Adjusted cash flow (cash flow before working capital changes, a non-GAAP measure - see page 7 for reconciliation to the GAAP measure) for the third quarter of 2009 decreased 63% to $57.6 million, or $1.65 per diluted share, compared to $154.0 million, or $4.94 per diluted share, for the third quarter 2008.

Swift Energy produced 2.22 million barrels of oil equivalent (“MMBoe”) during the third quarter of 2009, which is a 4% decrease compared to third quarter 2008 production of 2.32 MMBoe and a 2% decrease compared to second quarter 2009 production.

Terry Swift, Chief Executive Officer of Swift Energy, commented, “Our third quarter 2009 results demonstrate the effectiveness of cost cutting measures undertaken in the first half of the year as well as increasing momentum in our core areas of operation. The commissioning of production facilities at Bay de Chene, better than expected performance from our recompletion and work-over programs in Lake Washington and a mild gulf coast storm season all contributed to better than expected operational and financial results.

“We have just finalized a joint venture with an industry partner to develop a portion of our acreage in South Texas believed to be prospective for the Eagle Ford shale. Drilling activity in this joint venture will begin before the end of the year, and if successful, will accelerate throughout 2010. We have also returned a drilling rig to the Lake Washington field and expect activity levels there to increase over the next twelve months.

“The focus and preparation of everyone at Swift Energy is resulting in more efficient and cost effective operations. As we increase activity levels, we expect to return to a course of meaningful production and reserves growth.”

Total revenues for the third quarter of 2009 decreased 55% to $96.3 million from the $213.8 million generated in the third quarter of 2008, primarily attributable to lower commodity prices. Revenues for the third quarter of 2009 increased 16% when compared to second quarter 2009 revenues as increased realized crude oil prices offset slightly lower natural gas prices.

Depreciation, depletion and amortization expense (“DD&A”) of $18.48 per barrel of oil equivalent (“Boe”) in the third quarter 2009 decreased from $22.52 per Boe of DD&A in the comparable period in 2008, primarily as a result of a lower depletable property base, lower production and lower future development costs. Lease operating expenses, before severance and ad valorem taxes, were $8.34 per Boe in the third quarter of 2009, a decrease of 23% compared to costs of $10.77 per Boe in the third quarter of 2008. The decrease in lease operating expenses was predominantly due to the continuation of cost reduction initiatives, including lower costs for contract field labor and for workovers, along with decreased natural gas processing, plant operating expenses and other non-operated costs. Severance and ad valorem taxes were down appreciably to $5.27 per Boe from $8.69 per Boe in the comparable period due to lower commodity prices.

General and administrative expenses decreased to $3.98 per Boe during the third quarter of 2009 from $4.36 per Boe in the same period in 2008 as a result of reduced staffing levels and other cost reduction initiatives. Interest expense increased to $3.31 per Boe in the third quarter of 2009 compared to $2.99 per Boe for the same period in 2008 due to higher borrowings through the Company’s credit facility and less capitalized interest in the 2009 period.

Swift Energy’s third quarter 2009 production was 2.22 MMBoe, a decrease of 4% when compared to 2008 third quarter production of 2.32 MMBoe. Sequentially, production decreased 2% from the 2.26 MMBoe produced in the second quarter of 2009. Third quarter production decreased as a result of minimal new drilling activity, shut-in production at Bay de Chene, which was restored on August 28, and natural declines. Production for the third quarter of 2009 was better than expected due to the start-up of production facilities at Bay de Chene in late August, higher than expected production rates from the Company’s recompletion and work-over programs in Lake Washington and a mild gulf coast storm season.

The Company realized an aggregate average price of $44.14 per Boe during the quarter, a decrease of 52% from the $92.34 average price received in the third quarter of 2008, but an improvement sequentially, as third quarter average prices were 20% higher compared to average prices realized in the second quarter of this year.

In the third quarter of 2009, average crude oil prices decreased 44% to $68.15 per barrel from $122.71 per barrel realized in the same period in 2008. For the same periods, average natural gas prices were $2.84 per thousand cubic feet (“Mcf”), a decrease of 71% from the $9.70 per Mcf average price realized a year earlier. Prices for natural gas liquids (“NGL”) averaged $35.09 per barrel in the third quarter for a 50% decrease from third quarter 2008 NGL prices of $70.55 per barrel.

Swift Energy drilled three wells during the third quarter of 2009. Two horizontal wells and one vertical well were drilled in the Olmos formation at the AWP field in McMullen County, Texas during the third quarter.

In the Company’s South Texas core area, the R Bracken 33H well, located in the AWP field and now online for over ten months, continues to perform above expectations. The estimated ultimate recovery of this well is now anticipated to be at the high end of our original 3-5 billion cubic feet equivalent estimate.

The R Bracken 34H and 35H horizontal wells were drilled and completed in the Olmos formation in the southern portion of the AWP field during the third quarter. The initial production rate for the R Bracken 34H was 5.7 million cubic feet of gas per day (“MMcf/d”) with flowing tubing pressure of 2,175 psi on a 36/64” choke. This well’s production decline has already turned hyperbolic and production has stabilized at the current production rate of approximately 1.8 MMcf/d. The initial production rate of the R Bracken 35H well, the second horizontal well drilled during the quarter, was 4.6 MMcfe/d with a flowing tubing pressure of 4,200 psi on a 14/64” choke. Mechanical difficulties developed after approximately five days of production and the well was plugged off in the well bore. The well bore was subsequently cleaned out and the well is currently being brought online slowly at a controlled rate of 2.3 MMcf/d with flowing tubing pressure of 1,900 psi.

The R Bracken 36H is currently being drilled. In this well, a pilot hole was drilled, cored and logged. Cores and logs of this well will be utilized to enhance the understanding of the depositional environments of the Southwest AWP area and enhance the Company’s ability to relate petrophysical properties to logs and to better predict reserve recoveries in future development wells. The completion design of this well will be modified to reduce the risk of mechanical issues similar to those encountered by the R Bracken 35H. One additional horizontal Olmos well will be drilled after the R Bracken 36H and then the rig will be released to allow time for a technical evaluation of the 2009 horizontal Olmos drilling program.

In the northern portion of AWP, a shallow drilling program commenced during the quarter. The Gonzalez #2 well, a vertical well, was drilled to a depth of 9,510 feet and logged 25 feet of net pay during the third quarter to the Olmos formation in AWP. This well initially tested at a rate of just over 100 Boe per day (“Boe/d”) and is now producing to sales. The Quintanilla #2 and #3 wells were drilled during the fourth quarter to depths of 9,571 and 9,570 feet encountering 27 feet and 25 feet of pay in the Olmos formation, respectively. The Quintanilla #2 tested at a rate of 218 Boe/d and is waiting on connection to production facilities. The Quintanilla #3 will be fracture stimulated after it is connected to production facilities. One rig will remain active, drilling oil targets, in this area for the remainder of 2009.

Additionally, over 150 wells in the AWP field have been identified as candidates for an additional fracture stimulation operation. Since the beginning of September, eleven of these identified wells have been fracture stimulated. Initial production rates in these eleven wells averaged 600 Mcf/d, which is significantly higher than the average results from previous fracture stimulations in the field. The Company plans to perform fracture stimulations on two wells per week for the remainder of 2009 and into 2010.

On November 2, Swift Energy announced a joint exploration and development agreement with Petrohawk Energy Corporation (“Petrohawk”). The Company will retain a 50% interest in an approximate 26,000 acre prospect area located in its AWP field. This prospect area covers leasehold interests beneath the Olmos formation (including the Eagle Ford Shale formation) extending to the base of the Pearsall formation. The Company received approximately $26 million in cash consideration upon signing the agreement, and Petrohawk will also fund approximately $13 million of capital expenditures on Swift Energy’s behalf within the first twelve months of the joint venture. Presently, Swift Energy expects to utilize this entire $13 million amount to cover drilling and completion costs of horizontal wells targeting the Eagle Ford Shale in the joint venture area. If the full amount is not utilized during the first twelve months of the joint venture, the difference will be paid to Swift Energy as a cash consideration. An appraisal well will be drilled to test the Eagle Ford shale horizon in this joint venture area in 2009 with one rig expected to be active during all of 2010.

Additionally, the Company has a sizable acreage position of prospective Eagle Ford Shale acreage outside of this joint venture, which it owns 100%. Plans to evaluate and appraise the other Eagle Ford acreage positions include drilling a horizontal test well before year-end.

In its Southeast Louisiana core area, the Company began a shallow drilling program during the third quarter in the Lake Washington field, located in Plaquemines Parish, Louisiana. The CM 400 was drilled to a measured depth of 6,023 feet and encountered 31 feet of true vertical net pay. The CM 403 was drilled to a measured depth of 5,365 feet and encountered an estimated 52 feet of true vertical net pay. Both wells concluded drilling operations during the fourth quarter and are now being connected to production facilities. This one rig program will remain active during the fourth quarter.

Also during the quarter at Lake Washington, a production optimization program involving gas lift enhancements and sliding sleeve shifts to change productive zones was continued to assist in mitigation of natural field declines. Well work was completed on four wells and five recompletions were performed during the third quarter. All five recompletions tested above expectations.

In the Bay de Chene field, located in Jefferson and Lafourche Parishes, facilities construction and upgrades resulting from damages caused by Hurricane Gustav were completed and these facilities were brought online August 28. Initial crude oil production averaged approximately 2,590 gross barrels of oil per day (“BBls/d”) along with natural gas production of 20.4 MMcf/d over the first seven days after the start-up of these facilities, which was higher than expected. Field-wide production over the last seven days has averaged approximately 1,100 gross BBls/d of oil and 17.1 MMcf/d of natural gas. No wells have been drilled in Bay de Chene in 2009 nor are any wells planned to be drilled there until 2010.

After a regular semi-annual review of its $500 million facility by its bank group, Swift Energy’s borrowing base was affirmed at $300 million effective November 1, 2009. Swift Energy had $80.8 million outstanding on this facility as of September 30, 2009.

Swift Energy has purchased natural gas floors that will cover 600,000 MMbtu per month of its first quarter 2010 natural gas production at an average NYMEX strike price of $4.90 per MMBtu. In addition, the Company has entered into a collar transaction that provides a floor price of $4.50 per MMBtu covering 200,000 per month of first quarter 2010 natural gas production and a ceiling price of $6.80 per MMBtu for 100,000 MMBtu per month during the first quarter. The Company has also purchased floors for its second quarter 2010 natural gas production at a $4.66 per MMBtu average NYMEX strike price covering 880,000 MMBtu per month. On an ongoing basis, details of Swift Energy’s complete price risk management activities can be found on the Company’s website (www.swiftenergy.com).

Swift Energy will conduct a live conference call today, November 3, at 9:00 a.m. CST to discuss third quarter 2009 financial results. To participate in this conference call, dial 973-339-3086 five to ten minutes before the scheduled start time and indicate your intention to participate in the Swift Energy conference call. A delayed digital replay of the call will also be available November 3 through November 10, by dialing 706-645-9291 and using pin #27924363. Additionally, the conference call will be available over the internet by accessing the Company’s website at www.swiftenergy.com and by clicking on the event hyperlink. This webcast will be available online and archived at the Company’s website for approximately two weeks after the call.

Swift Energy Company, founded in 1979 and headquartered in Houston, engages in developing, exploring, acquiring and operating oil and gas properties, with a focus on oil and natural gas reserves onshore in Louisiana and Texas and in the inland waters of Louisiana.

This press release 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 the uncertainty and costs of finding, replacing, developing and acquiring reserves, availability of labor, services, supplies and facility capacity, hurricanes or tropical storms disrupting operations, and, volatility in oil or gas prices, uncertainty and costs of finding, replacing, developing or acquiring reserves, and disruption of operations 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.