Swift Energy’s financial results for the three-month period ending September 30 added to the celebration of the Company’s 25th anniversary on October 11. Our revenues reached $74.9 million—a record high that exceeded our 2003 third-quarter revenues by 45%. Before the effect of a debt retirement expense of $6.8 million (a non-GAAP measure), our net income was $18.5 million, or $0.65 per diluted share; after the effect, it was $14.1 million, or $0.50 per diluted share, a 100% increase over our net income in the third quarter of 2003. Cash flow before working capital changes (a non-GAAP measure) rose 69% to $46.8 million, or $1.64 per diluted share. (Our November 4 press release, which is available on our web site, provides the reconciliation of GAAP to non-GAAP measures.)

For the first nine months of 2004, our revenues totaled $211.3 million, a 36% increase from the same period in 2003, and our net income was $41.6 million, or $1.47 per diluted share, a 104% increase. Cash flow before working capital changes increased 48% to $127.7 million.

Our strong performance this year comes both from our increasing production, particularly our crude oil production, and from the higher prices we have received for our oil and natural gas. During the third quarter we received an average of $5.36 per thousand cubic feet of natural gas equivalent (Mcfe) compared to $3.82 per Mcfe in the third quarter of 2003. For the first nine months we received an average of $5.00 per Mcfe compared to $3.97 per Mcfe for the same period in 2003. In the first and second quarters of this year, our average prices increased to $4.62 and $5.04 per Mcfe, respectively.

Our total marketed production during the third quarter of 2004 was 13.9 billion cubic feet of natural gas equivalent (Bcfe), a 2% increase from the third quarter of 2003 but somewhat lower than we anticipated because of a sales delay in New Zealand and a shut- in for a short period in the Lake Washington Field in Plaquemines Parish, Louisiana, during the hurricane season. For the first nine months of the year, our total marketed production was 42.5 Bcfe, a 7% increase from the first nine months of 2003.

Our domestic production during the third quarter of 2004 was 10.2 Bcfe, which was 16% higher than in the third quarter of 2003. For the first nine months of 2004, our domestic production was 30.8 Bcfe, a 23% increase over the same period in 2003. These increases are largely attributable to increased oil production in the Lake Washington Field. During the third quarter of 2004, domestic oil production was 33% higher than in the third quarter of 2003, comprising 59.5% of our total domestic production and selling at an average of $41.60 per barrel.

In New Zealand, our sales volume during the third quarter totaled 3.7 Bcfe, a 23% decrease from the same period in 2003. This decrease would have been smaller if a tanker lifting scheduled for September had not been delayed until October. The overall prices we receive in New Zealand continue to improve, with average crude oil prices reaching $47.75 per barrel (in U.S. dollars), a 66% increase from the third quarter of 2003.

Domestically, we continue to focus our operations in the Lake Washington Area, pushing our average daily rates of production from the field during the first nine months of 2004 to 9,800 net barrels of oil equivalent (BOE) from 5,000 net BOE for the same period in 2003. Our total production from the field during the first nine months of 2004 increased by 94% from the same period in 2003, despite the loss in sales of approximately 117,000 BOE during the field shut-in. During the month of October we averaged 12,500 net BOE per day, surpassing our year-end exit goal of 12,000 net BOE per day.

Since we began operations in Lake Washington in 2001, we have drilled 111 wells to the field’s multiple Miocene sand layers at depths of 3,000 to 10,000 feet with a 79% success rate, a majority with 100% working interests. Because we focused on a three-dimensional seismic survey over the entire area through most of this year, our 2004 Lake Washington drilling program for the first nine months was reduced to 21 wells with 17 completions. During the third quarter, we had six completions out of seven wells drilled. We now have three drilling rigs in the field with plans to drill 8 to12 wells during the fourth quarter.

Based on the analysis of our new seismic data combined with our geological studies of Lake Washington, we are identifying additional potential oil targets at intermediate depths of 6,000 to 12,000 feet, as well as gaining insights relative to reservoir management and future facility design. We have also acquired 550 square miles of three-dimensional seismic data for an area to the west of Lake Washington and are merging it with our own data to obtain better imaging of deeper potential targets, most likely natural gas targets. We already have permits to drill over 100 wells in Lake Washington, and with the additional targets from seismic interpretation we expect to have up to a five-year drilling inventory in the area. In order to accommodate such a program we are working hard to increase our processing and delivery capacity above our current levels.

In the AWP Olmos Area in McMullen County, Texas, we completed three out of four development wells drilled to the Olmos sand during the third quarter and completed two more wells drilled early in the fourth quarter, bringing the total number of AWP completions this year to 13 wells out of 15 drilled, all with 100% working interests. We plan to return a rig to the area early next year.

We also drilled development wells in three other South Texas counties during the third quarter. Two were completed in the Wilcox sands, one in Goliad County and the other in Duval County with 87% and 69% working interests, respectively. The third well, drilled to the Frio sands in Willacy County with a 72% working interest, was unsuccessful. We plan to drill one more well in South Texas during the fourth quarter and will begin drilling a dual horizontal well in the Austin Chalk trend in our Brookeland Area in East Texas early next year.

In New Zealand, we are very optimistic that our detailed studies of the rock formations and oil and gas recovery methods in the Rimu/Kauri Area are now paying off. During the third quarter, we modified our fracture stimulation techniques in the Kauri formation on three wells drilled earlier in the year (the Kauri-E3, -E4, and -E5) and, while the results have not yet been determined for one well, the test flow rates on the other two wells were 10.3 and 10.8 million cubic feet of natural gas equivalent per day plus several hundred barrels of condensate, approximately double what we have seen in the earlier Kauri wells. The Kauri-E6 well, which also targeted the Kauri sandstone but was drilled deeper to test the Tariki sand at that location, was completed in the Tariki sand, where it encountered a limited reservoir, and it is now awaiting recompletion in the Kauri sandstone. The Kauri-E7 well was spudded in the fourth quarter and is now drilling, with additional Kauri wells to follow next year. In order to handle the increasing gas production, we expanded the processing capacity of the Rimu Production Station earlier in the year from its original 10 million to 20 million cubic feet of gas per day and are looking at further expansions of the plant.

During the third quarter we also completed the final well in a six-well program in the Rimu/Kauri Area targeting the shallow oil-bearing Manutahi sand. We have completed five of the wells with various completion methods and are evaluating the optimal method for continued drilling next year.

In our New Zealand TAWN Area, we finished drilling the Tariki-D1 well targeting the Tariki sand to a total depth of 8,570 feet early in the fourth quarter. The well is currently undergoing completion and production testing. In 2005, we expect our overall New Zealand program to include two to four exploration wells.

For all the foregoing third-quarter activities, our capital expenditures were $42.6 million, well within the $49.3 million net cash provided by our operating activities. Our liquidity position remains very strong, and our bank line is still largely untapped. As has been our custom, we continue to layer in forward protection in this very strong commodity market by purchasing floor prices for both oil and gas, a strategy that has served us well in the past.

To reiterate, I can state that this year of our 25th anniversary truly has been an exceptional year for Swift Energy Company, and, I believe, it foretells good tidings for the future. Not only does the Company have much to look forward to, but so also do all of its stakeholders.