SWIFT ENERGY COMPANY NEWS

SWIFT ENERGY REPORTS RECORD 2001 PRODUCTION; REVENUES AND NET EARNINGS DOWN DUE TO LOWER PRICES AND HIGHER COSTS

HOUSTON, February 14, 2002 - Swift Energy Company (NYSE, PCX: SFY) reported today that production for 2001 increased to an annual record of 44.8 billion cubic feet equivalent (“Bcfe”), an increase of 6% from 2000 levels. Year-end 2001 reserves quantities increased approximately 3% to 646 Bcfe. Net earnings for 2001, excluding non-recurring charges principally due to a full cost pool writedown, totaled $42.5 million ($1.67 per diluted share) down from $59.2 million ($2.51 per diluted share) last year, primarily due to significantly lower oil prices and overall increased costs. The non-recurring charges of $101.0 million before taxes include a domestic, non-cash, full cost ceiling adjustment of $98.9 million before tax ($63.5 million after tax).

Revenues for 2001 totaled $183.8 million, down 4% from $191.6 million in 2000, and cash flow from operations, before changes in working capital, totaled $124.0 million ($5.01 per share) for 2001, a decline of 12% from $140.9 million ($6.63 per share) in the prior year. The Company experienced higher costs in 2001 in several areas. Lease operating and depreciation, depletion and amortization expenses increased primarily as a result of increased severance and production taxes, higher capital expenditures for drilling and workover activity as well as the result of numerous inefficiencies that resulted from the industry being pushed to capacity during the past year. General and administrative costs increased as expected due to a reduced amount of reimbursement associated with the final stages of the Company managed partnership divestiture and liquidation process. Interest expense declined by 21% due to lower interest rates and the conversion in December 2000 of debt.

As anticipated and previously disclosed, Swift has now quantified and recorded a domestic, non-cash, full cost ceiling adjustment during the fourth quarter of 2001. This domestic $98.9 million pre-tax charge ($63.5 million after-tax) resulted from the application of ceiling test rules as prescribed by the Securities and Exchange Commission for companies that follow the full cost method of accounting. Under the full cost method of accounting, a company’s net book value of its oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. Full cost companies must use the prices in effect at the end of each quarter to calculate the ceiling value of reserves. In addition to this domestic ceiling adjustment, Swift also expensed $2.1 million of charges in the fourth quarter for certain delinquent accounts receivable, the majority of which is related to gas sold to Enron in November, and a write-off of debt issuance costs for a planned offering that was cancelled based upon market conditions following the events of September 11, 2001.

Revenues in the fourth quarter 2001 were $27.9 million, down 52% from $58.2 million in the fourth quarter of 2000. Primarily as a result of the previously mentioned domestic, non-cash, full cost ceiling adjustment, the net loss reported for the fourth quarter of 2001 was $67.1 million ($2.71 per diluted share) compared to net income of $19.5 million ($0.80 per diluted share) for the same quarter in 2000. Cash flow from operations, before changes in working capital, declined 73% to $12.3 million ($0.49 per share) compared to $44.9 million ($2.06 per share) in the fourth quarter of 2000.

Fourth quarter production of 11.5 Bcfe increased 10% from 10.5 Bcfe in the fourth quarter of 2000 and decreased slightly from the third quarter of 2001 levels. Reflecting lower market prices, average natural gas prices received in the fourth quarter were $2.21 per thousand cubic feet (“Mcf”), a decrease of 60% from the $5.55 per Mcf received a year earlier, while oil prices averaged $16.02 per barrel, down 50% from oil prices in the previous year’s fourth quarter. This provided a composite average price for the quarter of $2.43 per thousand cubic feet equivalent (“Mcfe”), which was 56% less than the $5.49 per Mcfe received in the fourth quarter of 2000 and 28% less than the $3.36 per Mcfe received in the third quarter of 2001. Natural gas accounted for 51% of total production during the fourth quarter.

Due to the recent weakness in oil and gas prices and the successful closing of the TAWN acquisition, the Company is adjusting its capital budget and 2002 guidance accordingly. The Company expects that production for the first quarter of 2002 will range from 11.5 to 12.0 Bcfe, which is an upward revision of previous guidance of 11.0 to 11.5 Bcfe, with approximately 15 - 20% coming from New Zealand. Production from New Zealand will become a significant factor in the Company’s production this year resulting from the acquisition of the TAWN properties and the completion of the Rimu Production Station allowing for initial production from the Rimu/Kauri area. Given the current outlook for commodity prices, the Company’s capital expenditure budget, excluding the net effect of acquisitions and dispositions, is being reduced approximately 27% to $77.9 million dollars. Production for the full year 2002, however, is still expected to increase 10% to 20% (49.0 to 54.0 Bcfe) with 25% to 35% of the full year production coming from New Zealand.

The Company also reported an increase in proven reserves of 3% and a reserve replacement rate of 137%. Total reserves reported as of December 31, 2001, were 646 Bcfe, up from 629 Bcfe at the end of 2000. These reserves included 325 billion cubic feet of natural gas (50% of total) and 53.5 million barrels of oil and natural gas liquids. Of the total, 544 Bcfe (84%) were domestic reserves, and the remaining reserves of 102 Bcfe (16%) were from New Zealand. The proved developed reserves associated with the TAWN property acquisition of 65 Bcfe, which closed in January 2002, are not included in the Company’s year-end reserve report.

Domestic reserves were 57% proved developed with 53% of the total being natural gas. These reserves were concentrated in the Company's core areas including the AWP Olmos area (32% of total/38% of domestic), the Masters Creek area (16%/19%), the Brookeland area (9%/11%) and the Lake Washington Field (11%/13%).

With regard to New Zealand reserves, 34% are classified as proved developed with the remainder classified as proved undeveloped. Oil and natural gas liquids comprise 64% of these reserves. During 2001, the Company focused primarily on development of the Upper Tariki in the Rimu area with a limited amount of exploration in the Kauri area. Recent drilling information and long term test data in the Rimu area resulted in a downward revision in reserves quantities of approximately 38 Bcfe. Proven reserve additions in the Kauri area from the shallow Manutahi oil sands were estimated at approximately 17 Bcfe. The net downward revision of approximately 21 Bcfe for proven quantities in New Zealand does not reflect any offset by reserve additions in probable and possible reserves categories. The drilling activity and subsequent testing established the presence of hydrocarbons in numerous additional formations, which are not presently considered as proven reserves. Considerable new probable and possible reserve quantities have been established in the Kauri, Manutahi, Urenui, Upper and Lower Tariki sands. Current drilling and testing operations will provide additional information and may re-classify probable or possible reserves into the proven categories. In particular, the Kauri-A1 well, as previously disclosed, will complete testing in the second or third quarter of 2002. The Company has identified nine distinct hydrocarbon-bearing formations in the Rimu/Kauri area.

Terry Swift, President and Chief Executive Officer of Swift Energy Company, noted that, “In light of the current market prices and the successful closing of the strategic TAWN properties in New Zealand, management presented the Swift Board of Directors with a greatly reduced budget focusing on lower risk crude oil development and potential acquisition opportunities, both domestic and international. During this time of price weakness, we have implemented cost reduction programs and are committed to improving our product margins in our core domestic properties. The Company remains positioned for growth domestically. Based on our recent geologic mapping and drilling results, we believe the Lake Washington Field holds considerable promise. Swift will focus considerable effort developing this long-life, oil producing, domestic project. In New Zealand, Swift will commission and begin operating the Rimu Production Station this quarter and continue development of its new Petroleum Mining Permit 38151 focusing on the Upper Tariki sand, which may require hydraulic fracture treatments to optimize production and recoveries. We will also be concentrating on the potential that the shallow Manutahi oil sands hold for development. We currently expect to test, and appraise, our Kauri, Matai and Tawa prospects within the next eighteen months. We continue to believe that this area has the potential for 250 million barrels of oil equivalent or more. The Company is also considering a joint venture partner to accelerate these significant exploratory tests through a sale of up to 25% of its position in the Rimu/Kauri permits.”

During the fourth quarter of 2001, the Company participated in four development wells and two exploratory wells. All of these wells were completed except for one exploration well, the Rodriguez #1 well, which was temporarily abandoned in the Garcia Ranch area. Two development wells were drilled and completed in the Lake Washington Field and one in the Masters Creek area plus one non-operated well. For the full year 2001, the Company drilled and completed 36 development wells (100% success rate) and six of 11 exploratory wells (55% success rate).

Early in 2002, the Company finished drilling the CM #196 well (100% working interest), in the Duckhead Prospect in the Lake Washington Field in Plaquemines Parish, Louisiana. This exploratory well encountered hydrocarbon shows while drilling in three different sand intervals below 8,000 feet; however, it also experienced mechanical difficulties, including tools stuck in the hole, and a full suite of logs was not obtained. Casing was set at a depth of 7,661 feet, and the well will be used as a water injection well. The Company plans to re-drill this prospect later in the year.

Also in the Lake Washington Field, the Company has drilled the SL 212 #99 well (100% working interest) and found 41 feet of pay in an I-series sand. The well is waiting for a completion rig for completion and testing. The drilling rig will be moving to the BLD-CM #15 well (100% working interest) with a target depth of 7,150 feet. Also, the CM #192 well (100% working interest), which had originally been reported as producing over 800 Mcf/d of natural gas, began producing oil, as expected, at rates up to 300 barrels of oil per day with 500 Mcf/d of natural gas. Swift has completed some initial infrastructure improvements and other upgrade work in the field, which will reduce operating costs and enhance production throughput.

The Kauri-A3 well encountered approximately 42 feet of Manutahi sand with hydrocarbons confirmed with mud logs and through wireline electric logs. Casing was set, and the well is now waiting for the completion rig. Additional testing of the Kauri-A1 and Kauri-A2 wells was suspended during the drilling of the Kauri-A3 well. The Kauri-A2 had been completed over the Manutahi sand. Plans are underway to develop additional pads to further develop this shallow Manutahi sand, each of which could see up to five wells drilled in the next few years. The Rimu-A2 well is being sidetracked to target the Upper Tariki sand and is currently at a depth of 11,516 feet.

The Rimu Production Station, including the oil and gas separation and processing facilities, is now expected to be operational in March, with commissioning and plant start-up expected to begin this month and take up to eight weeks to come up to full operational status.

The Company will conduct a conference call and live webcast on Thursday, February 14, at 1:00 p.m. Central Standard Time, in conjunction with this fourth quarter earnings release. To participate in this conference call dial 973-872-3462 five to ten minutes before the start of the call and indicate your intention to participate in the Swift Energy conference call. This call will be available for digital replay until February 28th by dialing (973) 341-3080 (PIN# 3067454). Additionally, the conference call will be available by accessing the Company’s website at www.swiftenergy.com and clicking on the hyperlink.

Swift Energy Company engages in developing, exploring, acquiring, and operating oil and gas properties, with a focus on onshore 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 grown its proved oil and gas reserves, production, and cash flow over the last five years through a disciplined program of acquisitions and drilling, while maintaining a strong financial position.