The Company’s net income was $6.1 million or $0.22 per diluted share, including the cumulative effect of the accounting change. The Statement of Financial Accounting Standards No. 143 (SFAS 143) implemented January 1, 2003, is a mandated accounting change that amounted to a one-time charge for the Company of $4.4 million (net of tax), or $0.16 per diluted share. SFAS 143 "Accounting for Asset Retirement Obligations" requires companies to record the present value of estimated future abandonment obligations as a liability, with a corresponding increase in oil and gas assets.

Production increased 5% to 12.9 Billion cubic feet equivalent (“Bcfe”) in the first quarter of 2003 from 12.3 Bcfe of production in the first quarter of last year. Production increased 2% from fourth quarter 2002 levels. Domestic production was 7.7 Bcfe, and New Zealand production was 5.2 Bcfe for the first quarter of 2003.

Terry Swift, President and CEO of Swift Energy Company, noted, “We started the year with good operational success, and we have certainly been buoyed by the strong pricing environment. Our principal goal for the year is to deliver added value by meeting our production and reserve targets, while improving our operating margins. Despite the temporary partial shut-in at Lake Washington, we continue to make progress on our goals. In order to take advantage of today’s domestic natural gas market, we are now accelerating several budgeted natural gas wells and fracture stimulations that were planned to take place later in the year. New Zealand activity also has been promising this year, with the doubling of net sales during the first quarter 2003 compared to the same quarter last year, and the successful implementation of several projects in the first-half of 2003. Second-half drilling plans will allow us to better evaluate both the Kauri and Manutahi sands.”

Revenues & Expenses

Total revenues for the first quarter 2003 totaled $53.5 million, an increase of approximately 56% from revenues of $34.4 million during the first quarter in 2002. Total revenue for the first quarter of 2003 is net of $1.4 million of losses from derivative product price hedging activities, which compares with a $0.1 million gain from such activities for the first quarter of 2002. Cash flow before changes in working capital increased 176% to $31.6 million ($1.16 per diluted share) in the first quarter of 2003 compared to $11.5 million ($0.45 per diluted share) in the first quarter of 2002. Net cash provided by operating activities increased 147% to $26.8 million ($0.98 per diluted share) compared to $10.8 million ($0.43 per diluted share) in the first quarter of 2002.

Controllable lease operating expenses improved nearly 2% on a per unit basis compared to the first quarter of 2002. During the same period, general and administrative costs increased, both in total and on a per unit basis, primarily as a result of the increased costs associated with certain corporate governance actions taken in response to the recently enacted Sarbanes-Oxley Act and related regulations and also due to lower reimbursements due to the recent liquidation and dissolution of all public partnerships managed by the Company.

Production & Pricing

Domestic production was 7.7 Bcfe in the first quarter 2003, a 20% decline from 9.7 Bcfe of production in the first quarter of 2002. However, domestic production did increase 1% from fourth quarter 2002 levels and was above the Company’s most recent guidance. Despite this modest increase, there were two distinct events that negatively affected our domestic production levels for the quarter. The previously reported partial shut-in of the Lake Washington Field, in Plaquemines Parish, Louisiana, lowered production in the first quarter of 2003 by approximately 0.7-1.0 Bcfe. It is anticipated that second quarter production will also be reduced by a similar amount, as is reflected in the updated second quarter and full-year 2003 guidance that is part of this press release. Additionally, due to the relatively higher natural gas price as compared to the crude oil price during the first quarter, the Company elected to not process and separately sell the natural gas liquids (“NGLs”) in certain fields in the first quarter. This practice improves the economics of the natural gas sold; however, it reduces NGL volumes. Natural gas accounted for 47% of domestic production during the first quarter and 60% of total production.

In New Zealand, the Company produced 5.2 Bcfe, a virtual doubling over the same quarter production last year and an increase of nearly 4% from production levels in the fourth quarter of 2002. Higher natural gas demand in New Zealand has allowed the Company to both increase production from the TAWN fields, as well as increase the realized price received. Normal maintenance will occur at both the TAWN and Rimu production facilities in the second quarter and is expected to last about seven to ten days at each facility, which also is reflected in the Company’s forward guidance included with this press release.

The first quarter culminated in significantly higher commodity prices: average domestic natural gas prices received in the first quarter were $6.03 per thousand cubic feet (“Mcf”), a three-fold increase from the $1.94 per Mcf received a year earlier, while crude oil prices averaged $32.80 per barrel, up 71% from crude oil prices in the previous year’s first quarter. Condensate and natural gas liquids prices received domestically also increased significantly over those in the first quarter of 2002, providing a composite average domestic price for the quarter of $5.68 per thousand cubic feet equivalent (“Mcfe”), which was 145% more than the $2.32 per Mcfe received in the first quarter of 2002, and 45% more than the $3.93 per Mcfe received in the fourth quarter of 2002.

In New Zealand, the Company has seen its average realized price increase for five straight quarters due to a beneficial currency exchange rate and non-contracted natural gas sales into the tightening New Zealand gas market. The composite average price for New Zealand was $2.15 per Mcfe, a 35% increase over prices received in the first quarter of the previous year. Similar increases over prices received in the same quarter last year were seen on an individual product basis, with the Company receiving an average price of $1.62 per Mcf for its natural gas in 2003, a 34% increase from $1.21 received in 2002; $32.36 per barrel of crude oil in 2003, up 65% from $19.67 per barrel averaged in 2002; and $12.89 per barrel for natural gas liquids in 2003, a 31% increase from $9.81 per barrel averaged in 2002.

Domestic Operations

The Company successfully drilled 13 of 19 wells in the first quarter. The Company has successfully drilled two additional wells, one in Lake Washington and one in the AWP/Olmos area, since the last update on April 28, bringing the year-to-date total to 19 successes out of 25 wells drilled. The Company currently has two drilling rigs working in Lake Washington, one rig operating in the AWP/Olmos area in McMullen County, Texas and one rig scheduled to spud a well in the Brookeland Field in Newton County, Texas in mid-third quarter. One non-operated rig is also working in the Garcia Ranch area in Kenedy County, Texas.

Scheduled facility upgrades are underway in the Lake Washington Field that are expected to bring capacity to over 14,000 barrels per day gross processing capacity during the third quarter.

New Zealand Operations

As previously reported, the Company successfully drilled the Kauri-F1 well, targeting the shallow Manutahi Sand, in the first quarter and expects to install a pumping unit on that well to begin a prolonged production test. The Kauri-A4 well that was fracture stimulated in the first quarter, more than doubling initial test rates, is scheduled to be connected to the Rimu Production Station in the third quarter of this year. The Rimu-A2A well was treated with a CO₂ injection in an attempt to improve the Tariki Sand performance and is currently undergoing further evaluation. The Company currently plans to drill two delineation wells in the Kauri Sand, several additional Manutahi wells and one to two exploration wells in the second half of the year.

Bank Borrowing Base

As previously reported, the Company’s borrowing base was recently reaffirmed at $195 million, effective May 1. Due to improving market conditions and expectations for higher levels of cash flow, the Company has requested that its commitment amount with its bank group be reduced to $150 million effective May 9, 2003. Under the terms of its credit facility, the Company can increase this commitment amount back to the total amount of the borrowing base, at its discretion.

Earnings Conference Call

Swift Energy Company will discuss first quarter earnings results Wednesday, May 7, at 9:00 a.m. CDT. The dial-in number is 973-872-3462. Please dial-in five to ten minutes prior to the start of the call. A pass code is not required to participate in this call. The digital replay number is 973-341-3080 (Pin #3851829) and will be available until May 21, 2003. In addition, this call will be webcast 'live' and archived through our website at http://www.swiftnergy.com. 

Annual Shareholders Meeting

Swift Energy’s Annual meeting of Shareholders will be held May 13, 2003 at the Wyndham Greenspoint Hotel in Salon A, 12400 Greenspoint Drive, Houston Texas 77060 at 4:00 p.m. CDT. The public is invited to attend to hear management’s review of the Company’s 2002 activities and discuss the opportunities for 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.

Deferred Tax Percentage

98%