barrel. The Company will participate in 60% of any prices received above this ceiling. The Company also purchased natural gas floors for 100,000 MMBtu per month from April through and including October 2003 at a floor price of $4.50 per MMBtu.

As a result of the above mentioned and previously reported transactions, the Company has entered into hedges covering approximately 65-70 % of the Company’s expected total crude oil production in the first quarter and 45-50 % of expected total crude oil production in the second quarter. Similarly, in regards to domestic natural gas, the Company has now protected approximately 40-45 % of its expected natural gas production in the first quarter, 55-60 % in the second quarter, 35-40 % in the third quarter, and 10-15% in the fourth quarter.

Swift Energy now maintains all its previously announced price risk management information (hedge positions) on its guidance page on the Swift Energy website (www.swiftenergy.com).

Guidance

The Company has reiterated its guidance that was released last month in conjunction with a series of analyst and investor meetings beginning January 21, 2003. The Company would also like to note that the costs listed do not include the effect of FASB 143 that requires implementation in 2003, accounting for the liability of plugging and abandonment of well bores.

Earnings Conference Call

The Company will conduct a conference call and live web cast on Wednesday, February 12, at 9:00 a.m. Central Standard Time, in conjunction with this fourth quarter and annual earnings release. To participate in this conference call, dial 973-872-3462 five to ten minutes before the scheduled start time and indicate your intention to participate in the Swift Energy conference call. This call will be available for digital replay until February 19, 2002 by dialing 973-341-3080 and using pin #3597778. Additionally, the conference call will be available over the Internet by accessing the Company’s website at www.swiftenergy.com and clicking on the event hyperlink. This webcast will be available online at the Company’s website through February 26, 2003.

Swift Energy Company engages 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. Founded in 1979 with headquarters in Houston, Texas, the Company has consistently grown its proved oil and gas reserves, production, and cash flow through a disciplined program of acquisitions and drilling, while maintaining a strong financial position.

This material includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The opinions, forecasts, projections, guidance or other statements other than statements of historical fact, are forward-looking statements. These statements are based upon assumptions that are subject to change and to risks, especially volatility in oil or gas prices, and lately availability of services and supplies. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Certain risks and uncertainties inherent in the Company’s business are set forth in the filings of the Company with the Securities and Exchange Commission. Estimates of future financial or operating performance provided by the Company are based on existing market conditions and engineering and geologic information available at this time. Actual financial and operating performance may be higher or lower. Future performance is dependent upon oil and gas prices, exploratory and development drilling results, engineering and geologic information and changes in market conditions.