Swift Energy had a very eventful and overall a very positive second quarter. Our oil and gas production was 12.7 billion cubic feet equivalent (Bcfe), up 13% from the same quarter in 2001 and up 3% from the first quarter of this year. While commodity prices were still well below those we enjoyed during the first half of last year, the average price received for our combined oil and gas sales during the second quarter of this year was 39% higher than it was in the first quarter. Our second-quarter expenditures were within our cash flow, and with net proceeds of $224.95 million from the debt and equity offerings we closed during the quarter, our balance sheet was strengthened and our Company liquidity was significantly improved. We also had no short-term bank debt at the end of the quarter.

With the persistently low commodity prices within our industry, our net income for the second quarter of 2002 declined significantly from the second quarter of 2001—by 76% to $3.6 million ($0.13 per diluted share). Cash flow from operating activities before working capital changes declined 47% to $20.3 million ($0.76 per share). The corresponding numbers for the six-months period ending June 30 were an 82% decrease in net income to $6.6 million ($0.25 per diluted share) and a 63% decrease in cash flow to $31.7 million ($1.23 per share).

To continue operating within our cash flow, we have taken numerous steps to cut operational costs. Nevertheless, we made excellent progress during the second quarter in adding long-lived stable production to our production base. Domestically, the additions were made in our newest core area, the Lake Washington Field, which surrounds a deep salt dome in Plaquemines Parish, Louisiana. Largely targeting relatively shallow sands (typically the A through E sands at depths of 1,500 to 4,000 feet), we drilled one exploratory well and seven development wells in the field during the second quarter, all with 100% Swift working interests. Of these, four are in production, and two, including the exploratory well, are awaiting a completion rig. In the third quarter, we have already drilled five additional development wells, three of which have good hydrocarbon shows and one of which will be redrilled because of mechanical problems. Our average daily net production from the Lake Washington Area has increased from 652 barrels of oil equivalent (BOEs) in March 2001 to 1,817 BOEs in June 2002.

Like our wells in the AWP Olmos Field in South Texas, the Lake Washington wells should be long-term producers with relatively flat decline rates and thus will help stabilize our production base. Initially, we had planned to drill 22 wells in the Lake Washington Area during 2002, but now we have decided to increase that number by five to ten wells using funds generated through cost savings, the deferral of other projects, and the marketing of some of our non-core assets. This decision follows the encouraging drilling results in the field plus an upside surprise. In one of our second-quarter wells (the Cockrell-Moran #187), we were targeting the deep H and K sands, and to reach them, we angled the initially straight bore hole away from the salt dome face. At a depth of 4,278 feet we entered a highly productive 179-foot thickness of the F sand, not previously known to be productive. Positive results for this sand have since been found in two additional wells, and we now predict that it has risked potential reserves of 10 to 20 million barrels of oil. As a result, we will include the F sand as a regular target for at least one-half of our remaining Lake Washington wells this year. In the meantime, we are mapping the deeper horizons in the area—at depths of 6,000 feet and greater—for future drilling.

As we concentrate on the Lake Washington Area, we are also performing additional technical reviews of the Garcia Ranch area in the southern tip of Texas and plan to spud the first of several prospects there in September. In the AWP Olmos Field, we are continuing to perform refractures and, having recently been granted an Entity for Density permit from the state of Texas, we will be in a position to increase and upgrade our inventory of proved undeveloped locations for in-fill drilling. As announced earlier, further drilling in the Masters Creek Area in Louisiana and the Brookeland Area in Texas has been deferred while we focus on lower cost, lower risk, and longer-lived properties in the current low-price environment.

In New Zealand, our combined oil and gas production during the second quarter was 45% higher than in the first quarter, both because the Rimu Production Station (RPS) in the Rimu/Kauri Area became operational in April and because we had increased production from our new TAWN Area. The RPS production averaged 1,011 BOEs per day, and we expect the station to be operating above 50% of its capacity (now rated at 5,000 BOEs per day) by year end. Current production is from two wells from the Rimu A pad, but a third well, recently fractured, will be added soon, and another well will be drilled from the pad before year end. The Rimu B pad wells have pressures below the RPS inlet pressure and will not be added to the production stream until later.

The second-quarter production from the TAWN properties averaged 40 million cubic feet of gas equivalent (MMcfe) per day. In the third quarter, however, demand for the TAWN production is expected to fall to about 35 MMcfe per day, as more hydroelectric power becomes available from recent rainfall. Like the AWP and Lake Washington fields, the TAWN fields have added long-lived stable production to our production base and also have considerable enhancement potential.

Our current drilling in New Zealand is focused on the Kauri-A4 well, a deep exploratory well that was spudded in June and will be drilling for about 100 days. We will do extensive testing of any potentially productive zones encountered in the well, including the expected Kauri, Tariki, and Kapuni sands, after which we will resume production testing of the shallow Kauri-A2 and -A3 wells and the deep Kauri-A1 well. During the second quarter, we also participated (with a 15% working interest) in the drilling of a deep well located between our TAWN and Rimu/Kauri properties. This well, the Huinga-1B, is currently undergoing testing.

It has, indeed, been an eventful second quarter—and not only in the field. We recently appointed Ernst & Young LLP as our new independent public accountants and have made a number of other business decisions to optimally navigate the current industry environment. In these and other actions, our Board of Directors has provided us with excellent advice. We will continue benefiting from that advice as the Board welcomes its newest member, Mr. Raymond E. Galvin, formerly president of Chevron U.S.A. Production Company. With these leaders and the superb managers and staff we have throughout the Company, I am extremely optimistic about the future of Swift Energy Company.